Edgar Filing: LOEWS CORP

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K


[X]		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
		THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2012


[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From to

Commission File Number 1-6541

LOEWS CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

13-2646102

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

667 Madison Avenue, New York, N.Y. 10065-8087

(Address of principal executive offices) (Zip Code)

(212) 521-2000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class								Name of each exchange on which registered
Loews Common Stock, par value $0.01 per share								New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes

No X

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes X

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ].

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer X Accelerated filer Non-accelerated filer Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes

No X

The aggregate market value of voting and non-voting common equity held by non-affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $12,707,000,000.

As of February 15, 2013, there were 391,885,833 shares of Loews common stock outstanding.

Documents Incorporated by Reference:

Portions of the Registrant’s definitive proxy statement intended to be filed by Registrant with the Commission prior to April 30, 2013 are incorporated by reference into Part III of this Report.

LOEWS CORPORATION

INDEX TO ANNUAL REPORT ON

FORM 10-K FILED WITH THE

SECURITIES AND EXCHANGE COMMISSION

For the Year Ended December 31, 2012


Item		Page
No.	PART I		No.

1	Business
	CNA Financial Corporation		3
	Diamond Offshore Drilling, Inc.		9
	Boardwalk Pipeline Partners, LP		12
	HighMount Exploration & Production LLC		15
	Loews Hotels Holding Corporation		20
	Executive Officers of the Registrant		21
	Available Information		22
1A	Risk Factors		22
1B	Unresolved Staff Comments		43
2	Properties		43
3	Legal Proceedings		43
4	Mine Safety Disclosures		43

	PART II

5	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		44
6	Selected Financial Data		46
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		47
7A	Quantitative and Qualitative Disclosures about Market Risk		94
8	Financial Statements and Supplementary Data		98
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		177
9A	Controls and Procedures		177
9B	Other Information		177

	PART III

	Certain information called for by Part III (Items 10, 11, 12, 13 and 14) has been omitted as Registrant intends to file with the Securities and Exchange Commission not later than 120 days after the close of its fiscal year a definitive Proxy Statement pursuant to Regulation 14A.

	PART IV

15	Exhibits and Financial Statement Schedules		178

PART I

Unless the context otherwise requires, references in this Report to “Loews Corporation,” “we,” “our,” “us” or like terms refer to the business of Loews Corporation excluding its subsidiaries.

Item 1. Business.

We are a holding company. Our subsidiaries are engaged in the following lines of business:

—

commercial property and casualty insurance (CNA Financial Corporation, a 90% owned subsidiary);

—

operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc., a 50.4% owned subsidiary);

—

transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas (Boardwalk Pipeline Partners, LP, a 55% owned subsidiary);

—

exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC, a wholly owned subsidiary); and

—

operation of hotels (Loews Hotels Holding Corporation, a wholly owned subsidiary).

Please read information relating to our major business segments from which we derive revenue and income contained in Note 20 of the Notes to Consolidated Financial Statements, included under Item 8.

CNA FINANCIAL CORPORATION

CNA Financial Corporation (together with its subsidiaries, “CNA”) was incorporated in 1967 and is an insurance holding company. CNA’s property and casualty and remaining life & group insurance operations are primarily conducted by Continental Casualty Company (“CCC”), incorporated in 1897, and The Continental Insurance Company (“CIC”), organized in 1853, and certain other affiliates. CIC became a subsidiary of CNA in 1995 as a result of the acquisition of The Continental Corporation (“Continental”). CNA accounted for 65.6%, 63.4% and 63.0% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

CNA’s insurance products primarily include commercial property and casualty coverages, including surety. CNA’s services include risk management, information services, warranty and claims administration. CNA’s products and services are primarily marketed through independent agents, brokers and managing general underwriters to a wide variety of customers, including small, medium and large businesses, insurance companies, associations, professionals and other groups.

CNA’s property and casualty field structure consists of 49 underwriting locations across the United States. In addition, there are five centralized processing operations which handle policy processing, billing and collection activities, and also act as call centers to optimize service. The claims structure consists of two regional claim centers designed to efficiently handle the high volume of low severity claims including property damage, liability, and workers’ compensation medical only claims, and 16 principal claim offices handling the more complex claims. In addition, CNA has underwriting and claim capabilities in Canada and Europe.

CNA Specialty

CNA Specialty includes the following business groups:

Professional & Management Liability: Professional & Management Liability provides management and professional liability insurance and risk management services and other specialized property and casualty coverages in the United States. This group provides professional liability coverages to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and technology firms. Professional & Management Liability also provides directors and officers (“D&O”), employment practices, fiduciary and fidelity coverages. Specific areas of focus include small and mid-size firms as well as privately held firms and not-for-profit

organizations, where tailored products for this client segment are offered. Products within Professional & Management Liability are distributed through brokers, independent agents and managing general underwriters. Professional & Management Liability, through CNA HealthPro, also offers insurance products to serve the health care industry. Products include professional liability and associated standard property and casualty coverages, and are distributed on a national basis through brokers, independent agents and managing general underwriters. Key customer segments include long term care facilities, allied health care providers, life sciences, dental professionals and mid-size and large health care facilities.

International: International provides similar management and professional liability insurance and other specialized property and casualty coverages, through similar distribution channels, in Canada and Europe.

Surety: Surety offers small, medium and large contract and commercial surety bonds. CNA Surety provides surety and fidelity bonds in all 50 states through a network of independent agencies. On June 10, 2011, CNA completed the acquisition of the noncontrolling interest of CNA Surety.

Warranty and Alternative Risks: Warranty and Alternative Risks provides extended service contracts and related products that provide protection from the financial burden associated with mechanical breakdown and other related losses, primarily for vehicles and portable electronic communication devices.

CNA Commercial

CNA Commercial’s property products include standard and excess property coverages, as well as marine coverage, and boiler and machinery. Casualty products include standard casualty insurance products such as workers’ compensation, general and product liability, commercial auto and umbrella coverages. Most insurance programs are provided on a guaranteed cost basis; however, CNA also offers specialized loss-sensitive insurance programs to those customers viewed as higher risk and less predictable in exposure.

These property and casualty products are offered as part of CNA’s Small Business, Commercial and International insurance groups. CNA’s Small Business insurance group serves its smaller commercial accounts and the Commercial insurance group serves CNA’s middle markets and its larger risks. In addition, CNA Commercial provides total risk management services relating to claim and information services to the large commercial insurance marketplace, through a wholly owned subsidiary, CNA ClaimPlus, Inc., a third party administrator. The International insurance group primarily consists of the commercial product lines of CNA’s operations in Europe and Canada. During the fourth quarter of 2011, CNA sold its 50% ownership interest in First Insurance Company of Hawaii (“FICOH”).

Also included in CNA Commercial is CNA Select Risk (“Select Risk”), which includes CNA’s excess and surplus lines coverages. Select Risk provides specialized insurance for selected commercial risks on both an individual customer and program basis. Customers insured by Select Risk are generally viewed as higher risk and less predictable in exposure than those covered by standard insurance markets. Select Risk’s products are distributed throughout the United States through specialist producers, program agents and brokers.

Hardy

In July of 2012, CNA completed the acquisition of Hardy Underwriting Bermuda Limited (“Hardy”), a specialized Lloyd’s of London (“Lloyd’s”) underwriter. Through Lloyd’s Syndicate 382, Hardy underwrites primarily short-tail exposures in the following coverages: Marine & Aviation provides coverage for a variety of large risks including energy, cargo and specie, marine hull and general aviation. Non-Marine Property comprises direct and facultative property, including construction insurance of industrial and commercial risks (heavy industry, general manufacturing and commercial property portfolios), together with residential and small commercial risks. Property Treaty Reinsurance offers catastrophe reinsurance on an excess of loss basis, proportional treaty and excess of loss coverages and crop reinsurance. Specialty Lines offers coverage for a variety of risks including political violence, accident and health and financial institutions.

Life & Group Non-Core

Life & Group Non-Core primarily includes the results of the life and group lines of business that are in run-off. CNA continues to service its existing individual long term care commitments, its payout annuity business and its pension deposit business. CNA also retains a block of group reinsurance and life settlement contracts. These businesses are being managed as a run-off operation. CNA’s group long term care business, while considered non-core, continues to accept new employees in existing groups.

Other

Other primarily includes certain CNA corporate expenses, including interest on CNA corporate debt, and the results of certain property and casualty business in run-off, including CNA Re and asbestos and environmental pollution (“A&EP”). In 2010, CNA ceded substantially all of its legacy A&EP liabilities under the Loss Portfolio Transfer, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

Direct Written Premiums by Geographic Concentration

Set forth below is the distribution of CNA’s direct written premiums by geographic concentration.


Year Ended December 31	2012			2011			2010


California		9.5	%		9.4	%		9.3	%
Texas		7.4			6.7			6.5
New York		7.1			6.7			6.8
Illinois		6.5			4.9			4.0
Florida		5.8			6.1			6.1
New Jersey		3.5			3.5			3.5
Pennsylvania		3.4			3.4			3.4
Canada		3.0			3.0			2.9
All other states, countries or political subdivisions		53.8			56.3			57.5

		100.0	%		100.0	%		100.0	%

Approximately 9.2%, 8.8% and 6.9% of CNA’s direct written premiums were derived from outside of the United States for the years ended December 31, 2012, 2011 and 2010.

Property and Casualty Claim and Claim Adjustment Expenses

The following loss reserve development table illustrates the change over time of reserves established for property and casualty claim and claim adjustment expenses at the end of the preceding ten calendar years for CNA’s property and casualty insurance companies. The table excludes CNA’s life insurance subsidiaries, and as such, the carried reserves will not agree to the Consolidated Financial Statements included under Item 8. The first section shows the reserves as originally reported at the end of the stated year. The second section, reading down, shows the cumulative amounts paid as of the end of successive years with respect to the originally reported reserve liability. The third section, reading down, shows re-estimates of the originally recorded reserves as of the end of each successive year, which is the result of CNA’s property and casualty insurance subsidiaries’ expanded awareness of additional facts and circumstances that pertain to the unsettled claims. The last section compares the latest re-estimated reserves to the reserves originally established, and indicates whether the original reserves were adequate or inadequate to cover the estimated costs of unsettled claims.

The loss reserve development table is cumulative and, therefore, ending balances should not be added since the amount at the end of each calendar year includes activity for both the current and prior years. The development amounts in the table below include the impact of reinsurance commutations, but exclude the impact of the allowance for doubtful accounts on reinsurance receivables.


	Schedule of Loss Reserve Development

Year Ended December 31	2002			2003			2004			2005			2006			2007			2008			2009		2010(a)		2011			2012(b)

(In millions of dollars)

Originally reported gross reserves for unpaid claim and claim adjustment expenses		25,719			31,284			31,204			30,694			29,459			28,415			27,475			26,712		25,412		24,228			24,696
Originally reported ceded recoverable		10,490			13,847			13,682			10,438			8,078			6,945			6,213			5,524		6,060		4,967			5,075

Originally reported net reserves for unpaid claim and claim adjustment expenses		15,229			17,437			17,522			20,256			21,381			21,470			21,262			21,188		19,352		19,261			19,621

Cumulative net paid as of:
One year later		5,373			4,382			2,651			3,442			4,436			4,308			3,930			3,762		3,472		4,277			-
Two years later		8,768			6,104			4,963			7,022			7,676			7,127			6,746			6,174		6,504		-			-
Three years later		9,747			7,780			7,825			9,620			9,822			9,102			8,340			8,374		-		-			-
Four years later		10,870			10,085			9,914			11,289			11,312			10,121			9,863			-		-		-			-
Five years later		12,814			11,834			11,261			12,465			11,973			11,262			-			-		-		-			-
Six years later		14,320			12,988			12,226			12,917			12,858			-			-			-		-		-			-
Seven years later		15,291			13,845			12,551			13,680			-			-			-			-		-		-			-
Eight years later		16,022			14,073			13,245			-			-			-			-			-		-		-			-
Nine years later		16,180			14,713			-			-			-			-			-			-		-		-			-
Ten years later		16,754			-			-			-			-			-			-			-		-		-			-
Net reserves re-estimated as of:
End of initial year		15,229			17,437			17,522			20,256			21,381			21,470			21,262			21,188		19,352		19,261			19,621
One year later		17,650			17,671			18,513			20,588			21,601			21,463			21,021			20,643		18,923		19,081			-
Two years later		18,248			19,120			19,044			20,975			21,706			21,259			20,472			20,237		18,734		-			-
Three years later		19,814			19,760			19,631			21,408			21,609			20,752			20,014			20,012		-		-			-
Four years later		20,384			20,425			20,212			21,432			21,286			20,350			19,784			-		-		-			-
Five years later		21,076			21,060			20,301			21,326			20,982			20,155			-			-		-		-			-
Six years later		21,769			21,217			20,339			21,060			20,815			-			-			-		-		-			-
Seven years later		21,974			21,381			20,142			20,926			-			-			-			-		-		-			-
Eight years later		22,168			21,199			20,023			-			-			-			-			-		-		-			-
Nine years later		22,016			21,100			-			-			-			-			-			-		-		-			-
Ten years later		21,922			-			-			-			-			-			-			-		-		-			-

Total net (deficiency) redundancy		(6,693	)		(3,663	)		(2,501	)		(670	)		566			1,315			1,478			1,176		618		180			-


Reconciliation to gross re-estimated reserves:
Net reserves re-estimated		21,922			21,100			20,023			20,926			20,815			20,155			19,784			20,012		18,734		19,081			-
Re-estimated ceded recoverable		16,903			15,273			14,131			11,455			9,131			7,728			6,686			6,032		6,536		5,316			-

Total gross re-estimated reserves		38,825			36,373			34,154			32,381			29,946			27,883			26,470			26,044		25,270		24,397			-


Total gross (deficiency) redundancy		(13,106	)		(5,089	)		(2,950	)		(1,687	)		(487	)		532			1,005			668		142		(169	)		-


Net (deficiency) redundancy related to:
Asbestos		(827	)		(177	)		(123	)		(113	)		(112	)		(107	)		(79	)		-		-		-			-
Environmental pollution		(282	)		(209	)		(209	)		(159	)		(159	)		(159	)		(76	)		-		-		-			-

Total asbestos and environmental pollution		(1,109	)		(386	)		(332	)		(272	)		(271	)		(266	)		(155	)		-		-		-			-
Core (Non-asbestos and environmental pollution)		(5,584	)		(3,277	)		(2,169	)		(398	)		837			1,581			1,633			1,176		618		180			-

Total net (deficiency) redundancy		(6,693	)		(3,663	)		(2,501	)		(670	)		566			1,315			1,478			1,176		618		180			-

(a)

Effective January 1, 2010, CNA ceded approximately $1.5 billion of net asbestos and environmental pollution claim and allocated claim adjustment expense reserves relating to its continuing operations under a retroactive reinsurance agreement with an aggregate limit of $4.0 billion, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

(b)	On July 2, 2012, CNA acquired Hardy. As a result of this acquisition, net reserves were increased by $291 million. Further information on this acquisition is included in Note 2 of the Notes to Consolidated Financial Statements included under Item 8.

Please read information relating to CNA’s property and casualty claim and claim adjustment expense reserves and reserve development set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), and in Notes 1 and 8 of the Notes to Consolidated Financial Statements, included under Item 8.

Investments

Please read Item 7, MD&A – Investments and Notes 1, 3, 4 and 5 of the Notes to Consolidated Financial Statements, included under Item 8.

Other

Competition: The property and casualty insurance industry is highly competitive both as to rate and service. CNA competes with a large number of stock and mutual insurance companies and other entities for both distributors and customers. Insurers compete on the basis of factors including products, price, services, ratings and financial strength. CNA must continuously allocate resources to refine and improve its insurance products and services.

There are approximately 2,800 individual companies that sell property and casualty insurance in the United States. Based on 2011 statutory net written premiums, CNA is the seventh largest commercial insurance writer and the 13th largest property and casualty insurance organization in the United States.

Regulation: The insurance industry is subject to comprehensive and detailed regulation and supervision. Each domestic and foreign jurisdiction has established supervisory agencies with broad administrative powers relative to licensing insurers and agents, approving policy forms, establishing reserve requirements, prescribing the form and content of statutory financial reports, and regulating capital adequacy and the type, quality and amount of investments permitted. Such regulatory powers also extend to premium rate regulations, which require that rates not be excessive, inadequate or unfairly discriminatory. In addition to regulation of dividends by insurance subsidiaries, intercompany transfers of assets may be subject to prior notice or approval by insurance regulators, depending on the size of such transfers and payments in relation to the financial position of the insurance subsidiaries making the transfer or payment.

Hardy is also supervised by the Council of Lloyd’s, which is the franchisor for all Lloyd’s operations. The Council of Lloyd’s has wide discretionary powers to regulate Lloyd’s underwriting, such as establishing the capital requirements for syndicate participation. In addition, the annual business plans of each syndicate are subject to the review and approval of the Lloyd’s Franchise Board, which is responsible for business planning and monitoring for all syndicates.

The European Union’s executive body, the European Commission, is implementing new capital adequacy and risk management regulations called Solvency II that would apply to CNA’s European operations. In addition, global regulators, including the United States National Association of Insurance Commissioners, are working with the International Association of Insurance Supervisors (“IAIS”) to consider changes to insurance company supervision. Among the areas being addressed are company and group capital requirements, group supervision and enterprise risk management. It is not currently clear to what extent or how the activities of the IAIS will impact CNA or U.S. insurance regulation.

Domestic insurers are also required by the state insurance regulators to provide coverage to insureds who would not otherwise be considered eligible by the insurers. Each state dictates the types of insurance and the level of coverage that must be provided to such involuntary risks. CNA’s share of these involuntary risks is mandatory and generally a function of its respective share of the voluntary market by line of insurance in each state.

Further, insurance companies are subject to state guaranty fund and other insurance-related assessments. Guaranty fund assessments are levied by the state departments of insurance to cover claims of insolvent insurers. Other insurance-related assessments are generally levied by state agencies to fund various organizations including disaster relief funds, rating bureaus, insurance departments, and workers’ compensation second injury funds, or by industry organizations that assist in the statistical analysis and ratemaking process.

Although the federal government does not directly regulate the business of insurance, federal legislative and regulatory initiatives can impact the insurance industry in a variety of ways. These initiatives and legislation include tort reform proposals; proposals addressing natural catastrophe exposures; terrorism risk mechanisms; federal financial services reforms; various tax proposals affecting insurance companies; and possible regulatory limitations, impositions and restrictions arising from the Dodd-Frank Wall Street Reform and Consumer Protection Act, as well as the Patient Protection and Affordable Care Act, both enacted in 2010.

Various legislative and regulatory efforts to reform the tort liability system have, and will continue to, impact CNA’s industry. Although there has been some tort reform with positive impact to the insurance industry, new causes of action and theories of damages continue to be proposed in state court actions or by federal or state legislatures that continue to expand liability for insurers and their policyholders. For example, some state legislatures have from time to time considered legislation addressing direct actions against insurers related to bad faith claims. As a result of this unpredictability in the law, insurance underwriting is expected to continue to be difficult in commercial lines, professional liability and other specialty coverages.

The Dodd-Frank Wall Street Reform and Consumer Protection Act expanded the federal presence in insurance oversight and may increase the regulatory requirements to which CNA may be subject. The Act’s requirements include streamlining the state-based regulation of reinsurance and nonadmitted insurance (property or casualty insurance placed from insurers that are eligible to accept insurance, but are not licensed to write insurance in a particular state). The Act also established a new Federal Insurance Office within the U.S. Department of the Treasury. The Act called for numerous studies and contemplates further regulation.

The Patient Protection and Affordable Care Act and the related amendments in the Health Care and Education Reconciliation Act may increase CNA’s operating costs and underwriting losses. This landmark legislation may lead to numerous changes in the health care industry that could create additional operating costs for CNA, particularly with respect to its workers’ compensation and long term care products.

Properties: The Chicago location houses CNA’s principal executive offices. CNA’s subsidiaries own or lease office space in various cities throughout the United States and in other countries. The following table sets forth certain information with respect to CNA’s principal office locations:


Location	Size (square feet)		Principal Usage


333 S. Wabash Avenue Chicago, Illinois		732,332	Principal executive offices of CNA
401 Penn Street Reading, Pennsylvania		169,941	Property and casualty insurance offices
2405 Lucien Way Maitland, Florida		111,724	Property and casualty insurance offices
125 S. Broad Street New York, New York		68,935	Property and casualty insurance offices
101 S. Reid Street Sioux Falls, South Dakota		64,789	Property and casualty insurance offices
4150 N. Drinkwater Boulevard Scottsdale, Arizona		56,281	Property and casualty insurance offices
600 N. Pearl Street Dallas, Texas		50,088	Property and casualty insurance offices
675 Placentia Avenue Brea, California		49,957	Property and casualty insurance offices
4267 Meridian Parkway Aurora, Illinois		46,903	Data center
10375 Park Meadows Drive Littleton, Colorado		41,706	Property and casualty insurance offices

CNA leases its office space described above except for the buildings in Chicago, Illinois, Reading, Pennsylvania and Aurora, Illinois, which are owned.

DIAMOND OFFSHORE DRILLING, INC.

Diamond Offshore Drilling, Inc. (“Diamond Offshore”) is engaged, through its subsidiaries, in the business of operating drilling rigs that are chartered on a contract basis for fixed terms by companies engaged in the exploration and production of hydrocarbons. Offshore rigs are mobile units that can be relocated based on market demand. Diamond Offshore accounted for 21.1%, 23.6% and 23.0% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

Rigs: Diamond Offshore owns 44 offshore drilling rigs, consisting of 32 semisubmersible rigs, seven jack-ups and five dynamically positioned drillships, four of which are under construction with deliveries scheduled for the second and fourth quarters of 2013 and the second and fourth quarters of 2014. Diamond Offshore’s semisubmersible fleet also includes the Ocean Onyx and Ocean Apex, two moored semisubmersible rigs which are under construction and expected to be delivered in the third quarter of 2013 and the second quarter of 2014. Diamond Offshore’s diverse fleet enables it to offer a broad range of services worldwide in both the floater market (ultra-deepwater, deepwater and mid-water) and the non-floater, or jack-up market.

A floater rig is a type of mobile offshore drilling unit that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersible rigs hold position while drilling by use of a series of small propulsion units or thrusters that provide dynamic positioning (“DP”) to keep the rig on location, or with anchors tethered to the seabed. Although DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats; non-DP, or moored, semisubmersible rigs require tug boats or the use of a heavy lift vessel to move between locations.

A drillship is an adaptation of a maritime vessel which is designed and constructed to carry out drilling operations by means of a substructure with a moon pool centrally located in the hull. Drillships are typically self-propelled and are positioned over a drillsite through the use of either an anchoring system or a DP system similar to those used on semisubmersible rigs.

Diamond Offshore’s floater fleet (semisubmersibles and drillships) can be further categorized based on the nominal water depth for each class of rig as follows:


Category	Rated Water Depth (a) (in feet)	Number of Units in Fleet

Ultra-Deepwater	7,501 to 12,000	12 (b)
Deepwater	5,000 to 7,500	7 (c)
Mid-Water	400 to 4,999	18 (d)

(a)

Rated water depth for semisubmersibles and drillships reflects the maximum water depth in which a floating rig has been designed to operate. However, individual rigs are capable of drilling, or have drilled, in marginally greater water depths depending on conditions (such as salinity of the ocean, weather and sea conditions).

(b)	Includes four drillships under construction.

(c)	Includes two rigs to be constructed utilizing the hulls of two of Diamond Offshore’s existing mid-water floaters.

(d)	Includes three rigs which are being marketed for sale.

Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. Diamond Offshore’s jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is able to operate is principally determined by the length of the rig’s legs. The rig hull includes the drilling equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed until they are firm and stable, and resistance is sufficient to elevate the hull above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the

water and then the legs are retracted for relocation to another drillsite. All of Diamond Offshore’s jack-up rigs are equipped with a cantilever system that enables the rig to extend its drilling package over the aft end of the rig.

Fleet Enhancements and Additions: Diamond Offshore’s long term strategy is to upgrade its fleet to meet customer demand for advanced, efficient and high-tech rigs by acquiring or building new rigs when possible to do so at attractive prices, and otherwise by enhancing the capabilities of its existing rigs at a lower cost and reduced construction period than newbuild construction would require. Diamond Offshore has contracted with Hyundai Heavy Industries Co. Ltd., for the construction of four dynamically positioned, ultra-deepwater drillships. Diamond Offshore expects the aggregate cost for the four drillships, including commissioning, spares and project management costs, to be approximately $2.6 billion.

Construction has begun on two moored semisubmersible rigs designed to operate in water depths up to 6,000 feet. The rigs will be constructed utilizing the hulls of two of Diamond Offshore’s mid-water floaters and the aggregate cost of the two rigs is estimated to be approximately $680 million, including commissioning, spares and project management costs.

In February of 2013, Diamond Offshore announced that one of its mid-water floaters, the Ocean Patriot, will undergo enhancements to enable the rig to work in the North Sea at an estimated aggregate cost of approximately $120 million. The enhancement project is expected to begin during the third quarter of 2013 with completion expected in early 2014.

Diamond Offshore will evaluate further rig acquisition and upgrade opportunities as they arise. However, Diamond Offshore can provide no assurance whether, or to what extent, it will continue to make rig acquisitions or upgrades to its fleet.

Markets: The principal markets for Diamond Offshore’s contract drilling services are the following:

—

South America, principally offshore Brazil;

—

Australia and Asia, including Malaysia, Indonesia, Thailand and Vietnam;

—

the Middle East, including Kuwait, Qatar and Saudi Arabia;

—

Europe, principally in the United Kingdom (“U.K.”) and Norway;

—

East and West Africa;

—

the Mediterranean Basin, including Egypt; and

—

the Gulf of Mexico, including the U.S. and Mexico.

Diamond Offshore actively markets its rigs worldwide. From time to time Diamond Offshore’s fleet operates in various other markets throughout the world.

Diamond Offshore believes its presence in multiple markets is valuable in many respects. For example, Diamond Offshore believes that its experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and other international areas in which Diamond Offshore operates, while production experience it has gained through its Brazilian and North Sea operations has potential application worldwide. Additionally, Diamond Offshore believes its performance for a customer in one market area enables it to better understand that customer’s needs and better serve that customer in different market areas or other geographic locations.

Drilling Contracts: Diamond Offshore’s contracts to provide offshore drilling services vary in their terms and provisions. Diamond Offshore typically obtains its contracts through a competitive bid process, although it is not unusual for Diamond Offshore to be awarded drilling contracts following direct negotiations. Drilling contracts generally provide for a basic fixed dayrate regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for reductions in rates during periods when the rig is being moved or when

drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, Diamond Offshore generally pays the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of Diamond Offshore’s revenues. In addition, from time to time, Diamond Offshore’s dayrate contracts may also provide for the ability to earn an incentive bonus from its customer based upon performance.

The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a group of wells, which Diamond Offshore refers to as a well-to-well contract, or a fixed period of time, in what Diamond Offshore refers to as a term contract. Many drilling contracts may be terminated by the customer in the event the drilling rig is destroyed or lost or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party to the contract. Certain of Diamond Offshore’s contracts also permit the customer to terminate the contract early by giving notice, and in most circumstances, this requires the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension.

Customers: Diamond Offshore provides offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2012, 2011 and 2010, Diamond Offshore performed services for 35, 52 and 46 different customers. During 2012, 2011 and 2010, one of Diamond Offshore’s customers in Brazil, Petróleo Brasileiro S.A. (“Petrobras”), (a Brazilian multinational energy company that is majority-owned by the Brazilian government), accounted for 33%, 35% and 24% of Diamond Offshore’s annual total consolidated revenues. OGX Petróleo e Gás Ltda. (“OGX”), (a privately owned Brazilian oil and natural gas company), accounted for 12%, 14% and 14% of Diamond Offshore’s annual total consolidated revenues in each of the years ended December 31, 2012, 2011 and 2010. No other customer accounted for 10% or more of Diamond Offshore’s annual total consolidated revenues during 2012, 2011 or 2010.

Brazil is one of the most active floater markets in the world today. Currently, the greatest concentration of Diamond Offshore’s operating assets is offshore Brazil, where it has 12 rigs contracted. Diamond Offshore’s contract backlog attributable to its expected operations offshore Brazil is $1.2 billion, $1.0 billion, $0.5 billion and $62 million for the years 2013, 2014, 2015 and 2016.

Competition: Despite consolidation in recent years, the offshore contract drilling industry remains highly competitive with numerous industry participants, none of which at the present time has a dominant market share. The industry may also experience additional consolidation in the future, which could create other large competitors. Some of Diamond Offshore’s competitors may have greater financial or other resources than Diamond Offshore. Diamond Offshore competes with offshore drilling contractors that together have almost 780 mobile rigs available worldwide.

The offshore contract drilling industry is influenced by a number of factors, including global economies and demand for oil and natural gas, current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs.

Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job. Customers may also consider rig availability and location, a drilling contractor’s operational and safety performance record, and condition and suitability of equipment. Diamond Offshore believes it competes favorably with respect to these factors.

Diamond Offshore competes on a worldwide basis, but competition may vary significantly by region at any particular time. Competition for offshore rigs generally takes place on a global basis, as these rigs are highly mobile and may be moved, at a cost that may be substantial, from one region to another. It is characteristic of the offshore contract drilling industry to move rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. Significant new rig construction and upgrades of existing drilling units could also intensify price competition.

Governmental Regulation: Diamond Offshore’s operations are subject to numerous international, foreign, U.S., state and local laws and regulations that relate directly or indirectly to its operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use.

Operations Outside the United States: Diamond Offshore’s operations outside the U.S. accounted for approximately 94%, 90% and 81% of its total consolidated revenues for the years ended December 31, 2012, 2011 and 2010.

Properties: Diamond Offshore owns an office building in Houston, Texas, where its corporate headquarters are located, offices and other facilities in New Iberia, Louisiana, Aberdeen, Scotland, Macae, Brazil and Ciudad del Carmen, Mexico. Additionally, Diamond Offshore currently leases various office, warehouse and storage facilities in Louisiana, Australia, Indonesia, Norway, Malaysia, Singapore, Egypt, Equatorial Guinea, Angola, Vietnam and the U.K. to support its offshore drilling operations.

BOARDWALK PIPELINE PARTNERS, LP

Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”) is engaged in integrated natural gas and natural gas liquids (“NGLs”) transportation and storage and natural gas gathering and processing. Boardwalk Pipeline accounted for 8.1%, 8.1% and 7.7% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

We own approximately 55% of Boardwalk Pipeline comprised of 102,719,466 common units, 22,866,667 class B units and a 2% general partner interest. A wholly owned subsidiary of ours, Boardwalk Pipelines Holding Corp. (“BPHC”) is the general partner and holds all of Boardwalk Pipeline’s incentive distribution rights which entitle the general partner to an increasing percentage of the cash that is distributed by Boardwalk Pipeline in excess of $0.4025 per unit per quarter.

In October of 2012, Boardwalk Pipeline acquired Boardwalk Louisiana Midstream LLC (“Louisiana Midstream”) for approximately $620 million. Louisiana Midstream provides transportation and storage services for natural gas and NGLs, fractionation services for NGLs and brine supply services for producers and consumers of petrochemicals through two hubs in southern Louisiana.

Boardwalk Pipeline owns and operates approximately 14,170 miles of interconnected natural gas pipelines directly serving customers in 13 states and indirectly serving customers throughout the northeastern and southeastern United States through numerous interconnections with unaffiliated pipelines. Boardwalk Pipeline also owns approximately 240 miles of NGL pipelines in Louisiana. In 2012, its pipeline systems transported approximately 2.5 trillion cubic feet (“Tcf”) of gas and approximately 7.1 million barrels (“MMbbls”) of NGLs. Average daily throughput on Boardwalk Pipeline’s natural gas pipeline systems during 2012 was approximately 6.9 billion cubic feet (“Bcf”). Boardwalk Pipeline’s natural gas storage facilities are comprised of 14 underground storage fields located in four states with aggregate working gas capacity of approximately 201.0 Bcf and Boardwalk Pipeline’s NGL storage facilities consist of eight salt dome storage caverns located in one state with an aggregate storage capacity of approximately 17.6 MMbbls. Boardwalk Pipeline also owns two salt dome caverns for use in providing brine supply services and to support the NGL cavern operations.

The pipeline and storage systems of Boardwalk Pipeline consist of the following:

The Gulf Crossing pipeline system, which originates in Texas and proceeds into Louisiana, operates approximately 360 miles of natural gas pipeline. The pipeline system has a peak-day delivery capacity of 1.7 Bcf per day and average daily throughput for the year ended December 31, 2012 was 1.3 Bcf per day.

The Gulf South pipeline system runs approximately 7,240 miles along the Gulf Coast in the states of Texas, Louisiana, Mississippi, Alabama and Florida. Gulf South has two natural gas storage facilities with 83.0 Bcf of working gas storage capacity. The pipeline system has a peak-day delivery capacity of 6.8 Bcf per day and average daily throughput for the year ended December 31, 2012 was 3.0 Bcf per day.

The Texas Gas pipeline system originates in Louisiana, East Texas and Arkansas and runs for approximately 6,110 miles north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, and into Ohio, with smaller diameter lines extending into Illinois. The pipeline system has a peak-day delivery capacity of 4.4 Bcf per day and average daily throughput for the year ended December 31, 2012 was 2.5 Bcf per day. Texas Gas owns nine natural gas storage fields with 84.0 Bcf of working gas storage capacity.

Field Services operates natural gas gathering, compression, treating and processing infrastructure in southern Texas and in the Marcellus Shale area in Pennsylvania with approximately 355 miles of pipeline.

Boardwalk HP Storage Company, LLC (“HP Storage”) owns and operates seven salt dome natural gas storage caverns in Mississippi, with 36.3 Bcf of total storage capacity, of which approximately 23.0 Bcf is working gas capacity. HP Storage also operates approximately 105 miles of pipeline which connects its facilities with several major natural gas pipelines, including Gulf South. Average daily throughput for the pipeline system for the year ended December 31, 2012 was 0.1 Bcf per day. HP Storage also owns undeveloped land which is suitable for up to six additional storage caverns, one of which is expected to be placed in service in 2013.

Louisiana Midstream’s storage services provide approximately 53.2 MMbbls of salt dome storage capacity, including approximately 11.0 Bcf of working natural gas storage capacity and approximately 17.6 MMbbls of salt dome NGL storage capacity, significant brine supply infrastructure including two salt dome caverns and more than 240 miles of pipeline assets, including an extensive ethylene distribution system.

Boardwalk Pipeline’s current expansion projects include the following:

Southeast Market Expansion: The Southeast Market Expansion project is an interconnection between Boardwalk Pipeline’s Gulf South pipeline and HP Storage facilities, additional compression facilities and approximately 70 miles of additional pipeline, adding 0.5 Bcf per day of peak-day transmission capacity, subject to Federal Energy Regulatory Commission (“FERC”) approval. The project is expected to be placed in service in the second half of 2014 and will cost approximately $300 million. The Southeast Market Expansion project is fully contracted with a weighted-average contract life of approximately 10 years.

South Texas Eagle Ford Expansion: The South Texas Eagle Ford Expansion construction project consists of 55 miles of gathering pipeline and a cryogenic processing plant. The system will have the capability of gathering in excess of 0.3 Bcf per day of liquids-rich gas in the Eagle Ford Shale production area in Texas and processing up to 150 MMcf per day of liquids-rich gas. Boardwalk Pipeline will also provide re-delivery of processed residue gas to a number of interstate and intrastate pipelines. Boardwalk Pipeline has executed long term fee-based gathering and processing agreements for approximately 50% of the plant’s processing capacity. The plant and new pipeline are estimated to cost approximately $180 million and are expected to be placed in service in April of 2013.

Salt Dome Storage: HP Storage is developing a new salt dome storage cavern having working gas capacity of approximately 5.3 Bcf, which is expected to be placed in service in the second quarter of 2013 with an estimated cost of approximately $23 million.

Choctaw Brine Supply Expansion Projects: Louisiana Midstream is engaged in two brine supply service expansion projects. The first brine supply project consists of the development of a one million barrel brine pond, which was placed in service in January of 2013 at a total cost of approximately $13 million. Louisiana Midstream has executed seven-year, fixed-fee contracts in support of this project. The second project, which is supported by a 20-year commitment with minimum volume requirements, consists of constructing 26 miles of 12-inch pipeline from Louisiana Midstream’s facilities to a petrochemical customer’s plant. This project is expected to cost approximately $50 million and is expected to be placed in service in the third quarter of 2013.

Customers: Boardwalk Pipeline serves a broad mix of customers, including producers of natural gas, local distribution companies, marketers, electric power generators, industrial users and interstate and intrastate pipelines, located throughout the Gulf Coast, Midwest and Northeast regions of the U.S.

Competition: Boardwalk Pipeline competes with numerous other pipelines that provide transportation, storage and other services at many locations along its pipeline systems. Boardwalk Pipeline also competes with pipelines that are attached to new natural gas supply sources that are being developed closer to some of its traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of Boardwalk Pipeline’s traditional customers. As a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with Boardwalk Pipeline’s natural gas pipeline services. Further, natural gas competes with other forms of energy available to Boardwalk Pipeline’s customers, including electricity, coal, fuel oils and alternative fuel sources.

The principal elements of competition among pipelines are available capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. In many cases, the elements of competition, in particular flexibility, terms of service and reliability, are key differentiating factors between competitors. This is especially the case with capacity being sold on a longer term basis. Boardwalk Pipeline is focused on finding opportunities to enhance its competitive profile in these areas by increasing the flexibility of its pipeline systems to meet the demands of customers, such as power generators and industrial users, and is continually reviewing its services and terms of service to offer customers enhanced service options.

Seasonality: Boardwalk Pipeline’s revenues can be affected by weather, natural gas price levels and natural gas price volatility. Weather impacts natural gas demand for heating needs and power generation, which in turn influences the short term value of transportation and storage across Boardwalk Pipeline’s pipeline systems. Colder than normal winters can result in an increase in the demand for natural gas for heating needs and warmer than normal summers can impact cooling needs, both of which typically result in increased pipeline transportation revenues and throughput. While traditionally peak demand for natural gas occurs during the winter months driven by heating needs, the increased use of natural gas for cooling needs during the summer months has partially reduced the seasonality of revenues. In 2012, approximately 53% of Boardwalk Pipeline’s revenue was recognized in the first and fourth quarters of the year.

Governmental Regulation: FERC regulates Boardwalk Pipeline’s natural gas operating subsidiaries under the Natural Gas Act (“NGA”) of 1938 and the Natural Gas Policy Act (“NGPA”) of 1978. FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the extension, enlargement or abandonment of facilities under its jurisdiction. Where required, Boardwalk Pipeline’s natural gas interstate subsidiaries hold certificates of public convenience and necessity issued by FERC covering certain of their facilities, activities and services. The maximum rates that may be charged by Boardwalk Pipeline’s subsidiaries operating under FERC’s jurisdiction, for all aspects of the natural gas transportation services it provides, are established through FERC’s cost-of-service rate-making process. The maximum rates that may be charged by Boardwalk Pipeline for storage services on Texas Gas, with the exception of services associated with a portion of the working gas capacity on that system, are established through FERC’s cost-of-service rate-making process. Key determinants in FERC’s cost-of-service rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. FERC has authorized Boardwalk Pipeline to charge market-based rates for its firm and interruptible storage services for the majority of its storage facilities. None of Boardwalk Pipeline’s FERC-regulated entities has an obligation to file a new rate case.

Boardwalk Pipeline is also regulated by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 (“NGPSA”) and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas and NGL pipeline facilities. Boardwalk Pipeline has received authority from the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency of DOT, to operate certain natural gas pipeline assets under special permits that will allow it to operate those assets at higher than normal operating pressures of up to 0.80 of the pipe’s Specified Minimum Yield Strength (“SMYS”). Operating at higher than normal operating pressures will allow each of these pipelines to transport all of the volumes Boardwalk Pipeline has contracted for with its customers. PHMSA retains discretion whether to grant or maintain authority for Boardwalk Pipeline to operate these natural gas pipeline assets at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along their pipelines and take additional measures to protect pipeline

segments located in highly populated areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Act”) was enacted in 2012 and increased maximum civil penalties for certain violations to $200,000 per violation per day, and from a total cap of $1 million to $2 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

Boardwalk Pipeline’s operations are also subject to extensive federal, state, and local laws and regulations relating to protection of the environment. Such regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental regulations also require that Boardwalk Pipeline’s facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.

Properties: Boardwalk Pipeline is headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. Boardwalk Pipeline also leases approximately 108,000 square feet of office space in Owensboro, Kentucky. Boardwalk Pipeline’s operating subsidiaries own their respective pipeline systems in fee. However, substantial portions of these systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents.

HIGHMOUNT EXPLORATION & PRODUCTION LLC

HighMount Exploration & Production, LLC (“HighMount”) is engaged in the exploration, production and marketing of natural gas and oil (including condensate and NGLs). HighMount accounted for 2.0%, 2.5% and 2.9% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

HighMount’s proved reserves and production are primarily located in the Sonora field, a tight sands gas formation within the Permian Basin in West Texas. HighMount holds mineral rights on over 500,000 net acres in the Permian Basin, with over 6,000 producing wells. In addition, HighMount has working interests in undeveloped oil and gas properties located on approximately 73,000 net acres in Oklahoma and approximately 9,000 net acres in the Texas Panhandle which contain primarily oil reserves. During 2012, HighMount began the commercial development of its Oklahoma properties, utilizing horizontal drilling and hydraulic fracturing technologies.

HighMount’s interests in developed and undeveloped acreage, wellbores and well facilities generally take the form of working interests in leases that have varying terms. HighMount’s interests in these properties are, in many cases, held jointly with third parties and may be subject to royalty, overriding royalty, carried, net profits and other similar interests and contractual arrangements with other parties as is customary in the oil and gas industry. HighMount also owns and operates approximately 3,000 miles of gathering lines and over 65,000 horsepower of compression which are used to transport natural gas and NGLs principally from HighMount’s producing wells to processing plants and pipelines owned by third parties.

We use the following terms throughout this discussion of HighMount’s business, with “equivalent” volumes computed with oil and NGL quantities converted to Mcf, on an energy equivalent ratio of one barrel to six Mcf:


Average price	-	Average price during the twelve-month period, prior to the date of the estimate, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements with customers, excluding escalations based upon future conditions
Bbl	-	Barrel (of oil or NGLs)
Bcf	-	Billion cubic feet (of natural gas)
Bcfe	-	Billion cubic feet of natural gas equivalent
Developed acreage	-	Acreage assignable to productive wells
Gross acres	-	Total acres in which HighMount owns a working interest
Gross wells	-	Total number of wells in which HighMount owns a working interest
Mcf	-	Thousand cubic feet (of natural gas)
Mcfe	-	Thousand cubic feet of natural gas equivalent
MMBbl	-	Million barrels (of oil or NGLs)
MMBtu	-	Million British thermal units
MMcf	-	Million cubic feet (of natural gas)
MMcfe	-	Million cubic feet of natural gas equivalent
Net acres	-	The sum of all gross acres covered by a lease or other arrangement multiplied by the working interest owned by HighMount in such gross acreage
Net wells	-	The sum of all gross wells multiplied by the working interest owned by HighMount in such wells
NGL	-	Natural Gas Liquids – largely ethane and propane as well as some heavier hydrocarbons
Productive wells	-	Producing wells and wells mechanically capable of production
Proved reserves	-	Quantities of natural gas, NGLs and oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations
Proved developed reserves	-	Proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods
Proved undeveloped reserves	-	Proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required
Tcf	-	Trillion cubic feet (of natural gas)
Tcfe	-	Trillion cubic feet of natural gas equivalent
Undeveloped acreage	-	Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas

As of December 31, 2012, HighMount owned 825.1 Bcfe of net proved reserves, of which 84.1% were classified as proved developed reserves. HighMount’s estimated total proved reserves consist of 557.6 Bcf of natural gas, 35.1 MMBbls of NGLs, and 9.5 MMBbls of oil and condensate. HighMount produced approximately 154 MMcfe per day of net natural gas, NGLs and oil during 2012. HighMount holds leasehold or drilling rights in 0.7 million net acres, of which 0.5 million is developed acreage and the balance is held for future exploration and development drilling opportunities. HighMount participated in the drilling of 91 wells during 2012, of which 83 (or 91.2%) are productive wells.

Reserves: HighMount’s reserves represent its share of reserves based on its net revenue interest in each property. Estimated reserves as of December 31, 2012 are based upon studies for each of HighMount’s properties prepared by HighMount staff engineers and are the responsibility of management. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with Securities and Exchange Commission (“SEC”) guidelines.

HighMount employs various internal controls to validate the reserve estimation process. The main internal controls include (i) detailed reviews of reserve-related information by reserve engineering and executive management, (ii) reserve audits performed by an independent third party reserve auditor, (iii) segregation of duties, and (iv) system reconciliation or automated interface between various systems used in the reserve estimation process.

HighMount employs a team of reservoir engineers that specialize in HighMount’s areas of operation. The reservoir engineering team reports to HighMount’s Chief Operating Officer. The compensation of HighMount’s reservoir engineers is not dependent on the quantity of reserves booked. HighMount also employs a lead evaluator who reports to the Chief Financial Officer. HighMount’s lead evaluator has over 33 years of petroleum engineering experience, most of which have been in the reservoir engineering and reserve fields. He is a member in good standing of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers, as well as a Licensed Professional Engineer in the State of Texas.

HighMount’s reserves estimates for 2012 have been independently audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and governmental agencies. NSAI was founded in 1961 and performs consulting services under Texas Board of Professional Engineers Registration No. F-2699. The technical person primarily responsible for NSAI’s audit and audit letter has 32 years of industry experience and has been practicing consulting petroleum engineering at NSAI since 1989.

The following table sets forth HighMount’s proved reserves at December 31, 2012, based on average 2012 prices of $2.76 per MMBtu for natural gas, $41.11 per Bbl for NGLs and $94.71 per Bbl for oil. Approximately 95% of HighMount’s proved reserves were located in the Permian Basin in Texas and approximately 5% of proved reserves were located in Oklahoma.

Natural Gas
(MMcf)

NGLs

(Bbls)

Oil

(Bbls)

Natural Gas
Equivalents
(MMcfe)

Proved developed

490,978

28,835,347

4,945,283

693,662

Proved undeveloped

66,577

6,263,323

4,546,590

131,436

Total proved

557,555

35,098,670

9,491,873

825,098

HighMount reviews its proved reserves on an annual basis. During 2012, total proved reserves declined 309 Bcfe, reflecting (i) a 328 Bcfe reduction as a result of economic factors such as lower gas prices and higher operating expenses, and as a result of higher production decline rates of its producing wells, partly due to the suspension of uneconomic maintenance and recompletion work, (ii) a 56 Bcfe reduction as a result of production during the year, offset by (iii) additions of 75 Bcfe through drilling and booking of proved undeveloped locations.

At December 31, 2012, HighMount had proved undeveloped reserves of 131 Bcfe on locations scheduled to be drilled in the next five years. During 2012, HighMount recorded negative net reserve revisions of 198 Bcfe primarily due to a reclassification of proved undeveloped reserves to the non-proved category because these reserves were no longer economical due to the decrease in natural gas prices. Also, 48 Bcfe of non-proved reserves were promoted to the proved undeveloped category as a result of the 2012 drilling activity. During 2012, HighMount spent $14 million to convert 2 Bcfe from proved undeveloped reserves to proved developed reserves through drilling. As of December 31, 2012, there were no proved undeveloped locations that had remained undeveloped for five years or more.

Estimated net quantities of proved natural gas and oil reserves at December 31, 2012, 2011 and 2010 and changes in the reserves during 2012, 2011 and 2010 are shown in Note 14 of the Notes to Consolidated Financial Statements included under Item 8.

HighMount’s Sonora properties typically have relatively long reserve lives and high well completion success rates. Based on December 31, 2012 proved reserves and HighMount’s average production from these properties during 2012, the average reserve-to-production index of HighMount’s proved reserves is 15 years.

In order to replenish reserves as they are depleted by production, and to increase reserves, HighMount develops its existing acreage by drilling new wells and, where available, employing new technologies and drilling strategies designed to enhance production from existing wells. In addition, HighMount seeks to acquire additional acreage in its core areas of operation, as well as other locations where its management has identified an opportunity.

During 2012, 2011 and 2010, HighMount engaged in the drilling activity presented in the following table:


Year Ended December 31	2012				2011				2010

	Gross		Net		Gross		Net		Gross		Net

Development Wells
Productive Wells		83		78.5		46		46.0		227		221.3
Dry Wells		8		8.0		5		5.0		11		11.0

Total Development Wells		91		86.5		51		51.0		238		232.3


Exploratory Wells
Productive Wells						10		9.5
Dry Wells						2		2.0		2		2.0

Total Exploratory Wells						12		11.5		2		2.0


Total Completed Wells		91		86.5		63		62.5		240		234.3

In addition, at December 31, 2012, HighMount had 23 (20.2 net) wells in progress.

Acreage: As of December 31, 2012, HighMount owned interests in 1,107,551 gross (700,281 net) acres in the United States which is comprised of 609,659 gross (467,602 net) developed acres, and 497,892 gross (232,679 net) undeveloped acres.

As of December 31, 2012, leases covering 86,577, 27,859 and 9,843 of HighMount’s net acreage will expire by December 31, 2013, 2014 and 2015, if production is not established or HighMount takes no other action to extend the terms.

Production and Sales: Please see the Production and Sales statistics table for additional information included in the MD&A under Item 7.

HighMount utilizes its own marketing and sales personnel to market the natural gas and oil that it produces to large energy companies and intrastate pipelines and gathering companies. Production is typically sold and delivered directly to a pipeline at liquid pooling points or at the tailgates of various processing plants, where it then enters a pipeline system. Permian Basin natural gas sales prices are primarily at a Houston Ship Channel Index.

To manage the risk of fluctuations in prevailing commodity prices, HighMount enters into commodity and basis swaps and other derivative instruments.

Wells: As of December 31, 2012, HighMount had working interests in 6,133 gross producing wells (5,874 net producing wells) located primarily in the Permian Basin. In addition, HighMount had royalty interests in approximately 250 wells located in the Permian Basin. Wells located in the Permian Basin have a typical well depth in the range of 6,000 to 9,000 feet.

Competition: HighMount competes with other oil and gas companies in all aspects of its business, including acquisition of producing properties and leases and obtaining goods, services and labor, including drilling rigs and well completion services. HighMount also competes in the marketing of produced natural gas and oil. Some of HighMount’s competitors have substantially larger financial and other resources than HighMount. Factors that affect HighMount’s ability to acquire producing properties include available funds, available information about the property and standards established by HighMount for minimum projected return on investment. Natural gas and oil also compete with alternative fuel sources, including heating oil and coal.

Governmental Regulation: All of HighMount’s operations are conducted onshore in the United States. The U.S. oil and gas industry, and HighMount’s operations, are subject to regulation at the federal, state and local level. Such regulation includes requirements with respect to, among other things: permits to drill and to conduct other operations; provision of financial assurances (such as bonds) covering drilling and well operations; the location of wells; the method of drilling and completing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; the marketing, transportation and reporting of production; the valuation and payment of royalties; the size of drilling and spacing units (regarding the density of wells which may be drilled in a particular area); the unitization or pooling of natural gas and oil properties; maximum rates of production from natural gas and oil wells; venting or flaring of natural gas; and the ratability of production and the operation of gathering systems and related assets.

HighMount uses hydraulic fracturing to stimulate the production of oil and natural gas. In recent years, concerns have been raised that the fracturing process may, among other things, contaminate underground sources of drinking water. The conference committee report for The Department of the Interior, Environment, and Related Agencies Appropriations Act for Fiscal Year 2010 requested the United States Environmental Protection Agency (“EPA”) to conduct a study of hydraulic fracturing, particularly the relationship between hydraulic fracturing and drinking water. In December of 2012 the EPA issued a progress report of the projects the EPA is conducting as part of the study. A final draft report is expected to be released for public comment and peer review in 2014. Several bills have been introduced in Congress seeking federal regulation of hydraulic fracturing, which has historically been regulated at the state level, though none of the proposed legislation has been passed into law. HighMount believes that similar bills will continue to be introduced in Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing; however, HighMount cannot predict whether any such bill will be passed into law or, if passed, the substance of any such new law.

The Federal Energy Policy Act of 2005 amended the NGA to prohibit natural gas market manipulation by any entity, directed the FERC to facilitate market transparency in the sale or transportation of physical natural gas and significantly increased the penalties for violations of the NGA of 1938, the NGPA of 1978, or FERC regulations or orders thereunder. In addition, HighMount owns and operates gas gathering lines and related facilities which are regulated by the DOT and state agencies with respect to safety and operating conditions.

HighMount’s operations are also subject to federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants, and the protection of public health, natural resources, wildlife and the environment. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, HighMount’s operations may require it to obtain permits for, among other things, air emissions, discharges into surface waters, and the construction and operation of underground injection wells or surface pits to dispose of produced saltwater and other non-hazardous oilfield wastes. HighMount could be required, without regard to fault or the legality of the original disposal, to remove or remediate previously disposed wastes, to suspend or cease operations in contaminated areas or to perform remedial well plugging operations or cleanups to prevent future contamination.

In September of 2009, the EPA adopted regulations under the Clean Air Act requiring the monitoring and reporting of annual greenhouse gas (“GHG”) emissions by certain large U.S. GHG emitters. Affected companies are required to monitor their GHG emissions and report to the EPA. Oil and gas exploration and production companies that emit more than 25,000 metric tons of GHG per year from any facility (as defined in the regulations), including HighMount, are required to monitor and report emissions for facilities that meet the emissions threshold. HighMount filed its first GHG report in September of 2012 for the 2011 reporting year.

Properties: In addition to its interests in oil and gas producing properties, HighMount leases an aggregate of approximately 56,300 square feet of office space in Houston, Texas, which includes its corporate headquarters, and approximately 83,800 square feet of office space in Oklahoma City, Oklahoma. HighMount also leases other surface rights and office, warehouse and storage facilities necessary to operate its business. In addition to leased properties, HighMount also owns a 44,000 square foot office building in Sonora, Texas, and a 1,500 square foot office building in Morrison, Oklahoma.

LOEWS HOTELS HOLDING CORPORATION

The subsidiaries of Loews Hotels Holding Corporation (“Loews Hotels”), our wholly owned subsidiary, presently operate a chain of 19 primarily upper, upscale hotels. Each hotel in the chain is managed by Loews Hotels. Ten of these hotels are owned by Loews Hotels, five are owned by joint ventures in which Loews Hotels has a significant equity interest and four are managed for unaffiliated owners. Loews Hotels’ earnings are derived from the operation of its wholly owned hotels, its share of earnings in joint venture hotels and hotel management fees earned from both joint venture and managed hotels. Loews Hotels accounted for 2.7%, 2.4% and 2.1% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010. The hotels are described below.


Name and Location	Number of Rooms	Land Lease Information (if applicable)


Owned:
Loews Annapolis Hotel, Annapolis, Maryland	220
Loews Boston Back Bay Hotel, Boston, Massachusetts	225
Loews Coronado Bay, San Diego, California	440	Land lease expiring 2034
Loews Le Concorde Hotel, Quebec City, Canada	405	Land lease expiring 2069
Loews Madison Hotel, Washington, D.C.	356
Loews Miami Beach Hotel, Miami Beach, Florida	790
Loews Philadelphia Hotel, Philadelphia, Pennsylvania	585
Loews Regency Hotel, New York, New York	350	Land lease expiring 2036 with renewal option for 24 years

Loews Vanderbilt Hotel, Nashville, Tennessee	340
Loews Hotel Vogue, Montreal, Canada	140

Joint Venture/Managed:
The Don CeSar, a Loews Hotel, St. Pete Beach, Florida	347
Hard Rock Hotel, at Universal Orlando, Orlando, Florida	650
Loews Hollywood Hotel, Hollywood, California	632
Loews Portofino Bay Hotel, at Universal Orlando, Orlando, Florida	750
Loews Royal Pacific Resort at Universal Orlando, Orlando, Florida	1,000

Management Contract:
Loews Atlanta Hotel, Atlanta, Georgia	414
Loews New Orleans Hotel, New Orleans, Louisiana	285
Loews Santa Monica Beach Hotel, Santa Monica, California	340
Loews Ventana Canyon, Tucson, Arizona	400

Competition: Competition from other hotels and lodging facilities is vigorous in all areas in which Loews Hotels operates. The demand for hotel rooms in many areas is seasonal and dependent on general and local economic conditions. Loews Hotels properties also compete with facilities offering similar services in locations other than those in which its hotels are located. Competition among luxury hotels is based primarily on location and service. Competition among resort and commercial hotels is based on price as well as location and service. Because of the competitive nature of the industry, hotels must continually make expenditures for updating, refurnishing and repairs and maintenance, in order to prevent competitive obsolescence.

Recent Developments:

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In June of 2012, Loews Hotels acquired a hotel in Hollywood, California, which is now operating as the Loews Hollywood Hotel. In November of 2012, Loews Hotels formed a joint venture with an institutional investor, which acquired an equity interest in the Loews Hollywood Hotel.

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In December of 2012, Loews Hotels sold the Loews Denver Hotel.

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In January of 2013, Loews Hotels acquired a hotel in Washington, D.C., which is now operating as the Loews Madison Hotel.

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In February of 2013, Loews Hotels acquired a hotel in Boston, Massachusetts, which is now operating as the Loews Boston Back Bay Hotel.

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In 2012, Loews Hotels became a 50% partner in a joint venture which is constructing an 1,800 guestroom hotel at Universal Orlando, Florida.

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In December of 2012, Loews Hotels agreed to purchase, upon completion of development expected to occur in 2015, a 400 guestroom hotel in Chicago, Illinois.

EMPLOYEE RELATIONS

Including our operating subsidiaries as described below, we employed approximately 18,300 persons at December 31, 2012. We, and our subsidiaries, have experienced satisfactory labor relations.

CNA employed approximately 7,500 persons.

Diamond Offshore employed approximately 5,300 persons, including international crew personnel furnished through independent labor contractors.

Boardwalk Pipeline employed approximately 1,200 persons, approximately 110 of whom are union members covered under collective bargaining units.

HighMount employed approximately 400 persons.

Loews Hotels employed approximately 3,625 persons, approximately 965 of whom are union members covered under collective bargaining units.

EXECUTIVE OFFICERS OF THE REGISTRANT


Name	Position and Offices Held	Age	First Became Officer


David B. Edelson	Senior Vice President	53	2005
Gary W. Garson	Senior Vice President, General Counsel and Secretary	66	1988
Peter W. Keegan	Senior Vice President and Chief Financial Officer	68	1997
Richard W. Scott	Senior Vice President and Chief Investment Officer	59	2009
Kenneth I. Siegel	Senior Vice President	55	2009
Andrew H. Tisch	Office of the President, Co-Chairman of the Board and Chairman of the Executive Committee	63	1985
James S. Tisch	Office of the President, President and Chief Executive Officer	60	1981
Jonathan M. Tisch	Office of the President and Co-Chairman of the Board	59	1987

Andrew H. Tisch and James S. Tisch are brothers and are cousins of Jonathan M. Tisch. None of the other officers or directors of Registrant is related to any other.

All of our executive officers except for Kenneth I. Siegel and Richard W. Scott have been engaged actively and continuously in our business for more than the past five years. Prior to joining us in 2009, Mr. Siegel was employed as a Managing Director in the Mergers & Acquisitions Department at Barclays Capital Inc. and previously in a similar capacity at Lehman Brothers. Prior to joining us in 2009, Mr. Scott was employed at American International Group, Inc. for more than five years, serving in various senior investment positions, including Chief Investment Officer–Insurance Portfolio Management.

Officers are elected and hold office until their successors are elected and qualified, and are subject to removal by the Board of Directors.

AVAILABLE INFORMATION

Our website address is www.loews.com. We make available, free of charge, through the website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after these reports are electronically filed with or furnished to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee charter, Compensation Committee charter and Nominating and Governance Committee charter have also been posted and are available on our website.

Item 1A. RISK FACTORS.

Our business faces many risks. We have described below some of the more significant risks which we and our subsidiaries face. There may be additional risks that we do not yet know of or that we do not currently perceive to be significant that may also impact our business or the business of our subsidiaries.

Each of the risks and uncertainties described below could lead to events or circumstances that have a material adverse effect on our business, results of operations, cash flows, financial condition or equity and/or the business, results of operations, financial condition or equity of one or more of our subsidiaries.

You should carefully consider and evaluate all of the information included in this Report and any subsequent reports we may file with the SEC or make available to the public before investing in any securities issued by us. Our subsidiaries, CNA Financial Corporation, Diamond Offshore Drilling, Inc. and Boardwalk Pipeline Partners, LP, are public companies and file reports with the SEC. You are also cautioned to carefully review and consider the information contained in the reports filed by those subsidiaries before investing in any of their securities.

Risks Related to Us and Our Subsidiary, CNA Financial Corporation

If CNA determines that its recorded insurance reserves are insufficient to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, CNA may need to increase its insurance reserves.

CNA maintains insurance reserves to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, including the estimated cost of the claims adjudication process, for reported and unreported claims and for future policy benefits. Reserves represent CNA’s best estimate at a given point in time. Insurance reserves are not an exact calculation of liability but instead are complex estimates derived by CNA, generally utilizing a variety of reserve estimation techniques from numerous assumptions and expectations about future events, many of which are highly uncertain, such as estimates of claims severity, frequency of claims, mortality, morbidity, discount rates, inflation, claims handling, case reserving policies and procedures, underwriting and pricing policies, changes in the legal and regulatory environment and the lag time between the occurrence of an insured event and the time of its ultimate settlement. Mortality is the relative incidence of death. Morbidity is the frequency and severity of illness, sickness and diseases contracted. Many of these uncertainties are not precisely quantifiable and require significant judgment on CNA’s part. As trends in underlying claims develop, particularly in so-called “long tail” or long duration coverages, CNA is sometimes required to add to its reserves. This is called unfavorable net prior year

development and results in a charge to earnings in the amount of the added reserves, recorded in the period the change in estimate is made. These charges can be substantial.

CNA is also subject to the uncertain effects of emerging or potential claims and coverage issues that arise as industry practices and legal, judicial, social, economic and other environmental conditions change. These issues have had, and may continue to have, a negative effect on CNA’s business by either extending coverage beyond the original underwriting intent or by increasing the number or size of claims, resulting in further increases in CNA’s reserves. The effects of these and other unforeseen emerging claim and coverage issues are extremely hard to predict. Examples of emerging or potential claims and coverage issues include:

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the effects of worldwide economic conditions, which have resulted in an increase in the number and size of certain claims including both directors and officers (“D&O”) and errors and omissions (“E&O”) insurance claims related to corporate failures, as well as other coverages;

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class action litigation relating to claims handling and other practices; and

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mass tort claims, including bodily injury claims related to welding rods, benzene, lead, noise induced hearing loss, injuries from various medical products including pharmaceuticals, and various other chemical and radiation exposure claims.

In light of the many uncertainties associated with establishing the estimates and making the assumptions necessary to establish reserve levels, CNA reviews and changes its reserve estimates in a regular and ongoing process as experience develops and further claims are reported and settled. If estimated reserves are insufficient for any reason, the required increase in reserves would be recorded as a charge against earnings in the period in which reserves are determined to be insufficient. These charges could be substantial.

CNA’s key assumptions used to determine reserves for long term care products and payout annuity contracts could vary significantly from actual experience.

CNA’s reserves for long term care products and payout annuity contracts are based on certain key assumptions including morbidity, mortality, policy persistency (the percentage of policies remaining in force) and discount rates (which are impacted by expected investment yields). A prolonged period during which interest rates remain at levels lower than those anticipated in CNA’s reserving may result in shortfalls in investment income on assets supporting policy obligations, which may require changes to reserves. These assumptions, while based on historical data and industry experience and monitored consistently, are critical bases for reserve estimates and are inherently uncertain. If estimated reserves are insufficient for any reason, the required increase in reserves would be recorded as a charge against earnings in the period in which reserves are determined to be insufficient. These charges could be substantial.

Catastrophe losses are unpredictable and could result in material losses.

Catastrophe losses are an inevitable part of CNA’s business. Various events can cause catastrophe losses. These events can be natural or man-made, and may include hurricanes, windstorms, earthquakes, hail, severe winter weather, fires, and acts of terrorism. The frequency and severity of these catastrophe events are inherently unpredictable. In addition, longer-term natural catastrophe trends may be changing and new types of catastrophe losses may be developing due to climate change, a phenomenon that has been associated with extreme weather events linked to rising temperatures, and includes effects on global weather patterns, greenhouse gases, sea, land and air temperatures, sea levels, rain, hail and snow.

The extent of CNA’s losses from catastrophes is a function of the total amount of its insured exposures in the affected areas, the frequency and severity of the events themselves, the level of reinsurance assumed and ceded and reinsurance reinstatement premiums, if any. As in the case of catastrophe losses generally, it can take a long time for the ultimate cost to CNA to be finally determined, as a multitude of factors contribute to such costs, including evaluation of general liability and pollution exposures, additional living expenses, infrastructure disruption, business interruption and reinsurance collectibility. Reinsurance coverage for terrorism events is provided only in limited

circumstances, especially in regard to “unconventional” terrorism acts, such as nuclear, biological, chemical or radiological attacks. As a result, catastrophe losses are particularly difficult to estimate.

As CNA’s claim experience develops on a specific catastrophe, CNA may be required to adjust its reserves, or take unfavorable net prior year development, to reflect revised estimates of the total cost of claims.

CNA has exposure related to A&EP claims, which could result in material losses.

CNA’s property and casualty insurance subsidiaries have exposures related to A&EP claims. CNA’s experience has been that establishing claim and claim adjustment expense reserves for casualty coverages relating to A&EP claims is subject to uncertainties that are greater than those presented by other claims. Additionally, traditional actuarial methods and techniques employed to estimate the ultimate cost of claims for more traditional property and casualty exposures are less precise in estimating claim and claim adjustment expense reserves for A&EP. As a result, estimating the ultimate cost of both reported and unreported A&EP claims is subject to a higher degree of variability.

On August 31, 2010, CNA completed a retroactive reinsurance transaction under which substantially all of its legacy A&EP liabilities were ceded to National Indemnity Company (“NICO”), a subsidiary of Berkshire Hathaway Inc., subject to an aggregate limit of $4.0 billion (“Loss Portfolio Transfer”). If the other parties to the Loss Portfolio Transfer do not fully perform their obligations, CNA’s liabilities for A&EP claims covered by the Loss Portfolio Transfer exceed the aggregate limit of $4.0 billion, or CNA determines it has exposures to A&EP claims not covered by the Loss Portfolio Transfer, CNA may need to increase its recorded net reserves which would result in a charge against CNA’s earnings. These charges could be substantial.

CNA’s premium writings and profitability are affected by the availability and cost of reinsurance.

CNA purchases reinsurance to help manage its exposure to risk. Under CNA’s ceded reinsurance arrangements, another insurer assumes a specified portion of CNA’s exposure in exchange for a specified portion of policy premiums. Market conditions determine the availability and cost of the reinsurance protection CNA purchases, which affects the level of its business and profitability, as well as the level and types of risk CNA retains. If CNA is unable to obtain sufficient reinsurance at a cost it deems acceptable, CNA may be unwilling to bear the increased risk and would reduce the level of its underwriting commitments.

CNA may not be able to collect amounts owed to it by reinsurers which could result in higher net incurred losses.

CNA has significant amounts recoverable from reinsurers which are reported as receivables on its balance sheets and are estimated in a manner consistent with claim and claim adjustment expense reserves or future policy benefits reserves. The ceding of insurance does not, however, discharge CNA’s primary liability for claims. As a result, CNA is subject to credit risk relating to its ability to recover amounts due from reinsurers. In the past, certain of CNA’s reinsurance carriers have experienced credit downgrades by rating agencies within the term of CNA’s contractual relationship. Such action increases the likelihood that CNA will not be able to recover amounts due. In addition, reinsurers could dispute amounts which CNA believes are due to it. If CNA is not able to collect the amounts due from reinsurers for any of the foregoing reasons, its net incurred losses will be higher.

CNA may not be able to collect amounts owed to it by policyholders who hold deductible policies which could result in higher net incurred losses.

A portion of CNA’s business is written under deductible policies. Under these policies, CNA is obligated to pay the related insurance claims and are reimbursed by the policyholder to the extent of the deductible, which may be significant. As a result CNA is exposed to credit risk to the policyholder. If CNA is not able to collect the amounts due from policyholders, its incurred losses will be higher.

CNA has incurred and may continue to incur significant realized and unrealized investment losses and volatility in net investment income arising from volatility in the capital and credit markets.

CNA’s investment portfolio is exposed to various risks, such as interest rate, credit and currency risks, many of which are unpredictable. Investment returns are an important part of CNA’s overall profitability. General economic conditions, changes in financial markets such as fluctuations in interest rates, credit conditions and currency, commodity and stock prices, and many other factors beyond CNA’s control can adversely affect the value of its investments and the realization of investment income. Further, CNA invests a portion of its assets in equity securities and limited partnerships which are subject to greater market volatility than its fixed income investments. In addition, limited partnership investments generally present, higher illiquidity than fixed income investments. As a result of all of these factors, CNA may not realize an adequate return on its investments, may incur losses on sales of its investments, and may be required to write-down the value of its investments.

CNA’s valuation of investments and impairment of securities requires significant judgment which is inherently uncertain.

CNA exercises significant judgment in analyzing and validating fair values, which are primarily provided by third parties, for securities in its investment portfolio including those that are not regularly traded in active markets. CNA also exercises significant judgment in determining whether the impairment of particular investments is temporary or other-than-temporary. The valuation of residential and commercial mortgage and other asset backed securities can be particularly sensitive to fairly small changes in collateral performance. Due to the inherent uncertainties involved with these judgments, CNA may incur unrealized losses and conclude that other-than-temporary write-downs of its investments are required.

CNA is subject to capital adequacy requirements and, if it is unable to maintain or raise sufficient capital to meet these requirements, regulatory agencies may restrict or prohibit CNA from operating its business.

Insurance companies such as CNA are subject to capital adequacy standards set by regulators to help identify companies that merit further regulatory attention. These standards apply specified risk factors to various asset, premium and reserve components of statutory capital and surplus reported in CNA’s statutory basis of accounting financial statements. Current rules, including those promulgated by insurance regulators and specialized markets such as Lloyd’s, require companies to maintain statutory capital and surplus at a specified minimum level determined using the applicable regulatory capital adequacy formula. If CNA does not meet these minimum requirements, CNA may be restricted or prohibited from operating its business. If CNA is required to record a material charge against earnings in connection with a change in estimates or the occurrence of an event or if it incurs significant losses related to its investment portfolio, CNA may violate these minimum capital adequacy requirements unless it is able to raise sufficient additional capital.

While we have provided CNA with substantial amounts of capital in prior years, we may be restricted in our ability or may not be willing to provide additional capital support to CNA in the future. If CNA is in need of additional capital, CNA may be required to secure this funding from sources other than us. CNA may be limited in its ability to raise significant amounts of capital on favorable terms or at all.

CNA’s insurance subsidiaries, upon whom CNA depends for dividends in order to fund its working capital needs, are limited by insurance regulators in their ability to pay dividends.

CNA is a holding company and is dependent upon dividends, loans and other sources of cash from its subsidiaries in order to meet its obligations. Ordinary dividend payments or dividends that do not require prior approval by the insurance subsidiaries’ domiciliary insurance regulator are generally limited to amounts determined by formula which varies by jurisdiction. The formula for the majority of domestic states is the greater of 10% of the prior year statutory surplus or the prior year statutory net income, less the aggregate of all dividends paid during the twelve months prior to the date of payment. Some jurisdictions including certain domestic states, however, have an additional stipulation that dividends cannot exceed the prior year’s earned surplus. If CNA is restricted, by regulatory rule or otherwise, from paying or receiving inter-company dividends, CNA may not be able to fund its working capital needs and debt service requirements from available cash. As a result, CNA would need to look to other sources of capital which may be more expensive or may not be available at all.

Rating agencies may downgrade their ratings of CNA and thereby adversely affect its ability to write insurance at competitive rates or at all.

Ratings are an important factor in establishing the competitive position of insurance companies. CNA’s insurance company subsidiaries, as well as CNA’s public debt, are rated by rating agencies, namely, A.M. Best Company (“A.M. Best”), Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s (“S&P”). Ratings reflect the rating agency’s opinions of an insurance company’s or insurance holding company’s financial strength, capital adequacy, operating performance, strategic position and ability to meet its obligations to policyholders and debt holders.

Due to the intense competitive environment in which CNA operates, the uncertainty in determining reserves and the potential for CNA to take material unfavorable net prior year development in the future, and possible changes in the methodology or criteria applied by the rating agencies, the rating agencies may take action to lower CNA’s ratings in the future. If CNA’s property and casualty insurance financial strength ratings are downgraded below current levels, CNA’s business and results of operations could be materially adversely affected. The severity of the impact on CNA’s business is dependent on the level of downgrade and, for certain products, which rating agency takes the rating action. Among the adverse effects in the event of such downgrades would be the inability to obtain a material volume of business from certain major insurance brokers, the inability to sell a material volume of CNA’s insurance products to certain markets, and the required collateralization of certain future payment obligations or reserves.

In addition, it is possible that a lowering of our corporate debt ratings by certain of the rating agencies could result in an adverse impact on CNA’s ratings, independent of any change in CNA’s circumstances. CNA has entered into several settlement agreements and assumed reinsurance contracts that require collateralization of future payment obligations and assumed reserves if its ratings or other specific criteria fall below certain thresholds. The ratings triggers are generally more than one level below CNA’s current ratings.

Risks Related to Us and Our Subsidiary, Diamond Offshore Drilling, Inc.

Diamond Offshore’s business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.

Diamond Offshore’s business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since Diamond Offshore’s customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to affect demand for Diamond Offshore’s rigs. Oil and gas prices have been, and are expected to continue to be, extremely volatile and are affected by numerous factors beyond Diamond Offshore’s control, including:

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worldwide demand for oil and gas;

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the level of economic activity in energy-consuming markets;

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the worldwide economic environment or economic trends, such as recessions;

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the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;

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the level of production in non-OPEC countries;

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the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;

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civil unrest;

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the cost of exploring for, producing and delivering oil and gas;

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the discovery rate of new oil and gas reserves;

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the rate of decline of existing and new oil and gas reserves;

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available pipeline and other oil and gas transportation and refining capacity;

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the ability of oil and gas companies to raise capital;

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weather conditions;

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natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;

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the policies of various governments regarding exploration and development of their oil and gas reserves;

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development and exploitation of alternative fuels or energy sources;

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competition for customers’ drilling budgets from land-based energy markets around the world;

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domestic and foreign tax policy; and

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advances in exploration and development technology.

Diamond Offshore’s business involves numerous operating hazards which could expose it to significant losses and significant damage claims. Diamond Offshore is not fully insured against all of these risks and its contractual indemnity provisions may not fully protect Diamond Offshore.

Diamond Offshore’s operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages.

Consistent with industry practice, Diamond Offshore’s contracts with its customers generally contain contractual rights to indemnity from its customer for, among other things, pollution originating from the well, while Diamond Offshore retains responsibility for pollution originating from the rig. However, Diamond Offshore’s contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by itself, its subcontractors and/or suppliers and Diamond Offshore’s customers may dispute, or be unable to meet, their contractual indemnification obligations.

Diamond Offshore maintains liability insurance, which includes coverage for environmental damage; however, because of contractual provisions and policy limits, Diamond Offshore’s insurance coverage may not adequately cover its losses and claim costs. In addition, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, Diamond Offshore does not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Moreover, insurance costs across the industry have increased following the Macondo incident and, in the future, certain insurance coverage is likely to become more costly and may become less available or not available at all.

Diamond Offshore believes that the policy limit under its marine liability insurance is within the range that is customary for companies of its size in the offshore drilling industry and is appropriate for its business. However, if an accident or other event occurs that exceeds Diamond Offshore’s coverage limits or is not an insurable event under its insurance policies, or is not fully covered by contractual indemnity, it could have a material adverse effect on its results of operations, financial condition and cash flows. There can be no assurance that Diamond Offshore will continue to carry the insurance it currently maintains, that its insurance will cover all types of losses or that those parties with contractual obligations to indemnify Diamond Offshore will necessarily be financially able to indemnify Diamond Offshore against all of these risks. In addition, no assurance can be made that Diamond Offshore will be able to maintain adequate insurance in the future at rates it considers to be reasonable or that Diamond Offshore will be able to obtain insurance against some risks.

Diamond Offshore’s industry is highly competitive and cyclical, with intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of Diamond Offshore’s competitors may have greater financial or other resources than it does. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered.

Diamond Offshore’s industry has historically been cyclical. There have been periods of lower demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and high dayrates. Diamond Offshore cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of Diamond Offshore’s drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

Significant new rig construction and upgrades of existing drilling rigs could also intensify price competition. Based on analyst reports, Diamond Offshore believes that there are approximately 67 floaters on order and scheduled for delivery between 2013 and 2016, with approximately 75% of these rigs scheduled for delivery in 2013 and 2014. The resulting increases in rig supply could be sufficient to depress rig utilization and intensify price competition from both existing competitors, as well as new entrants into the offshore drilling market. Not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. The majority of the floaters on order are dynamically positioned drilling rigs, which further increases competition with Diamond Offshore’s fleet in certain circumstances, depending on customer requirements. In Brazil, Petrobras, which accounted for approximately 33% of Diamond Offshore’s consolidated revenues in 2012 and, as of February 1, 2013, accounted for approximately $2.6 billion of contract drilling backlog through 2016 and to which nine of Diamond Offshore’s floaters are currently contracted, has announced plans to construct locally 29 new ultra-deepwater drilling units to be delivered beginning in 2015. These new drilling rigs, if built, would increase rig supply and could intensify price competition in Brazil as well as other markets as they enter the market, would compete with, and could displace, Diamond Offshore’s deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect Diamond Offshore’s utilization rates, particularly in Brazil.

Diamond Offshore can provide no assurance that its current backlog of contract drilling revenue will be ultimately realized.

As of February 1, 2013, Diamond Offshore’s contract drilling backlog was approximately $8.6 billion for contracted future work extending, in some cases, until 2019. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, Diamond Offshore may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. Diamond Offshore can provide no assurance that it will be able to perform under these contracts due to events beyond its control or that Diamond Offshore will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, Diamond Offshore can provide no assurance that its customers will be able to or

willing to fulfill their contractual commitments. Diamond Offshore’s inability to perform under its contractual obligations or to execute definitive agreements or its customers’ inability or unwillingness to fulfill their contractual commitments may have a material adverse effect on Diamond Offshore’s business.

Diamond Offshore relies heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a customer could have a material adverse impact on its financial results.

Diamond Offshore provides offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. In 2012, Diamond Offshore’s five largest customers in the aggregate accounted for 62% of its consolidated revenues. Diamond Offshore expects Petrobras and OGX, which accounted for approximately 33% and 12% of Diamond Offshore’s consolidated revenues in 2012, to continue to be significant customers in 2013. Diamond Offshore’s contract drilling backlog, as of February 1, 2013, includes $1.0 billion, or 36% and $187 million or 7% of its contracted backlog for 2013, which is attributable to contracts with Petrobras and OGX for operations offshore Brazil. Petrobras has announced plans to construct locally, 29 new ultra-deepwater drilling units to be delivered beginning in 2015. These new drilling units, if built, would compete with, and could displace, Diamond Offshore’s deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect utilization rates, particularly in Brazil. While it is normal for Diamond Offshore’s customer base to change over time as work programs are completed, the loss of, or a significant reduction in the number of rigs contracted with, any major customer may have a material adverse effect on Diamond Offshore’s business.

The terms of Diamond Offshore’s drilling contracts may limit its ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market.

The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of decreasing demand for offshore rigs, drilling contractors generally prefer longer term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing levels and ensure utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates. Conversely, in periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. An inability to obtain longer term contracts in a declining market or to fully benefit from increasing dayrates in an improving market through shorter term contracts may limit Diamond Offshore’s profitability.

Contracts for Diamond Offshore’s drilling rigs are generally fixed dayrate contracts, and increases in Diamond Offshore’s operating costs could adversely affect the profitability on those contracts.

Diamond Offshore’s contracts for its drilling rigs provide for the payment of a fixed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by Diamond Offshore. Many of Diamond Offshore’s operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond Diamond Offshore’s control. The gross margin that Diamond Offshore realizes on these fixed dayrate contracts will fluctuate based on variations in Diamond Offshore’s operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, Diamond Offshore may be unable to fully recover increased or unforeseen costs from its customers.

Diamond Offshore’s drilling contracts may be terminated due to events beyond its control.

Diamond Offshore’s customers may terminate some of their term drilling contracts if the drilling rig is destroyed or lost or if Diamond Offshore has to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of Diamond Offshore’s drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate Diamond Offshore for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time. During periods of depressed market conditions, Diamond Offshore may be subject to an increased risk of its customers seeking to repudiate their contracts. Diamond Offshore’s

customers’ ability to perform their obligations under drilling contracts may also be adversely affected by restricted credit markets and economic downturns. If Diamond Offshore’s customers cancel some of their contracts, and Diamond Offshore is unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are disputed or suspended for an extended period of time or if a number of contracts are renegotiated, it could materially and adversely affect Diamond Offshore’s financial condition, results of operations and cash flows.

Significant portions of Diamond Offshore’s operations are conducted outside the United States and involve additional risks not associated with domestic operations.

Diamond Offshore operates in various regions throughout the world which may expose it to political and other uncertainties, including risks of:

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war and civil disturbances;

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piracy or assaults on property or personnel;

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kidnapping of personnel;

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expropriation or nationalization of property or equipment;

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renegotiation or nullification of existing contracts;

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changing political conditions;

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imposition of trade barriers or import-export quotas;

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foreign and domestic monetary policies;

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the inability to repatriate income or capital;

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difficulties in collecting accounts receivable and longer collection periods;

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fluctuations in currency exchange rates;

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regulatory or financial requirements to comply with foreign bureaucratic actions;

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travel limitations or operational problems caused by public health threats;

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difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations;

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difficulties in obtaining visas or work permits for employees on a timely basis; and

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changing taxation policies.

Diamond Offshore is subject to the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing its international operations in addition to worldwide anti-bribery laws. In addition, international contract drilling operations are subject to various laws and regulations in countries in which Diamond Offshore operates, including laws and regulations relating to:

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the equipping and operation of drilling rigs;

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import - export quotas or other trade barriers;

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repatriation of foreign earnings or capital;

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oil and gas exploration and development;

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taxation of offshore earnings and earnings of expatriate personnel; and

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use and compensation of local employees and suppliers by foreign contractors.

Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect Diamond Offshore’s ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments may materially and adversely affect Diamond Offshore’s ability to compete.

In addition, the shipment of goods, including the movement of a drilling rig across international borders, subjects Diamond Offshore to extensive trade laws and regulations. Diamond Offshore’s import activities are governed by unique customs laws and regulations that differ in each of the countries in which Diamond Offshore operates and often impose record keeping and reporting obligations. The laws and regulations concerning import/export activity and record keeping and reporting requirements are complex and change frequently. These laws and regulations may be enacted, amended enforced and/or interpreted in a manner that could materially and adversely impact Diamond Offshore’s operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which may be outside of Diamond Offshore’s control. Shipping delays or denials could cause unscheduled downtime for rigs. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to Diamond Offshore, among other things.

Diamond Offshore may enter into drilling contracts that exposes it to greater risks than it normally assumes.

From time to time, Diamond Offshore may enter into drilling contracts with national oil companies, government-controlled entities or others that expose it to greater risks than it normally assumes, such as exposure to greater environmental or other liability and more onerous termination provisions giving the customer a right to terminate without cause or upon little or no notice. Upon termination, these contracts may not result in a payment to Diamond Offshore, or if a termination payment is required, it may not fully compensate Diamond Offshore for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time. For example, Diamond Offshore currently operates, and expects to continue to operate, its drilling rigs offshore Mexico for PEMEX – Exploración y Producción (“PEMEX”), the national oil company of Mexico. The terms of these contracts expose Diamond Offshore to greater environmental liability than it normally assumes, and provide that, among other things, each contract can be terminated by PEMEX on short notice, contractually or by statute, subject to certain conditions. While Diamond Offshore believes that the financial terms of these contracts and its operating safeguards in place mitigate these risks, it can provide no assurance that the increased risk exposure will not have a material negative impact on future operations or financial results.

Fluctuations in exchange rates and nonconvertibility of currencies could result in losses.

Due to Diamond Offshore’s international operations, Diamond Offshore may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where it does not effectively hedge an exposure to a foreign currency. Diamond Offshore may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. Diamond Offshore can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.

Diamond Offshore may be required to accrue additional tax liability on certain of its foreign earnings.

Certain of Diamond Offshore’s international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited (“DOIL”), a wholly owned Cayman Islands subsidiary of Diamond Offshore. It is Diamond Offshore’s intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities. Diamond Offshore does not expect to provide for U.S. taxes on any future earnings generated by DOIL, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future

distribution be made from any unremitted earnings of this subsidiary, Diamond Offshore may be required to record additional U.S. income taxes.

Rig conversions, upgrades or new builds may be subject to delays and cost overruns.

From time to time, Diamond Offshore adds new capacity through conversions or upgrades to existing rigs or through new construction, such as its four, ultra-deepwater drillships under construction and its construction of the Ocean Apex and Ocean Onyx. Projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:

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shortages of equipment, materials or skilled labor;

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work stoppages;

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unscheduled delays in the delivery of ordered materials and equipment;

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unanticipated cost increases;

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weather interferences or storm damage;

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difficulties in obtaining necessary permits or in meeting permit conditions;

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design and engineering problems;

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availability of suppliers to recertify equipment for enhanced regulations;

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customer acceptance delays;

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shipyard failures or unavailability; and

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failure or delay of third party service providers, civil unrest and labor disputes.

Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new construction in accordance with its design specifications may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling contract, resulting in a loss of contract drilling backlog and revenue to Diamond Offshore. If a drilling contract is terminated under these circumstances, Diamond Offshore may not be able to secure a replacement contract with equally favorable terms.

Diamond Offshore has elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM.

Because the amount of insurance coverage available to Diamond Offshore has been limited, and the cost for such coverage is substantial, Diamond Offshore has elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM. This results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts.

Risks Related to Us and Our Subsidiary, Boardwalk Pipeline Partners, LP

Boardwalk Pipeline may not be able to maintain or replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis.

Each year, a portion of Boardwalk Pipeline’s natural gas transportation contracts expire and need to be renewed or replaced. Boardwalk Pipeline may not be able to extend contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts. A key driver that influences the rates and terms of its transportation contracts is the current and anticipated basis spreads - generally meaning the difference in the price of natural gas at receipt and delivery points on its natural gas pipeline systems which influence how much

customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by its pipeline systems. As new sources of natural gas have been identified and developed, changes in pricing dynamics between supply basins, pooling points and market areas have occurred. As a result of the increase in overall pipeline capacity and the new sources of supply, basis spreads on its pipeline systems have narrowed over the past several years, reducing the transportation rates Boardwalk Pipeline can negotiate with its customers on contracts due for renewal for its firm transportation services. The narrowing of basis differentials has also adversely affected the rates it is able to charge for its interruptible and short term firm transportation services. As a result, the rates Boardwalk Pipeline is able to obtain on renewals of expiring contracts are generally lower than those under the expiring contracts, which adversely impacts its revenues and distributable cash.

The development of large new gas supply basins in the U.S. and the overall increase in the supply of natural gas created by such development can significantly affect Boardwalk Pipeline’s business.

Growing supplies of natural gas are being produced in new production areas that are not connected to Boardwalk Pipeline’s system and are closer to large end-user market areas than the supply basins connected to its system that traditionally served these markets. For example, gas produced in the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio is being shipped to nearby northeast markets such as New York and Philadelphia which have traditionally been served by gas produced in Gulf Coast and mid-continent production areas which are connected to its pipelines. This has caused and may continue to cause gas produced in supply areas connected to its system to be diverted to other market areas which may adversely affect capacity utilization and transportation rates on its systems. In addition, as discussed above, growing supplies of natural gas from developing supply basins, especially shale plays, connected to Boardwalk Pipeline’s system have caused and may continue to cause basis spreads to narrow. All of these dynamics continue to impair Boardwalk Pipeline’s ability to renew or replace existing contracts or to sell interruptible and short term firm transportation services at attractive rates, which adversely impacts Boardwalk Pipeline’s revenues and distributable cash flows.

Changes in the price of natural gas and NGLs impacts supply of and demand for those commodities, which impacts Boardwalk Pipeline’s business.

Natural gas prices in the U.S. are currently lower than historical averages driven by the abundant and growing gas supply discussed above. The prices of natural gas and NGLs fluctuates in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:

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worldwide economic conditions;

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weather conditions, seasonal trends and hurricane disruptions;

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the relationship between the available supplies and the demand for natural gas and NGLs;

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new supply sources;

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the availability of adequate transportation capacity;

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storage inventory levels;

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the price and availability of oil and other forms of energy;

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the effect of energy conservation measures;

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the nature and extent of, and changes in, governmental regulation, new regulations adopted by the EPA for example greenhouse gas legislation and taxation; and

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the anticipated future prices of natural gas, oil and other commodities.

It is difficult to predict future changes in natural gas and NGL prices. However, the economic environment that has existed over the last several years generally indicates a bias toward continued downward pressure on natural gas prices. Sustained low natural gas prices could negatively impact producers including those directly connected to Boardwalk Pipeline’s pipelines that have contracted for capacity with them.

Conversely, future increases in the price of natural gas could make alternative energy sources more competitive and reduce demand for natural gas. A reduced level of demand for natural gas could reduce the utilization of capacity on Boardwalk Pipeline’s systems, reduce the demand for its services and could result in the non-renewal of contracted capacity as contracts expire and affect its midstream businesses.

Boardwalk Pipeline may not have sufficient available cash, to continue making distributions to unitholders at the current distribution rate or at all.

The amount of cash Boardwalk Pipeline can distribute to its unitholders, including us, principally depends upon the amount of cash it generates from its operations and financing activities and the amount of cash it requires, or determines to use, for other purposes, all of which fluctuate from quarter to quarter based on a number of factors. Many of these factors are beyond the control of Boardwalk Pipeline. Some of the factors that influence the amount of cash Boardwalk Pipeline has available for distribution in any quarter include:

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the level of capital expenditures it makes or anticipates making, including for expansion and growth projects;

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the cost and form of payment for pending or anticipated acquisitions and growth or expansion projects and the commercial success of any such initiatives;

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the amount of cash necessary to meet its current or anticipated debt service requirements and other liabilities;

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fluctuations in working capital needs;

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its ability to borrow funds and/or access capital markets to fund operations or capital expenditures, including acquisitions; restrictions contained in its debt agreements; and

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fluctuations in cash generated by its operations, including as a result of the seasonality of its business, customer payment issues and general business conditions such as, among others, contract renewals, basis spreads, market rates, and fluctuations in PAL revenues.

Boardwalk Pipeline may determine to reduce or eliminate distributions at any time it determines that its cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects or other business needs. Any such reduction would reduce the amount of cash available to us.

Investments that Boardwalk Pipeline makes, whether through acquisitions or growth projects, that appear to be accretive may nevertheless reduce its distributable cash flows.

Boardwalk Pipeline plans to continue to grow and diversify its business by among other things, investing in assets through acquisitions and organic growth projects. Its ability to grow, diversify and increase distributable cash flows will depend, in part, on its ability to close and execute on accretive acquisitions and projects. Any such transaction involves potential risks that may include, among other things:

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the diversion of management’s and employees’ attention from other business concerns;

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inaccurate assumptions about volume, revenues and costs, including potential synergies;

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a decrease in liquidity as a result of Boardwalk Pipeline using available cash or borrowing capacity to finance the acquisition or project;

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a significant increase in interest expense or financial leverage if Boardwalk Pipeline incurs additional debt to finance the acquisition or project;

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inaccurate assumptions about the overall costs of equity or debt;

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an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets;

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unforeseen difficulties operating in new product areas or new geographic areas; and

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changes in regulatory requirements.

Additionally, acquisitions contain the following risks:

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an inability to integrate successfully the businesses it acquires;

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the assumption of unknown liabilities for which Boardwalk Pipeline is not indemnified, for which its indemnity is inadequate or for which its insurance policies may exclude from coverage;

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limitations on rights to indemnity from the seller; and

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customer or key employee losses of an acquired business.

Boardwalk Pipeline is exposed to credit risk relating to nonperformance by its customers.

Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Boardwalk Pipeline’s exposure generally relates to receivables for services provided, future performance under firm agreements and volumes of gas or other products owed by customers for imbalances or product loaned by it to them under certain of its services. For Boardwalk Pipeline’s FERC-regulated business, Boardwalk Pipeline’s tariffs only allow it to require limited credit support in the event that its transportation customers are unable to pay for its services. If any of its significant customers have credit or financial problems which result in a delay or failure to pay for services provided by them or contracted for with them, or to repay the product they owe them, it could have a material adverse effect on Boardwalk Pipeline’s business. In addition, as contracts expire, the credit or financial failure of any of its customers could also result in the non-renewal of contracted capacity, which could have a material adverse effect on its business.

Boardwalk Pipeline depends on certain key customers for a significant portion of its revenues. The loss of any of these key customers could result in a decline in its revenues.

Boardwalk Pipeline relies on a limited number of customers for a significant portion of revenues. Its largest customer in terms of revenue, Devon Gas Services, LP, represented over 12% of its 2012 revenues. Boardwalk Pipeline’s top ten customers comprised approximately 47% of its revenues in 2012. Boardwalk Pipeline may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce its contracted transportation volumes and the rates it can charge for its services.

Boardwalk Pipeline’s natural gas transportation and storage operations are subject to FERC’s rate-making policies which could limit its ability to recover the full cost of operating its pipelines, including earning a reasonable return.

Boardwalk Pipeline is subject to extensive regulations relating to the rates it can charge for its natural gas transportation and storage operations. For Boardwalk Pipeline’s cost-based services, FERC establishes both the maximum and minimum rates it can charge. The basic elements that FERC considers are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. Boardwalk Pipeline may not be able to recover all of its costs, including certain costs associated with pipeline integrity, through existing or future rates.

Customers or FERC can challenge the existing rates on any of Boardwalk Pipeline’s pipelines. Such a challenge against them could adversely affect its ability to charge rates that would cover future increases in its costs or even to continue to collect rates to maintain its current revenue levels that are designed to permit a reasonable opportunity to recover current costs and depreciation and earn a reasonable return.

If any of Boardwalk Pipeline’ pipelines under FERC jurisdiction were to file a rate case, or if they have to defend their rates in a proceeding commenced by a customer or FERC, Boardwalk Pipeline would be required, among other things, to establish that the inclusion of an income tax allowance in its cost of service is just and reasonable. Under current FERC policy, since it is a limited partnership and does not pay U.S. federal income taxes, this would require it to show that its unitholders (or their ultimate owners) are subject to federal income taxation. To support such a showing, Boardwalk Pipeline’s general partner may elect to require owners of its units to re-certify their status as being subject to U.S. federal income taxation on the income generated by Boardwalk Pipeline or may attempt to provide other evidence. Boardwalk Pipeline can provide no assurance that the evidence it might provide to FERC will be sufficient to establish that its unitholders (or their ultimate owners) are subject to U.S. federal income tax liability on the income generated by Boardwalk Pipeline’s jurisdictional pipelines. If Boardwalk Pipeline is unable to make such a showing, FERC could disallow a substantial portion of the income tax allowance included in the determination of the maximum rates that may be charged by its pipelines, which could result in a reduction of such maximum rates from current levels.

Pipeline safety laws and regulations requiring the performance of integrity management programs or the use of certain safety technologies could subject Boardwalk Pipeline to increased capital and operating costs and require it to use more comprehensive and stringent safety controls.

Boardwalk Pipeline’s pipelines are subject to regulation by the DOT under the NGPSA with respect to natural gas and the HLPSA with respect to NGLs, both as amended. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGLs pipeline facilities. These amendments have resulted in the adoption of rules by the DOT, through PHMSA, that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. These regulations have resulted in an overall increase in maintenance costs. Due to recent highly publicized incidents on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. Boardwalk Pipeline could incur significant additional costs if new or more stringently interpreted pipeline safety requirements are implemented.

The 2011 Act was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1 million to $2 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

Boardwalk Pipeline needs to maintain authority from PHMSA to operate portions of its pipeline systems at higher than normal operating pressures.

Boardwalk Pipeline has entered into firm transportation contracts with shippers which utilize the design capacity of certain of its pipeline assets, assuming that Boardwalk Pipeline operates those pipeline assets at higher than normal operating pressures (up to 0.80 of the pipeline’s SMYS). Boardwalk Pipeline has authority from PHMSA to operate those pipeline assets at such higher pressures, however PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or materially modify such authority, Boardwalk Pipeline may not be able to transport all of its contracted quantities of natural gas on its pipeline assets and could incur significant additional costs to re-obtain such authority or to develop alternate ways to meet its contractual obligations.

Risks Related to Us and Our Subsidiary, HighMount Exploration & Production LLC

HighMount may not be able to replace reserves and sustain production at current levels. Replacing reserves is risky and uncertain and requires significant capital expenditures.

HighMount’s success depends largely upon its ability to find, develop or acquire additional reserves that are economically recoverable. Unless HighMount replaces the reserves produced through successful development, exploration or acquisition, its proved reserves will decline over time. HighMount may not be able to successfully find and produce reserves economically in the future or to acquire proved reserves at acceptable costs. HighMount makes a substantial amount of capital expenditures for the acquisition, exploration and development of reserves. HighMount’s net cash flows have been negatively impacted by reduced natural gas and NGL prices as well as increased drilling costs developing HighMount’s oil reserves. If HighMount’s cash flow from operations is not sufficient to fund its capital expenditure budget, there can be no assurance that financing will be available or available at favorable terms to meet those requirements.

Estimates of natural gas and oil reserves are uncertain and inherently imprecise.

Estimating the volume of proved natural gas and oil reserves is a complex process and is not an exact science because of numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, these estimates are inherently imprecise.

Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves most likely will vary from HighMount’s estimates. Any significant variance could materially affect the quantities and present value of HighMount’s reserves. In addition, HighMount may adjust estimates of proved reserves upward or downward to reflect production history, results of exploration and development drilling, prevailing commodity prices and prevailing development expenses.

The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate representation of their value.

If commodity prices remain depressed, HighMount may be required to take additional write-downs of the carrying values of its properties.

HighMount may be required, under full cost accounting rules, to write-down the carrying value of its natural gas and oil properties. A number of factors could result in a write-down, including continued low commodity prices, a substantial downward adjustment to estimated proved reserves, a substantial increase in estimated development costs, or deterioration in exploration results. It is difficult to predict future changes in gas prices. However, the abundance of natural gas supply discoveries over the last few years would generally indicate a bias toward downward pressure on prices. HighMount utilizes the full cost method of accounting for its exploration and development activities. Under full cost accounting, HighMount is required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of

HighMount’s natural gas properties that is equal to the expected after tax present value (discounted at the required rate of 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges, calculated using the average first day of the month price for the preceding 12-month period.

If the net book value of HighMount’s exploration and production (“E&P”) properties (reduced by any related net deferred income tax liability) exceeds its ceiling limitation, HighMount will impair or “write-down” the book value of its E&P properties. HighMount recorded a ceiling test impairment charge in each quarter of 2012, totaling $433 million (after taxes) for the year ended December 31, 2012 as a result of declines in natural gas and NGL prices. A write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Depending on the magnitude of any future impairment, a ceiling test write-down could significantly reduce HighMount’s income, or produce a loss.

Natural gas, oil and other commodity prices are volatile.

The commodity price HighMount receives for its production heavily influences its revenue, profitability, access to capital and future rate of growth. If the current low price environment for natural gas continues, HighMount’s results of operations will be lower as well. HighMount is subject to risks due to frequent and possibly substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and HighMount expects this volatility to continue. The markets and prices for natural gas and oil depend upon factors beyond HighMount’s control. These factors include, among others, economic and market conditions, domestic production and import levels, storage levels, basis differentials, weather, government regulations and taxation. Lower commodity prices may reduce the amount of natural gas and oil that HighMount can produce economically.

HighMount engages in commodity price hedging activities.

The extent of HighMount’s commodity price risk is related to the effectiveness and scope of HighMount’s hedging activities. To the extent HighMount hedges its commodity price risk, HighMount will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor. Furthermore, because HighMount has entered into derivative transactions related to only a portion of its natural gas and oil production, HighMount will continue to have direct commodity price risk on the unhedged portion. HighMount’s actual future production may be significantly higher or lower than HighMount estimates at the time it enters into derivative transactions for that period.

As a result, HighMount’s hedging activities may not be as effective as HighMount intends in reducing the volatility of its cash flows, and in certain circumstances may actually increase the volatility of cash flows. In addition, even though HighMount’s management monitors its hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement or if the hedging arrangement is imperfect or ineffective.

Risks Related to Us and Our Subsidiaries Generally

In addition to the specific risks and uncertainties faced by our subsidiaries, as discussed above, we and all of our subsidiaries face risks and uncertainties related to, among other things, terrorism, hurricanes and other natural disasters, competition, government regulation, dependence on key executives and employees, litigation, dependence on information technology and compliance with environmental laws.

Acts of terrorism could harm us and our subsidiaries.

Future terrorist attacks and the continued threat of terrorism in this country or abroad, as well as possible retaliatory military and other action by the United States and its allies, could have a significant impact on the assets and businesses of certain of our subsidiaries. CNA issues coverages that are exposed to risk of loss from a terrorism act. Terrorist acts or the threat of terrorism, including increased political, economic and financial market instability and volatility in the price of oil and gas, could affect the market for Diamond Offshore’s drilling services, Boardwalk Pipeline’s transportation, gathering and storage services and HighMount’s exploration and production

activities. In addition, future terrorist attacks could lead to reductions in business travel and tourism which could harm Loews Hotels. While our subsidiaries take steps that they believe are appropriate to secure their assets, there is no assurance that they can completely secure them against a terrorist attack or obtain adequate insurance coverage for terrorist acts at reasonable rates.

Our subsidiaries are subject to extensive federal, state and local governmental regulations.

The businesses operated by our subsidiaries are impacted by current and potential federal, state and local governmental regulations which impose or might impose a variety of restrictions and compliance obligations on those companies. Governmental regulations can also change materially in ways that could adversely affect those companies. Risks faced by our subsidiaries related to governmental regulation include the following:

CNA. The insurance industry is subject to comprehensive and detailed regulation and supervision. Most insurance regulations are designed to protect the interests of CNA’s policyholders rather than its investors. Each jurisdiction in which CNA does business has established supervisory agencies that regulate its business. In addition, the Lloyd’s marketplace sets rules under which its members, including CNA’s Hardy syndicate operate. These rules and regulations include the following:

—

standards of solvency, including risk-based capital measurements;

—

restrictions on the nature, quality and concentration of investments;

—

restrictions on CNA’s ability to withdraw from unprofitable lines of insurance or unprofitable market areas;

—

the required use of certain methods of accounting and reporting;

—

the establishment of reserves for unearned premiums, losses and other purposes;

—

potential assessments for funds necessary to settle covered claims against impaired, insolvent or failed private or quasi-governmental insurers;

—

licensing of insurers and agents;

—

approval of policy forms;

—

limitations on the ability of CNA’s insurance subsidiaries to pay dividends to us; and

—

limitations on the ability to non-renew, cancel or change terms and conditions in policies.

Regulatory powers also extend to premium rate regulations which require that rates not be excessive, inadequate or unfairly discriminatory. CNA may also be required by the jurisdictions in which it does business to provide coverage to persons who would not otherwise be considered eligible. Each jurisdiction dictates the types of insurance and the level of coverage that must be provided to such involuntary risks. CNA’s share of these involuntary risks is mandatory and is generally a function of its respective share of the voluntary market by line of insurance in each jurisdiction.

Diamond Offshore. The offshore drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. Diamond Offshore may be required to make significant capital expenditures for additional equipment to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to Diamond Offshore’s operating costs or result in a reduction in revenues associated with downtime required to install such equipment, or may otherwise significantly limit drilling activity.

In the aftermath of the Macondo well blowout in April of 2010 and the subsequent investigation into the causes of the event, new rules have been implemented for oil and gas operations in the GOM and in many of the international locations in which Diamond Offshore operates, including new standards for well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system (“SEMS”). New regulations may continue to be announced, including rules regarding drilling systems and equipment, such as blowout preventer and well control systems and lifesaving systems as well as rules regarding employee training, engaging personnel in safety management and requiring third party audits of SEMS programs. Such new regulations could require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase Diamond Offshore’s operating costs and cause downtime for its rigs if it is required to take any of them out of service between scheduled surveys or inspections, or if it is required to extend scheduled surveys or inspections, to meet any such new requirements. Diamond Offshore is not able to predict the likelihood, nature or extent of additional rulemaking, nor is it able to predict the future impact of these events on operations. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of Diamond Offshore’s operations, and enhanced permitting requirements as well as escalating costs borne by its customers could reduce exploration activity in the GOM and therefore demand for its services.

Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect Diamond Offshore’s operations by limiting drilling opportunities.

Boardwalk Pipeline. Boardwalk Pipeline’s natural gas transportation and storage operations are subject to extensive regulation by FERC and the DOT among other federal and state authorities. In addition to FERC rules and regulations related to the rates Boardwalk Pipeline can charge for its services, federal regulations extend to pipeline safety, operating terms and conditions of service, the types of services Boardwalk Pipeline may offer, construction or abandonment of facilities, accounting and record keeping, and relationships and transactions with affiliated companies. These regulations can adversely impact Boardwalk Pipeline’s ability to compete for business, construct new facilities, including by increasing the lead times to develop projects, offer new services, or recover the full cost of operating its pipelines.

HighMount. All of HighMount’s operations are conducted onshore in the United States. The U.S. oil and gas industry, and HighMount’s operations, are subject to regulation at the federal, state and local level. Such regulation includes requirements with respect to, among other things: permits to drill and to conduct other operations; provision of financial assurances (such as bonds) covering drilling and well operations; the location of wells; the method of drilling and completing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; the marketing, transportation and reporting of production; the valuation and payment of royalties; the size of drilling and spacing units (regarding the density of wells which may be drilled in a particular area); the unitization or pooling of natural gas and oil properties; maximum rates of production from natural gas and oil wells; venting or flaring of natural gas; and the ratability of production and the operation of gathering systems and related assets. Changes in these regulations, which HighMount cannot predict, could be harmful to HighMount’s business and results of operations.

Hydraulic fracturing is a technique commonly used by oil and gas exploration companies, including HighMount, to stimulate the production of oil and natural gas by injecting fluids and sand into underground wells at high pressures, causing fractures or fissures in the geological formation which allow oil and gas to flow more freely. In recent years, concerns have been raised that the fracturing process and disposal of drilling fluids may contaminate underground sources of drinking water. The conference committee report for The Department of the Interior, Environment, and Related Agencies Appropriations Act for Fiscal Year 2010 requested the EPA to conduct a study of hydraulic fracturing, particularly the relationship between hydraulic fracturing and drinking water. In December of 2012 the EPA issued a progress report of the projects the EPA is conducting as part of the study. A final draft report is expected to be released for public comment and peer review in 2014. Several bills were introduced in the 111^th and 112^th Congresses seeking federal regulation of hydraulic fracturing, which has historically been regulated at the state level, though none of the proposed legislation was passed into law. Similar bills may be introduced in the

current Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. If hydraulic fracturing is banned or significantly restricted by federal regulation or otherwise, it could impair HighMount’s ability to economically drill new wells, which would reduce its production, revenues and profitability.

HighMount owns and operates gas gathering lines and related facilities which are regulated by the DOT and state agencies with respect to safety and operating conditions. PHMSA has established minimum federal safety standards for certain gas gathering lines. PHMSA has indicated that changes to the current regulatory framework are needed to address gas exploration and production activities. If implemented, the new changes could impact HighMount’s ability to transport some of its natural gas or cause HighMount to incur additional costs.

Our subsidiaries face significant risks related to compliance with environmental laws.

Our subsidiaries have extensive obligations and financial exposure related to compliance with federal, state and local environmental laws, many of which have become increasingly stringent in recent years and may in some cases impose strict liability, which could be substantial, rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. For example, Diamond Offshore could be liable for damages and costs incurred in connection with oil spills related to its operations, including for conduct of or conditions caused by others. HighMount is subject to extensive environmental regulation in the conduct of its business, particularly related to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. Boardwalk Pipeline is also subject to laws and regulations, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which it disposes of waste, requiring remedial action to remove or mitigate contamination and requiring capital expenditures to comply with pollution control requirements.

We are subject to physical and financial risks associated with climate change.

As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our subsidiaries and their suppliers and customers. We and our subsidiaries may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and related services provided by our energy subsidiaries. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas. In addition, changing global weather patterns have been associated with extreme weather events and could change longer-term natural catastrophe trends, including increasing the frequency and severity of hurricanes and other natural disasters which could increase future catastrophe losses at CNA and damage to property, disruption of business and higher operating costs at Diamond Offshore, Boardwalk Pipeline, HighMount and Loews Hotels.

There is currently no federal regulation that limits GHG emissions in the U.S. However, several bills were introduced in Congress in recent years that would regulate U.S. GHG emissions under a cap and trade system. Although these bills were not passed into law, some regulation of that type may be enacted in the U.S. in the near future. In addition, in 2009 the EPA adopted regulations under the Clean Air Act requiring the monitoring and reporting of annual GHG emissions by operators of facilities that emit more than 25,000 metric tons of GHG per year, which includes Boardwalk Pipeline and HighMount. Numerous states and several regional multi-state climate initiatives have announced or adopted plans to regulate GHG emissions, though the state programs vary widely. The establishment of a GHG reporting system and registry may be a first step toward broader regulation of GHG emissions. Compliance with future laws and regulations could impose significant costs on affected companies or adversely affect the demand for and the cost to produce and transport hydrocarbon-based fuel, which would adversely affect the businesses of our energy subsidiaries.

Any significant interruption in the operation of critical computer systems could materially disrupt operations.

We and our subsidiaries have become more reliant on technology to help increase efficiency in our businesses. We are dependent upon operational and financial computer systems to process the data necessary to conduct almost all aspects of our businesses. Any failure of our or our subsidiaries’ computer systems, or those of our or their customers, vendors or others with whom we and they do business, could materially disrupt business operations. Computer and other business facilities and systems could become unavailable or impaired from a variety of causes, including among others, storms and other natural disasters, terrorist attacks, utility outages or complications encountered as existing systems are replaced or upgraded. In addition, it has been reported that unknown entities or groups have mounted so-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Any cyber attacks that affect our or our subsidiaries’ facilities could have a material adverse effect on our and their business or reputation.

Loss of key vendor relationships or failure of a vendor to protect personal information could result in a materially adverse effect on our operations.

We and our subsidiaries rely on services and products provided by many vendors in the United States and abroad. These include, for example, vendors of computer hardware, software and services, as well as other critical materials and services. If one or more key vendors becomes unable to continue to provide products or services, or fails to protect our proprietary information, including in some cases personal information of employees, customers or hotel guests, we and our subsidiaries may experience a material adverse effect on our or their business or reputation.

We could incur impairment charges related to the carrying value of the long-lived assets and goodwill of our subsidiaries.

Our subsidiaries regularly evaluate their long-lived assets and goodwill for impairment whenever events or changes in circumstances indicate the carrying value of these assets may not be recoverable. Most notably, we could incur impairment charges related to the carrying value of offshore drilling equipment at Diamond Offshore, natural gas and oil properties at HighMount, pipeline equipment at Boardwalk Pipeline and hotel properties owned by Loews Hotels.

We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each unit’s fair value as of the testing date. We calculate the fair value of our reporting units (each of our principal operating subsidiaries) based on estimates of future discounted cash flows, which reflect management’s judgments and assumptions regarding the appropriate risk-adjusted discount rate, future industry conditions and operations and other factors. Asset impairment evaluations are, by nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets which could impact the need to record an impairment charge and the amount of any charge taken.

We are a holding company and derive substantially all of our income and cash flow from our subsidiaries.

We rely upon our invested cash balances and distributions from our subsidiaries to generate the funds necessary to meet our obligations and to declare and pay any dividends to holders of our common stock. Our subsidiaries are separate and independent legal entities and have no obligation, contingent or otherwise, to make funds available to us, whether in the form of loans, dividends or otherwise. The ability of our subsidiaries to pay dividends to us is also subject to, among other things, the availability of sufficient earnings and funds in such subsidiaries, applicable state laws, including in the case of the insurance subsidiaries of CNA, laws and rules governing the payment of dividends by regulated insurance companies, and their compliance with covenants in their respective loan agreements. Claims of creditors of our subsidiaries will generally have priority as to the assets of such subsidiaries over our claims and our creditors and shareholders.

We could have liability in the future for tobacco-related lawsuits.

As a result of our ownership of Lorillard, Inc. (“Lorillard”) prior to the separation of Lorillard from us in 2008 (the “Separation”), from time to time we have been named as a defendant in tobacco-related lawsuits and could be named as a defendant in additional tobacco-related suits, notwithstanding the completion of the Separation. In the Separation Agreement entered into between us and Lorillard and its subsidiaries in connection with the Separation, Lorillard and each of its subsidiaries has agreed to indemnify us for liabilities related to Lorillard’s tobacco business, including liabilities that we may incur for current and future tobacco-related litigation against us. An adverse decision in a tobacco-related lawsuit against us could, if the indemnification is deemed for any reason to be unenforceable or any amounts owed to us thereunder are not collectible, in whole or in part, have a material adverse effect on our financial condition, results of operations and equity. We do not expect that the Separation will alter the legal exposure of either entity with respect to tobacco-related claims. We do not believe that we have any liability for tobacco-related claims, and we have never been held liable for any such claims.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our corporate headquarters is located in approximately 136,000 square feet of leased office space in New York City. Information relating to our subsidiaries’ properties is contained under Item 1.

Item 3. Legal Proceedings.

None.

Item 4. Mine Safety Disclosures.

None.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Price Range of Common Stock

Our common stock is listed on the New York Stock Exchange under the symbol “L.” The following table sets forth the reported high and low sales prices in each calendar quarter:

2012

2011

High

Low

High

Low

First Quarter

$ 40.16

$ 37.02

$ 45.31

$ 39.06

Second Quarter

41.80

38.14

44.46

39.99

Third Quarter

42.86

39.04

42.64

33.79

Fourth Quarter

43.36

39.57

41.66

32.90

The following graph compares annual total return of our Common Stock, the Standard & Poor’s 500 Composite Stock Index (“S&P 500 Index”) and our Peer Group (“Loews Peer Group”) for the five years ended December 31, 2012. The graph assumes that the value of the investment in our Common Stock, the S&P 500 Index and the Loews Peer Group was $100 on December 31, 2007 and that all dividends were reinvested.

LOGO


	2007	2008	2009	2010	2011	2012
Loews Common Stock	100.00	56.48	73.34	79.06	76.98	83.84
S&P 500 Index	100.00	63.00	79.67	91.68	93.61	108.59
Loews Peer Group (a)	100.00	60.93	78.15	86.97	91.66	104.06

(a)

The Loews Peer Group consists of the following companies that are industry competitors of our principal operating subsidiaries: Ace Limited, W.R. Berkley Corporation, Cabot Oil & Gas Corporation, The Chubb Corporation, Energy Transfer Partners L.P., Ensco plc, The Hartford Financial Services Group, Inc., Kinder Morgan Energy Partners, L.P., Noble Corporation, Range Resources Corporation, Spectra Energy Corp, Transocean Ltd. and The Travelers Companies, Inc.

Dividend Information

We have paid quarterly cash dividends on Loews common stock in each year since 1967. Regular dividends of $0.0625 per share of Loews common stock were paid in each calendar quarter of 2012 and 2011.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides certain information as of December 31, 2012 with respect to our equity compensation plans under which our equity securities are authorized for issuance.

Plan category

Number of
securities to be
issued upon exercise
of outstanding
options, warrants
and rights

Weighted average
exercise price of
outstanding options,
warrants and rights

Number of
securities remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected
in the first column)

Equity compensation plans approved by security holders (a)

6,535,150

36.96

7,129,900

Equity compensation plans not approved by security
holders (b)

N/A

(a)	Reflects stock options and stock appreciation rights awarded under the Loews Corporation 2000 Stock Option Plan.

(b)	We do not have equity compensation plans that have not been approved by our shareholders.

Approximate Number of Equity Security Holders

We have approximately 1,170 holders of record of our common stock.

Common Stock Repurchases

We repurchased our common stock in 2012 as follows:


Period	Total number of shares purchased		Average price paid per share


January 1, 2012 – March 31, 2012		2,500	$38.42
April 1, 2012 – June 30, 2012		1,302,700	38.99
July 1, 2012 – September 30, 2012		2,187,630	40.11
October 1, 2012 – December 31, 2012		2,060,000	40.60

Item 6. Selected Financial Data.

The following table presents selected financial data. The table should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data of this Form 10-K.


Year Ended December 31	2012			2011			2010			2009			2008

(In millions, except per share data)

Results of Operations:

Revenues	$	14,552		$	14,129		$	14,615		$	14,117		$	13,247
Income before income tax	$	1,399		$	2,226		$	2,902		$	1,728		$	594
Income from continuing operations	$	1,110		$	1,694		$	2,008		$	1,384		$	585
Discontinued operations, net								(20	)		(2	)		4,713

Net income		1,110			1,694			1,988			1,382			5,298
Amounts attributable to noncontrolling interests		(542	)		(632	)		(699	)		(819	)		(763)

Net income attributable to Loews Corporation	$	568		$	1,062		$	1,289		$	563		$	4,535


Income (loss) attributable to:
Loews common stock:
Income (loss) from continuing operations	$	568		$	1,062		$	1,308		$	565		$	(177)
Discontinued operations, net								(19	)		(2	)		4,501

Loews common stock		568			1,062			1,289			563			4,324
Former Carolina Group stock:
Discontinued operations, net														211

Net income	$	568		$	1,062		$	1,289		$	563		$	4,535


Diluted Net Income (Loss) Per Share:

Loews common stock:
Income (loss) from continuing operations	$	1.43		$	2.62		$	3.11		$	1.31		$	(0.37)
Discontinued operations, net								(0.04	)		(0.01	)		9.43

Net income	$	1.43		$	2.62		$	3.07		$	1.30		$	9.06


Former Carolina Group stock:
Discontinued operations, net	$	-		$	-		$	-		$	-		$	1.95


Financial Position:

Investments	$	53,048		$	49,028		$	48,907		$	46,034		$	38,450
Total assets		80,021			75,268			76,198			73,990			69,791
Debt		9,210			9,001			9,477			9,485			8,258
Shareholders’ equity		19,459			18,772			18,386			16,833			13,068
Cash dividends per share:
Loews common stock		0.25			0.25			0.25			0.25			0.25
Former Carolina Group stock		-			-			-			-			0.91
Book value per share of Loews common stock		49.67			47.33			44.35			39.60			30.04
Shares outstanding of Loews common stock		391.81			396.59			414.55			425.07			435.09

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Management’s discussion and analysis of financial condition and results of operations is comprised of the following sections:


		Page No.

Overview
Consolidated Financial Results		48
Parent Company Structure		48
Critical Accounting Estimates		49
Results of Operations by Business Segment		52
CNA Financial		52
Diamond Offshore		65
Boardwalk Pipeline		72
HighMount		74
Loews Hotels		77
Corporate and Other		79
Liquidity and Capital Resources		80
CNA Financial		80
Diamond Offshore		81
Boardwalk Pipeline		82
HighMount		83
Loews Hotels		84
Corporate and Other		84
Contractual Obligations		85
Investments		86
Accounting Standards Update		90
Forward-Looking Statements		91

OVERVIEW

We are a holding company. Our subsidiaries are engaged in the following lines of business:

—

commercial property and casualty insurance (CNA Financial Corporation (“CNA”), a 90% owned subsidiary);

—

operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc. (“Diamond Offshore”), a 50.4% owned subsidiary);

—

transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas (Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”), a 55% owned subsidiary);

—

exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC (“HighMount”), a wholly owned subsidiary); and

—

operation of hotels (Loews Hotels Holding Corporation (“Loews Hotels”), a wholly owned subsidiary).

Unless the context otherwise requires, references in this Report to “Loews Corporation,” “the Company,” “Parent Company,” “we,” “our,” “us” or like terms refer to the business of Loews Corporation excluding its subsidiaries.

The following discussion should be read in conjunction with Item 1A, Risk Factors, and Item 8, Financial Statements and Supplementary Data of this Form 10-K.

Consolidated Financial Results

Consolidated net income for the year ended December 31, 2012 was $568 million, or $1.43 per share, compared to $1.1 billion, or $2.62 per share, in 2011. Net income in 2012 includes catastrophe losses of $243 million (after tax and noncontrolling interests) at CNA primarily related to Storm Sandy and after tax ceiling test impairment charges of $433 million at HighMount related to the carrying value of its natural gas and oil properties reflecting declines in natural gas and NGL prices. Lower results at Diamond Offshore also contributed to the reduction in net income, partially offset by higher earnings at Boardwalk Pipeline and higher parent company investment income as a result of improved performance of equity investments.

CNA’s earnings declined due to higher catastrophe losses related to Storm Sandy and a lower level of favorable net prior year development in 2012 than in 2011, partially offset by increased investment income. Increased investment income reflects improved performance of limited partnership investments.

Diamond Offshore earnings decreased as a result of lower rig utilization and a decrease in average dayrate partially offset by lower interest expense.

Boardwalk Pipeline’s earnings increased primarily due to the contributions from recent acquisitions, lower general and administrative expenses as well as lower impairment charges in 2012.

Book value per share increased to $49.67 at December 31, 2012 from $47.33 at December 31, 2011.

Parent Company Structure

We are a holding company and derive substantially all of our cash flow from our subsidiaries. We rely upon our invested cash balances and distributions from our subsidiaries to generate the funds necessary to meet our obligations and to declare and pay any dividends to our shareholders. The ability of our subsidiaries to pay dividends is subject to, among other things, the availability of sufficient earnings and funds in such subsidiaries, applicable state laws, including in the case of the insurance subsidiaries of CNA, laws and rules governing the payment of dividends by regulated insurance companies (see Note 13 of the Notes to Consolidated Financial Statements included under Item 8) and compliance with covenants in their respective loan agreements. Claims of creditors of

our subsidiaries will generally have priority as to the assets of such subsidiaries over our claims and those of our creditors and shareholders.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires us to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the related notes. Actual results could differ from those estimates.

The Consolidated Financial Statements and accompanying notes have been prepared in accordance with GAAP, applied on a consistent basis. We continually evaluate the accounting policies and estimates used to prepare the Consolidated Financial Statements. In general, our estimates are based on historical experience, evaluation of current trends, information from third party professionals and various other assumptions that we believe are reasonable under the known facts and circumstances.

We consider the accounting policies discussed below to be critical to an understanding of our Consolidated Financial Statements as their application places the most significant demands on our judgment. Due to the inherent uncertainties involved with these types of judgments, actual results could differ significantly from estimates, which may have a material adverse impact on our results of operations or equity.

Insurance Reserves

Insurance reserves are established for both short and long-duration insurance contracts. Short-duration contracts are primarily related to property and casualty insurance policies where the reserving process is based on actuarial estimates of the amount of loss, including amounts for known and unknown claims. Long-duration contracts include long term care products and payout annuity contracts and are estimated using actuarial estimates about mortality, morbidity and persistency as well as assumptions about expected investment returns. The reserve for unearned premiums on property and casualty contracts represents the portion of premiums written related to the unexpired terms of coverage. The reserving process is discussed in further detail in the Reserves – Estimates and Uncertainties section below.

Reinsurance and Other Receivables

An exposure exists with respect to the collectibility of ceded property and casualty and life reinsurance to the extent that any reinsurer is unable to meet its obligations or disputes the liabilities CNA has ceded under reinsurance agreements. An allowance for doubtful accounts on reinsurance receivables is recorded on the basis of periodic evaluations of balances due from reinsurers, reinsurer solvency, CNA’s past experience and current economic conditions. Further information on CNA’s reinsurance receivables is included in Note 16 of the Notes to Consolidated Financial Statements included under Item 8.

Additionally, an exposure exists with respect to the collectibility of amounts due from customers on other receivables. An allowance for doubtful accounts is recorded on the basis of periodic evaluations of balances due currently or in the future, management’s experience and current economic conditions.

If actual experience differs from the estimates made by management in determining the allowances for doubtful accounts on reinsurance and other receivables, net receivables as reflected on our Consolidated Balance Sheets may not be collected. Therefore, our results of operations and/or equity could be materially adversely impacted.

Litigation

We and our subsidiaries are involved in various legal proceedings that have arisen during the ordinary course of business. We evaluate the facts and circumstances of each situation, and when management determines it necessary, a liability is estimated and recorded. Please read Note 18 of the Notes to Consolidated Financial Statements included under Item 8.

Valuation of Investments and Impairment of Securities

We classify fixed maturity securities and equity securities as either available-for-sale or trading which are both carried at fair value. Fair value represents the price that would be received in a sale of an asset in an orderly transaction between market participants on the measurement date, the determination of which requires us to make a significant number of assumptions and judgments. Securities with the greatest level of subjectivity around valuation are those that rely on inputs that are significant to the estimated fair value and that are not observable in the market or cannot be derived principally from or corroborated by observable market data. These unobservable inputs are based on assumptions consistent with what we believe other market participants would use to price such securities. Further information on fair value measurements is included in Note 4 of the Notes to Consolidated Financial Statements included under Item 8.

CNA’s investment portfolio is subject to market declines below amortized cost that may be other-than-temporary and therefore result in the recognition of impairment losses in earnings. Factors considered in the determination of whether or not a decline is other-than-temporary include a current intention or need to sell the security or an indication that a credit loss exists. Significant judgment exists regarding the evaluation of the financial condition and expected near-term and long term prospects of the issuer, the relevant industry conditions and trends, and whether CNA expects to receive cash flows sufficient to recover the entire amortized cost basis of the security. CNA has an Impairment Committee which reviews the investment portfolio on at least a quarterly basis, with ongoing analysis as new information becomes available. Further information on CNA’s process for evaluating impairments is included in Note 3 of the Notes to Consolidated Financial Statements included under Item 8.

Long Term Care Products and Payout Annuity Contracts

Future policy benefit reserves for CNA’s long term care products and payout annuity contracts are based on certain assumptions including morbidity, mortality, policy persistency and discount rates, which are impacted by expected investment yields. The adequacy of the reserves are contingent on actual experience related to these key assumptions, which were generally established at time of issue. If actual experience differs from these assumptions, the reserves may not be adequate, requiring CNA to add to reserves. Therefore, our results of operations and/or equity could be adversely impacted. The reserving process is discussed in further detail in the Reserves – Estimates and Uncertainties section below.

Pension and Postretirement Benefit Obligations

We make a significant number of assumptions in order to estimate the liabilities and costs related to our pension and postretirement benefit obligations under our benefit plans. The assumptions that have the most impact on pension costs are the discount rate and the expected long term rate of return on plan assets. These assumptions are evaluated relative to current market factors such as inflation, interest rates and fiscal and monetary policies. Changes in these assumptions can have a material impact on pension obligations and pension expense.

In determining the discount rate assumption, we utilized current market information and liability information, including a discounted cash flow analysis of our pension and postretirement obligations. In particular, the basis for our discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of our plan liabilities. The yield curve was applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curves and indices evaluated in the selection of the discount rate are comprised of high quality corporate bonds that are rated AA by an accepted rating agency.

Further information on our pension and postretirement benefit obligations is included in Note 15 of the Notes to Consolidated Financial Statements included under Item 8.

Valuation of HighMount’s Proved Reserves

HighMount follows the full cost method of accounting for natural gas and oil exploration and production activities. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depleted using the units-of-production method. The depletable base of costs includes estimated future costs to be incurred in developing proved natural gas and oil reserves, as well as

capitalized asset retirement costs, net of projected salvage values. Capitalized costs in the depletable base are subject to a ceiling test. The test limits capitalized amounts to a ceiling, the present value of estimated future net revenues to be derived from the production of proved natural gas and oil reserves, using calculated average prices adjusted for any cash flow hedges in place. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a write-down of the assets must be recognized in that period. A write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. For the year ended December 31, 2012, HighMount recognized non-cash impairment charges of $680 million ($433 million after tax) related to the carrying value of natural gas and oil properties, as discussed further in Note 7 of the Notes to Consolidated Financial Statements included under Item 8. In addition, gains or losses on the sale or other disposition of natural gas and oil properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

HighMount’s estimate of proved reserves requires a high degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. HighMount’s estimated proved reserves are based upon studies for each of its properties prepared by HighMount staff engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. Determination of proved reserves is based on, among other things, (i) a pricing mechanism for oil and gas reserves which uses an average 12-month price; (ii) a limitation on the classification of reserves as proved undeveloped to locations scheduled to be drilled within five years; and (iii) a 10% discount factor used in calculating discounted future net cash flows.

The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of HighMount’s estimates or assumptions in the future and revisions to the value of HighMount’s proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. Given the volatility of natural gas and oil prices, it is possible that HighMount’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near term.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company uses a probability-weighted cash flow analysis to test property and equipment for impairment based on relevant market data. If an asset is determined to be impaired, a loss is recognized to reduce the carrying amount to the fair value of the asset. Management’s cash flow assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from the reported amounts.

Goodwill

Goodwill is required to be evaluated on an annual basis and whenever, in management’s judgment, there is a significant change in circumstances that would be considered a triggering event. Management must apply judgment in assessing qualitatively whether events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Factors such as a reporting unit’s planned future operating results, long term growth outlook and industry and market conditions are considered. Judgment is also applied in determining the estimated fair value of reporting units’ assets and liabilities for purposes of performing quantitative goodwill impairment tests. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples.

Income Taxes

Deferred income taxes are recognized for temporary differences between the financial statement and tax return bases of assets and liabilities. Any resulting future tax benefits are recognized to the extent that realization of such benefits is more likely than not, and a valuation allowance is established for any portion of a deferred tax asset that management believes may not be realized. The assessment of the need for a valuation allowance requires

management to make estimates and assumptions about future earnings, reversal of existing temporary differences and available tax planning strategies. If actual experience differs from these estimates and assumptions, the recorded deferred tax asset may not be fully realized resulting in an increase to income tax expense in our results of operations. In addition, the ability to record deferred tax assets in the future could be limited resulting in a higher effective tax rate in that future period.

The Company has not established deferred tax liabilities for certain of its foreign earnings as it intends to indefinitely reinvest those earnings to finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision could have a material impact on our financial results.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

Unless the context otherwise requires, references to net operating income (loss), net realized investment results and net income (loss) reflect amounts attributable to Loews Corporation Shareholders.

CNA Financial

Reserves – Estimates and Uncertainties

Property and Casualty Claim and Claim Adjustment Expense Reserves

CNA maintains loss reserves to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, including the estimated cost of the claims adjudication process, for claims that have been reported but not yet settled (case reserves) and claims that have been incurred but not reported (“IBNR”). Claim and claim adjustment expense reserves are reflected as liabilities and are included on the Consolidated Balance Sheets under the heading “Insurance Reserves.” Adjustments to prior year reserve estimates, if necessary, are reflected in results of operations in the period that the need for such adjustments is determined. The carried case and IBNR reserves as of each balance sheet date are provided in the discussion that follows and in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

The level of reserves CNA maintains represents its best estimate, as of a particular point in time, of what the ultimate settlement and administration of claims will cost based on CNA’s assessment of facts and circumstances known at that time. Reserves are not an exact calculation of liability but instead are complex estimates that CNA derives, generally utilizing a variety of actuarial reserve estimation techniques, from numerous assumptions and expectations about future events, both internal and external, many of which are highly uncertain.

CNA is subject to the uncertain effects of emerging or potential claims and coverage issues that arise as industry practices and legal, judicial, social, economic and other environmental conditions change. These issues have had, and may continue to have, a negative effect on CNA’s business by either extending coverage beyond the original underwriting intent or by increasing the number or size of claims. Examples of emerging or potential claims and coverage issues include:

—

class action litigation relating to claims handling and other practices; and

—

mass tort claims, including bodily injury claims related to welding rods, benzene, lead, noise induced hearing loss, injuries from various medical products including pharmaceuticals and various other chemical and radiation exposure claims.

The impact of these and other unforeseen emerging or potential claims and coverage issues is difficult to predict and could materially adversely affect the adequacy of CNA’s claim and claim adjustment expense reserves and could lead to future reserve additions.

CNA’s property and casualty insurance subsidiaries also have actual and potential exposures related to asbestos and environmental pollution (“A&EP”) claims. CNA’s experience has been that establishing reserves for casualty coverages relating to A&EP claims and the related claim adjustment expenses are subject to uncertainties that are greater than those presented by other claims. Additionally, traditional actuarial methods and techniques employed to estimate the ultimate cost of claims for more traditional property and casualty exposures are less precise in estimating claim and claim adjustment reserves for A&EP. As a result, estimating the ultimate cost of both reported and unreported A&EP claims is subject to a higher degree of variability.

To mitigate the risks posed by CNA’s exposure to A&EP claims and claim adjustment expenses, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8, on August 31, 2010, CNA completed a transaction with NICO, a subsidiary of Berkshire Hathaway Inc., under which substantially all of CNA’s legacy A&EP liabilities were ceded to NICO effective January 1, 2010 (“Loss Portfolio Transfer”).

The Loss Portfolio Transfer is considered a retroactive reinsurance contract. In the event that the cumulative claim and allocated claim adjustment expenses ceded under the Loss Portfolio Transfer exceed the consideration paid, the resulting gain from such excess would be deferred. A cumulative amortization adjustment would be recognized in earnings in the period such excess arises so that the resulting deferred gain would reflect the balance that would have existed if the revised estimate was available at the inception date of the Loss Portfolio Transfer. This accounting generally results in a reserve charge because of the timing difference between the recognition of the gross adverse reserve development and the related ceded reinsurance benefit. However, there is no economic impact as long as the additional losses are within the limit under the contract. Any future adverse prior year development in excess of approximately $230 million would put the Loss Portfolio Transfer into an overall gain position under retroactive reinsurance accounting.

Establishing Reserve Estimates

In developing claim and claim adjustment expense (“loss” or “losses”) reserve estimates, CNA’s actuaries perform detailed reserve analyses that are staggered throughout the year. The data is organized at a “product” level. A product can be a line of business covering a subset of insureds such as commercial automobile liability for small or middle market customers, it can encompass several lines of business provided to a specific set of customers such as dentists, or it can be a particular type of claim such as construction defect. Every product is analyzed at least once during the year, with the exception of certain run-off products which are analyzed on a periodic basis. The analyses generally review losses gross of ceded reinsurance and apply the ceded reinsurance terms to the gross estimates to establish estimates net of reinsurance. In addition to the detailed analyses, CNA reviews actual loss emergence for all products each quarter.

The detailed analyses use a variety of generally accepted actuarial methods and techniques to produce a number of estimates of ultimate loss. CNA’s actuaries determine a point estimate of ultimate loss by reviewing the various estimates and assigning weight to each estimate given the characteristics of the product being reviewed. The reserve estimate is the difference between the estimated ultimate loss and the losses paid to date. The difference between the estimated ultimate loss and the case incurred loss (paid loss plus case reserve) is IBNR. IBNR calculated as such includes a provision for development on known cases (supplemental development) as well as a provision for claims that have occurred but have not yet been reported (pure IBNR).

Most of CNA’s business can be characterized as long-tail. For long-tail business, it will generally be several years between the time the business is written and the time when all claims are settled. CNA’s long-tail exposures include commercial automobile liability, workers’ compensation, general liability, medical, professional liability, other professional liability coverages, assumed reinsurance run-off and products liability. Short-tail exposures include property, commercial automobile physical damage, marine and warranty. CNA Specialty and CNA Commercial contain both long-tail and short-tail exposures. Hardy contains primarily short-tail exposures. Other contains long-tail exposures.

Various methods are used to project ultimate loss for both long-tail and short-tail exposures including, but not limited to, the following:

—

paid development;

—

incurred development;

—

loss ratio;

—

Bornhuetter-Ferguson using paid loss;

—

Bornhuetter-Ferguson using incurred loss;

—

frequency times severity; and

—

stochastic modeling.

The paid development method estimates ultimate losses by reviewing paid loss patterns and applying them to accident or policy years with further expected changes in paid loss. Selection of the paid loss pattern may require consideration of several factors including the impact of inflation on claims costs, the rate at which claims professionals make claim payments and close claims, the impact of judicial decisions, the impact of underwriting changes, the impact of large claim payments and other factors. Claim cost inflation itself may require evaluation of changes in the cost of repairing or replacing property, changes in the cost of medical care, changes in the cost of wage replacement, judicial decisions, legislative changes and other factors. Because this method assumes that losses are paid at a consistent rate, changes in any of these factors can impact the results. Since the method does not rely on case reserves, it is not directly influenced by changes in the adequacy of case reserves.

For many products, paid loss data for recent periods may be too immature or erratic for accurate predictions. This situation often exists for long-tail exposures. In addition, changes in the factors described above may result in inconsistent payment patterns. Finally, estimating the paid loss pattern subsequent to the most mature point available in the data analyzed often involves considerable uncertainty for long-tail products such as workers’ compensation.

The incurred development method is similar to the paid development method, but it uses case incurred losses instead of paid losses. Since the method uses more data (case reserves in addition to paid losses) than the paid development method, the incurred development patterns may be less variable than paid patterns. However, selection of the incurred loss pattern typically requires analysis of all of the same factors described above. In addition, the inclusion of case reserves can lead to distortions if changes in case reserving practices have taken place, and the use of case incurred losses may not eliminate the issues associated with estimating the incurred loss pattern subsequent to the most mature point available.

The loss ratio method multiplies earned premiums by an expected loss ratio to produce ultimate loss estimates for each accident or policy year. This method may be useful for immature accident or policy periods or if loss development patterns are inconsistent, losses emerge very slowly, or there is relatively little loss history from which to estimate future losses. The selection of the expected loss ratio typically requires analysis of loss ratios from earlier accident or policy years or pricing studies and analysis of inflationary trends, frequency trends, rate changes, underwriting changes, and other applicable factors.

The Bornhuetter-Ferguson method using paid loss is a combination of the paid development method and the loss ratio method. This method normally determines expected loss ratios similar to the approach used to estimate the expected loss ratio for the loss ratio method and typically requires analysis of the same factors described above. This method assumes that future losses will develop at the expected loss ratio level. The percent of paid loss to ultimate loss implied from the paid development method is used to determine what percentage of ultimate loss is yet to be paid. The use of the pattern from the paid development method typically requires consideration of the same factors listed in the description of the paid development method. The estimate of losses yet to be paid is added to current paid losses to estimate the ultimate loss for each year. For long-tail lines, this method will react very slowly if actual

ultimate loss ratios are different from expectations due to changes not accounted for by the expected loss ratio calculation.

The Bornhuetter-Ferguson method using incurred loss is similar to the Bornhuetter-Ferguson method using paid loss except that it uses case incurred losses. The use of case incurred losses instead of paid losses can result in development patterns that are less variable than paid patterns. However, the inclusion of case reserves can lead to distortions if changes in case reserving have taken place, and the method typically requires analysis of the same factors that need to be reviewed for the loss ratio and incurred development methods.

The frequency times severity method multiplies a projected number of ultimate claims by an estimated ultimate average loss for each accident or policy year to produce ultimate loss estimates. Since projections of the ultimate number of claims are often less variable than projections of ultimate loss, this method can provide more reliable results for products where loss development patterns are inconsistent or too variable to be relied on exclusively. In addition, this method can more directly account for changes in coverage that impact the number and size of claims. However, this method can be difficult to apply to situations where very large claims or a substantial number of unusual claims result in volatile average claim sizes. Projecting the ultimate number of claims may require analysis of several factors including the rate at which policyholders report claims to CNA, the impact of judicial decisions, the impact of underwriting changes and other factors. Estimating the ultimate average loss may require analysis of the impact of large losses and claim cost trends based on changes in the cost of repairing or replacing property, changes in the cost of medical care, changes in the cost of wage replacement, judicial decisions, legislative changes and other factors.

Stochastic modeling produces a range of possible outcomes based on varying assumptions related to the particular product being modeled. For some products, CNA uses models which rely on historical development patterns at an aggregate level, while other products are modeled using individual claim variability assumptions supplied by the claims department. In either case, multiple simulations are run and the results are analyzed to produce a range of potential outcomes. The results will typically include a mean and percentiles of the possible reserve distribution which aid in the selection of a point estimate.

For many exposures, especially those that can be considered long-tail, a particular accident or policy year may not have a sufficient volume of paid losses to produce a statistically reliable estimate of ultimate losses. In such a case, CNA’s actuaries typically assign more weight to the incurred development method than to the paid development method. As claims continue to settle and the volume of paid loss increases, the actuaries may assign additional weight to the paid development method. For most of CNA’s products, even the incurred losses for accident or policy years that are early in the claim settlement process will not be of sufficient volume to produce a reliable estimate of ultimate losses. In these cases, CNA will not assign any weight to the paid and incurred development methods. CNA will use the loss ratio, Bornhuetter-Ferguson and frequency times severity methods. For short-tail exposures, the paid and incurred development methods can often be relied on sooner primarily because CNA’s history includes a sufficient number of years to cover the entire period over which paid and incurred losses are expected to change. However, CNA may also use the loss ratio, Bornhuetter-Ferguson and frequency times severity methods for short-tail exposures.

For other more complex products where the above methods may not produce reliable indications, CNA uses additional methods tailored to the characteristics of the specific situation.

Periodic Reserve Reviews

The reserve analyses performed by CNA’s actuaries result in point estimates. Each quarter, the results of the detailed reserve reviews are summarized and discussed with CNA’s senior management to determine the best estimate of reserves. This group considers many factors in making this decision. The factors include, but are not limited to, the historical pattern and volatility of the actuarial indications, the sensitivity of the actuarial indications to changes in paid and incurred loss patterns, the consistency of claims handling processes, the consistency of case reserving practices, changes in CNA’s pricing and underwriting, pricing and underwriting trends in the insurance market, and legal, judicial, social and economic trends.

CNA’s recorded reserves reflect its best estimate as of a particular point in time based upon known facts, consideration of the factors cited above and its judgment. The carried reserve may differ from the actuarial point estimate as the result of CNA’s consideration of the factors noted above as well as the potential volatility of the projections associated with the specific product being analyzed and other factors impacting claims costs that may not be quantifiable through traditional actuarial analysis. This process results in management’s best estimate which is then recorded as the loss reserve.

Currently, CNA’s recorded reserves are modestly higher than the actuarial point estimate. For CNA Commercial, CNA Specialty and Hardy, the difference between CNA’s reserves and the actuarial point estimate is primarily driven by uncertainty with respect to immature accident years, claim cost inflation, changes in claims handling, tort reform roll-backs which may adversely impact claim costs and the effects from the economy. For CNA’s legacy A&EP liabilities, the difference between CNA’s reserves and the actuarial point estimate is primarily driven by the potential tail volatility of run-off exposures.

The key assumptions fundamental to the reserving process are often different for various products and accident or policy years. Some of these assumptions are explicit assumptions that are required of a particular method, but most of the assumptions are implicit and cannot be precisely quantified. An example of an explicit assumption is the pattern employed in the paid development method. However, the assumed pattern is itself based on several implicit assumptions such as the impact of inflation on medical costs and the rate at which claim professionals close claims. As a result, the effect on reserve estimates of a particular change in assumptions typically cannot be specifically quantified, and changes in these assumptions cannot be tracked over time.

CNA’s recorded reserves are management’s best estimate. In order to provide an indication of the variability associated with CNA’s net reserves, the following discussion provides a sensitivity analysis that shows the approximate estimated impact of variations in significant factors affecting CNA’s reserve estimates for particular types of business. These significant factors are the ones that CNA believes could most likely materially impact the reserves. This discussion covers the major types of business for which CNA believes a material deviation to its reserves is reasonably possible. There can be no assurance that actual experience will be consistent with the current assumptions or with the variation indicated by the discussion. In addition, there can be no assurance that other factors and assumptions will not have a material impact on CNA’s reserves.

Within CNA Specialty, CNA believes a material deviation to its net reserves is reasonably possible for professional liability and related business. This business includes professional liability coverages provided to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and technology firms. This business also includes D&O, employment practices, fiduciary, fidelity and surety coverages, as well as insurance products serving the health care delivery system. The most significant factor affecting reserve estimates for this business is claim severity. Claim severity is driven by the cost of medical care, the cost of wage replacement, legal fees, judicial decisions, legislative changes and other factors. Underwriting and claim handling decisions such as the classes of business written and individual claim settlement decisions can also impact claim severity. If the estimated claim severity increases by 9%, CNA estimates that the net reserves would increase by approximately $500 million. If the estimated claim severity decreases by 3%, CNA estimates that net reserves would decrease by approximately $150 million. CNA’s net reserves for this business were approximately $5.3 billion at December 31, 2012.

Within CNA Commercial, the two types of business for which CNA believes a material deviation to its net reserves is reasonably possible are workers’ compensation and general liability.

For CNA Commercial workers’ compensation, since many years will pass from the time the business is written until all claim payments have been made, claim cost inflation on claim payments is the most significant factor affecting workers’ compensation reserve estimates. Workers’ compensation claim cost inflation is driven by the cost of medical care, the cost of wage replacement, expected claimant lifetimes, judicial decisions, legislative changes and other factors. If estimated workers’ compensation claim cost inflation increases by 100 basis points for the entire period over which claim payments will be made, CNA estimates that its net reserves would increase by approximately $450 million. If estimated workers’ compensation claim cost inflation decreases by 100 basis points for the entire period over which claim payments will be made, CNA estimates that its net reserves would decrease

by approximately $400 million. Net reserves for CNA Commercial workers’ compensation were approximately $4.9 billion at December 31, 2012.

For CNA Commercial general liability, the most significant factor affecting reserve estimates is claim severity. Claim severity is driven by changes in the cost of repairing or replacing property, the cost of medical care, the cost of wage replacement, judicial decisions, legislation and other factors. If the estimated claim severity for general liability increases by 6%, CNA estimates that its net reserves would increase by approximately $250 million. If the estimated claim severity for general liability decreases by 3%, CNA estimates that its net reserves would decrease by approximately $100 million. Net reserves for CNA Commercial general liability were approximately $3.8 billion at December 31, 2012.

Given the factors described above, it is not possible to quantify precisely the ultimate exposure represented by claims and related litigation. As a result, CNA regularly reviews the adequacy of its reserves and reassesses its reserve estimates as historical loss experience develops, additional claims are reported and settled and additional information becomes available in subsequent periods.

In light of the many uncertainties associated with establishing the estimates and making the assumptions necessary to establish reserve levels, CNA reviews its reserve estimates on a regular basis and makes adjustments in the period that the need for such adjustments is determined. These reviews have resulted in CNA’s identification of information and trends that have caused CNA to change its reserves in prior periods and could lead to the identification of a need for additional material increases or decreases in claim and claim adjustment expense reserves, which could materially affect our results of operations and equity and CNA’s business and insurer financial strength and corporate debt ratings positively or negatively. See the Ratings section of this MD&A for further information regarding CNA’s financial strength and corporate debt ratings.

The following table summarizes gross and net carried reserves for CNA’s property and casualty operations:


December 31	2012		2011

(In millions)

Gross Case Reserves	$	8,771	$	8,707
Gross IBNR Reserves		9,824		9,642

Total Gross Carried Claim and Claim Adjustment Expense Reserves	$	18,595	$	18,349


Net Case Reserves	$	7,811	$	7,806
Net IBNR Reserves		8,786		8,607

Total Net Carried Claim and Claim Adjustment Expense Reserves	$	16,597	$	16,413

The following table summarizes the gross and net carried reserves for certain property and casualty business in run-off, including CNA Re and A&EP:


December 31	2012		2011

(In millions)

Gross Case Reserves	$	1,207	$	1,321
Gross IBNR Reserves		1,955		1,808

Total Gross Carried Claim and Claim Adjustment Expense Reserves	$	3,162	$	3,129


Net Case Reserves	$	292	$	347
Net IBNR Reserves		220		244

Total Net Carried Claim and Claim Adjustment Expense Reserves	$	512	$	591

Life & Group Non-Core Policyholder Reserves

CNA calculates and maintains reserves for policyholder claims and benefits for Life & Group Non-Core based on actuarial assumptions. The determination of these reserves is fundamental to its financial results and requires management to make assumptions about expected investment and policyholder experience over the life of the contract. Since many of these contracts may be in force for several decades, these assumptions are subject to significant estimation risk.

The actuarial assumptions represent management’s best estimate at the date the contract was issued plus a margin for adverse deviation. Actuarial assumptions include estimates of morbidity, mortality, policy persistency, discount rates and expenses over the life of the contracts. Under GAAP, these assumptions are locked in throughout the life of the contract unless a premium deficiency develops. The impact of differences between the actuarial assumptions and actual experience is reflected in results of operations each period.

Annually, management assesses the adequacy of its GAAP reserves by product group by performing premium deficiency testing. In this test, reserves computed using best estimate assumptions as of the date of the test without provisions for adverse deviation are compared to the recorded reserves. If reserves determined based on management’s current best estimate assumptions are greater than the existing net GAAP reserves (i.e. reserves net of any Deferred acquisition costs asset), the existing net GAAP reserves are adjusted to the greater amount.

Payout Annuity Reserves

CNA’s payout annuity reserves consist primarily of single premium group and structured settlement annuities. The annuity payments are generally fixed and are either for a specified period or contingent on the survival of the payee. These reserves are discounted except for reserves for loss adjustment expenses on structured settlements not funded by annuities in its property and casualty insurance companies. In 2012 and 2011, CNA recognized a premium deficiency on its payout annuity reserves. Therefore, the actuarial assumptions established at time of issue have been unlocked and updated to management’s then current best estimate. The actuarial assumptions that management believes are subject to the most variability are discount rates and mortality.

The table below summarizes the estimated pretax impact on CNA’s results of operations from various hypothetical revisions to its assumptions. CNA has assumed that revisions to such assumptions would occur in each policy type, age and duration within each policy group. Although such hypothetical revisions are not currently required or anticipated, CNA believes they could occur based on past variances in experience and its expectations of the ranges of future experience that could reasonably occur.


December 31, 2012	Estimated Reduction to Pretax Income

(In millions of dollars)

Hypothetical revisions
Discount rate:
50 basis point decline	$	131
100 basis point decline		277
Mortality:
5% decline		25
10% decline		51

Any actual adjustment would be dependent on the specific policies affected and, therefore, may differ from the estimates summarized above.

Long Term Care Reserves

Long term care policies provide benefits for nursing home, assisted living and home health care subject to various daily and lifetime caps. Policyholders must continue to make periodic premium payments to keep the policy in force. Generally CNA has the ability to increase policy premiums, subject to state regulatory approval.

CNA’s long term care reserves consist of an active life reserve, a liability for due and unpaid claims, claims in the course of settlement and incurred but not reported claims. The active life reserve represents the present value of expected future benefit payments and expenses less expected future premium.

The actuarial assumptions that management believes are subject to the most variability are discount rates, morbidity, and persistency, which can be affected by policy lapses and death. The table below summarizes the estimated pretax impact on CNA’s results of operations from various hypothetical revisions to its assumptions. CNA has assumed that revisions to such assumptions would occur in each policy type, age and duration within each policy group. Although such hypothetical revisions are not currently required or anticipated, CNA believes they could occur based on past variances in experience and its expectations of the ranges of future experience that could reasonably occur.

It should be noted that CNA’s current GAAP long term care reserves contain a level of margin in excess of management’s current best estimates. Any required increase in the net GAAP reserves resulting from the hypothetical revisions in the table below would first reduce the margin before they would affect results of operations. The estimated impact to results of operations in the table below are after consideration of the existing margin.


December 31, 2012	Estimated Reduction to Pretax Income

(In millions of dollars)

Hypothetical revisions
Discount rate:
50 basis point decline	$	491
100 basis point decline		1,221
Morbidity:
5% increase		357
10% increase		869
Persistency:
5% decline in voluntary lapse and mortality		208
10% decline in voluntary lapse and mortality		607

Any actual adjustment would be dependent on the specific policies affected and, therefore, may differ from the estimates summarized above.

The following table summarizes the net carried Life & Group Non-Core policyholder reserves:

December 31, 2012

Claim and claim
adjustment expenses

Future
policy benefits

Policyholders’
funds

Separate
account business

(In millions)

Long term care

1,683

6,879

Payout annuities

637

2,008

Institutional markets

100

312

Other

Total (a)

2,366

8,903

100

312


December 31, 2011	Claim and claim adjustment expenses		Future policy benefits		Policyholders’ funds		Separate account business

(In millions)

Long term care	$	1,470	$	6,374
Payout annuities		660		1,997
Institutional markets		1		15	$	129	$	417
Other		53		5

Total (a)	$	2,184	$	8,391	$	129	$	417

(a)

Reserve amounts are net of $1.3 billion and $1.4 billion of ceded reserves and exclude $1.8 billion and $627 million of future policy benefits relating to Shadow Adjustments as of December 31, 2012 and 2011, as further discussed in Note 1 of the Notes to Consolidated Financial Statements included under Item 8. Reserves at December 31, 2012 and 2011 also exclude $162 million and $95 million of claim and claim adjustment expenses relating to Shadow Adjustments.

Results of Operations

The following table summarizes the results of operations for CNA for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8.


Year Ended December 31	2012			2011			2010

(In millions)

Revenues:
Insurance premiums	$	6,882		$	6,603		$	6,515
Net investment income		2,282			2,054			2,316
Investment gains (losses)		60			(19	)		86
Other		323			325			291

Total		9,547			8,963			9,208


Expenses:
Insurance claims and policyholders’ benefits		5,896			5,489			4,985
Amortization of deferred acquisition costs		1,274			1,176			1,168
Other operating expenses		1,327			1,234			1,777
Interest		170			185			157

Total		8,667			8,084			8,087

Income before income tax		880			879			1,121
Income tax expense		(247	)		(244	)		(335)

Income from continuing operations		633			635			786
Discontinued operations, net								(20)

Net income		633			635			766
Amounts attributable to noncontrolling interests		(63	)		(78	)		(129)

Net income attributable to Loews Corporation	$	570		$	557		$	637

2012 Compared with 2011

Net income increased $13 million in 2012 as compared with 2011. Net investment income increased $228 million, driven by significantly favorable limited partnership results. In addition, investment gains (losses) increased $79 million ($45 million after tax and noncontrolling interests). See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Insurance premiums also increased $279 million, including the acquisition of Hardy. Insurance claims and policyholders’ benefits increased $407 million, primarily due to higher catastrophe impacts, including $171 million (after tax and noncontrolling interests) from Storm Sandy, and decreased favorable net prior year development. Further information on net prior year development for 2012 and 2011 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

2011 Compared with 2010

As further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8, on August, 31, 2010, CNA completed the Loss Portfolio Transfer. We recognized a loss of $328 million (after tax and noncontrolling interests) in the third quarter of 2010, of which $309 million related to our continuing operations and $19 million related to our discontinued operations.

Net income decreased $80 million in 2011 as compared with 2010. Excluding the loss associated with the Loss Portfolio Transfer, net income decreased $408 million in 2011 as compared with 2010. Net investment income decreased $262 million, reflecting significant unfavorable limited partnership results. In addition, investment gains (losses) decreased $105 million ($56 million after tax and noncontrolling interests). See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Partially offsetting these decreases was an $88 million increase in insurance premiums. Insurance claims and policyholders’ benefits increased $504 million, primarily due to a lower level of favorable net prior year development, higher catastrophe losses and decreased results in CNA’s payout annuity business. CNA’s payout annuity business was negatively impacted by a $104 million (after tax and noncontrolling interests) increase in insurance reserves, due to unlocking actuarial reserve assumptions for anticipated adverse changes in mortality and discount rates, which reflect the current low interest rate environment and CNA’s view of expected investment yields, as discussed in Life & Group Non-Core Policyholder Reserves above. Further information on net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

CNA Property and Casualty Insurance Operations

CNA’s property and casualty insurance operations consist of professional, financial, specialty property and casualty products and services and commercial insurance and risk management products.

In evaluating the results of the property and casualty businesses, CNA utilizes the loss ratio, the expense ratio, the dividend ratio and the combined ratio. These ratios are calculated using GAAP financial results. The loss ratio is the percentage of net incurred claim and claim adjustment expenses to net earned premiums. The expense ratio is the percentage of insurance underwriting and acquisition expenses, including the amortization of deferred acquisition costs, to net earned premiums. The dividend ratio is the ratio of policyholders’ dividends incurred to net earned premiums. The combined ratio is the sum of the loss, expense and dividend ratios.

The following table summarizes the results of CNA’s property and casualty operations for the years ended December 31, 2012, 2011 and 2010.

Year Ended December 31, 2012

CNA
Specialty

CNA
Commercial

Hardy

Total

(In millions, except %)

Net written premiums

2,924

3,373

117

6,414

Net earned premiums

2,898

3,306

120

6,324

Net investment income

592

854

1,449

Net operating income (loss)

453

250

(21

)

682

Net realized investment gains

Net income (loss)

465

273

(21

)

717

Ratios:

Loss and loss adjustment expense

63.2

77.9

60.3

70.8%

Expense

31.5

35.3

57.2

34.0

Dividend

0.1

0.3

0.2

Combined

94.8

113.5

117.5

105.0%


Year Ended December 31, 2011	CNA Specialty		CNA Commercial		Total

(In millions, except %)

Net written premiums	$	2,872	$	3,350	$	6,222
Net earned premiums		2,796		3,240		6,036
Net investment income		500		763		1,263
Net operating income		465		333		798
Net realized investment gains (losses)		(3)		10		7
Net income		462		343		805

Ratios:
Loss and loss adjustment expense		59.3%		70.9%		65.5%
Expense		30.7		34.6		32.9
Dividend		(0.1)		0.3		0.1

Combined		89.9%		105.8%		98.5%


Year Ended December 31, 2010


Net written premiums	$	2,691	$	3,208	$	5,899
Net earned premiums		2,679		3,256		5,935
Net investment income		591		873		1,464
Net operating income		561		464		1,025
Net realized investment gains (losses)		18		(14)		4
Net income		579		450		1,029

Ratios:
Loss and loss adjustment expense		54.0%		66.8%		61.0%
Expense		30.6		35.4		33.3
Dividend		0.5		0.4		0.4

Combined		85.1%		102.6%		94.7%

2012 Compared with 2011

Net written premiums increased $192 million in 2012 as compared with 2011. Net written premiums for 2012 included $117 million related to Hardy and for 2011 included $128 million related to First Insurance Company of Hawaii (“FICOH”). Excluding Hardy and FICOH, the increase in net written premiums was primarily driven by positive rate achievement, partially offset by lower new business levels in certain lines in CNA Specialty. Net earned premiums increased $288 million in 2012 as compared with 2011, including $120 million related to Hardy during 2012 and $125 million related to FICOH during 2011. Excluding Hardy and FICOH, the increase in net earned premiums was consistent with increases in net written premiums and the impact of favorable premium development in CNA Commercial in 2012 as compared to unfavorable premium development in 2011.

The CNA Specialty average rate increased 5% in 2012 as compared to flat average rate in 2011 for the policies that renewed in each period. Retention of 86% and 87% was achieved in each period. The CNA Commercial average rate increased 7% in 2012 as compared with an increase of 2% in 2011 for the policies that renewed in each period. Retention of 78% was achieved in each period.

Net operating income decreased $116 million in 2012 as compared to 2011. The decrease in net operating income was primarily due to lower favorable net prior year development, higher catastrophe losses for CNA Commercial and decreased current accident year underwriting results in CNA Specialty. These unfavorable impacts were partially offset by higher net investment income and the inclusion of the Surety business on a wholly owned basis in 2012 for CNA Specialty. Catastrophe losses were $243 million (after tax and noncontrolling interests) in 2012 as compared to $130 million (after tax and noncontrolling interests) in 2011.

The combined ratio increased 6.5 points in 2012 as compared to 2011. The loss ratio increased 5.3 points in 2012 as compared to 2011, primarily due to higher catastrophe losses in CNA Commercial, lower favorable net prior year development and a higher current accident year loss ratio. The expense ratio increased by 1.1 points, primarily due to the favorable impact of recoveries in 2011 on insurance receivables written off in prior years in CNA Commercial and increased acquisition and underwriting expenses in CNA Specialty.

Favorable net prior year development decreased by $189 million, from $428 million in 2011 to $239 million in 2012. Further information on net prior year development for 2012 and 2011 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

2011 Compared with 2010

Net written premiums increased $323 million in 2011 as compared with 2010, primarily driven by new business, positive rate achievement in CNA Commercial, improved economic conditions reflected in insured exposures, as well as lower reinsurance costs. Net earned premiums increased $101 million in 2011 as compared with 2010, consistent with increases in net written premiums over recent quarters and favorable premium development in CNA Specialty, partially offset by unfavorable premium development in CNA Commercial.

The average rate for CNA Specialty was flat for 2011 as compared to a decrease of 2% in 2010 for the policies that renewed in each period. Retention of 87% and 86% was achieved in each period. The average rate for CNA Commercial increased 2% in 2011 as compared with an increase of 1% in 2010 for the policies that renewed in each period. Retention of 78% and 80% was achieved in each period.

Net operating income decreased $227 million in 2011 as compared to 2010 primarily due to lower net investment income, higher catastrophe losses and lower favorable net prior year development. Catastrophe losses were $130 million (after tax and noncontrolling interests) in 2011 as compared to $71 million (after tax and noncontrolling interests) in 2010.

The combined ratio increased 3.8 points in 2011 as compared to 2010. The loss ratio increased 4.5 points in 2011 as compared to 2010, primarily due to lower favorable net prior year development and higher catastrophe losses. The expense ratio improved by 0.4 points, primarily due to the favorable impact of recoveries in 2011 on insurance receivables written off in prior years in CNA Commercial.

Favorable net prior year development decreased by $172 million, from $600 million in 2010 to $428 million in 2011. Further information on net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

Life & Group Non-Core and Other Operations

Life & Group Non-Core primarily includes the results of the life and group lines of business that are in run-off. Other primarily includes certain CNA corporate expenses, including interest on corporate debt and the results of certain property and casualty business in run-off, including CNA Re and A&EP. In 2010, CNA ceded substantially all of its legacy A&EP liabilities under the Loss Portfolio Transfer, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

The following table summarizes the results of CNA’s Life & Group Non-Core and Other operations for the years ended December 31, 2012, 2011 and 2010.


Year Ended December 31, 2012	Life & Group Non-Core		Other			Total

(In millions)

Net earned premiums	$	560				$	560
Net investment income		801	$	32			833
Net loss		(81)		(66	)		(147)

Year Ended December 31, 2011


Net earned premiums	$	569				$	569
Net investment income		759	$	32			791
Net operating loss		(187)		(44	)		(231)
Net realized investment losses		(4)		(13	)		(17)
Net loss		(191)		(57	)		(248)

Year Ended December 31, 2010


Net earned premiums	$	582				$	582
Net investment income		715	$	137			852
Net operating loss		(81)		(334	)		(415)
Net realized investment gains		30		12			42
Net loss		(51)		(322	)		(373)

2012 Compared with 2011

Net earned premiums, which relate primarily to the individual and group long term care businesses, decreased $9 million in 2012 as compared with 2011, primarily due to lapsing of policies in CNA’s individual long term care business, which is in run-off, partially offset by increased premiums resulting from rate increase actions related to this business.

Net loss decreased $101 million in 2012 as compared with 2011. The results include expenses of $22 million (after tax and noncontrolling interests) in 2012 and $104 million (after tax and noncontrolling interests) in 2011 related to CNA’s payout annuity business, due to unlocking actuarial reserve assumptions. The initial reserving assumptions for these contracts were determined at issuance, including a margin for adverse deviation, and were locked in throughout the life of the contract unless a premium deficiency developed. The increase to the related reserves in 2012 related to anticipated adverse changes in discount rates, which reflect the current low interest rate environment and CNA’s view of expected future investment yields. The increase in 2011 related to anticipated adverse changes in mortality and discount rates. Additionally, long term care claim reserves were increased $18 million (after tax and noncontrolling interests) in 2012 and $30 million (after tax and noncontrolling interests) in 2011.

The decrease in net loss was also driven by improved results in Life & Group Non-Core life settlement contracts business and the impact of unfavorable performance in 2011 on its remaining pension deposit business.

2011 Compared with 2010

Net earned premiums, which relate primarily to the individual and group long term care businesses, decreased $13 million in 2011 as compared with 2010.

Net loss decreased $125 million in 2011 as compared with 2010, primarily driven by the loss of $328 million (after tax and noncontrolling interests) as a result of the Loss Portfolio Transfer consummated in the third quarter of 2010. As a result of that transaction, the investment income allocated to Other decreased substantially because of the lower net reserve base and associated risk capital.

These net loss decreases were partially offset by net loss increases in CNA’s payout annuity, pension deposit and long term care businesses. In 2011, CNA’s payout annuity business was negatively impacted by a $104 million (after tax and noncontrolling interests) increase in insurance reserves, as discussed above. In 2010, CNA’s payout annuity reserves were increased by $35 million (after tax and noncontrolling interests), resulting from unlocking assumptions. Additionally, long term care claim reserves were increased by $30 million (after tax and noncontrolling interests) in 2011.

A number of CNA’s separate account pension deposit contracts guarantee principal and an annual minimum rate of interest. If aggregate contract value in the separate account exceeds the fair value of the related assets, an additional Policyholders’ funds liability is established. In 2011, CNA increased this pretax liability by $18 million. In 2010, CNA decreased this pretax liability by $24 million.

Diamond Offshore

Diamond Offshore’s operating income is primarily a function of contract drilling revenue earned less contract drilling expenses incurred or recognized. The two most significant variables affecting Diamond Offshore’s revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. These factors are not within Diamond Offshore’s control and are difficult to predict. Revenue from dayrate drilling contracts are generally recognized as services are performed, consequently, when a rig is idle, no dayrate is earned and revenue will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, Diamond Offshore may receive fees for the mobilization of equipment. In addition, some of Diamond Offshore’s drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which it may be compensated.

Diamond Offshore’s operating income is also a function of varying levels of operating expenses. Operating expenses generally are not affected by changes in dayrates, and short term reductions in utilization do not necessarily result in lower operating expenses. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “warm stacked” state with a full crew. In addition, when a rig is idle, Diamond Offshore is responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, Diamond Offshore may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income.

Operating expenses represent all direct and indirect costs associated with the operation and maintenance of Diamond Offshore’s drilling equipment. The principal components of Diamond Offshore’s operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of Diamond Offshore’s operating expenses. In general, labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which Diamond Offshore’s rigs operate. In addition, the costs associated with training new and seasoned employees can be significant. Diamond Offshore expects its labor and training costs to increase in 2013 as a result of increased hiring and training activities as it continues the process of crewing its four new drillships. Costs to repair and maintain equipment fluctuate depending upon the type of activity the drilling rig is performing, as well as the age and condition of the equipment and the regions in which Diamond Offshore’s rigs are working.

Operating income is negatively impacted when Diamond Offshore performs certain regulatory inspections, which it refers to as a 5-year survey, or special survey, that are due every five years for each of Diamond Offshore’s rigs. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs which are recognized as incurred. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.

In addition, operating income may also be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs located in the United Kingdom (“U.K.”) and Norwegian sectors of the North Sea.

As a result of anticipated downtime in the current year for rig mobilizations, regulatory surveys and shipyard projects, Diamond Offshore expects contract drilling revenue in 2013 to decline from the levels attained in 2012. During 2013, 11 of Diamond Offshore’s rigs will require 5-year surveys and one of its U.K. rigs will require dry-docking for inspections. These 12 rigs will be out of service for approximately 830 days in the aggregate. Diamond Offshore also expects to spend an additional approximately 590 days during 2013 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects, including contract preparation work for the Ocean Endeavor and North Sea enhancements for the Ocean Patriot, each of which is expected to require approximately 180 days of downtime. Diamond Offshore can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects.

Diamond Offshore is self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to Diamond Offshore’s rigs or equipment, it could have a material adverse effect on its financial condition, results of operations and cash flows. Under its insurance policy that expires on May 1, 2013, Diamond Offshore carries physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which its deductible for physical damage is $25 million per occurrence. Diamond Offshore does not typically retain loss-of-hire insurance policies to cover its rigs.

In addition, under its current insurance policy, Diamond Offshore carries marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. Diamond Offshore believes that the policy limit for its marine liability insurance is within the range that is customary for companies of its size in the offshore drilling industry and is appropriate for Diamond Offshore’s business. Diamond Offshore’s deductibles for marine liability coverage, including for personal injury claims, are $10 million for the first occurrence and vary in amounts ranging between $5 million and, if aggregate claims exceed certain thresholds, up to $100 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year.

Recent Developments

Internationally, the ultra-deepwater and deepwater floater markets are generally strong and continue to show signs of further strengthening, particularly for ultra-deepwater rigs where there are reportedly few, if any, uncontracted rigs available to work in 2013, inclusive of the expected 2013 newbuild deliveries, with the market expected to remain strong throughout 2013. Diamond Offshore believes that the diminished availability of rigs in this market could continue to put upward pressure on dayrates during 2013. However, due to its contracted backlog in 2013 (100% and 92% for its ultra-deepwater and deepwater fleets), Diamond Offshore has limited availability in this market and may not be able to benefit from higher price fixtures during that period. Newbuild orders for ultra-deepwater and deepwater floaters continued to be placed in 2012, including Diamond Offshore’s order for a fourth drillship and a semisubmersible rig, both of which are currently under construction. Based on recent analyst data, there are 67 floater rigs, primarily ultra-deepwater and deepwater units, on order or under construction, excluding an estimated 29 rigs to be built on behalf of Petróleo Brasileiro S.A., (“Petrobras”), which is currently Diamond Offshore’s most significant customer. Excluding Petrobras’ ordered rigs, nearly 73% of the floaters scheduled for delivery in 2014 and beyond are not yet contracted for future work, including two of Diamond Offshore’s drillships and one of its semisubmersible rigs under construction. In addition, Petrobras has recently announced that it plans to cap the number of its contracted deepwater rigs beginning in 2016. According to industry analysts, they believe Petrobras intends to fill the majority of its deepwater requirement with its own rigs, which are not yet under construction but which are scheduled for delivery in 2015 and beyond, although industry analysts believe that this timing may be delayed due to current Brazilian shipyard limitations. If imposed by Petrobras, this limit on the

number of contracted rigs could lead to additional availability and increased competition in the deepwater market in the future.

Market demand for mid-water floaters is generally stable and is also strengthening in certain geographic markets. In both the U.K. and Norway sectors of the North Sea, the mid-water market is very strong with industry analysts predicting the next availability of rigs in late 2013. A 2012 discovery offshore Norway has resulted in increased interest in the harsh North Sea region, where there is a limited number of rigs capable of working and the barriers to entry are high, primarily due to significant rig modifications necessary to operate in the region. In February of 2013, Diamond Offshore announced its plan to upgrade one of its mid-water floaters for North Sea operations, with a minimum three-year contract for the upgraded rig in the U.K. sector of the North Sea beginning in 2014. In the Mediterranean region, demand remains solid, including the Black Sea region where recent gas discoveries have led to increased interest in the region. The Southeast Asia and Australia markets also remain steady with indications of possible strengthening.

Four of Diamond Offshore’s marketed jack-up rigs are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing. Diamond Offshore’s other international jack-up commenced a two year bareboat charter offshore Ecuador in 2012. During 2012, Diamond Offshore sold six jack-up rigs, resulting in a pretax gain of approximately $76 million.

Drilling activity on the Outer Continental Shelf of the GOM has continued to strengthen and has surpassed pre-Macondo levels. Additionally, some industry analysts predict that drilling activity, particularly in the ultra-deepwater market, will continue to strengthen in 2013 and beyond. However, Diamond Offshore’s ability to meet this demand is limited in the near term. Diamond Offshore currently has two semisubmersible rigs on contract in the GOM, one of which is expected to have limited availability in the second half of 2013. It also has one mid-water floater and one jack-up rig there available for contract. Looking forward, Diamond Offshore’s two ultra-deepwater drillships as well as one semisubmersible rig under construction which are scheduled for delivery in 2014, none of which have been contracted and could be positioned in this market. The Ocean Onyx which is currently under construction, is expected to commence a one-year contract plus potential option periods in the GOM during the third quarter of 2013.

Contract Drilling Backlog

The following table reflects Diamond Offshore’s contract drilling backlog as of February 1, 2013, October 17, 2012 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012) and February 1, 2012 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2011). Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Diamond Offshore’s calculation also assumes full utilization of its drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92% – 98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in Diamond Offshore’s contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.


	February 1, 2013		October 17, 2012		February 1, 2012

(In millions)

Floaters:
Ultra-Deepwater (a)	$	4,422	$	4,660	$	4,926
Deepwater (b)		1,229		1,373		1,081
Mid-Water (c)		2,649		2,510		2,348

Total Floaters		8,300		8,543		8,355
Jack-ups		272		203		277

Total	$	8,572	$	8,746	$	8,632

(a)	As of February 1, 2013, for ultra-deepwater floaters includes (i) $1.3 billion attributable to contracted operations offshore Brazil for the years 2013 to 2015 and (ii) $1.8 billion attributable to future work for two drillships under construction for the years 2013 to 2019.

(b)	As of February 1, 2013, for deepwater floaters includes (i) $563 million attributable to contracted operations offshore Brazil for the years 2013 to 2016 and (ii) $179 million for the years 2013 to 2014 attributable to future work for the Ocean Onyx, which is under construction.

(c)	As of February 1, 2013, for mid-water floaters includes $880 million attributable to contracted operations offshore Brazil for the years 2013 to 2015.

The following table reflects the amount of Diamond Offshore’s contract drilling backlog by year as of February 1, 2013:

Year Ended December 31

Total

2013

2014

2015

2016 – 2019

(In millions)

Floaters:

Ultra-Deepwater (a)

4,422

979

1,223

996

1,224

Deepwater (b)

1,229

569

456

142

Mid-Water (c)

2,649

1,106

955

408

180

Total Floaters

8,300

2,654

2,634

1,546

1,466

Jack-ups

272

140

Total

8,572

2,794

2,706

1,594

1,478

(a)

As of February 1, 2013, for ultra-deepwater floaters includes (i) $524 million, $473 million and $324 million for the years 2013 to 2015, attributable to contracted operations offshore Brazil and (ii) $29 million, $299 million and $361 million for the years 2013 to 2015, and $1.1 billion in the aggregate for the years 2016 to 2019, attributable to future work for two drillships under construction.

(b)

As of February 1, 2013, for deepwater floaters includes (i) $218 million, $149 million, $134 million and $62 million for the years 2013 to 2016, attributable to contracted operations offshore Brazil and (ii) $45 million and $134 million for the years 2013 and 2014, attributable to future work for the Ocean Onyx, which is under construction.

(c)	As of February 1, 2013, for mid-water floaters includes $456 million, $342 million and $82 million for the years 2013 to 2015, attributable to contracted operations offshore Brazil.

The following table reflects the percentage of rig days committed by year as of February 1, 2013. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in Diamond Offshore’s fleet, to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected final commissioning dates for rigs under construction.


Year Ended December 31	2013 (a)		2014 (a)		2015 (a)		2016 - 2019


Floaters:
Ultra-Deepwater		100%		86%		57%		14%
Deepwater		92%		44%		15%		2%
Mid-Water		72%		50%		18%		2%
Total Floaters		83%		60%		30%		6%
Jack-ups		69%		39%		20%		1%

(a)	As of February 1, 2013, includes approximately 1,540, 660 and 140 currently known, scheduled shipyard, survey and mobilization days for 2013, 2014 and 2015.

Dayrate and Utilization Statistics


Year Ended December 31	2012		2011		2010


Revenue earning days (a)
Floaters:
Ultra-Deepwater		2,475		2,387		1,873
Deepwater		1,605		1,718		1,342
Mid-Water		4,639		5,254		5,800
Jack-ups (b)		1,753		2,218		3,028

Utilization (c)
Floaters:
Ultra-Deepwater		85%		82%		66%
Deepwater		88%		94%		74%
Mid-Water		68%		72%		79%
Jack-ups (d)		53%		47%		61%

Average daily revenue (e)
Floaters:
Ultra-Deepwater	$	354,900	$	342,900	$	358,400
Deepwater		368,800		416,500		401,900
Mid-Water		263,600		269,600		281,000
Jack-ups		90,200		81,900		87,700

(a)	A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

(b)	Revenue earning days for the years ended December 31, 2012, 2011 and 2010 included approximately 87 days, 720 days and 1,167 days, earned by Diamond Offshore’s jack-up rigs during the respective periods prior to being sold in 2012 and 2010.

(c)	Utilization is calculated as the ratio of total revenue earnings days divided by the total calendar days in the period for all rigs in Diamond Offshore’s fleet (including cold stacked rigs).

(d)	Utilization for Diamond Offshore’s jack-up rigs would have been 87%, 59% and 73% for the years ended December 31, 2012, 2011 and 2010, excluding revenue earning days and total calendar days associated with rigs that were sold in 2012 and 2010.

(e)	Average daily revenue is defined as contract drilling revenue (excluding revenue for mobilization, demobilization and contract preparation) per revenue earning day.

Results of Operations

The following table summarizes the results of operations for Diamond Offshore for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:


Year Ended December 31	2012			2011			2010

(In millions)

Revenues:
Contract drilling revenues	$	2,936		$	3,254		$	3,230
Net investment income		5			7			3
Investment gains					1
Other		131			73			128

Total		3,072			3,335			3,361


Expenses:
Contract drilling expenses		1,537			1,549			1,391
Other operating expenses		572			535			546
Interest		46			73			91

Total		2,155			2,157			2,028

Income before income tax		917			1,178			1,333
Income tax expense		(223	)		(250	)		(413)
Amounts attributable to noncontrolling interests		(357	)		(477	)		(474)

Net income attributable to Loews Corporation	$	337		$	451		$	446

2012 Compared with 2011

Contract drilling revenue decreased $318 million and net income decreased $114 million in 2012 as compared with 2011. Contract drilling revenue for 2012 was negatively impacted by a decrease in both revenue earning days and average daily revenue earned by Diamond Offshore’s deepwater and mid-water floaters, partially offset by favorable revenue variances for its ultra-deepwater floaters. Contract drilling expense decreased $12 million primarily due to a decrease in expense for mid-water floaters and jack-ups due to the movement of certain rigs to other operating regions with lower cost structures, lower repair and inspection costs, as well as the absence of operating costs in 2012 for the recently sold jack-up rigs. The decrease in contract drilling expense was partially offset by an increase in costs associated with ultra-deepwater and deepwater floaters, primarily due to higher personnel related, inspection and shorebase support costs in 2012.

Revenue generated by ultra-deepwater floaters increased $61 million in 2012 as compared with 2011, primarily due to increased average daily revenue of $30 million and increased utilization of $30 million due to higher revenue earning days. The increase in average daily revenue is primarily due to higher dayrates earned by the Ocean Monarch operating internationally during 2012 compared with the rig operating in the GOM in 2011. The increase in revenue earning days is primarily due to downtime associated with the Ocean Monarch in 2011, partially offset by a decrease in revenue earning days in 2012 for other ultra-deepwater rigs as a result of scheduled surveys and shipyard projects as well as unscheduled downtime for repairs in 2012.

Revenue generated by deepwater floaters decreased $135 million in 2012 as compared with 2011, primarily due to a $76 million decrease in average daily revenue, a $47 million decrease in utilization as a result of fewer revenue earning days and a $12 million decrease in amortized mobilization fees. The decline in average daily revenue during 2012 is primarily due to the completion of the Ocean Valiant’s contract in Angola in December of 2011 which was at a significantly higher dayrate than the rig earned during 2012. The decrease in utilization during 2012 is primarily due to higher incremental downtime for shipyard projects and inspections as compared with 2011.

Revenue generated by mid-water floaters decreased $207 million in 2012 as compared with 2011, primarily due to a $166 million decrease in utilization, a $28 million decrease in average daily revenue and a $13 million decrease in amortized mobilization fees. Revenue earning days decreased by 615, primarily attributable to planned downtime

for mobilization and shipyard projects, unplanned downtime for repairs, the warm stacking of rigs between contracts and additional days a rig was cold-stacked.

Revenue generated by jack-up rigs decreased $37 million in 2012 as compared with 2011, primarily due to the sale of six jack-up rigs in 2012, three of which operated during 2011.

Net income decreased in 2012 as compared with 2011 reflecting a decline in revenue and a $19 million impairment loss (after tax and noncontrolling interests) on three mid-water floaters which are expected to be disposed of in 2013. Net income for 2012 included a $32 million gain (after tax and noncontrolling interests) on the sale of six jack-up rigs. In addition, interest expense decreased $27 million in 2012 as compared with 2011 primarily due to incremental interest costs capitalized during 2012 related to the continuing rig construction projects.

Diamond Offshore’s annual effective tax rate for 2012 increased as compared with 2011. The higher effective tax rate in 2012 is primarily the result of differences in the mix of Diamond Offshore’s domestic and international pre-tax earnings and losses, the mix of international tax jurisdictions in which Diamond Offshore operates and the impact of a tax law provision that expired at the end of 2011. This provision allowed Diamond Offshore to defer recognition of certain foreign earnings for U.S. tax purposes during 2011, which deferral was unavailable in 2012. Diamond Offshore’s 2011 tax expense also included the reversal of $15 million of U.S. income tax expense, originally recognized in 2010, related to Diamond Offshore’s intention at that time to repatriate certain foreign earnings which changed in 2011 subsequent to its decision to build new drillships overseas.

The American Taxpayer Relief Act of 2012, or the Act, was signed into law on January 2, 2013. The Act extends through 2013 several expired or expiring temporary business provisions which are retroactively extended to the beginning of 2012. One of the extenders will again allow Diamond Offshore to defer recognition of certain foreign earnings for U.S. tax purposes. As required by GAAP, the effects of new legislation are recognized when signed into law. Consequently, Diamond Offshore expects to reduce its first quarter 2013 tax expense by approximately $28 million as a result of recognizing the 2012 effect of the extenders.

As Diamond Offshore’s rigs frequently operate in different tax jurisdictions as they move from contract to contract, its effective tax rate can fluctuate substantially and its historical effective tax rates may not be sustainable and could increase materially.

2011 Compared with 2010

Contract drilling revenue increased $24 million and net income increased $5 million in 2011 as compared with 2010. Revenue generated by Diamond Offshore’s floater rigs increased an aggregate $95 million in 2011 as compared with 2010, while revenue generated by its jack-up fleet declined $71 million. Except for Diamond Offshore’s deepwater floaters, average daily revenue earned by its other rigs decreased during 2011 compared to the levels attained in 2010. Utilization for ultra-deepwater and deepwater floaters increased significantly in 2011 as compared with 2010; however, utilization for mid-water floater and jack-up fleets decreased in 2011. One additional mid-water floater and one jack-up rig were cold stacked during 2011. The Ocean Courage and Ocean Valor, which began operating under contract late in the first quarter and in the fourth quarter of 2010, contributed incremental revenue of $162 million during 2011. Total contract drilling expense increased $158 million during 2011 as compared with 2010, reflecting incremental contract drilling expense for the Ocean Courage and Ocean Valor, higher amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.

Revenue from ultra-deepwater floaters increased $123 million in 2011 as compared with 2010, primarily due to increased utilization of $184 million, partially offset by a decrease in average daily revenue of $36 million and the receipt of a $31 million contract termination fee in 2010. Revenue earning days increased primarily due to the two new ultra-deepwater floaters which were under contract in Brazil for all of 2011 generating $162 million in incremental revenue. However, aggregate revenue earned by Diamond Offshore’s six other ultra-deepwater rigs decreased $39 million due to a lower average daily revenue earned, partially offset by an increase in revenue earning days due to downtime in 2010 associated with the relocation of three rigs from the GOM to international locations.

Revenue from deepwater floaters increased $169 million in 2011 as compared with 2010. This increase was primarily due to a $152 million increase in utilization and a $25 million increase in average daily revenue, partially offset by an $8 million decrease in amortized mobilization fees. Revenue earning days increased in 2011, primarily due to fewer non-operating days for repairs, inspections and contract preparation activities as compared to 2010.

Revenue from mid-water floaters decreased $197 million in 2011 as compared with 2010, primarily due to decreased utilization of $153 million, decreased average daily revenue of $59 million and decreased amortized mobilization fees of $9 million, partially offset by a $24 million demobilization fee received in relation to the Ocean Yorktown’s completion of its contract offshore Brazil. Revenue earning days decreased by 546, primarily attributable to additional cold stacked days in 2011 compared to 2010, partially offset by less warm stacked days between contracts.

Revenue from jack-up rigs decreased $71 million in 2011 as compared with 2010, primarily due to decreased utilization of $71 million and decreased average daily revenue of $13 million, partially offset by a $13 million increase in amortized mobilization fees. Revenue earning days decreased by 810, reflecting the impact of cold stacking rigs during the period, the sale of the Ocean Shield in July 2010 and an increase in warm stacked days in between contracts, partially offset by a decrease in the number of non-revenue earning days for repairs and mobilization of rigs.

Net income increased in 2011 as compared with 2010, primarily due to the changes in contract drilling revenue and expense discussed above. In addition, interest expense decreased $18 million, primarily due to interest capitalized in 2011 on Diamond Offshore’s three drillships under construction at that time. In 2010, Diamond Offshore recognized a pretax gain of $33 million related to the sale of the Ocean Shield.

Diamond Offshore’s annual effective tax rate decreased in 2011 as compared with 2010. The lower effective tax rate in the current year is primarily the result of differences in the mix of Diamond Offshore’s domestic and international pretax earnings and losses, as well as the mix of international tax jurisdictions in which Diamond Offshore operates. Also contributing to the lower effective tax rate in 2011 was the impact of a tax law provision that expired at the end of 2009 but was subsequently signed back into law in December 2010. This provision allowed Diamond Offshore to defer recognition of certain foreign earnings for U.S. income tax purposes. The extension of this tax law provision, and Diamond Offshore’s decisions to build three new drillships overseas caused Diamond Offshore to reassess its intent to repatriate certain foreign earnings to the U.S. It is now Diamond Offshore’s intent to reinvest those earnings internationally. Consequently, Diamond Offshore is no longer providing taxes on those foreign earnings and has reversed previously accrued taxes related to those earnings.

Boardwalk Pipeline

Boardwalk Pipeline derives revenues primarily from the transportation and storage of natural gas and natural gas liquids (“NGLs”) and gathering and processing of natural gas for third parties. Transportation services consist of firm natural gas transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, whereby the customer pays to transport gas only when capacity is available and used. Boardwalk Pipeline offers firm natural gas storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (“PAL”) services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement. Boardwalk Pipeline’s NGL contracts are generally fee-based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. NGL storage rates are market based rates and contracts are typically fixed-price arrangements with escalation clauses. Boardwalk Pipeline is not in the business of buying and selling natural gas and NGLs other than for system management purposes, but changes in the level of natural gas and NGL prices may impact the volumes of gas transported and stored on its pipeline systems. Boardwalk Pipeline’s operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at its compressor stations.

The amount of natural gas being produced from unconventional natural gas production areas has greatly increased in recent years. This dynamic drove the pipeline industry, including Boardwalk Pipeline, to construct substantial new pipeline infrastructure to support this development. However, the oversupply of gas from these and other production areas has resulted in gas prices that are substantially lower than in recent years, which has caused producers to scale back production to levels below those that were expected when the new infrastructure was built. In addition, certain of these new supply basins, such as the Marcellus and Utica Shale plays, are closer to the traditional high value markets served by interstate pipelines like Boardwalk Pipeline, a development that has further affected how natural gas moves across the interstate pipeline grid. These factors have led to increased competition in certain pipeline markets, as well as substantially narrower price differentials than previous years between producing/supply areas and market areas (basis spreads), which has put significant downward pressure on pricing for both firm and interruptible transportation capacity that Boardwalk Pipeline is currently marketing. Boardwalk Pipeline does not expect basis spreads on its system to improve in the current year.

As of December 31, 2012, a substantial portion of Boardwalk Pipeline’s transportation capacity was contracted for under firm transportation agreements having a weighted-average remaining life of approximately 6.0 years. However, each year a portion of Boardwalk Pipeline’s firm transportation agreements expire and must be renewed or replaced. Boardwalk Pipeline renewed or replaced contracts for most of the firm transportation capacity that expired in 2012, though on average at lower rates. The amount of contracted transportation capacity which will expire in 2013 is greater than in recent years. In light of the market conditions discussed above, Boardwalk Pipeline expects that transportation contracts renewed or entered into in 2013 will be at lower rates than expiring contracts. Remaining available capacity will be marketed and sold on a short term firm or interruptible basis, which will also be at lower rates based on current market conditions. Boardwalk Pipeline expects that these circumstances will negatively affect transportation revenues and distributable cash flows in 2013.

The market for storage and PAL services is also impacted by the factors discussed above, as well as by natural gas price differentials between time periods, such as winter to summer (time period price spreads). Time period price spreads declined from 2010 to 2011 and improved in the first half of 2012; however, Boardwalk Pipeline believes that current forward pricing curves indicate that the spreads for 2013 may not be as favorable. Forward pricing curves change frequently as a result of a variety of market factors, including weather, levels of storage gas and available capacity, among others and as such may not be a reliable predictor of actual future events. Accordingly, Boardwalk Pipeline cannot predict its future revenues from interruptible storage and PAL services due to the uncertainty and volatility in market conditions discussed above.

Results of Operations

The following table summarizes the results of operations for Boardwalk Pipeline for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:


Year Ended December 31	2012			2011			2010

(In millions)

Revenues:
Other revenue, primarily operating	$	1,187		$	1,144		$	1,128
Net investment income								1
Investment losses		(3	)

Total		1,184			1,144			1,129


Expenses:
Operating		717			760			695
Interest		166			173			151

Total		883			933			846

Income before income tax		301			211			283
Income tax expense		(70	)		(57	)		(73)
Amounts attributable to noncontrolling interests		(122	)		(77	)		(96)

Net income attributable to Loews Corporation	$	109		$	77		$	114

2012 Compared with 2011

Total revenues increased $40 million in 2012 as compared with 2011, primarily due to $63 million of revenues earned by Boardwalk HP Storage Company, LLC (“HP Storage”), acquired in December of 2011, and Boardwalk Louisiana Midstream LLC (“Louisiana Midstream”), acquired in October of 2012, and higher PAL and storage revenues of $14 million resulting from improved market conditions. The increase in revenues was partially offset by a decrease in retained fuel of $34 million primarily due to lower natural gas prices.

Operating expenses decreased $43 million in 2012 as compared with 2011. The primary drivers of the decrease were charges incurred in 2011 including a $29 million impairment charge associated with Boardwalk Pipeline’s materials and supplies, an expense of $5 million representing an insurance deductible associated with replacing compressor assets and $4 million of gas losses associated with the Bistineau storage facility. In addition, in the 2012 period there were lower fuel costs of $21 million due to lower natural gas prices, lower general and administrative expenses of $16 million as a result of cost management activities and lower operation and maintenance expenses of $11 million primarily from lower maintenance project costs and outside services. These decreases were partially offset by $38 million of expenses incurred by HP Storage and Louisiana Midstream and $9 million of asset impairment charges. The 2011 period included a gain of $9 million from the sale of storage gas. Interest expense decreased $7 million for 2012, primarily from a charge recorded in 2011 on the early extinguishment of debt, partially offset by increased debt levels and higher average interest rates.

2011 Compared with 2010

Total revenues increased $15 million in 2011 as compared with 2010. Gas transportation revenues, excluding fuel, increased $61 million primarily from increased capacities resulting from the completion of several compression projects in 2010, operating the Fayetteville Lateral at its design capacity and the acquisition of HP Storage. PAL and storage revenues decreased $19 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods and fuel retained decreased $16 million primarily due to lower natural gas prices.

Operating expenses increased $65 million in 2011 as compared with 2010. The increase includes a $29 million impairment charge associated with Boardwalk Pipeline’s materials and supplies, most of which was subsequently sold. There were also higher operation and maintenance expenses of $18 million primarily due to maintenance projects for pipeline integrity management and reliability spending and lower amounts of labor capitalized from fewer growth projects and higher depreciation and property taxes of $12 million associated with an increase in the asset base. These increases were partially offset by lower fuel consumed of $9 million primarily due to lower natural gas prices. Interest expense increased by $22 million in 2011, primarily from a $13 million charge on the early extinguishment of debt and $8 million resulting from higher average interest rates on Boardwalk Pipeline’s long term debt and lower capitalized interest.

HighMount

We use the following terms throughout this discussion of HighMount’s results of operations, with “equivalent” volumes computed with oil and NGL quantities converted to Mcf, on an energy equivalent ratio of one barrel to six Mcf:


Bbl	-	Barrel (of oil or NGLs)
Bcf	-	Billion cubic feet (of natural gas)
Bcfe	-	Billion cubic feet of natural gas equivalent
Mbbl	-	Thousand barrels (of oil or NGLs)
Mcf	-	Thousand cubic feet (of natural gas)
Mcfe	-	Thousand cubic feet of natural gas equivalent
MMBtu	-	Million British thermal units

HighMount’s revenues and profitability depend substantially on natural gas and oil prices and HighMount’s ability to increase its natural gas and oil production. For the period July 2008 through December 2012, NYMEX natural gas contract settlement prices have ranged from a high of $13.11 in July 2008 to a low of $2.04 in May 2012. This price decline is reflective of an increase in the supply of natural gas resulting from new sources of supply

recoverable from shale formations, primarily the result of technological advancements in horizontal drilling and hydraulic fracturing. As a result of the decline in natural gas prices, HighMount changed its drilling program in 2011 to develop properties that produce primarily oil and natural gas liquids to benefit from the higher prices for these commodities. During 2012, NGL prices declined significantly and as a result HighMount reduced its overall drilling program and focused its capital investments primarily on oil producing properties. The reduced natural gas and NGL prices, as well as the increased drilling costs developing HighMount’s oil reserves negatively impacted HighMount’s net cash flow. Revenues from the sale of NGL and oil, including the impact of hedges, amounted to 46% of HighMount’s total revenues for the year ended December 31, 2012 as compared to 34% of its total revenue for the year ended December 31, 2011. The price HighMount realizes for its production is also affected by HighMount’s hedging activities, as well as locational differences in market prices. As a result of ceiling test impairment charges recorded in 2012 which were primarily due to significant declines in natural gas and NGL prices, HighMount performed quarterly goodwill impairment tests and no impairment charges were required.

HighMount’s operating expenses consist primarily of production expenses, production and ad valorem taxes, as well as depreciation, depletion and amortization (“DD&A”) expenses. Production expenses represent costs incurred to operate and maintain wells, related equipment and facilities and transportation costs. Production and ad valorem taxes increase or decrease primarily when prices of natural gas and oil increase or decrease, but they are also affected by changes in production and state incentive programs, as well as appreciated property values. HighMount calculates depletion using the units-of-production method, which depletes the capitalized costs and future development costs associated with evaluated properties based on the ratio of production volumes for the current period to total remaining reserve volumes for the evaluated properties. HighMount’s depletion expense is affected by its capital spending program and projected future development costs, as well as reserve changes resulting from drilling programs, well performance and revisions due to changing commodity prices.

Production and Sales Statistics

Presented below are production and sales statistics related to HighMount’s operations for 2012, 2011 and 2010:


Year Ended December 31	2012		2011		2010


Gas production (Bcf)		39.1		45.4		57.4
Gas sales (Bcf)		36.6		42.7		53.6
Oil production/sales (Mbbls)		501.0		282.2		253.9
NGL production/sales (Mbbls)		2,357.2		2,693.7		3,008.9
Equivalent production (Bcfe)		56.2		63.3		77.0
Equivalent sales (Bcfe)		53.7		60.6		73.2

Average realized prices without hedging results:
Gas (per Mcf)	$	2.67	$	3.94	$	4.30
NGL (per Bbl)		37.35		52.70		40.96
Oil (per Bbl)		86.29		89.43		73.80
Equivalent (per Mcfe)		4.26		5.54		5.09

Average realized prices with hedging results:
Gas (per Mcf)	$	4.24	$	5.84	$	6.03
NGL (per Bbl)		38.36		39.60		34.84
Oil (per Bbl)		91.41		89.43		73.80
Equivalent (per Mcfe)		5.42		6.30		6.10

Average cost per Mcfe:
Production expenses	$	1.33	$	1.20	$	1.12
Production and ad valorem taxes		0.23		0.39		0.37
General and administrative expenses		0.76		0.68		0.62
Depletion expense		1.45		1.18		0.93

In the second quarter of 2010, HighMount completed the sale of exploration and production assets located in the Antrim Shale in Michigan and the Black Warrior Basin in Alabama. The Michigan and Alabama properties represented approximately 17% in aggregate of HighMount’s total proved reserves as of December 31, 2009, prior to the sales.

Results of Operations

The following table summarizes the results of operations for HighMount for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included in Item 8.


Year Ended December 31	2012			2011			2010

(In millions)

Revenues:
Other revenue, primarily operating	$	297		$	390		$	455
Investment losses					(34	)		(30)

Total		297			356			425


Expenses:
Other operating expenses
Impairment of natural gas and oil properties		680
Operating		239			245			258
Interest		14			46			61

Total		933			291			319

Income (loss) before income tax		(636	)		65			106
Income tax (expense) benefit		229			(24	)		(48)

Net income (loss) attributable to Loews Corporation	$	(407	)	$	41		$	58

2012 Compared with 2011

HighMount’s operating revenues decreased $93 million in 2012 as compared with 2011 due to decreased natural gas and NGL prices and sales volumes. Average prices realized per Mcfe were $5.42 in 2012 compared to $6.30 in 2011. HighMount sold 53.7 Bcfe in 2012 compared to 60.6 Bcfe in 2011. The decrease in sales volume was primarily due to the continued reduction in capital spending on natural gas drilling since 2008.

HighMount had hedges in place as of December 31, 2012 that covered approximately 59.5% and 26.6% of its total estimated 2013 and 2014 natural gas equivalent production at a weighted average price of $6.27 and $5.39 per Mcfe.

For the year ended December 31, 2012, HighMount recorded non-cash ceiling test impairment charges of $680 million ($433 million after tax) related to the carrying value of its natural gas and oil properties. The write-downs were the result of declines in natural gas and NGL prices. The December 31, 2012 ceiling test calculation was based on average 2012 prices of $2.76 per MMBtu for natural gas, $41.11 per Bbl for NGLs and $94.71 per Bbl for oil. See Valuation of HighMount’s Proved Reserves included in Critical Accounting Estimates above for further information.

Operating expenses were $239 million and $245 million in 2012 and 2011. Production expenses and production and ad valorem taxes were $98 million in 2012 as compared with $109 million in 2011. DD&A expenses were $101 million in 2012 as compared with $94 million in 2011. The increase in DD&A expenses was primarily due to negative reserve revisions in 2011 and projected future development activity focused on developing oil reserves.

In connection with refinancing its $1.1 billion variable rate term loans, a pretax loss of $34 million was recorded in the fourth quarter of 2011, reflecting derivative losses from termination of interest rate hedge activities. Interest expense decreased $32 million in 2012 as compared with 2011 due to a lower outstanding debt balance in 2012.

2011 Compared with 2010

HighMount’s operating revenues decreased $65 million in 2011 as compared with 2010. Operating revenues decreased by $46 million due to the sale of HighMount’s assets in Michigan and Alabama in 2010. Permian Basin operating revenues decreased by $19 million on sales volumes of 60.6 Bcfe in 2011 compared to 66.5 Bcfe in 2010. Average prices realized per Mcfe for Permian Basin sales were $6.30 in 2011 compared to $6.02 in 2010, which reflects hedging activities. The decrease in Permian Basin sales volume is primarily due to the reduction in HighMount’s drilling activity in response to lower natural gas prices.

HighMount had hedges in place as of December 31, 2011 that covered approximately 51.7% and 16.3% of its total estimated 2012 and 2013 natural gas equivalent production at a weighted average price of $5.79 and $5.44 per Mcfe.

In connection with refinancing its $1.1 billion variable rate term loans a pretax loss of $34 million was recorded in the fourth quarter of 2011, reflecting derivative losses from termination of interest rate hedge activities. As a result of the Michigan and Alabama asset sales in 2010, HighMount recognized a pretax loss of $30 million in Investment losses related to its interest rate and commodity hedging activities. HighMount used the proceeds from the basin sales to reduce the outstanding debt under its term loans by $500 million, which resulted in a $15 million decrease in interest expense in 2011.

Operating expenses decreased $13 million in 2011 as compared with 2010. The decline reflects a $21 million decrease related to the sale of HighMount’s assets in Michigan and Alabama, partially offset by an $8 million increase in operating expenses in the Permian Basin. The increase in operating expenses is due to higher DD&A expenses, partially offset by lower general and administrative expenses.

DD&A expenses were $94 million and $92 million for the years ended December 31, 2011 and 2010. This reflects a $10 million increase in the Permian Basin, due to negative reserve revisions and projected future development, offset by an $8 million decrease due to the sale of HighMount’s assets in Michigan and Alabama.

Loews Hotels

The following table summarizes the results of operations for Loews Hotels for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:


Year Ended December 31	2012			2011			2010

(In millions)

Revenues:
Other revenue, primarily operating	$	396		$	336		$	307
Net investment income		1			1			1

Total		397			337			308


Expenses:
Other Operating expenses
Operating		366			306			284
Depreciation		30			29			29
Equity income from joint ventures		(24	)		(24	)		(17)
Interest		11			9			10

Total		383			320			306

Income before income tax		14			17			2
Income tax expense		(7	)		(4	)		(1)

Net income attributable to Loews Corporation	$	7		$	13		$	1


EBITDA	$	55		$	55		$	41

Earnings before interest, tax, depreciation and amortization (“EBITDA”) is an indicator of operating performance used by Loews Hotels to measure its ability to service debt, fund capital expenditures and expand its business. EBITDA is a non-GAAP financial measure that is not meant to replace net income as defined by GAAP. The following table reconciles EBITDA to Net income attributable to Loews Corporation for the years ended December 31, 2012, 2011 and 2010.


Year Ended December 31	2012			2011			2010

(In millions)

EBITDA	$	55		$	55		$	41
Depreciation		(30	)		(29	)		(29)
Interest		(11	)		(9	)		(10)
Income tax expense		(7	)		(4	)		(1)

Net income attributable to Loews Corporation	$	7		$	13		$	1

2012 Compared with 2011

Revenues increased by $60 million in 2012 as compared to 2011. Net income decreased by $6 million as compared to 2011.

The increase in revenues is due to $21 million from the addition of the Loews Hollywood Hotel to the portfolio of owned properties for five months of 2012 and higher revenue per available room (“RevPAR”). RevPAR is an industry measure of the combined effect of occupancy rates and average room rates on room revenues. Other hotel operating revenues primarily include guest charges for food and beverages. RevPAR, occupancy rates and average room rates as discussed below are for owned hotels only. RevPAR increased $5.71 to $168.89 in 2012 as compared to 2011 reflecting improving occupancy and average room rates. Occupancy rates increased to 75.3% in 2012 from 73.6% in 2011. Average room rates increased by $2.69, or 1.2%, in 2012 as compared to 2011. In addition, revenues include $4 million from the gain on the sale of the Loews Denver Hotel in the fourth quarter of 2012.

Revenues and operating expenses for 2012 also include $27 million of cost reimbursements from joint venture and managed properties, relating mainly to payroll incurred on behalf of the owners of hotel properties managed by us.

Equity income from joint venture properties in 2012 is consistent with 2011. Increases in average room rates at joint venture properties was offset by lower occupancy rates in 2012 as compared to 2011.

Operating expenses increased $60 million in 2012 as compared to 2011, due to expenses of $22 million, including acquisition and transition related costs, from the Loews Hollywood Hotel and $13 million of costs related to the closure of the Loews Regency Hotel for renovation, partially offset by $7 million related to the partial recovery of a loan guarantee payment. In addition, operating expenses in 2012 include $27 million for cost reimbursements from joint venture and managed properties as discussed above.

2011 Compared with 2010

Revenues increased by $29 million in 2011 as compared to 2010. Net income increased by $12 million as compared to 2010.

RevPAR increased $15.29 to $163.18 in 2011 as compared to 2010. The increase in RevPAR reflects improving occupancy and average room rates. Occupancy rates increased to 73.6% in 2011 from 70.1% in 2010. Average room rates increased by $10.46, or 5.0%, in 2011 as compared to 2010.

The improvement in operating results for 2011 as compared to 2010 is due primarily to increases in RevPAR described above, and increases in equity income from joint venture properties reflecting higher occupancy and average room rates.

Corporate and Other

Corporate and Other operations consist primarily of investment income at the Parent Company, corporate interest expenses and other corporate administrative costs. Investment income includes earnings on cash and short term investments held at the Parent Company level to meet current and future liquidity needs, as well as results of limited partnership investments and the trading portfolio managed to take advantage of potential market opportunities.

The following table summarizes the results of operations for Corporate and Other for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:


Year Ended December 31	2012			2011			2010

(In millions)

Revenues:
Net investment income	$	61		$	1		$	187
Other		1			(2	)		(3)

Total		62			(1	)		184


Expenses:
Operating		106			87			80
Interest		40			44			47

Total		146			131			127

Income (loss) before income tax		(84	)		(132	)		57
Income tax (expense) benefit		29			47			(24)

Net income (loss) attributable to Loews Corporation	$	(55	)	$	(85	)	$	33

2012 Compared with 2011

Revenues increased by $63 million for 2012 as compared to 2011, primarily due to improved performance of equity and fixed income investments in the trading portfolio, partially offset by lower performance of limited partnership investments for 2012.

Net results improved $30 million for 2012 as compared to 2011. These changes were due primarily to the change in revenues discussed above, partially offset by an increase in corporate overhead expenses and reduced corporate overhead allocated to our subsidiaries.

2011 Compared with 2010

Revenues decreased by $185 million in 2011 as compared to 2010. There was a net loss of $85 million in 2011 as compared to net income of $33 million in 2010. Due to less favorable equity investment returns and overall capital market volatility, the results of the trading portfolio were flat for 2011 as compared to significant gains in 2010. Earnings on cash and short term investments were also negatively impacted in 2011 by lower effective income yields.

LIQUIDITY AND CAPITAL RESOURCES

CNA Financial

Cash Flows

CNA’s primary operating cash flow sources are premiums and investment income from its insurance subsidiaries. CNA’s primary operating cash flow uses are payments for claims, policy benefits and operating expenses, including interest expense on corporate debt. Additionally, cash may be paid or received for income taxes.

For 2012, net cash provided by operating activities was $1.3 billion as compared with $1.7 billion for 2011. Cash flows resulting from reinsurance contract commutations are reported as operating activities. During 2012, operating cash flows were decreased by $30 million related to net cash outflows from commutations as compared with net cash inflows of $547 million during 2011. Additionally, CNA received a $29 million tax refund in 2012 as compared to tax payments of $61 million in 2011.

Net cash used by operating activities was $89 million in 2010. As further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8 and previously referenced in this MD&A, in 2010 CNA completed the Loss Portfolio Transfer transaction. As a result of this transaction, operating cash flows were reduced for the initial net cash settlement with NICO. Excluding the impact of this transaction, net cash provided by operating activities was approximately $1.8 billion for 2010.

Cash flows from investing activities include the purchase and disposition of available-for-sale financial instruments. Additionally, cash flows from investing activities may include the purchase and sale of businesses, land, buildings, equipment and other assets not generally held for resale.

Net cash used by investing activities was $934 million for 2012, as compared with net cash used of $1.1 billion for 2011 and net cash provided of $767 million for 2010. The cash flow from investing activities is impacted by various factors such as the anticipated payment of claims, financing activity, asset/liability management and individual security buy and sell decisions made in the normal course of portfolio management. Additionally, during 2012, CNA acquired Hardy. Net cash provided by investing activities in 2010 primarily related to the sale of short term investments which was used to fund the $1.9 billion initial net cash settlement with NICO as discussed above.

Cash flows from financing activities may include proceeds from the issuance of debt and equity securities, outflows for stockholder dividends or repayment of debt and outlays to reacquire equity instruments. Net cash used by financing activities was $239 million, $644 million and $742 million for 2012, 2011 and 2010.

Liquidity

CNA believes that its present cash flows from operations, investing activities and financing activities are sufficient to fund its current and expected working capital and debt obligation needs and CNA does not expect this to change in the near term. There are currently no amounts outstanding under CNA’s $250 million senior unsecured revolving credit facility.

CNA has an effective Registration Statement on Form S-3 registering the future sale of an unlimited amount of its debt and equity securities.

Dividends

Dividends of $0.60 per share of CNA’s common stock were declared and paid in 2012. On February 8, 2013, CNA’s Board of Directors declared a quarterly dividend of $0.20 per share, payable March 7, 2013 to stockholders of record on February 21, 2013. The declaration and payment of future dividends is at the discretion of CNA’s Board of Directors and will depend on many factors, including CNA’s earnings, financial condition, business needs, and regulatory constraints.

Ratings

Ratings are an important factor in establishing the competitive position of insurance companies. CNA’s insurance company subsidiaries are rated by major rating agencies, and these ratings reflect the rating agency’s opinion of the insurance company’s financial strength, operating performance, strategic position and ability to meet its obligations to policyholders. Agency ratings are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any time by the issuing organization. Each agency’s rating should be evaluated independently of any other agency’s rating. One or more of these agencies could take action in the future to change the ratings of CNA’s insurance subsidiaries.

The table below reflects the various group ratings issued by A.M. Best Company (“A.M. Best”), Moody’s and S&P for the property and casualty and life companies. The table also includes the ratings for CNA senior debt.


	Insurance Financial Strength Ratings			Corporate Debt Ratings

	Property & Casualty		Life	CNA

	CCC Group	Western Group	CAC	Senior Debt

A.M. Best	A	A	A-	bbb
Moody’s	A3	Not rated	Not rated	Baa2
S&P	A-	A-	Not rated	BBB-

S&P maintains a positive outlook and A.M. Best maintains a stable outlook on CNA. In June of 2012, Moody’s upgraded CNA’s debt rating to Baa2 with a stable outlook, affirmed CNA’s insurance financial strength rating and revised its outlook on CNA’s financial strength rating to positive from stable.

If CNA’s property and casualty insurance financial strength ratings were downgraded below current levels, its business and results of operations could be materially adversely affected. The severity of the impact on CNA’s business is dependent on the level of downgrade and, for certain products, which rating agency takes the rating action. Among the adverse effects in the event of such downgrades would be the inability to obtain a material volume of business from certain major insurance brokers, the inability to sell a material volume of CNA’s insurance products to certain markets and the required collateralization of certain future payment obligations or reserves. Downgrades of corporate debt ratings could result in adverse effects upon CNA’s liquidity position, including negatively impacting CNA’s ability to access capital markets, and increasing its financing costs.

Further, additional collateralization may be required for certain settlement agreements and assumed reinsurance contracts, as well as derivative contracts, if CNA’s ratings or other specific criteria fall below certain thresholds.

Diamond Offshore

Cash and investments totaled $1.5 billion at December 31, 2012, compared to $1.2 billion at December 31, 2011. In 2012, Diamond Offshore paid cash dividends totaling $490 million, consisting of aggregate regular cash dividends of $69 million and aggregate special cash dividends of $421 million. On February 4, 2013, Diamond Offshore declared a regular quarterly dividend of $0.125 per share and a special dividend of $0.75 per share.

Cash provided by operating activities in 2012 was $1.3 billion, compared to $1.4 billion in 2011, a decrease of $109 million compared to the 2011 period, primarily due to lower earnings. Cash used in investing activities in 2012 decreased $245 million compared to 2011. This decrease was due to the sale of six jack-up rigs for cash proceeds of $132 million in 2012 and higher capital expenditures in 2011 related to the first installments for the construction of three new ultra-deepwater drillships.

Diamond Offshore is currently obligated under two vessel modification agreements and four turnkey contracts for the construction of two semisubmersible rigs and four new ultra-deepwater drillships. Diamond Offshore estimates that the aggregate cost for the construction of the two semisubmersible rigs and the four new drillships, including commissioning, spares and project management, to be approximately $680 million and $2.6 billion, of which $93 million and $648 million has already been paid.

In September of 2012, Diamond Offshore entered into a $750 million syndicated, senior unsecured five-year revolving credit agreement for general corporate purposes, that provides for revolving loans, up to $250 million in performance or other standby letters of credit and up to $75 million in swingline loans. As of December 31, 2012, there were no loans or letters of credit outstanding under the credit agreement.

For 2013, Diamond Offshore has budgeted approximately $1.8 billion for capital expenditures of which approximately $1.3 billion will be spent towards the construction of its new drillships and semisubmersible rigs, and approximately $120 million will be spent on the North Sea enhancement project for the Ocean Patriot. Diamond Offshore expects to finance its 2013 capital expenditures through the use of existing cash balances and cash flows from operations.

In addition, Diamond Offshore may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Diamond Offshore’s ability to access the capital markets by issuing debt or equity securities will be dependent on its results of operations, its current financial condition, current market conditions and other factors beyond its control.

A substantial portion of Diamond Offshore’s cash flows has been and is expected to continue to be invested in the enhancement of its drilling fleet. Diamond Offshore determines the amount of cash required to meet its capital commitments by evaluating its rig construction obligations, the need to upgrade rigs to meet specific customer requirements and its ongoing rig equipment enhancement and replacement programs. As a result of Diamond Offshore’s intention to indefinitely reinvest the earnings of its wholly owned subsidiary, Diamond Offshore International Limited (“DOIL”), to finance its foreign activities, Diamond Offshore does not expect such earnings to be available for distribution to its stockholders or to finance its domestic activities. However, Diamond Offshore believes that the operating cash flows generated by and cash reserves of DOIL, and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. will be sufficient to meet both its working capital requirements and its capital commitments over the next twelve months. Diamond Offshore will, however, continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.

Boardwalk Pipeline

At December 31, 2012 and 2011, cash and investments amounted to $4 million and $23 million. Funds from operations for the year ended December 31, 2012 amounted to $576 million, compared to $454 million in 2011. In 2012 and 2011, Boardwalk Pipeline’s capital expenditures were $227 million and $142 million. During 2012, Boardwalk Pipeline purchased from us the remaining 80% interest in HP Storage for $285 million and acquired Louisiana Midstream for $620 million. These acquisitions were funded using cash from operations, borrowings under Boardwalk Pipeline’s revolving credit facility and debt and equity offerings as further discussed below. For the years ended December 31, 2012 and 2011, Boardwalk Pipeline paid cash distributions of $479 million and $420 million to its partners.

Boardwalk Pipeline’s ability to access the capital markets for debt and equity financing under reasonable terms depends on its financial condition, credit ratings and market conditions. Boardwalk Pipeline anticipates that its existing capital resources, including the revolving credit facility and future cash flows generated from operations will be adequate to fund its operations, including its maintenance capital expenditures. Boardwalk Pipeline may seek to access the capital markets to fund some or all of its growth capital expenditures, acquisitions or for general corporate purposes, including to refinance all or a portion of its indebtedness, a significant amount of which matures in the next five years.

In April of 2012, Boardwalk Pipeline entered into a Second Amended and Restated Revolving Credit Agreement (“Amended Credit Agreement”) with aggregate lending commitments of $1.0 billion. The Amended Credit Agreement has a maturity date of April 27, 2017. As of December 31, 2012, Boardwalk Pipeline had $302 million of loans outstanding under this revolving credit facility with a weighted-average interest rate of 1.3% and had no letters of credit issued. As of December 31, 2012, Boardwalk Pipeline was in compliance with all covenant requirements under the credit facility.

In 2012, Boardwalk Pipeline issued $300 million of 4.0% senior notes due June 2022 and $300 million of 3.4% senior notes due February 2023. The proceeds were used to redeem at maturity $225 million of 5.8% senior notes

due August 2012, repay in full its $200 million variable rate term loan due December 2016 and repay the $100 million of borrowings outstanding under the Subordinated Loan Agreement with us. The remaining proceeds were used to repay borrowings under Boardwalk Pipeline’s revolving credit facility.

In October of 2012, as part of financing the acquisition of Louisiana Midstream, Boardwalk Pipeline entered into a $225 million variable rate term loan due October 1, 2017.

In February, August and October of 2012, Boardwalk Pipeline sold 9.2 million, 11.6 million and 11.2 million common units in public offerings and received net proceeds of $250 million, $318 million and $298 million, including $5 million, $7 million and $6 million contributions from us to maintain our 2% general partner interest. The net proceeds were used to repay borrowings under Boardwalk Pipeline’s revolving credit facility, to purchase the remaining equity ownership of HP Storage and to acquire Louisiana Midstream.

Boardwalk Pipeline incurs substantial costs for ongoing maintenance of its pipeline systems and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. The Pipeline and Hazardous Materials Safety Administration has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted in an overall increase in Boardwalk Pipeline’s ongoing maintenance costs. Due to recent widely-known incidents that have occurred on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. Boardwalk Pipeline could incur significant additional costs if new or more stringently interpreted pipeline safety requirements are implemented.

Boardwalk Pipeline expects total capital expenditures to be approximately $350 million in 2013, including approximately $100 million for maintenance capital, $42 million of which will be related to pipeline integrity management. In 2012, total capital expenditures were $227 million, of which $80 million was recorded as maintenance capital.

Boardwalk Pipeline expects to spend approximately $250 million in 2013 on its current expansion projects, including $33 million related to the Southeast Market Expansion, $73 million related to the South Texas Eagle Ford Expansion, $16 million related to the Natural Gas Salt Dome Storage Project and $39 million related to the Choctaw Brine Supply Expansion Project.

HighMount

At December 31, 2012 and 2011, cash and investments amounted to $10 million and $85 million. Net cash flows provided by operating activities were $151 million and $140 million in 2012 and 2011. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs.

Cash used in investing activities in 2012 was $336 million, compared to $292 million in 2011. The primary driver of cash used in investing activities is capital spent developing HighMount’s natural gas and oil reserves. In addition, in 2011, HighMount paid approximately $106 million for the acquisition of working interests in oil and gas properties which was funded by a capital contribution from us. HighMount expects to spend approximately $270 million on capital expenditures in 2013 developing its natural gas and oil reserves, with a focus on oil drilling opportunities. Funds for capital expenditures and working capital requirements are expected to be provided primarily from operating activities, the available capacity under the revolving credit facility and capital contributions from us.

At December 31, 2012, HighMount had $600 million of term loans outstanding and $110 million was outstanding under HighMount’s $250 million revolving credit facility. HighMount’s credit agreement governing its term loans and revolving credit facility contains financial covenants typical for these types of agreements, including a maximum debt to capitalization ratio and a minimum ratio of the net present value of its projected future cash flows from its proved natural gas and oil reserves to total debt. The calculation of net present value, performed at least annually, is based on commodity prices determined by the lenders. A decline in commodity prices can reduce HighMount’s borrowing capacity requiring repayment of a portion of its line of credit funded by a capital contribution from us. As a result of declining commodity prices, in 2012, we made a $100 million capital

contribution to HighMount of which $90 million was used to repay a portion of the amount outstanding under the line of credit in order to meet debt covenant requirements. In January of 2013, HighMount borrowed an additional $10 million under its revolving credit facility, bringing total borrowings to $720 million. The credit agreement also contains customary restrictions or limitations on HighMount’s ability to engage in certain transactions, including transactions with affiliates. At December 31, 2012, HighMount was in compliance with all of its covenants under the credit agreement.

Loews Hotels

Funds from operations continue to exceed operating requirements. Cash and investments totaled $43 million at December 31, 2012, as compared to $81 million at December 31, 2011.

In January of 2013 the Loews Regency Hotel closed for an extensive renovation, with an anticipated completion in the fourth quarter of this year. Capital expenditures for the renovation are estimated to be approximately $85 million.

Loews Hotels has added three properties to its portfolio consisting of the Loews Hollywood Hotel in 2012 and the Loews Boston Back Bay Hotel and the Loews Madison Hotel in 2013. These acquisitions were funded with existing cash balances, third party joint venture equity, debt and approximately $88 million of net capital contributions by us.

Funds for future capital expenditures, including acquisitions of new properties, joint venture capital contributions, maintenance spending, renovation projects and working capital requirements will be provided from operations, refinancing, newly incurred debt, existing cash balances and advances or capital contributions from us.

Corporate and Other

Parent Company cash and investments, net of receivables and payables, at December 31, 2012 totaled $3.9 billion, as compared to $3.3 billion at December 31, 2011. During 2012, we received $683 million in interest and dividends from our subsidiaries, $285 million from the sale of our 80% ownership interest in HP Storage to Boardwalk Pipeline and $100 million from the repayment of subordinated debt by Boardwalk Pipeline. These inflows were partially offset by the payment of $222 million to fund treasury stock purchases, net capital contributions of approximately $100 million to our subsidiaries and $99 million of cash dividends to our shareholders.

As of December 31, 2012, there were 391,805,166 shares of Loews common stock outstanding. Depending on market and other conditions, we may purchase shares of our and our subsidiaries’ outstanding common stock in the open market or otherwise. During the year ended December 31, 2012, we purchased 5.6 million shares of Loews common stock at an aggregate cost of $222 million.

We have an effective Registration Statement on Form S-3 registering the future sale of an unlimited amount of our debt and equity securities.

We continue to pursue conservative financial strategies while seeking opportunities for responsible growth. These include the expansion of existing businesses, full or partial acquisitions and dispositions, and opportunities for efficiencies and economies of scale.

Off-Balance Sheet Arrangements

At December 31, 2012 and 2011, we did not have any off-balance sheet arrangements.

Contractual Obligations

Our contractual payment obligations are as follows:

Payments Due by Period

December 31, 2012

Total

Less than

1 year

1-3 years

3-5 years

More than
5 years

(In millions)

Debt (a)

12,919

488

2,646

3,494

6,291

Operating leases

399

107

146

Claim and claim adjustment expense reserves (b)

26,505

6,152

7,607

3,910

8,836

Future policy benefits reserves (c)

35,607

153

449

726

34,279

Policyholders’ funds reserves (c)

133

(1)

Rig construction contracts (d)

1,766

928

838

Purchase and other obligations

451

236

198

Total (e)

77,780

8,049

11,860

8,224

49,647

(a)	Includes estimated future interest payments.

(b)

Claim and claim adjustment expense reserves are not discounted and represent CNA’s estimate of the amount and timing of the ultimate settlement and administration of gross claims based on its assessment of facts and circumstances known as of December 31, 2012. See the Reserves - Estimates and Uncertainties section of this MD&A for further information.

(c)

Future policy benefits and policyholders’ funds reserves are not discounted and represent CNA’s estimate of the ultimate amount and timing of the settlement of benefits based on its assessment of facts and circumstances known as of December 31, 2012. Future policy benefit reserves of $697 million and policyholders’ fund reserves of $35 million related to business which has been 100% ceded to unaffiliated parties in connection with the sale of CNA’s individual life business in 2004 are not included. Additional information on future policy benefits and policyholders’ funds reserves is included in Note 1 of the Notes to Consolidated Financial Statements included under Item 8.

(d)

Diamond Offshore has entered into four turnkey contracts for the construction of four ultra-deepwater drillships with deliveries scheduled in 2013 and 2014. The aggregate cost of the four drillships is expected to be approximately $2.6 billion, of which $648 million has been paid. The final installments of the contracted price are payable upon delivery of each vessel. Diamond Offshore has also entered into construction contracts to upgrade two existing rigs. The upgrades are expected to be completed in 2013 and 2014 at an aggregate cost of approximately $680 million, of which $93 million has been paid.

(e)	Does not include expected contribution of approximately $100 million to the Company’s pension and postretirement plans in 2013.

Further information on our commitments, contingencies and guarantees is provided in the Notes to Consolidated Financial Statements included under Item 8.

INVESTMENTS

Investment activities of non-insurance subsidiaries primarily include investments in fixed income securities, including short term investments. The Parent Company portfolio also includes equity securities, including short sales and derivative instruments, and investments in limited partnerships. These types of investments generally present greater volatility, less liquidity and greater risk than fixed income investments and are included within Results of Operations – Corporate and Other.

We enter into short sales and invest in certain derivative instruments that are used for asset and liability management activities, income enhancements to our portfolio management strategy and to benefit from anticipated future movements in the underlying markets. If such movements do not occur as anticipated, then significant losses may occur. Monitoring procedures include senior management review of daily detailed reports of existing positions and valuation fluctuations to ensure that open positions are consistent with our portfolio strategy.

Credit exposure associated with non-performance by the counterparties to derivative instruments is generally limited to the uncollateralized change in fair value of the derivative instruments recognized in the Consolidated Balance Sheets. We mitigate the risk of non-performance by monitoring the creditworthiness of counterparties and diversifying derivatives to multiple counterparties. We occasionally require collateral from our derivative investment counterparties depending on the amount of the exposure and the credit rating of the counterparty.

Insurance

CNA maintains a large portfolio of fixed maturity and equity securities, including large amounts of corporate and government issued debt securities, residential and commercial mortgage-backed securities, and other asset-backed securities and investments in limited partnerships which pursue a variety of long and short investment strategies across a broad array of asset classes. CNA’s investment portfolio supports its obligation to pay future insurance claims and provides investment returns which are an important part of CNA’s overall profitability.

Net Investment Income

The significant components of CNA’s net investment income are presented in the following table:


Year Ended December 31	2012			2011			2010

(In millions)

Fixed maturity securities	$	2,022		$	2,011		$	2,051
Short term investments		5			8			15
Limited partnership investments		251			48			249
Equity securities		12			20			32
Trading portfolio		24			9			13
Other		24			16			10

Gross investment income		2,338			2,112			2,370
Investment expenses		(56	)		(58	)		(54)

Net investment income	$	2,282		$	2,054		$	2,316

Net investment income increased $228 million for 2012 as compared with 2011. The increase was primarily driven by a significant increase in limited partnership investment income, increased trading portfolio income and an increase in fixed maturity securities income. Limited partnership results were positively impacted by more favorable equity market returns, and overall capital market and credit spread volatility. The increase in fixed maturity securities income was driven by a higher invested asset base and a favorable net impact of changes in estimates of prepayments for asset-backed securities. These favorable impacts were partially offset by the effect of purchasing new investments at lower market interest rates.

Net investment income decreased $262 million in 2011 as compared with 2010. The decrease was primarily driven by a significant decrease in limited partnership results as well as lower fixed maturity security income. Limited partnership results were adversely impacted by less favorable equity market returns, and overall capital

market and credit spread volatility. The decrease in fixed maturity security income was primarily driven by the effect of purchasing new investments at lower market interest rates.

The fixed maturity investment portfolio provided a pretax effective income yield of 5.3%, 5.5% and 5.6% for the years ended December 31, 2012, 2011, and 2010. Tax-exempt municipal bonds generated $274 million, $240 million and $263 million of net investment income for the years ended December 31, 2012, 2011 and 2010.

Net Realized Investment Gains (Losses)

The components of CNA’s net realized investment results are presented in the following table:


Year Ended December 31	2012			2011			2010

(In millions)

Realized investment gains (losses):
Fixed maturity securities:
Corporate and other bonds	$	106		$	48		$	164
States, municipalities and political subdivisions		(4	)		5			(128)
Asset-backed		(26	)		(82	)		44
U.S. Treasury and obligations of government-sponsored enterprises		3			1			3
Foreign government		4			3			2
Redeemable preferred stock					3			7

Total fixed maturity securities		83			(22	)		92
Equity securities		(23	)		(1	)		(2)
Derivative securities		(2	)					(1)
Short term investments and other		2			4			(3)

Total realized investment gains (losses)		60			(19	)		86
Income tax (expense) benefit		(21	)		8			(36)
Amounts attributable to noncontrolling interests		(4	)		1			(4)

Net realized investment gains (losses) attributable to Loews Corporation	$	35		$	(10	)	$	46

Net realized investment gains increased $45 million for 2012 as compared with 2011, driven by lower other-than-temporary impairment (“OTTI”) losses recognized in earnings. Net realized investment gains decreased $56 million for 2011 as compared with 2010. Net realized investment results include OTTI losses of $100 million, $140 million and $151 million for 2012, 2011 and 2010. Further information on CNA’s realized gains and losses, including CNA’s OTTI losses and impairment decision process, is set forth in Note 3 of the Notes to Consolidated Financial Statements included under Item 8.

Portfolio Quality

CNA’s fixed maturity portfolio consists primarily of high quality bonds, 91.6% and 92.1% of which were rated as investment grade (rated BBB- or higher) at December 31, 2012 and 2011. The classification between investment grade and non-investment grade is based on a ratings methodology that takes into account ratings from two major providers, Standard & Poor’s (“S&P”) and Moody’s Investors Services, Inc. (“Moody’s”), in that order of preference. If a security is not rated by these providers, CNA formulates an internal rating. At December 31, 2012 and 2011, approximately 98% of the fixed maturity portfolio was rated by S&P or Moody’s, or was issued or guaranteed by the U.S. Government, Government agencies or Government-sponsored enterprises.

The following table summarizes the ratings of CNA’s fixed maturity portfolio at fair value:


December 31	2012			2011

(In millions of dollars)

U.S. Government, Government agencies and Government-sponsored enterprises	$	4,540	10.6%	$	4,760	11.9%
AAA		3,224	7.6		3,421	8.6
AA and A		19,305	45.3		17,807	44.6
BBB		11,997	28.1		10,790	27.0
Non-investment grade		3,567	8.4		3,159	7.9

Total	$	42,633	100.0%	$	39,937	100.0%

Non-investment grade fixed maturity securities, as presented in the table below, include high-yield securities rated below BBB- by bond rating agencies and other unrated securities that, according to CNA’s analysis, are below investment grade. Non-investment grade securities generally involve a greater degree of risk than investment grade securities. The amortized cost of CNA’s non-investment grade fixed maturity bond portfolio was $3.4 billion and $3.2 billion at December 31, 2012 and 2011. The following table summarizes the ratings of this portfolio at fair value.


December 31	2012			2011

(In millions of dollars)

BB	$	1,529	42.9%	$	1,484	47.0%
B		1,075	30.1		867	27.4
CCC - C		724	20.3		689	21.8
D		239	6.7		119	3.8

Total	$	3,567	100.0%	$	3,159	100.0%

The following table summarizes available-for-sale fixed maturity securities in a gross unrealized loss position by ratings distribution.

December 31, 2012

Estimated
Fair Value

Gross
Unrealized
Losses

(In millions of dollars)

U.S. Government, Government agencies and Government-sponsored enterprises

642

23.9%

29.1%

AAA

172

6.4

1.9

387

14.4

26.5

323

12.0

7.7

BBB

551

20.5

14.2

Non-investment grade

610

22.8

20.6

Total

2,685

100.0%

155

100.0%

The following table provides the maturity profile for these available-for-sale fixed maturity securities. Securities not due to mature on a single date are allocated based on weighted average life.

December 31, 2012

Estimated
Fair Value

Gross
Unrealized
Losses

(In millions of dollars)

Due in one year or less

213

7.9%

5.2%

Due after one year through five years

913

34.0

14.2

Due after five years through ten years

865

32.2

46.5

Due after ten years

694

25.9

34.1

Total

2,685

100.0%

155

100.0%

Duration

A primary objective in the management of the investment portfolio is to optimize return relative to corresponding liabilities and respective liquidity needs. CNA’s views on the current interest rate environment, tax regulations, asset class valuations, specific security issuer and broader industry segment conditions, and the domestic and global economic conditions, are some of the factors that enter into an investment decision. CNA also continually monitors exposure to issuers of securities held and broader industry sector exposures and may from time to time adjust such exposures based on its views of a specific issuer or industry sector.

A further consideration in the management of the investment portfolio is the characteristics of the corresponding liabilities and the ability to align the duration of the portfolio to those liabilities and to meet future liquidity needs, minimize interest rate risk and maintain a level of income sufficient to support the underlying insurance liabilities. For portfolios where future liability cash flows are determinable and typically long term in nature, CNA segregates investments for asset/liability management purposes. The segregated investments support the liabilities in Life & Group Non-Core including annuities, structured settlements and long term care products.

The effective durations of fixed maturity securities, short term investments and interest rate derivatives are presented in the table below. Short term investments are net of accounts payable and receivable amounts for securities purchased and sold, but not yet settled.

December 31, 2012

December 31, 2011

Fair Value

Effective
Duration
(Years)

Fair Value

Effective
Duration
(Years)

(In millions of dollars)

Investments supporting Life & Group Non-Core

$ 15,590

11.3

13,820

11.5

Other interest sensitive investments

28,855

3.9

28,071

3.9

Total

$ 44,445

6.5

41,891

6.4

The investment portfolio is periodically analyzed for changes in duration and related price change risk. Additionally, CNA periodically reviews the sensitivity of the portfolio to the level of foreign exchange rates and other factors that contribute to market price changes. A summary of these risks and specific analysis on changes is included in Item 7A – Quantitative and Qualitative Disclosures about Market Risk included herein.

Short Term Investments

The carrying value of the components of CNA’s short term investment portfolio is presented in the following table:


December 31	2012		2011

(In millions)

Short term investments:
Commercial paper	$	751	$	411
U.S. Treasury securities		617		903
Money market funds		301		45
Other		163		282

Total short term investments	$	1,832	$	1,641

European Exposure

CNA’s fixed maturity portfolio includes European exposure. The following table summarizes European exposure included within fixed maturity holdings:

Corporate

Sovereign

Total

December 31, 2012

Financial Sector

Other Sectors

(In millions)

AAA

224

118

419

227

128

390

878

796

1,680

BBB

386

1,109

1,501

Non-investment grade

193

208

Total fair value

1,730

2,303

165

4,198

Total amortized cost

1,615

2,027

161

3,803

European exposure is based on application of a country of risk methodology. Country of risk is derived from the issuing entity’s management location, country of primary listing, revenue and reporting currency. As of December 31, 2012, securities with a fair value and amortized cost of $2.0 billion and $1.8 billion relate to Eurozone countries, which consist of member states of the European Union that use the Euro as their national currency. Of this amount, securities with a fair value and amortized cost of $324 million and $298 million pertain to Greece, Italy, Ireland, Portugal and Spain.

ACCOUNTING STANDARDS UPDATE

For a discussion of accounting standards updates that have been adopted or will be adopted in the future, please read Note 1 of the Notes to Consolidated Financial Statements included under Item 8.

FORWARD-LOOKING STATEMENTS

Investors are cautioned that certain statements contained in this Report as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the “Act”). Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, which may be provided by management are also forward-looking statements as defined by the Act.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:

Risks and uncertainties primarily affecting us and our insurance subsidiaries

—

the risks and uncertainties associated with CNA’s loss reserves, as outlined under “Results of Operations by Business Segment – CNA Financial – Reserves – Estimates and Uncertainties” in this MD&A, including the sufficiency of the reserves and the possibility for future increases, which would be reflected in the results of operations in the period that the need for such adjustment is determined;

—

the risk that the other parties to the transaction in which, subject to certain limitations, CNA ceded its legacy A&EP liabilities will not fully perform their obligations to CNA, the uncertainty in estimating loss reserves for A&EP liabilities and the possible continued exposure of CNA to liabilities for A&EP claims that are not covered under the terms of the transaction;

—

the performance of reinsurance companies under reinsurance contracts with CNA;

—

the impact of competitive products, policies and pricing and the competitive environment in which CNA operates, including changes in CNA’s book of business;

—

product and policy availability and demand and market responses, including the level of ability to obtain rate increases and decline or non-renew underpriced accounts, to achieve premium targets and profitability and to realize growth and retention estimates;

—

general economic and business conditions, including recessionary conditions that may decrease the size and number of CNA’s insurance customers and create additional losses to CNA’s lines of business, especially those that provide management and professional liability insurance, as well as surety bonds, to businesses engaged in real estate, financial services and professional services, and inflationary pressures on medical care costs, construction costs and other economic sectors that increase the severity of claims;

—

conditions in the capital and credit markets, including continuing uncertainty and instability in these markets, as well as the overall economy, and their impact on the returns, types, liquidity and valuation of CNA’s investments;

—

conditions in the capital and credit markets that may limit CNA’s ability to raise significant amounts of capital on favorable terms, as well as restrictions on the ability or willingness of the Company to provide additional capital support to CNA;

—

the possibility of changes in CNA’s ratings by ratings agencies, including the inability to access certain markets or distribution channels and the required collateralization of future payment obligations as a result of such changes, and changes in rating agency policies and practices;

—

regulatory limitations, impositions and restrictions upon CNA, including the effects of assessments and other surcharges for guaranty funds and second-injury funds, other mandatory pooling arrangements and future assessments levied on insurance companies as well as the new federal financial regulatory reform of the insurance industry established by the Dodd-Frank Wall Street Reform and Consumer Protection Act;

—

increased operating costs and underwriting losses arising from the Patient Protection and Affordable Care Act and the related amendments in the Health Care and Education Reconciliation Act, as well as health care reform proposals at the state level;

—

regulatory limitations and restrictions, including limitations upon CNA’s ability to receive dividends from its insurance subsidiaries imposed by regulatory authorities, including regulatory capital adequacy standards;

—

weather and other natural physical events, including the severity and frequency of storms, hail, snowfall and other winter conditions, natural disasters such as hurricanes and earthquakes, as well as climate change, including effects on weather patterns, greenhouse gases, sea, land and air temperatures, sea levels, rain and snow;

—

regulatory requirements imposed by coastal state regulators in the wake of hurricanes or other natural disasters, including limitations on the ability to exit markets or to non-renew, cancel or change terms and conditions in policies, as well as mandatory assessments to fund any shortfalls arising from the inability of quasi-governmental insurers to pay claims;

—

man-made disasters, including the possible occurrence of terrorist attacks and the effect of the absence or insufficiency of applicable terrorism legislation on coverages;

—

the unpredictability of the nature, targets, severity or frequency of potential terrorist events, as well as the uncertainty as to CNA’s ability to contain its terrorism exposure effectively; and

—

the occurrence of epidemics.

Risks and uncertainties primarily affecting us and our energy subsidiaries

—

the impact of changes in worldwide demand for oil and natural gas and oil and gas price fluctuations on E&P activity, including possible write-downs of the carrying value of natural gas and NGL properties and impairments of goodwill and reduced demand for offshore drilling services;

—

the continuing effects of the Macondo well blowout, including, without limitation, the impact on drilling in the U.S. Gulf of Mexico, related delays in permitting activities and related regulations and market developments;

—

timing and cost of completion of rig upgrades, construction projects and other capital projects, including delivery dates and drilling contracts;

—

changes in foreign and domestic oil and gas exploration, development and production activity;

—

risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment and assets;

—

government policies regarding exploration and development of oil and gas reserves;

—

market conditions in the offshore oil and gas drilling industry, including utilization levels and dayrates;

—

timing and duration of required regulatory inspections for offshore oil and gas drilling rigs;

—

the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;

—

the availability, cost limits and adequacy of insurance and indemnification;

—

the impact of new pipelines or new gas supply sources on competition and basis spreads on Boardwalk Pipeline’s pipeline systems, which may impact its ability to maintain or replace expiring gas transportation and storage contracts and to sell short term capacity on its pipelines;

—

the costs of maintaining and ensuring the integrity and reliability of Boardwalk Pipeline’s pipeline systems;

—

the impact of current and future environmental laws and regulations and exposure to environmental liabilities including matters related to global climate change;

—

regulatory issues affecting natural gas transmission, including ratemaking and other proceedings particularly affecting Boardwalk Pipeline’s gas transmission subsidiaries;

—

the timing, cost, scope and financial performance of Boardwalk Pipeline’s recent, current and future acquisitions and growth projects, including the expansion into new product lines and geographical areas; and

—

the development of additional natural gas reserves and changes in reserve estimates.

Risks and uncertainties affecting us and our subsidiaries generally

—

general economic and business conditions;

—

risks of war, military operations, other armed hostilities, terrorist acts or embargoes;

—

potential changes in accounting policies by the Financial Accounting Standards Board, the Securities and Exchange Commission or regulatory agencies for any of our subsidiaries’ industries which may cause us or our subsidiaries to revise their financial accounting and/or disclosures in the future, and which may change the way analysts measure our and our subsidiaries’ business or financial performance;

—

the impact of regulatory initiatives and compliance with governmental regulations, judicial rulings and jury verdicts;

—

the results of financing efforts; by us and our subsidiaries, including any additional investments by us in our subsidiaries;

—

the ability of customers and suppliers to meet their obligations to us and our subsidiaries;

—

the consummation of contemplated transactions and agreements;

—

the successful integration, transition and management of acquired businesses;

—

the outcome of pending or future litigation, including any tobacco-related suits to which we are or may become a party;

—

possible casualty losses;

—

the availability of indemnification by Lorillard and its subsidiaries for any tobacco-related liabilities that we may incur as a result of tobacco-related lawsuits or otherwise, as provided in the Separation Agreement; and

—

potential future asset impairments.

Developments in any of these or other areas of risk and uncertainty, which are more fully described elsewhere in this Report and our other filings with the SEC, could cause our results to differ materially from results that have

been or may be anticipated or projected. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements speak only as of the date of this Report and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

We are a large diversified holding company. As such, we and our subsidiaries have significant amounts of financial instruments that involve market risk. Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Changes in the trading portfolio are recognized in the Consolidated Statements of Income. Market risk exposure is presented for each class of financial instrument held by us at December 31, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results which may occur.

Exposure to market risk is managed and monitored by senior management. Senior management approves our overall investment strategy and has responsibility to ensure that the investment positions are consistent with that strategy with an acceptable level of risk. We may manage risk by buying or selling instruments or entering into offsetting positions.

Interest Rate Risk – We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. We attempt to mitigate our exposure to interest rate risk by utilizing instruments such as interest rate swaps, commitments to purchase securities, options, futures and forwards. We monitor our sensitivity to interest rate changes by revaluing financial assets and liabilities using a variety of different interest rates. The Company uses duration and convexity at the security level to estimate the change in fair value that would result from a change in each security’s yield. Duration measures the price sensitivity of an asset to changes in the yield rate. Convexity measures how the duration of the asset changes with interest rates. The duration and convexity analysis takes into account the unique characteristics (e.g., call and put options and prepayment expectations) of each security, in determining the hypothetical change in fair value. The analysis is performed at the security level and is aggregated up to the asset category level.

The evaluation is performed by applying an instantaneous change in the yield rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on shareholders’ equity. The analysis presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one year period.

The sensitivity analysis estimates the change in the fair value of our interest sensitive assets and liabilities that were held on December 31, 2012 and 2011 due to an instantaneous change in the yield of the security at the end of the period of 100 basis points, with all other variables held constant.

The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes of market interest rates on our earnings or shareholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.

Our debt is denominated in U.S. Dollars and has been primarily issued at fixed rates, therefore, interest expense would not be impacted by interest rate shifts. The impact of a 100 basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $498 million and $455 million at December 31, 2012 and 2011. The impact of a 100 basis point decrease would result in an increase in market value of $543 million and $505 million at December 31, 2012 and 2011. HighMount has entered into interest rate swaps for a notional amount of

$300 million to hedge its exposure to fluctuations in LIBOR on a portion of its $600 million variable rate credit facility. These swaps effectively fix the interest rate at an effective rate of 3.4%. At December 31, 2012, the impact of a 100 basis point increase in interest rates on variable rate debt would increase interest expense by approximately $9 million on an annual basis.

Equity Price Risk – We have exposure to equity price risk as a result of our investment in equity securities and equity derivatives. Equity price risk results from changes in the level or volatility of equity prices which affect the value of equity securities or instruments that derive their value from such securities or indexes. Equity price risk was measured assuming an instantaneous 25% decrease in the underlying reference price or index from its level at December 31, 2012 and 2011, with all other variables held constant. A model was developed to analyze the observed changes in the value of limited partnerships held by the Company over a multiple year period along with the corresponding changes in various equity indices. The result of the model allowed us to estimate the change in value of limited partnerships when equity markets decline by 25%.

Foreign Exchange Rate Risk – Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. We have foreign exchange rate exposure when we buy or sell foreign currencies or financial instruments denominated in a foreign currency, which is reduced through the use of forward contracts. Our foreign transactions are primarily denominated in Australian dollars, Canadian dollars, British pounds, Brazilian reais and the European Monetary Unit. The sensitivity analysis assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their levels at December 31, 2012 and 2011, with all other variables held constant.

Commodity Price Risk – We have exposure to price risk as a result of our investments in commodities. Commodity price risk results from changes in the level or volatility of commodity prices that impact instruments which derive their value from such commodities. Commodity price risk was measured assuming an instantaneous increase of 20% from their levels at December 31, 2012 and 2011. The impact of a change in commodity prices on the Company’s non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the underlying hedged transaction, such as revenue from sales.

Credit Risk – We are exposed to credit risk relating to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Although nearly all of the Company’s customers pay for its services on a timely basis, the Company actively monitors the credit exposure to its customers. Certain of the Company’s subsidiaries may perform credit reviews of customers and may require customers to provide cash collateral, post a letter of credit, prepay for services or provide other credit enhancements.

The following tables present our market risk by category (equity prices, interest rates, foreign exchange rates and commodity prices) on the basis of those entered into for trading purposes and other than trading purposes.

Trading portfolio:


Category of risk exposure:	Fair Value Asset (Liability)					Market Risk

December 31	2012		2011			2012			2011

(In millions)

Equity prices (1):
Equity securities – long		$ 630		$ 590			$ (158	)		$ (148)
– short		(7)		(9	)		2			2
Options – purchased		19		33			23			18
– written		(14)		(23	)		(42	)		(2)
Interest rate (2):
Fixed maturities – long		161		109			5			(3)
– short		(77)					(7	)
Short term investments		2,526		2,092
Other derivatives		(3)		8			(3	)		(3)


Note:		The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of (1) a decrease in equity prices of 25% and (2) a decrease in yield rates of 100 basis points. Adverse changes on options which differ from those presented above would not necessarily result in a proportionate change to the estimated market risk exposure.

Other than trading portfolio:


Category of risk exposure:	Fair Value Asset (Liability)					Market Risk

December 31	2012		2011			2012			2011

(In millions)

Equity prices (1):
Equity securities:
General accounts (a)		$ 249		$ 304			$ (62	)		$ (76)
Limited partnership investments		3,090		2,711			(295	)		(242)
Interest rate (2):
Fixed maturities (a)		42,604		39,931			(2,818	)		(2,614)
Short term investments (a)		3,309		3,013			(3	)		(11)
Other invested assets, primarily mortgage loans		418		258			(18	)		(11)
Interest rate swaps and other (b)		(6)					10			13
Other derivative securities		(3)		(1	)
Separate accounts:
Fixed maturities		288		381			(4	)		(15)
Short term investments		21		32
Foreign exchange (3):
Forwards – short		4		(7	)		(27	)		(26)
Other invested assets		59					(11	)
Commodities (4):
Forwards – short (b)		36		42			(48	)		(43)


Note:	The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of (1) a decrease in equity prices of 25%, (2) an increase in yield rates of 100 basis points, (3) a decrease in the foreign currency exchange rates versus the U.S. dollar of 20% and (4) an increase in commodity prices of 20%.

	(a)	Certain securities are denominated in foreign currencies. An assumed 20% decline in the underlying exchange rates would result in an aggregate foreign currency exchange rate risk of $(490) and $(382) at December 31, 2012 and 2011.
	(b)	The market risk at December 31, 2012 and 2011 will generally be offset by recognition of the underlying hedged transaction.

Item 8. Financial Statements and Supplementary Data.

Financial Statements and Supplementary Data are comprised of the following sections:


		Page No.

Management’s Report on Internal Control Over Financial Reporting			99
Reports of Independent Registered Public Accounting Firm			100
Consolidated Balance Sheets			102
Consolidated Statements of Income			104
Consolidated Statements of Comprehensive Income			106
Consolidated Statements of Equity			107
Consolidated Statements of Cash Flows			109
Notes to Consolidated Financial Statements:			111
1.	Summary of Significant Accounting Policies		111
2.	Acquisition/Divestitures		119
3.	Investments		120
4.	Fair Value		126
5.	Derivative Financial Instruments		134
6.	Receivables		135
7.	Property, Plant and Equipment		135
8.	Claim and Claim Adjustment Expense Reserves		137
9.	Leases		144
10.	Income Taxes		145
11.	Debt		148
12.	Shareholders’ Equity		150
13.	Statutory Accounting Practices		151
14.	Supplemental Natural Gas and Oil Information (Unaudited)		152
15.	Benefit Plans		155
16.	Reinsurance		163
17.	Quarterly Financial Data (Unaudited)		165
18.	Legal Proceedings		165
19.	Commitments and Contingencies		166
20.	Business Segments		166
21.	Consolidating Financial Information		170

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for us. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2012, our internal control over financial reporting was effective.

Our independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on the Company’s internal control over financial reporting. The report of Deloitte & Touche LLP follows this Report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Loews Corporation

New York, NY

We have audited the internal control over financial reporting of Loews Corporation and subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2012 of the Company and our report dated February 22, 2013 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an explanatory paragraph regarding the change of accounting for costs associated with acquiring or renewing insurance contracts in 2012.

/s/ DELOITTE & TOUCHE LLP

New York, NY

February 22, 2013

100

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Loews Corporation

New York, NY

We have audited the accompanying consolidated balance sheets of Loews Corporation and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Loews Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 1 of the Notes to Consolidated Financial Statements, the Company changed its accounting for costs associated with acquiring or renewing insurance contracts in 2012.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New York, NY

February 22, 2013

101

Loews Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS



Assets:


December 31	2012		2011

(Dollar amounts in millions, except per share data)

Investments:

Fixed maturities, amortized cost of $38,324 and $37,466	$	42,765	$	40,040

Equity securities, cost of $893 and $902		898		927

Limited partnership investments		3,090		2,711

Other invested assets, primarily mortgage loans		460		245

Short term investments		5,835		5,105


Total investments		53,048		49,028

Cash		228		129

Receivables		9,366		9,259

Property, plant and equipment		13,935		13,618

Goodwill		996		908

Other assets		1,538		1,357

Deferred acquisition costs of insurance subsidiaries		598		552

Separate account business		312		417


Total assets	$	80,021	$	75,268

See Notes to Consolidated Financial Statements.

102

Loews Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS



Liabilities and Equity:

December 31	2012			2011

(Dollar amounts in millions, except per share data)

Insurance reserves:
Claim and claim adjustment expense	$	24,763		$	24,303
Future policy benefits		11,475			9,810
Unearned premiums		3,610			3,250
Policyholders’ funds		157			191

Total insurance reserves		40,005			37,554

Payable to brokers		205			162
Short term debt		19			88
Long term debt		9,191			8,913
Deferred incomes taxes		840			622
Other liabilities		4,773			4,309
Separate account business		312			417

Total liabilities		55,345			52,065


Commitments and contingent liabilities

Shareholders’ equity:
Preferred stock, $0.10 par value:
Authorized – 100,000,000 shares
Common stock, $0.01 par value:
Authorized – 1,800,000,000 shares
Issued – 392,054,766 and 396,585,226 shares		4			4
Additional paid-in capital		3,595			3,494
Retained earnings		15,192			14,890
Accumulated other comprehensive income		678			384

		19,469			18,772
Less treasury stock, at cost (249,600 shares)		(10	)

Total shareholders’ equity		19,459			18,772
Noncontrolling interests		5,217			4,431

Total equity		24,676			23,203

Total liabilities and equity	$	80,021		$	75,268

See Notes to Consolidated Financial Statements.

103

Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


Year Ended December 31	2012			2011			2010

(In millions, except per share data)

Revenues:
Insurance premiums	$	6,882		$	6,603		$	6,515
Net investment income		2,349			2,063			2,508
Investment gains (losses):
Other-than-temporary impairment losses		(129	)		(175	)		(254)
Portion of other-than-temporary impairment losses recognized in Other comprehensive income		(25	)		(41	)		22

Net impairment losses recognized in earnings		(154	)		(216	)		(232)
Other net investment gains		211			164			288

Total investment gains (losses)		57			(52	)		56
Contract drilling revenues		2,936			3,254			3,230
Other		2,328			2,261			2,306

Total		14,552			14,129			14,615


Expenses:
Insurance claims and policyholders’ benefits		5,896			5,489			4,985
Amortization of deferred acquisition costs		1,274			1,176			1,168
Contract drilling expenses		1,537			1,549			1,391
Other operating expenses (Notes 7 and 8)		4,006			3,167			3,652
Interest		440			522			517

Total		13,153			11,903			11,713

Income before income tax		1,399			2,226			2,902
Income tax expense		(289	)		(532	)		(894)

Income from continuing operations		1,110			1,694			2,008
Discontinued operations, net								(20)

Net income		1,110			1,694			1,988
Amounts attributable to noncontrolling interests		(542	)		(632	)		(699)

Net income attributable to Loews Corporation	$	568		$	1,062		$	1,289


Net income attributable to Loews Corporation:
Income from continuing operations	$	568		$	1,062		$	1,308
Discontinued operations, net								(19)

Net income	$	568		$	1,062		$	1,289

See Notes to Consolidated Financial Statements

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Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


Year Ended December 31	2012		2011		2010

(In millions, except per share data)

Basic net income per common share:
Income from continuing operations	$	1.44	$	2.62	$	3.12
Discontinued operations, net						(0.04)

Net income	$	1.44	$	2.62	$	3.08


Diluted net income per common share:
Income from continuing operations	$	1.43	$	2.62	$	3.11
Discontinued operations, net						(0.04)

Net income	$	1.43	$	2.62	$	3.07


Dividends per share	$	0.25	$	0.25	$	0.25

Basic weighted average number of shares outstanding		395.12		404.53		418.72

Diluted weighted average number of shares outstanding		395.87		405.32		419.52

See Notes to Consolidated Financial Statements.

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Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


Year Ended December 31	2012			2011			2010

(In millions)

Net income	$	1,110		$	1,694		$	1,988


Other comprehensive income (loss), after tax
Changes in:
Net unrealized gains on investments with other-than-temporary impairments		84			10			86
Net other unrealized gains on investments		339			362			494

Total unrealized gains on available-for-sale investments		423			372			580
Unrealized gains (losses) on cash flow hedges		(8	)		39			60
Foreign currency		39			(14	)		49
Pension liability		(132	)		(238	)		29


Other comprehensive income		322			159			718


Comprehensive income		1,432			1,853			2,706

Amounts attributable to noncontrolling interests		(575	)		(648	)		(771)


Total comprehensive income attributable to Loews Corporation	$	857		$	1,205		$	1,935

See Notes to Consolidated Financial Statements.

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Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF EQUITY


	Loews Corporation Shareholders
												Accumulated		Common
						Additional						Other		Stock
				Common		Paid-in			Retained			Comprehensive		Held in		Noncontrolling
	Total			Stock		Capital			Earnings			Income (Loss)		Treasury		Interests

(In millions)

Balance, January 1, 2010	$	21,085		$	4	$	3,637		$	13,693			$ (419)		$ (16)	$	4,186
Adjustment to initially apply guidance on accounting for costs associated with acquiring or renewing insurance contracts		(79	)							(65	)						(14)
Net income		1,988								1,289							699
Other comprehensive income		718											646				72
Dividends paid		(597	)							(105	)						(492)
Issuance of equity securities by subsidiary		279					83						1				195
Purchase of Loews treasury stock		(405	)												(405)
Issuance of Loews common stock		8					8
Retirement of treasury stock		-					(97	)		(309	)				406
Stock-based compensation		21					18										3
Other		10					18			(3	)		2				(7)

Balance, December 31, 2010		23,028			4		3,667			14,500			230		(15)		4,642
Net income		1,694								1,062							632
Other comprehensive income		159											143				16
Dividends paid		(500	)							(101	)						(399)
Acquisition of CNA Surety noncontrolling interests		(475	)				(59	)					17				(433)
Disposition of FICOH ownership interest		(155	)										(7)				(148)
Issuance of equity securities by subsidiary		152					28						1				123
Purchase of Loews treasury stock		(718	)												(718)
Retirement of treasury stock		-					(164	)		(569	)				733
Issuance of Loews common stock		4					4
Stock-based compensation		22					19										3
Other		(8	)				(1	)		(2	)						(5)

Balance, December 31, 2011	$	23,203		$	4	$	3,494		$	14,890		$	384	$	-	$	4,431

See Notes to Consolidated Financial Statements.

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Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF EQUITY

Loews Corporation Shareholders

Accumulated

Common

Additional

Other

Stock

Common

Paid-in

Retained

Comprehensive

Held in

Noncontrolling

Total

Stock

Capital

Earnings

Income

Treasury

Interests

(In millions)

Balance, December 31, 2011

23,203

3,494

14,890

384

4,431

Net income

1,110

568

542

Other comprehensive income

322

289

Dividends paid

(549)

(99)

(450)

Issuance of equity securities by subsidiary

774

115

654

Purchase of Loews treasury stock

(222)

Retirement of treasury stock

(47)

(165)

212

Issuance of Loews common stock

Stock-based compensation

Other

(2)

Balance, December 31, 2012

24,676

3,595

15,192

678

(10)

5,217

See Notes to Consolidated Financial Statements.

108

Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year Ended December 31	2012			2011			2010

(In millions)

Operating Activities:

Net income	$	1,110		$	1,694		$	1,988
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Income from discontinued operations								20
Investment (gains) losses		(57	)		52			(56)
Undistributed (earnings) losses		(103	)		74			(184)
Amortization of investments		(50	)		(64	)		(118)
Depreciation, depletion and amortization		905			833			816
Impairment of natural gas and oil properties		680
Provision for deferred income taxes		(22	)		268			470
Other non-cash items		55			52			(53)
Changes in operating assets and liabilities, net:
Receivables		327			1,085			(335)
Deferred acquisition costs		(16	)		(1	)		29
Insurance reserves		430			(237	)		(805)
Other assets		74			181			(83)
Other liabilities		(73	)		(326	)		132
Trading securities		(406	)		354			(1,778)

Net cash flow operating activities - continuing operations		2,854			3,965			43
Net cash flow operating activities - discontinued operations								(90)

Net cash flow operating activities - total		2,854			3,965			(47)


Investing Activities:

Purchases of fixed maturities		(10,299	)		(12,168	)		(16,715)
Proceeds from sales of fixed maturities		6,123			7,591			12,514
Proceeds from maturities of fixed maturities		3,699			3,055			3,340
Purchases of equity securities		(54	)		(72	)		(99)
Proceeds from sales of equity securities		86			178			341
Purchases of limited partnership investments		(372	)		(303	)		(663)
Proceeds from sales of limited partnership investments		227			143			166
Purchases of property, plant and equipment		(1,236	)		(857	)		(917)
Deposits for construction of offshore drilling equipment		(169	)		(478	)
Acquisitions		(987	)		(548	)
Dispositions		221			222			805
Change in short term investments		(192	)		1,461			1,892
Other, net		(142	)		(127	)		(76)

Net cash flow investing activities - continuing operations		(3,095	)		(1,903	)		588
Net cash flow investing activities - discontinued operations								76

Net cash flow investing activities - total		(3,095	)		(1,903	)		664

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Loews Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year Ended December 31	2012			2011			2010

(In millions)

Financing Activities:

Dividends paid	$	(99	)	$	(101	)		$ (105)
Dividends paid to noncontrolling interests		(450	)		(399	)		(492)
Acquisition of CNA Surety noncontrolling interests					(475	)
Purchases of treasury shares		(212	)		(732	)		(405)
Issuance of common stock		13			4			8
Proceeds from sale of subsidiary stock		849			172			344
Principal payments on debt		(2,910	)		(2,832	)		(659)
Issuance of debt		3,152			2,321			645
Other, net		(7	)		(11	)		(24)

Net cash flow financing activities - continuing operations		336			(2,053	)		(688)
Net cash flow financing activities - discontinued operations

Net cash flow financing activities - total		336			(2,053	)		(688)


Effect of foreign exchange rate on cash - continuing operations		4						1


Net change in cash		99			9			(70)
Net cash transactions:
From continuing operations to discontinued operations								(14)
To discontinued operations from continuing operations								14
Cash, beginning of year		129			120			190

Cash, end of year	$	228		$	129		$	120

See Notes to Consolidated Financial Statements.

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Loews Corporation and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

Basis of presentation – Loews Corporation is a holding company. Its subsidiaries are engaged in the following lines of business: commercial property and casualty insurance (CNA Financial Corporation (“CNA”), a 90% owned subsidiary); the operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc. (“Diamond Offshore”), a 50.4% owned subsidiary); transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas (Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”), a 55% owned subsidiary); exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC (“HighMount”), a wholly owned subsidiary); and the operation of hotels (Loews Hotels Holding Corporation (“Loews Hotels”), a wholly owned subsidiary). Unless the context otherwise requires, the terms “Company,” “Loews” and “Registrant” as used herein mean Loews Corporation excluding its subsidiaries and the term “Net income (loss) attributable to Loews Corporation” as used herein means Net income (loss) attributable to Loews Corporation Shareholders.

Principles of consolidation – The Consolidated Financial Statements include all subsidiaries and intercompany accounts and transactions have been eliminated. The equity method of accounting is used for investments in associated companies in which the Company generally has an interest of 20% to 50%.

Accounting estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and the related notes. Actual results could differ from those estimates.

Accounting changes – In October of 2010, the Financial Accounting Standards Board (“FASB”) issued updated accounting guidance which limits the capitalization of costs incurred to acquire or renew insurance contracts to those that are incremental direct costs of successful contract acquisitions. The previous guidance allowed the capitalization of acquisition costs that vary with and are primarily related to the acquisition of new and renewal insurance contracts, whether the costs related to successful or unsuccessful efforts.

As of January 1, 2012, the Company adopted the updated accounting guidance prospectively as of January 1, 2004, the earliest date practicable. Due to the lack of available historical data related to certain accident and health contracts issued prior to January 1, 2004, a full retrospective application of the change in accounting guidance was impracticable. Acquisition costs capitalized prior to January 1, 2004 will continue to be accounted for under the previous accounting guidance and will be amortized over the premium-paying period of the related policies using assumptions consistent with those used for computing future policy benefit reserves for such contracts.

The Company has adjusted its previously reported financial information included herein to reflect the change in accounting guidance for deferred acquisition costs. The impacts of adopting the new accounting standard on the Company’s Consolidated Balance Sheet as of December 31, 2011 were a $106 million decrease in Deferred acquisition costs of insurance subsidiaries and a $37 million decrease in Deferred income tax liabilities. The impacts to Accumulated other comprehensive income (“AOCI”) and Additional paid-in capital (“APIC”) were the result of the indirect effects of the Company’s adoption of this guidance on Shadow Adjustments, as further discussed below, and CNA’s acquisition of the noncontrolling interest of CNA Surety in 2011.

The impacts on the Company’s Consolidated Statements of Income for the years ended December 31, 2011 and 2010 were $234 million and $219 million decreases in Amortization of deferred acquisition costs, $242 million and $219 million increases in Other operating expenses, resulting in a $2 million decrease and a $1 million increase in Net income and a $0.01 decrease and no impact in Basic and Diluted net income per share. There were no changes to net cash flows from operating, investing or financing activities for the comparative periods presented as a result of the adoption of the new accounting standard.

Investments – The Company classifies its fixed maturity securities and equity securities as either available-for-sale or trading, and as such, they are carried at fair value. Short term investments are carried at fair value. Changes

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in fair value of trading securities are reported within Net investment income on the Consolidated Statements of Income. Changes in fair value related to available-for-sale securities are reported as a component of Other comprehensive income. The cost of fixed maturity securities classified as available-for-sale is adjusted for amortization of premiums and accretion of discounts to maturity, which are included in Net investment income on the Consolidated Statements of Income. Losses may be recognized within the Consolidated Statements of Income when a decline in value is determined by the Company to be other-than-temporary.

To the extent that unrealized gains on fixed income securities supporting long term care products and payout annuity contracts would result in a premium deficiency if those gains were realized, a related decrease in Deferred acquisition costs and/or increase in Insurance reserves is recorded, net of tax and noncontrolling interests, as a reduction of net unrealized gains through Other comprehensive income (“Shadow Adjustments”). For the years ended December 31, 2012 and 2011, Shadow Adjustments, net of participating policyholders’ interest, of $710 million and $515 million were recorded (after tax and noncontrolling interests). At December 31, 2012 and 2011, net unrealized gains on investments included in AOCI were correspondingly reduced by $1.4 billion and $650 million (after tax and noncontrolling interests).

For asset-backed securities included in fixed maturity securities, the Company recognizes income using an effective yield based on anticipated prepayments and the estimated economic life of the securities. When estimates of prepayments change, the effective yield is recalculated to reflect actual payments to date and anticipated future payments. The amortized cost of high credit quality securities is adjusted to the amount that would have existed had the new effective yield been applied since the acquisition of the securities. Such adjustments are reflected in Net investment income on the Consolidated Statements of Income. Interest income on lower rated securities is determined using the prospective yield method.

The Company’s carrying value of investments in limited partnerships is its share of the net asset value of each partnership, as determined by the General Partner. Certain partnerships for which results are not available on a timely basis are reported on a lag, primarily three months or less. These investments are accounted for under the equity method and changes in net asset values are recorded within Net investment income on the Consolidated Statements of Income.

Investments in derivative securities are carried at fair value with changes in fair value reported as a component of Investment gains (losses), Income (loss) from trading portfolio, or Other comprehensive income (loss), depending on their hedge designation. A derivative is typically defined as an instrument whose value is “derived” from an underlying instrument, index or rate, has a notional amount, requires little or no initial investment and can be net settled. Derivatives include, but are not limited to, the following types of investments: interest rate swaps, interest rate caps and floors, put and call options, warrants, futures, forwards, commitments to purchase securities, credit default swaps and combinations of the foregoing. Derivatives embedded within non-derivative instruments (such as call options embedded in convertible bonds) must be split from the host instrument when the embedded derivative is not clearly and closely related to the host instrument.

Hedging – The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedging transactions. The Company also formally assesses (both at the hedge’s inception and on an ongoing basis) whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in fair value or cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods. When it is determined that a derivative for which hedge accounting has been designated is not (or ceases to be) highly effective, the Company discontinues hedge accounting prospectively. See Note 5 for additional information on the Company’s use of derivatives.

Securities lending activities – The Company lends securities for the purpose of enhancing income or to finance positions to unrelated parties who have been designated as primary dealers by the Federal Reserve Bank of New York. Borrowers of these securities must deposit and maintain collateral with the Company of no less than 100% of the fair value of the securities loaned. U.S. Government securities and cash are accepted as collateral. The Company maintains effective control over loaned securities and, therefore, continues to report such securities as investments on the Consolidated Balance Sheets.

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Securities lending is typically done on a matched-book basis where the collateral is invested to substantially match the term of the loan. This matching of terms tends to limit risk. In accordance with the Company’s lending agreements, securities on loan are returned immediately to the Company upon notice. Collateral is not reflected as an asset of the Company. There was no collateral held at December 31, 2012 and 2011.

Revenue recognition – Premiums on property and casualty insurance contracts are recognized in proportion to the underlying risk insured which principally are earned ratably over the duration of the policies. Premiums on long term care contracts are earned ratably over the policy year in which they are due. The reserve for unearned premiums represents the portion of premiums written relating to the unexpired terms of coverage.

Insurance receivables include balances due currently or in the future, including amounts due from insureds related to losses under high deductible policies, and are presented at unpaid balances, net of an allowance for doubtful accounts. Amounts are considered past due based on policy payment terms. That allowance is determined based on periodic evaluations of aged receivables, management’s experience and current economic conditions. Insurance receivables and any related allowance are written off after collection efforts are exhausted or a negotiated settlement is reached.

Property and casualty contracts that are retrospectively rated contain provisions that result in an adjustment to the initial policy premium depending on the contract provisions and loss experience of the insured during the experience period. For such contracts, CNA estimates the amount of ultimate premiums that it may earn upon completion of the experience period and recognizes either an asset or a liability for the difference between the initial policy premium and the estimated ultimate premium. CNA adjusts such estimated ultimate premium amounts during the course of the experience period based on actual results to date. The resulting adjustment is recorded as either a reduction of or an increase to the earned premiums for the period.

Contract drilling revenue from dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, Diamond Offshore may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. Absent a contract, mobilization costs are recognized currently. From time to time, Diamond Offshore may receive fees from its customers for capital improvements to their rigs. Diamond Offshore defers such fees received and recognizes these fees into revenue on a straight-line basis over the period of the related drilling contract. Diamond Offshore capitalizes the costs of such capital improvements and depreciates them over the estimated useful life of the improvement.

Revenues from transportation and storage services are recognized in the period the service is provided based on contractual terms and the related transported and stored volumes. The majority of Boardwalk Pipeline’s operating subsidiaries are subject to Federal Energy Regulatory Commission (“FERC”) regulations and, accordingly, certain revenues collected may be subject to possible refunds to its customers. An estimated refund liability is recorded considering regulatory proceedings, advice of counsel and estimated total exposure.

HighMount’s natural gas and oil production revenue is recognized based on actual volumes of natural gas and oil sold to purchasers. Sales require delivery of the product to the purchaser, passage of title and probability of collection of purchaser amounts owed. Natural gas and oil production revenue is reported net of royalties. HighMount uses the sales method of accounting for gas imbalances. An imbalance is created when the volumes of gas sold by HighMount pertaining to a property do not equate to the volumes produced to which HighMount is entitled based on its interest in the property. An asset or liability is recognized to the extent that HighMount has an imbalance in excess of the remaining reserves on the underlying properties.

Claim and claim adjustment expense reserves – Claim and claim adjustment expense reserves, except reserves for structured settlements not associated with asbestos and environmental pollution (“A&EP”), workers’ compensation lifetime claims, and accident and health claims are not discounted and are based on (i) case basis estimates for losses reported on direct business, adjusted in the aggregate for ultimate loss expectations; (ii) estimates of incurred but not reported losses; (iii) estimates of losses on assumed reinsurance; (iv) estimates of future expenses to be incurred in the settlement of claims; (v) estimates of salvage and subrogation recoveries and (vi) estimates of amounts due from insureds related to losses under high deductible policies. Management considers current conditions and trends as well as past CNA and industry experience in establishing these estimates. The

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effects of inflation, which can be significant, are implicitly considered in the reserving process and are part of the recorded reserve balance. Ceded claim and claim adjustment expense reserves are reported as a component of Receivables on the Consolidated Balance Sheets.

Claim and claim adjustment expense reserves are presented net of anticipated amounts due from insureds related to losses under deductible policies of $1.3 billion and $1.4 billion as of December 31, 2012 and 2011. A significant portion of these amounts are supported by collateral. CNA also has an allowance for uncollectible deductible amounts, which is presented as a component of the allowance for doubtful accounts included in Receivables on the Consolidated Balance Sheets.

Structured settlements have been negotiated for certain property and casualty insurance claims. Structured settlements are agreements to provide fixed periodic payments to claimants. Certain structured settlements are funded by annuities purchased from Continental Assurance Company (“CAC”), a wholly owned and consolidated subsidiary of CNA, for which the related annuity obligations are reported in Future policy benefits reserves. Obligations for structured settlements not funded by annuities are included in claim and claim adjustment expense reserves and carried at present values determined using interest rates ranging from 7.1% to 9.7% at December 31, 2012 and 5.5% to 8.0% at December 31, 2011. At December 31, 2012 and 2011, the discounted reserves for unfunded structured settlements were $602 million and $632 million, net of discount of $1.0 billion and $1.1 billion.

Workers’ compensation lifetime claim reserves are calculated using mortality assumptions determined through statutory regulation and economic factors. Accident and health claim reserves are calculated using mortality and morbidity assumptions based on CNA and industry experience. Workers’ compensation lifetime claim reserves and accident and health claim reserves are discounted at interest rates ranging from 3.0% to 6.5% at both December 31, 2012 and 2011. At December 31, 2012 and 2011, such discounted reserves totaled $2.2 billion and $2.1 billion, net of discount of $837 million and $520 million.

Future policy benefits reserves – Reserves for long term care products and payout annuity contracts are computed using the net level premium method, which incorporates actuarial assumptions as to morbidity, mortality, persistency, discount rates, which are impacted by expected investment yields and expenses. Expense assumptions include the estimated effects of expenses to be incurred beyond the premium paying period. Actuarial assumptions generally vary by plan, age at issue and policy duration. The initial assumptions are determined at issuance, include a margin for adverse deviation, and are locked in throughout the life of the contract unless a premium deficiency develops. If a premium deficiency emerges, the assumptions are unlocked and deferred acquisition costs, if any, and the future policy benefit reserves are adjusted. Interest rates for long term care products range from 5.0% to 7.4% at December 31, 2012 and from 5.0% to 7.5% at December 31, 2011. Interest rates for payout annuity contracts range from 5.0% to 8.7% at December 31, 2012 and from 5.4% to 7.5% at December 31, 2011. In 2012, CNA unlocked assumptions related to its payout annuity contracts due to anticipated adverse changes in discount rates, which reflect the current low interest rate environment and its view of expected investment yields, resulting in loss recognition which increased insurance liabilities by $33 million. In 2011, CNA unlocked assumptions related to its payout annuity contracts due to anticipated adverse changes in mortality and discount rates resulting in loss recognition which increased insurance reserves by $166 million.

Policyholders’ funds reserves – Policyholders’ funds reserves primarily include reserves for investment contracts without life contingencies. For these contracts, policyholder liabilities are generally equal to the accumulated policy account values, which consist of an accumulation of deposit payments plus credited interest, less withdrawals and amounts assessed through the end of the period.

Guaranty fund and other insurance-related assessments – Liabilities for guaranty fund and other insurance-related assessments are accrued when an assessment is probable, when it can be reasonably estimated, and when the event obligating the entity to pay an imposed or probable assessment has occurred. Liabilities for guaranty funds and other insurance-related assessments are not discounted and are included as part of Other liabilities on the Consolidated Balance Sheets. As of December 31, 2012 and 2011, the liability balances were $143 million and $152 million. As of December 31, 2012 and 2011, included in Other assets on the Consolidated Balance Sheets were $2 million of related assets for premium tax offsets. This asset is limited to the amount that is able to be offset against premium tax on future premium collections from business written or committed to be written.

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Reinsurance – Reinsurance accounting allows for contractual cash flows to be reflected as premiums and losses. To qualify for reinsurance accounting, reinsurance agreements must include risk transfer. To meet risk transfer requirements, a reinsurance contract must include both insurance risk, consisting of underwriting and timing risk, and a reasonable possibility of a significant loss for the assuming entity.

Reinsurance receivables related to paid losses are presented at unpaid balances. Reinsurance receivables related to unpaid losses are estimated in a manner consistent with claim and claim adjustment expense reserves or future policy benefits reserves. Reinsurance receivables are reported net of an allowance for doubtful accounts on the Consolidated Balance Sheets. The cost of reinsurance is primarily accounted for over the life of the underlying reinsured policies using assumptions consistent with those used to account for the underlying policies or over the reinsurance contract period. The ceding of insurance does not discharge the primary liability of CNA.

CNA has established an allowance for doubtful accounts on reinsurance receivables which relates to both amounts already billed on ceded paid losses as well as ceded reserves that will be billed when losses are paid in the future. The allowance for doubtful accounts on reinsurance receivables is estimated on the basis of periodic evaluations of balances due from reinsurers, reinsurer solvency, management’s experience and current economic conditions. Reinsurer financial strength ratings are updated and reviewed on an annual basis or sooner if CNA becomes aware of significant changes related to a reinsurer. Because billed receivables are generally 5% or less of total reinsurance receivables, the age of the reinsurance receivables related to paid losses is not a significant input into the allowance analysis. Changes in the allowance for doubtful accounts on reinsurance receivables are presented as a component of Insurance claims and policyholders’ benefits on the Consolidated Statements of Income.

Amounts are considered past due based on the reinsurance contract terms. Reinsurance receivables related to paid losses and any related allowance are written off after collection efforts have been exhausted or a negotiated settlement is reached with the reinsurer. Reinsurance receivables related to paid losses from insolvent insurers are written off when the settlement due from the estate can be reasonably estimated. At the time reinsurance receivables related to paid losses are written off, any required adjustment to reinsurance receivables related to unpaid losses is recorded as a component of Insurance claims and policyholders’ benefits on the Consolidated Statements of Income.

Reinsurance contracts that do not effectively transfer the economic risk of loss on the underlying policies are recorded using the deposit method of accounting, which requires that premium paid or received by the ceding company or assuming company be accounted for as a deposit asset or liability. CNA had $3 million and $18 million recorded as deposit assets at December 31, 2012 and 2011, and $125 million and $123 million recorded as deposit liabilities at December 31, 2012 and 2011. Income on reinsurance contracts accounted for under the deposit method is recognized using an effective yield based on the anticipated timing of payments and the remaining life of the contract. When the anticipated timing of payments changes, the effective yield is recalculated to reflect actual payments to date and the estimated timing of future payments. The deposit asset or liability is adjusted to the amount that would have existed had the new effective yield been applied since the inception of the contract.

Participating insurance – Policyholder dividends are accrued using an estimate of the amount to be paid based on underlying contractual obligations under policies and applicable state laws. Limitations exist on the amount of income from participating life insurance contracts that may be distributed to shareholders, and therefore the share of income on these policies that cannot be distributed to shareholders is excluded from Shareholders’ Equity by a charge to Income and Other comprehensive income and the establishment of a corresponding liability.

Deferred acquisition costs – Acquisition costs include commissions, premium taxes and certain underwriting and policy issuance costs which are incremental direct costs of successful contract acquisitions. Deferred acquisition costs related to long term care contracts issued prior to January 1, 2004 include costs which vary with and are primarily related to the acquisition of business, as further discussed above.

Acquisition costs related to property and casualty business are deferred and amortized ratably over the period the related premiums are earned.

Deferred acquisition costs related to long term care contracts are amortized over the premium-paying period of the related policies using assumptions consistent with those used for computing future policy benefit reserves for such contracts. Assumptions are made at the date of policy issuance or acquisition and are consistently applied during the

115

lives of the contracts. Deviations from estimated experience are included in results of operations when they occur. For these contracts, the amortization period is typically the estimated life of the policy. At December 31, 2012 and 2011, deferred acquisition costs were presented net of Shadow Adjustments of $369 million and $398 million.

CNA evaluates deferred acquisition costs for recoverability. Anticipated investment income is considered in the determination of the recoverability of deferred acquisition costs. Adjustments, if necessary, are recorded in current results of operations.

Deferred acquisition costs are presented net of ceding commissions and other ceded acquisition costs. Unamortized deferred acquisition costs relating to contracts that have been substantially changed by a modification in benefits, features, rights or coverages that were not anticipated in the original contract are not deferred and are included as a charge to operations in the period during which the contract modification occurred.

Investments in life settlement contracts and related revenue recognition – Prior to 2002, CNA purchased investments in life settlement contracts. A life settlement contract is a contract between the owner of a life insurance policy (the policy owner) and a third party investor (investor). Under a life settlement contract, CNA obtained the ownership and beneficiary rights of an underlying life insurance policy.

CNA accounts for its investments in life settlement contracts using the fair value method. Under the fair value method, each life settlement contract is carried at its fair value at the end of each reporting period. The change in fair value, life insurance proceeds received and periodic maintenance costs, such as premiums, necessary to keep the underlying policy in force, are recorded in Other revenues on the Consolidated Statements of Income. The fair value of CNA’s investments in life settlement contracts were $100 million and $117 million at December 31, 2012 and 2011, and are included in Other assets on the Consolidated Balance Sheets. The cash receipts and payments related to life settlement contracts are included in Cash flows from operating activities on the Consolidated Statements of Cash Flows.

The following table details the values for life settlement contracts. The determination of fair value is discussed in Note 4.


	Number of Life Settlement Contracts		Fair Value of Life Settlement Contracts		Face Amount of Life Insurance Policies

(Dollar amounts in millions)

Estimated maturity during:
2013		70	$	15	$	41
2014		60		13		36
2015		60		11		34
2016		50		9		30
2017		40		7		27
Thereafter		390		45		237

Total		670	$	100	$	405

CNA uses an actuarial model to estimate the aggregate face amount of life insurance that is expected to mature in each future year and the corresponding fair value. This model projects the likelihood of the insured’s death for each inforce policy based upon CNA’s estimated mortality rates, which may vary due to the relatively small size of the portfolio of life settlement contracts. The number of life settlement contracts presented in the table above is based upon the average face amount of inforce policies estimated to mature in each future year.

The increase in fair value recognized for the years ended December 31, 2012, 2011 and 2010 on contracts still being held was $11 million, $5 million and $10 million. The gains recognized during the years ended December 31, 2012, 2011 and 2010 on contracts that settled were $42 million, $28 million and $19 million.

Separate Account Business – Separate account assets and liabilities represent contract holder funds related to investment and annuity products for which the policyholder assumes substantially all the risk and reward. The assets

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are segregated into accounts with specific underlying investment objectives and are legally segregated from CNA. All assets of the separate account business are carried at fair value with an equal amount recorded for separate account liabilities. Fee income accruing to CNA related to separate accounts is primarily included within Other revenues on the Consolidated Statements of Income.

A number of separate account pension deposit contracts guarantee principal and an annual minimum rate of interest. If aggregate contract value in the separate account exceeds the fair value of the related assets, an additional Policyholders’ funds liability is established. During 2012 and 2010, CNA decreased this pretax Policyholders’ funds liability by $20 million and $24 million. CNA increased this pretax Policyholders’ funds liability by $18 million in 2011. Certain of these contracts are subject to a fair value adjustment if terminated by the policyholder.

Goodwill – Goodwill represents the excess of purchase price over fair value of net assets of acquired entities. Goodwill is tested for impairment annually or when certain triggering events require additional tests. In 2012, Boardwalk Pipeline changed the date of its annual goodwill impairment test from December 31 to November 30. The change is preferable as it better aligns Boardwalk Pipeline’s goodwill impairment testing procedures with its planning process and alleviates resource constraints in connection with its year-end closing and financial reporting process. Due to significant judgments and estimates that are utilized in an impairment analysis, Boardwalk Pipeline determined it was impracticable to objectively determine operating and valuation estimates prior to November 30, 2012. As a result, the change in accounting principle was prospectively applied from November 30, 2012 and does not delay, accelerate, or avoid an impairment charge.

As a result of impairments of its Natural gas and oil properties (see Note 7), which were caused by declines in natural gas and natural gas liquids (“NGL”) prices, HighMount tested its goodwill for impairment at December 31, 2012. No impairment charge was required.

Property, plant and equipment – Property, plant and equipment is carried at cost less accumulated depreciation, depletion and amortization (“DD&A”). Depreciation is computed principally by the straight-line method over the estimated useful lives of the various classes of properties. Leaseholds and leasehold improvements are depreciated or amortized over the terms of the related leases (including optional renewal periods where appropriate) or the estimated lives of improvements, if less than the lease term.

The principal service lives used in computing provisions for depreciation are as follows:


		Years
Pipeline equipment		30 to 50
Offshore drilling equipment		15 to 30
Other		3 to 40

HighMount follows the full cost method of accounting for natural gas and oil exploration and production activities. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved natural gas and oil reserves, assuming an average price during the twelve month period adjusted for cash flow hedges in place, and limiting the classification of proved undeveloped reserves to locations scheduled to be drilled within five years. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. A write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Approximately 5.8% (unaudited) of HighMount’s total proved reserves as of December 31, 2012 are hedged by qualifying cash flow hedges, for which hedge adjusted prices were used to calculate estimated future net revenue. Future cash flows associated with settling asset retirement obligations that have been accrued in the Consolidated Balance Sheets are excluded from HighMount’s calculations of discounted cash flows under the full cost ceiling test.

Depletion of natural gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the base of costs subject to depletion also includes estimated future costs to be incurred in developing proved natural gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties including associated exploration-related costs are initially

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excluded from the depletable base. As the unproved properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over the terms of underlying leases. Once a property has been completely evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, proceeds from the sale or other disposition of natural gas and oil properties are accounted for as reductions of capitalized cost, unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case, a gain or loss is recognized.

Impairment of long-lived assets – The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets and intangibles with finite lives, under certain circumstances, are reported at the lower of carrying amount or fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.

Income taxes – The Company and its eligible subsidiaries file a consolidated tax return. Deferred income taxes are recognized for temporary differences between the financial statement and tax return bases of assets and liabilities, based on enacted tax rates and other provisions of the tax law. The effect of a change in tax laws or rates on deferred tax assets and liabilities is recognized in income in the period in which such change is enacted. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not, and a valuation allowance is established for any portion of a deferred tax asset that management believes may not be realized.

The Company recognizes uncertain tax positions that it has taken or expects to take on a tax return. The tax benefit of a qualifying position is the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority having full knowledge of all relevant information. See Note 10 for additional information on the provision for income taxes.

Pension and postretirement benefits – The Company recognizes the overfunded or underfunded status of its defined benefit plans in Other assets or Other liabilities in the Consolidated Balance Sheets. Changes in funded status related to prior service costs and credits and actuarial gains and losses are recognized in the year in which the changes occur through Accumulated other comprehensive income (loss). The Company measures its benefit plan assets and obligations at December 31. Annual service cost, interest cost, expected return on plan assets, amortization of prior service costs and credits and amortization of actuarial gains and losses are recognized in the Consolidated Statements of Income.

Stock based compensation – The Company records compensation expense upon issuance of share-based payment awards for all awards it grants, modifies, repurchases or cancels primarily on a straight-line basis over the requisite service period, generally four years. The share-based payment awards are valued using the Black-Scholes option pricing model. The application of this valuation model involves assumptions that are judgmental and highly sensitive in the valuation of these awards. These assumptions include the term that the awards are expected to be outstanding, an estimate of the volatility of the underlying stock price, applicable risk-free interest rates and the dividend yield of the Company’s stock.

The Company recognized compensation expense that decreased net income by $13 million for the year ended December 31, 2012. For the years ended December 31, 2011 and 2010 the Company recognized compensation expense that decreased net income by $12 million each year. Several of the Company’s subsidiaries also maintain their own stock option plans. The amounts reported above include the Company’s share of expense related to its subsidiaries’ plans.

Net income Per Share – Companies with complex capital structures are required to present basic and diluted net income per share. Basic net income per share excludes dilution and is computed by dividing net income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

For each of the years ended December 31, 2012, 2011 and 2010, approximately 0.8 million potential shares attributable to exercises under the Loews Corporation Stock Option Plan were included in the calculation of diluted net income per share. For those same periods, approximately 2.6 million, 2.0 million and 2.4 million Stock

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Appreciation Rights (“SARs”) were not included in the calculation of diluted net income per share due to the exercise price being greater than the average stock price.

Foreign currency – Foreign currency translation gains and losses are reflected in Shareholders’ equity as a component of Accumulated other comprehensive income (loss). The Company’s foreign subsidiaries’ balance sheet accounts are translated at the exchange rates in effect at each year end and income statement accounts are translated at the average exchange rates. Foreign currency transaction gains of $10 million for the year ended December 31, 2012 and foreign currency transaction losses of $5 million and $18 million for the years ended December 31, 2011 and 2010 were included in the Consolidated Statements of Income.

Regulatory accounting – The majority of Boardwalk Pipeline’s operating subsidiaries are regulated by FERC. GAAP for regulated entities requires Texas Gas Transmission, LLC (“Texas Gas”), a wholly owned subsidiary of Boardwalk Pipeline, to report certain assets and liabilities consistent with the economic effect of the manner in which independent third party regulators establish rates. Accordingly, certain costs and benefits are capitalized as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods. Regulatory accounting is not applicable to Boardwalk Pipeline’s other FERC regulated entities.

Supplementary cash flow information – Cash payments made for interest on long term debt, net of capitalized interest, amounted to $450 million, $526 million and $494 million for the years ended December 31, 2012, 2011 and 2010. Cash payments for federal, foreign, state and local income taxes amounted to $120 million, $322 million and $378 million for the years ended December 31, 2012, 2011 and 2010. Investing activities exclude $35 million and $14 million of accrued capital expenditures for the years ended December 31, 2012 and 2011. For the year ended December 31, 2010 investing activities include $51 million of previously accrued capital expenditures.

Note 2. Acquisition/Divestitures

CNA Financial

On July 2, 2012, CNA acquired Hardy Underwriting Bermuda Limited (“Hardy”), a specialized Lloyd’s of London (“Lloyd’s”) underwriter. Through Lloyd’s syndicate 382, Hardy underwrites primarily short-tail exposures in marine and aviation, non-marine property, specialty lines and property treaty reinsurance. Hardy has business operations in the United Kingdom, Bermuda, Bahrain, Guernsey and Singapore. For the year ended December 31, 2011, Hardy reported gross written premiums of $430 million. The purchase price for Hardy was $231 million and resulted in CNA recording $55 million of identifiable indefinite-lived intangible assets, $81 million of identifiable finite-lived intangible assets and $35 million of goodwill.

In November of 2011, CNA completed the sale of its 50% ownership interest in First Insurance Company of Hawaii (“FICOH”) and received $165 million in net proceeds. This sale did not have a significant impact on the Company’s results of operations.

On June 10, 2011, CNA completed the acquisition of all of the publicly traded shares of common stock of CNA Surety Corporation (“CNA Surety”) for $475 million. Prior to the acquisition, CNA owned approximately 61% of the outstanding common stock of CNA Surety.

Boardwalk Pipeline

On October 1, 2012, a joint venture between Boardwalk Pipeline and Boardwalk Pipelines Holding Corp. (“BPHC”), a wholly owned subsidiary of the Company, acquired Boardwalk Louisiana Midstream LLC (“Louisiana Midstream”), a company that provides salt dome storage, pipeline transportation, fractionation and brine supply services, from PL Logistics LLC for approximately $620 million. The acquisition was funded with proceeds from a $225 million five-year variable rate term loan and equity contributions by BPHC of $269 million for a 65% equity interest and of $148 million by Boardwalk Pipeline for a 35% equity interest. The joint venture recorded $25 million of identifiable finite-lived intangible assets and $56 million of goodwill. On October 15, 2012, Boardwalk Pipeline acquired BPHC’s 65% equity interest in the joint venture for $269 million, which did not result in any significant adjustments to the Consolidated Financial Statements.

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In December of 2011, Boardwalk HP Storage Company, LLC (“HP Storage”) acquired seven salt dome natural gas storage caverns and associated assets in Mississippi for approximately $550 million. HP Storage funded the acquisition with proceeds from a $200 million five-year variable rate term loan and equity contributions from BPHC and Boardwalk Pipeline. BPHC contributed $280 million for an 80% interest in HP Storage and Boardwalk Pipeline contributed $70 million for a 20% interest. HP Storage recorded $52 million of goodwill and $14 million of identifiable finite-lived intangible assets. In February of 2012, Boardwalk Pipeline acquired BPHC’s 80% interest in HP Storage for $285 million, which did not result in any significant adjustments to the Consolidated Financial Statements.

HighMount

In the fourth quarter of 2011, HighMount acquired working interests in oil and gas properties located in Oklahoma. The purchase price was approximately $106 million in cash and was included primarily in the cost of unproved properties within Property, plant and equipment in the Consolidated Balance Sheets.

In the second quarter of 2010, HighMount completed the sale of substantially all exploration and production assets located in the Antrim Shale in Michigan and the Black Warrior Basin in Alabama for approximately $530 million. These sales did not have a material impact on the Consolidated Statements of Income. In accordance with the full cost method of accounting, proceeds from these sales were accounted for as reductions of capitalized costs.

Note 3. Investments

Net investment income is as follows:


Year Ended December 31	2012		2011		2010

(In millions)

Fixed maturity securities	$	2,022	$	2,011	$	2,052
Short term investments		12		16		22
Limited partnership investments		283		97		315
Equity securities		12		20		32
Income (loss) from trading portfolio (a)		52		(39)		131
Other		24		16		10

Total investment income		2,405		2,121		2,562
Investment expenses		(56)		(58)		(54)

Net investment income	$	2,349	$	2,063	$	2,508

(a)	Includes net unrealized gains (losses) related to changes in fair value on trading securities still held of $6, $(58) and $88 for the years ended December 31, 2012, 2011 and 2010.

As of December 31, 2012, the Company held nine non-income producing fixed maturity securities aggregating $1 million of fair value. As of December 31, 2011, the Company held nine non-income producing fixed maturity securities aggregating $3 million of fair value. As of December 31, 2012 and 2011, no investments in a single issuer exceeded 10% of shareholders’ equity other than investments in securities issued by the U.S. Treasury and obligations of government-sponsored enterprises.

Investment gains (losses) are as follows:


Year Ended December 31	2012		2011		2010

(In millions)

Fixed maturity securities	$	83	$	(22)	$	92
Equity securities		(23)		(1)		(2)
Derivative instruments		(5)		(34)		(31)
Short term investments and other		2		5		(3)

Investment gains (losses) (a)	$	57	$	(52)	$	56

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(a)	Includes gross realized gains of $251, $299 and $525 and gross realized losses of $191, $322 and $435 on available-for-sale securities for the years ended December 31, 2012, 2011 and 2010.

Net change in unrealized gains (losses) on available-for-sale investments is as follows:


Year Ended December 31	2012		2011		2010

(In millions)

Fixed maturity securities	$	1,871	$	1,442	$	1,140
Equity securities		5		(2)		7
Other		(1)		(3)		(1)

Total net change in unrealized gains on available-for-sale investments	$	1,875	$	1,437	$	1,146

The components of other-than-temporary impairment (“OTTI”) losses recognized in earnings by asset type are as follows:


Year Ended December 31	2012		2011		2010

(In millions)

Fixed maturity securities available-for-sale:
Corporate and other bonds	$	27	$	95	$	68
States, municipalities and political subdivisions		34				62
Asset-backed:
Residential mortgage-backed		50		105		71
Commercial mortgage-backed						3
Other asset-backed				6		3

Total asset-backed		50		111		77
U.S. Treasury and obligations of government-sponsored enterprises		1

Total fixed maturity securities available-for-sale		112		206		207

Equity securities available-for-sale:
Common stock		6		8		11
Preferred stock		36		1		14

Total equity securities available-for-sale		42		9		25

Short term investments				1

Net OTTI losses recognized in earnings	$	154	$	216	$	232

A security is impaired if the fair value of the security is less than its cost adjusted for accretion, amortization and previously recorded OTTI losses, otherwise defined as an unrealized loss. When a security is impaired, the impairment is evaluated to determine whether it is temporary or other-than-temporary.

Significant judgment is required in the determination of whether an OTTI loss has occurred for a security. CNA follows a consistent and systematic process for determining and recording an OTTI loss. CNA has established a committee responsible for the OTTI process. This committee, referred to as the Impairment Committee, is made up of three officers appointed by CNA’s Chief Financial Officer. The Impairment Committee is responsible for evaluating all securities in an unrealized loss position on at least a quarterly basis.

The Impairment Committee’s assessment of whether an OTTI loss has occurred incorporates both quantitative and qualitative information. Fixed maturity securities that CNA intends to sell, or it more likely than not will be required to sell before recovery of amortized cost, are considered to be other-than-temporarily impaired and the entire difference between the amortized cost basis and fair value of the security is recognized as an OTTI loss in earnings. The remaining fixed maturity securities in an unrealized loss position are evaluated to determine if a credit loss exists. The factors considered by the Impairment Committee include: (i) the financial condition and near term prospects of the issuer, (ii) whether the debtor is current on interest and principal payments, (iii) credit ratings of the

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securities and (iv) general market conditions and industry or sector specific outlook. CNA also considers results and analysis of cash flow modeling for asset-backed securities, and when appropriate, other fixed maturity securities.

The focus of the analysis for asset-backed securities is on assessing the sufficiency and quality of underlying collateral and timing of cash flows based on scenario tests. If the present value of the modeled expected cash flows equals or exceeds the amortized cost of a security, no credit loss is judged to exist and the asset-backed security is deemed to be temporarily impaired. If the present value of the expected cash flows is less than amortized cost, the security is judged to be other-than-temporarily impaired for credit reasons and that shortfall, referred to as the credit component, is recognized as an OTTI loss in earnings. The difference between the adjusted amortized cost basis and fair value, referred to as the non-credit component, is recognized as OTTI in Other comprehensive income. In subsequent reporting periods, a change in intent to sell or further credit impairment on a security whose fair value has not deteriorated will cause the non-credit component originally recorded as OTTI in Other comprehensive income to be recognized as an OTTI loss in earnings.

CNA performs the discounted cash flow analysis using stressed scenarios to determine future expectations regarding recoverability. For asset-backed securities, significant assumptions enter into these cash flow projections including delinquency rates, probable risk of default, loss severity upon a default, over collateralization and interest coverage triggers and credit support from lower level tranches.

CNA applies the same impairment model as described above for the majority of non-redeemable preferred stock securities on the basis that these securities possess characteristics similar to debt securities and that the issuers maintain their ability to pay dividends. For all other equity securities, in determining whether the security is other-than-temporarily impaired, the Impairment Committee considers a number of factors including, but not limited to: (i) the length of time and the extent to which the fair value has been less than amortized cost, (ii) the financial condition and near term prospects of the issuer, (iii) the intent and ability of CNA to retain its investment for a period of time sufficient to allow for an anticipated recovery in value and (iv) general market conditions and industry or sector specific outlook.

The amortized cost and fair values of securities are as follows:

December 31, 2012

Cost or
Amortized
Cost

Gross
Unrealized
Gains

Gross
Unrealized
Losses

Estimated
Fair Value

Unrealized
OTTI Losses
(Gains)

(In millions)

Fixed maturity securities:

Corporate and other bonds

19,530

2,698

22,207

States, municipalities and political subdivisions

9,372

1,455

10,783

Asset-backed:

Residential mortgage-backed

5,745

246

5,920

(28)

Commercial mortgage-backed

1,692

147

1,822

(3)

Other asset-backed

929

952

Total asset-backed

8,366

416

8,694

(31)

U.S. Treasury and obligations of government- sponsored enterprises

172

182

Foreign government

588

613

Redeemable preferred stock

113

125

Fixed maturities available-for-sale

38,141

4,618

155

42,604

(31)

Fixed maturities, trading

183

161

Total fixed maturities

38,324

4,618

177

42,765

(31)

Equity securities:

Common stock

Preferred stock

190

197

Equity securities available-for-sale

228

249

Equity securities, trading

665

649

Total equity securities

893

101

898

Total

39,217

4,719

273

43,663

(31)

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December 31, 2011	Cost or Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value		Unrealized OTTI Losses (Gains)

(In millions)

Fixed maturity securities:
Corporate and other bonds	$	19,086	$	1,946	$	154	$	20,878
States, municipalities and political subdivisions		9,018		900		136		9,782
Asset-backed:
Residential mortgage-backed		5,786		172		183		5,775	$	99
Commercial mortgage-backed		1,365		48		59		1,354		(2)
Other asset-backed		946		13		4		955

Total asset-backed		8,097		233		246		8,084		97
U.S. Treasury and obligations of government-sponsored enterprises		479		14				493
Foreign government		608		28				636
Redeemable preferred stock		51		7				58

Fixed maturities available-for-sale		37,339		3,128		536		39,931		97
Fixed maturities, trading		127				18		109

Total fixed maturities		37,466		3,128		554		40,040		97

Equity securities:
Common stock		30		17				47
Preferred stock		258		4		5		257

Equity securities available-for-sale		288		21		5		304		-
Equity securities, trading		614		76		67		623

Total equity securities		902		97		72		927		-

Total	$	38,368	$	3,225	$	626	$	40,967	$	97

The available-for-sale securities in a gross unrealized loss position are as follows:


	Less than 12 Months				12 Months or Longer				Total

December 31, 2012	Estimated Fair Value		Gross Unrealized Losses		Estimated Fair Value		Gross Unrealized Losses		Estimated Fair Value		Gross Unrealized Losses

(In millions)

Fixed maturity securities:
Corporate and other bonds	$	846	$	13	$	108	$	8	$	954	$	21
States, municipalities and political subdivisions		254		5		165		39		419		44
Asset-backed:
Residential mortgage-backed		583		5		452		66		1,035		71
Commercial mortgage-backed		85		2		141		15		226		17

Total asset-backed		668		7		593		81		1,261		88
U.S. Treasury and obligations of government- sponsored enterprises		23		1						23		1
Redeemable preferred stock		28		1						28		1

Total	$	1,819	$	27	$	866	$	128	$	2,685	$	155

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	Less than 12 Months				12 Months or Longer				Total

December 31, 2011	Estimated Fair Value		Gross Unrealized Losses		Estimated Fair Value		Gross Unrealized Losses		Estimated Fair Value		Gross Unrealized Losses

(In millions)

Fixed maturity securities:
Corporate and other bonds	$	2,552	$	126	$	159	$	28	$	2,711	$	154
States, municipalities and political subdivisions		67		1		721		135		788		136
Asset-backed:
Residential mortgage-backed		719		36		874		147		1,593		183
Commercial mortgage-backed		431		39		169		20		600		59
Other asset-backed		389		4						389		4

Total asset-backed		1,539		79		1,043		167		2,582		246

Total fixed maturities available-for-sale		4,158		206		1,923		330		6,081		536
Equity securities available-for-sale:
Preferred stock		117		5						117		5

Total	$	4,275	$	211	$	1,923	$	330	$	6,198	$	541

Based on current facts and circumstances, the Company believes the unrealized losses presented in the table above are primarily attributable to broader economic conditions, changes in interest rates and credit spreads, market illiquidity and other market factors, but are not indicative of the ultimate collectibility of the current amortized cost of the securities. The Company has no current intent to sell these securities, nor is it more likely than not that it will be required to sell prior to recovery of amortized cost; accordingly, the Company has determined that there are no additional OTTI losses to be recorded at December 31, 2012.

The following table summarizes the activity for the years ended December 31, 2012, 2011 and 2010 related to the pretax credit loss component reflected in Retained earnings on fixed maturity securities still held at December 31, 2012, 2011 and 2010 for which a portion of an OTTI loss was recognized in Other comprehensive income.


Year Ended December 31	2012		2011		2010

(In millions)

Beginning balance of credit losses on fixed maturity securities	$	92	$	141	$	164
Additional credit losses for securities for which an OTTI loss was previously recognized		23		39		37
Credit losses for securities for which an OTTI loss was not previously recognized		2		11		11
Reductions for securities sold during the period		(14)		(67)		(62)
Reductions for securities the Company intends to sell or more likely than not will be required to sell		(8)		(32)		(9)

Ending balance of credit losses on fixed maturity securities	$	95	$	92	$	141

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Contractual Maturity

The following table summarizes available-for-sale fixed maturity securities by contractual maturity at December 31, 2012 and 2011. Actual maturities may differ from contractual maturities because certain securities may be called or prepaid with or without call or prepayment penalties. Securities not due at a single date are allocated based on weighted average life.


December 31	2012				2011

	Cost or Amortized Cost		Estimated Fair Value		Cost or Amortized Cost		Estimated Fair Value

(In millions)

Due in one year or less	$	1,648	$	1,665	$	1,802	$	1,812
Due after one year through five years		13,603		14,442		13,110		13,537
Due after five years through ten years		8,726		9,555		8,410		8,890
Due after ten years		14,164		16,942		14,017		15,692

Total	$	38,141	$	42,604	$	37,339	$	39,931

Limited Partnerships

The carrying value of limited partnerships as of December 31, 2012 and 2011 was approximately $3.1 billion and $2.7 billion which includes undistributed earnings of $828 million and $607 million. Limited partnerships comprising 74.0% of the total carrying value are reported on a current basis through December 31, 2012 with no reporting lag, 13.2% are reported on a one month lag and the remainder are reported on more than a one month lag. As of December 31, 2012 and 2011, the Company had 86 and 83 active limited partnership investments. The number of limited partnerships held and the strategies employed provide diversification to the limited partnership portfolio and the overall invested asset portfolio.

Of the limited partnerships held, 84.1% at December 31, 2012 and 2011, employ hedge fund strategies that generate returns through investing in securities that are marketable while engaging in various management techniques primarily in public fixed income and equity markets. These hedge fund strategies include both long and short positions in fixed income, equity and derivative instruments. The hedge fund strategies may seek to generate gains from mispriced or undervalued securities, price differentials between securities, distressed investments, sector rotation or various arbitrage disciplines. Within hedge fund strategies, approximately 52.3% were equity related, 27.1% pursued a multi-strategy approach, 16.8% were focused on distressed investments and 3.8% were fixed income related at December 31, 2012.

Limited partnerships representing 13.0% and 11.7% at December 31, 2012 and 2011 were invested in private debt and equity. The remaining were invested in various other partnerships including real estate. The ten largest limited partnership positions held totaled $1.6 billion and $1.3 billion as of December 31, 2012 and 2011. Based on the most recent information available regarding the Company’s percentage ownership of the individual limited partnerships, the carrying value reflected on the Consolidated Balance Sheets represents approximately 4.1% of the aggregate partnership equity at December 31, 2012 and 2011, and the related income reflected on the Consolidated Statements of Income represents approximately 3.3%, 3.9% and 3.5% of the changes in partnership equity for all limited partnership investments for the years ended December 31, 2012, 2011 and 2010.

While the Company generally does not invest in highly leveraged partnerships, there are risks which may result in losses due to short-selling, derivatives or other speculative investment practices. The use of leverage increases volatility generated by the underlying investment strategies.

The Company’s limited partnership investments contain withdrawal provisions that generally limit liquidity for a period of thirty days up to one year and in some cases do not permit withdrawals until the termination of the partnership. Typically, withdrawals require advance written notice of up to 90 days.

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Investment Commitments

As of December 31, 2012, the Company had committed approximately $202 million to future capital calls from various third party limited partnership investments in exchange for an ownership interest in the related partnerships.

As of December 31, 2012, the Company had mortgage loan commitments of $22 million representing signed loan applications received and accepted.

The Company invests in various privately placed debt securities, including bank loans, as part of its overall investment strategy and has committed to additional future purchases, sales and funding. As of December 31, 2012, the Company had commitments to purchase $185 million and sell $164 million of such investments.

Investments on Deposit

Securities with carrying values of approximately $3.6 billion and $3.5 billion were deposited by CNA’s insurance subsidiaries under requirements of regulatory authorities and others as of December 31, 2012 and 2011.

Cash and securities with carrying values of approximately $4 million and $5 million were deposited with financial institutions as collateral for letters of credit as of December 31, 2012 and 2011. In addition, cash and securities were deposited in trusts with financial institutions to secure reinsurance and other obligations with various third parties. The carrying values of these deposits were approximately $277 million and $288 million as of December 31, 2012 and 2011.

Note 4. Fair Value

Fair value is the price that would be received upon sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following fair value hierarchy is used in selecting inputs, with the highest priority given to Level 1, as these are the most transparent or reliable:

—

Level 1 – Quoted prices for identical instruments in active markets.

—

Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets.

—

Level 3 – Valuations derived from valuation techniques in which one or more significant inputs are not observable.

Prices may fall within Level 1, 2 or 3 depending upon the methodologies and inputs used to estimate fair value for each specific security. In general, the Company seeks to price securities using third party pricing services. Securities not priced by pricing services are submitted to independent brokers for valuation and, if those are not available, internally developed pricing models are used to value assets using methodologies and inputs the Company believes market participants would use to value the assets.

The Company performs control procedures over information obtained from pricing services and brokers to ensure prices received represent a reasonable estimate of fair value and to confirm representations regarding whether inputs are observable or unobservable. Procedures include (i) the review of pricing service or broker pricing methodologies, (ii) back-testing, where past fair value estimates are compared to actual transactions executed in the market on similar dates, (iii) exception reporting, where changes in price, period-over-period, are reviewed and challenged with the pricing service or broker based on exception criteria, (iv) detailed analyses, where the Company independently validates information regarding inputs and assumptions for individual securities and (v) pricing validation, where prices received are compared to prices independently estimated by the Company.

The fair values of CNA’s life settlement contracts are included in Other assets. Equity options purchased are included in Equity securities, and all other derivative assets are included in Receivables. Derivative liabilities are included in Payable to brokers. Assets and liabilities measured at fair value on a recurring basis are summarized in the tables below:

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December 31, 2012

Level 1

Level 2

Level 3

Total

(In millions)

Fixed maturity securities:

Corporate and other bonds

21,982

219

22,207

States, municipalities and political subdivisions

10,687

10,783

Asset-backed:

Residential mortgage-backed

5,507

413

5,920

Commercial mortgage-backed

1,693

129

1,822

Other asset-backed

584

368

952

Total asset-backed

7,784

910

8,694

U.S. Treasury and obligations of government-sponsored enterprises

158

182

Foreign government

140

473

613

Redeemable preferred stock

125

Fixed maturities available-for-sale

344

41,009

1,251

42,604

Fixed maturities, trading

161

Total fixed maturities

344

41,081

1,340

42,765

Equity securities available-for-sale

117

249

Equity securities, trading

642

649

Total equity securities

759

898

Short term investments

4,990

799

5,795

Other invested assets

Receivables

Life settlement contracts

100

Separate account business

306

312

Payable to brokers

(95)

(11)

(6)

(112)

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December 31, 2011	Level 1		Level 2		Level 3		Total

(In millions)

Fixed maturity securities:
Corporate and other bonds			$	20,396	$	482	$	20,878
States, municipalities and political subdivisions				9,611		171		9,782
Asset-backed:
Residential mortgage-backed				5,323		452		5,775
Commercial mortgage-backed				1,295		59		1,354
Other asset-backed				612		343		955

Total asset-backed				7,230		854		8,084
U.S. Treasury and obligations of government-sponsored enterprises	$	451		42				493
Foreign government		92		544				636
Redeemable preferred stock		5		53				58

Fixed maturities available-for-sale		548		37,876		1,507		39,931
Fixed maturities, trading				8		101		109

Total fixed maturities	$	548	$	37,884	$	1,608	$	40,040


Equity securities available-for-sale	$	124	$	113	$	67	$	304
Equity securities, trading		609				14		623

Total equity securities	$	733	$	113	$	81	$	927


Short term investments	$	4,570	$	508	$	27	$	5,105
Other invested assets						11		11
Receivables				79		8		87
Life settlement contracts						117		117
Separate account business		21		373		23		417
Payable to brokers		(32)		(20)		(23)		(75)

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The tables below present reconciliations for all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2012 and 2011:


																			Unrealized Gains (Losses) Recognized in Net Income on Level 3 Assets and Liabilities Held at December 31




			Net Realized Gains
			(Losses) and Net Change
			in Unrealized Gains
			(Losses)										Transfers		Transfers

	Balance,		Included in		Included in								into		out of		Balance,
2012	January 1		Net Income		OCI		Purchases		Sales		Settlements		Level 3		Level 3		December 31

(In millions)

Fixed maturity securities:
Corporate and other bonds	$	482	$	6	$	4	$	230	$	(135)	$	(88)	$	45	$	(325)	$	219	$	(3)
States, municipalities and political subdivisions		171						14				(89)						96
Asset-backed:
Residential mortgage-backed		452		(14)		2		97				(40)				(84)		413		(18)
Commercial mortgage-backed		59		8		14		165		(12)		(28)		13		(90)		129
Other asset-backed		343		11		8		615		(365)		(128)				(116)		368

Total asset-backed		854		5		24		877		(377)		(196)		13		(290)		910		(18)
Redeemable preferred stock		-				(1)		53		(26)								26

Fixed maturities available-for-sale		1,507		11		27		1,174		(538)		(373)		58		(615)		1,251		(21)
Fixed maturities, trading		101		(6)				1		(7)								89		(6)

Total fixed maturities	$	1,608	$	5	$	27	$	1,175	$	(545)	$	(373)	$	58	$	(615)	$	1,340	$	(27)


Equity securities available-for-sale	$	67	$	(36)	$	6	$	27	$	(16)					$	(14)	$	34	$	(38)
Equity securities, trading		14		(6)						(1)								7		(6)

Total equity securities	$	81	$	(42)	$	6	$	27	$	(17)	$	-	$	-	$	(14)	$	41	$	(44)


Short term investments	$	27					$	23	$	(4)	$	(41)	$	1			$	6
Other invested assets		11										(10)						1
Life settlement contracts		117	$	53								(70)						100	$	11
Separate account business		23								(21)								2
Derivative financial instruments, net		(15)		(4)	$	30				(6)								5		(1)

129


																			Unrealized Gains (Losses) Recognized in Net Income on Level 3 Assets and Liabilities Held at December 31



			Net Realized Gains
			(Losses) and Net Change
			in Unrealized Gains
			(Losses)										Transfers		Transfers

	Balance,		Included in		Included in								into		out of		Balance,
2011	January 1		Net Income		OCI		Purchases		Sales		Settlements		Level 3		Level 3		December 31

(In millions)

Fixed maturity securities:
Corporate and other bonds	$	624	$	(11)	$	(1)	$	484	$	(204)	$	(149)	$	79	$	(340)	$	482	$	(12)
States, municipalities and political subdivisions		266				(1)		3				(92)				(5)		171
Asset-backed:
Residential mortgage-backed		767		(16)		(11)		225		(290)		(60)				(163)		452		(6)
Commercial mortgage-backed		73		20		(7)		81		(27)						(81)		59
Other asset-backed		359		(9)		5		537		(341)		(99)		2		(111)		343		(5)

Total asset-backed		1,199		(5)		(13)		843		(658)		(159)		2		(355)		854		(11)
Redeemable preferred stock		3		3		(3)				(3)								-

Fixed maturities available-for-sale		2,092		(13)		(18)		1,330		(865)		(400)		81		(700)		1,507		(23)
Fixed maturities, trading		184		(11)						(72)								101		(4)

Total fixed maturities	$	2,276	$	(24)	$	(18)	$	1,330	$	(937)	$	(400)	$	81	$	(700)	$	1,608	$	(27)


Equity securities available-for-sale	$	26	$	(2)	$	2	$	66	$	(27)			$	5	$	(3)	$	67	$	(3)
Equity securities, trading		6		(7)				1						14				14		(7)

Total equity securities	$	32	$	(9)	$	2	$	67	$	(27)	$	-	$	19	$	(3)	$	81	$	(10)


Short term investments	$	27					$	39			$	(29)			$	(10)	$	27
Other invested assets		26	$	4					$	(19)								11	$	1
Life settlement contracts		129		33								(45)						117		5
Separate account business		41								(6)						(12)		23
Derivative financial instruments, net		(21)		(42)	$	(1)		9				40						(15)		1

Net realized and unrealized gains and losses are reported in Net income as follows:


Major Category of Assets and Liabilities		Consolidated Statements of Income Line Items


Fixed maturity securities available-for-sale		Investment gains (losses)
Fixed maturity securities, trading		Net investment income
Equity securities available-for-sale		Investment gains (losses)
Equity securities, trading		Net investment income
Other invested assets		Investment gains (losses) and Net investment income
Derivative financial instruments held in a trading portfolio		Net investment income
Derivative financial instruments, other		Investment gains (losses) and Other revenues
Life settlement contracts		Other revenues

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Securities shown in the Level 3 tables may be transferred in or out of Level 3 based on the availability of observable market information used to determine the fair value of the security. The availability of observable market information varies based on market conditions and trading volume and may cause securities to move in and out of Level 3 from reporting period to reporting period. There were $106 million of transfers from Level 2 to Level 1 and $72 million of transfers from Level 1 to Level 2 during the year ended December 31, 2012. There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2011. The Company’s policy is to recognize transfers between levels at the beginning of quarterly reporting periods.

Valuation Methodologies and Inputs

The following section describes the valuation methodologies and relevant inputs used to measure different financial instruments at fair value, including an indication of the level in the fair value hierarchy in which the instruments are generally classified.

Fixed Maturity Securities

Fixed maturity securities are valued using methodologies that model information generated by market transactions involving identical or comparable assets, as well as discounted cash flow methodologies. Common inputs include: prices from recently executed transactions of similar securities, broker/dealer quotes, benchmark yields, spreads off benchmark yields, interest rates and U.S. Treasury or swap curves. Specifically for asset-backed securities, key inputs include prepayment and default projections based on past performance of the underlying collateral and current market data.

Level 1 securities include highly liquid U.S. and foreign government bonds, and redeemable preferred stock, valued using quoted market prices. Level 2 securities include most other fixed maturity securities as the significant inputs are observable in the marketplace. Securities are generally assigned to Level 3 in cases where broker/dealer quotes are significant inputs to the valuation and there is a lack of transparency as to whether these quotes are based on information that is observable in the marketplace. Level 3 securities also include tax-exempt auction rate certificates and private placement debt securities. Fair value of auction rate securities is determined utilizing a pricing model with three primary inputs. The interest rate and spread inputs are observable from like instruments while the expected call date assumption is unobservable due to the uncertain nature of principal prepayments prior to maturity and the credit spread adjustment that is security specific. Fair value of certain private placement debt securities is determined using internal models with inputs that are not market observable.

Equity Securities

Level 1 equity securities include publicly traded securities valued using quoted market prices. Level 2 securities are primarily non-redeemable preferred stocks and common stocks valued using pricing for similar securities, recently executed transactions, broker/dealer quotes and other pricing models utilizing market observable inputs. Level 3 securities are priced using internal models with inputs that are not market observable.

Derivative Financial Instruments

Exchange traded derivatives are valued using quoted market prices and are classified within Level 1 of the fair value hierarchy. Level 2 derivatives primarily include currency forwards valued using observable market forward rates. Over-the-counter derivatives, principally interest rate swaps, total return swaps, commodity swaps, credit default swaps, equity warrants and options, are valued using inputs including broker/dealer quotes and are classified within Level 2 or Level 3 of the valuation hierarchy, depending on the amount of transparency as to whether these quotes are based on information that is observable in the marketplace.

Short Term Investments

The valuation of securities that are actively traded or have quoted prices are classified as Level 1. These securities include money market funds and treasury bills. Level 2 primarily includes commercial paper, for which all inputs are market observable. Fixed maturity securities purchased within one year of maturity are classified consistent with

131

fixed maturity securities discussed above. Short term investments as presented in the tables above differ from the amounts presented in the Consolidated Balance Sheets because certain short term investments, such as time deposits, are not measured at fair value.

Life Settlement Contracts

The fair values of life settlement contracts are determined as the present value of the anticipated death benefits less anticipated premium payments based on contract terms that are distinct for each insured, as well as CNA’s own assumptions for mortality, premium expense, and the rate of return that a buyer would require on the contracts, as no comparable market pricing data is available.

Separate Account Business

Separate account business includes fixed maturity securities, equities and short term investments. The valuation methodologies and inputs for these asset types have been described above.

Significant Unobservable Inputs

The table below presents quantitative information about the significant unobservable inputs utilized by the Company in the fair value measurements of Level 3 assets. Valuations for assets and liabilities not presented in the table below are primarily based on broker/dealer quotes for which there is a lack of transparency as to inputs used to develop the valuations. The quantitative detail of unobservable inputs from these broker quotes is neither provided nor reasonably available to the Company.

December 31, 2012

Fair Value

Valuation
Technique(s)

Unobservable

Input(s)

Range (Weighted
Average)

(In millions)

Assets

Fixed maturity securities

$ 121

Discounted cash flow

Expected call date

3.3 – 5.3 years (4.3 years)

Credit spread adjustment

0.02% – 0.48% (0.17%)

Market approach

Private offering price

$42.39 – $102.32 ($100.11)

Equity securities

Market approach

Private offering price

$4.54 – $3,842.00 per share

($571.17 per share)

Life settlement contracts

100

Discounted cash flow

Discount rate risk premium

Mortality assumption

69% – 883% (208.9%)

For fixed maturity securities, an increase to the expected call date assumption and credit spread adjustment or decrease in the private offering price would result in a lower fair value measurement. For equity securities, an increase in the private offering price would result in a higher fair value measurement. For life settlement contracts, an increase in the discount rate risk premium or decrease in the mortality assumption would result in a lower fair value measurement.

132

Financial Assets and Liabilities Not Measured at Fair Value

The carrying amount, estimated fair value and the level of the fair value hierarchy of the Company’s financial instrument assets and liabilities which are not measured at fair value on the Consolidated Balance Sheets are listed in the tables below. The carrying amounts reported on the Consolidated Balance Sheets for cash and short term investments not carried at fair value and certain other assets and liabilities approximate fair value due to the short term nature of these items.

Carrying

Estimated Fair Value

December 31, 2012

Amount

Level 1

Level 2

Level 3

Total

(In millions)

Financial assets:

Other invested assets, primarily mortgage loans

401

418

Financial liabilities:

Premium deposits and annuity contracts

100

104

Short term debt

Long term debt

9,191

10,170

202

10,372


	Carrying		Estimated
December 31, 2011	Amount		Fair Value

(In millions)

Financial assets:
Other invested assets, primarily mortgage loans	$	234	$	247

Financial liabilities:
Premium deposits and annuity contracts		109		114
Short term debt		88		90
Long term debt		8,913		9,533

The following methods and assumptions were used in estimating the fair value of these financial assets and liabilities.

The fair values of mortgage loans were based on the present value of the expected future cash flows discounted at the current interest rate for similar financial instruments, adjusted for specific loan risk.

Premium deposits and annuity contracts were valued based on cash surrender values or estimated fair values of policyholder liabilities, net of amounts ceded related to sold business.

Fair value of debt was based on observable market prices when available. When observable market prices were not available, the fair value for debt was based on observable market prices of comparable instruments adjusted for differences between the observed instruments and the instruments being valued or is estimated using discounted cash flow analyses, based on current incremental borrowing rates for similar types of borrowing arrangements.

133

Note 5. Derivative Financial Instruments

The Company uses derivatives in the normal course of business, primarily in an attempt to reduce its exposure to market risk (principally interest rate risk, credit risk, equity price risk, commodity price risk and foreign currency risk) stemming from various assets and liabilities. The Company’s principal objective under such strategies is to achieve the desired reduction in economic risk, even if the position does not receive hedge accounting treatment.

The Company enters into interest rate swaps, futures and commitments to purchase securities to manage interest rate risk. Credit derivatives such as credit default swaps are entered into to modify the credit risk inherent in certain investments. Forward contracts, futures, swaps and options are used primarily to manage foreign currency and commodity price risk.

In addition to the derivatives used for risk management purposes described above, the Company may also use derivatives for purposes of income enhancement. Income enhancement transactions are entered into with the intention of providing additional income or yield to a particular portfolio segment or asset class. Income enhancement transactions include but are not limited to interest rate swaps, call options, put options, credit default swaps, index futures and foreign currency forwards. See Note 4 for information regarding the fair value of derivative instruments.

A summary of the aggregate contractual or notional amounts and gross estimated fair values related to derivative financial instruments follows. The contractual or notional amounts for derivatives are used to calculate the exchange of contractual payments under the agreements and may not be representative of the potential for gain or loss on these instruments.


December 31	2012						2011

	Contractual/						Contractual/
	Notional		Estimated Fair Value				Notional		Estimated Fair Value

	Amount		Asset		(Liability)		Amount		Asset		(Liability)

(In millions)

With hedge designation:

Interest rate risk:
Interest rate swaps	$	300			$	(6)	$	300	$	3	$	(3)
Commodities:
Forwards – short		288	$	39		(3)		268		64		(22)
Foreign exchange:
Currency forwards – short		144		4				154		1		(8)

Without hedge designation:

Equity markets:
Options – purchased		255		19				286		33
– written		374				(11)		398				(23)
Equity swaps and warrants – long		14		6				63		16
Interest rate risk:
Interest rate swaps								100		1		(1)
Credit default swaps
– purchased protection		78				(2)		145		8		(1)
– sold protection		33				(2)		28				(2)
Foreign exchange:
Currency forwards – long		404				(2)		203		4
– short		128						330				(2)

For derivative financial instruments without hedge designation, changes in the fair value of derivatives not held in a trading portfolio are reported in Investment gains (losses) and changes in the fair value of derivatives held for trading purposes are reported in Net investment income on the Consolidated Statements of Income. Losses of $5 million, $34 million and $31 million were recorded in Investment gains (losses) for the years ended December 31,

134

2012, 2011 and 2010. Losses of $19 million, $14 million and $75 million were included in Net investment income for the years ended December 31, 2012, 2011 and 2010.

The Company’s derivative financial instruments with cash flow hedge designation hedge variable price risk associated with the purchase and sale of natural gas and other energy-related products, exposure to foreign currency losses on future foreign currency expenditures, as well as risks attributable to changes in interest rates on long term debt. Gains of $43 million, $33 million and $87 million were recognized in OCI related to these cash flow hedges for the years ended December 31, 2012, 2011 and 2010. Gains of $54 million and losses of $28 million and $11 million were reclassified from AOCI into income for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, the estimated amount of net unrealized gains associated with these cash flow hedges that will be reclassified from AOCI into earnings during the next twelve months was $34 million. For each of the years ended December 31, 2012, 2011 and 2010, the net amounts recognized due to ineffectiveness were less than $1 million.

Note 6. Receivables


December 31	2012		2011

(In millions)

Reinsurance	$	6,231	$	6,092
Insurance		1,983		1,726
Receivable from brokers		159		275
Accrued investment income		437		442
Federal income taxes		51		164
Other, primarily customer accounts		717		801

Total		9,578		9,500
Less: allowance for doubtful accounts on reinsurance receivables		73		91
allowance for other doubtful accounts		139		150

Receivables	$	9,366	$	9,259

Note 7. Property, Plant and Equipment


December 31	2012		2011

(In millions)

Pipeline equipment (net of accumulated DD&A of $1,168 and $926)	$	7,148	$	6,749
Offshore drilling equipment (net of accumulated DD&A of $3,347 and $3,378)		3,824		4,119
Natural gas and oil proved and unproved properties (net of accumulated DD&A of $2,813 and $2,056)		893		1,330
Other (net of accumulated DD&A of $874 and $899)		815		799
Construction in process		1,255		621

Property, plant and equipment, net	$	13,935	$	13,618

135

DD&A expense and capital expenditures are as follows:


Year Ended December 31	2012				2011				2010

			Capital				Capital				Capital
	DD&A		Expend.		DD&A		Expend.		DD&A		Expend.

(In millions)

CNA Financial	$	71	$	98	$	70	$	85	$	69	$	51
Diamond Offshore		394		721		399		783		396		399
Boardwalk Pipeline		256		247		231		142		222		204
HighMount		101		346		94		324		92		188
Loews Hotels		30		30		29		19		29		13
Corporate and other		7		10		10		19		8		5

Total	$	859	$	1,452	$	833	$	1,372	$	816	$	860

Capitalized interest related to the construction and upgrade of qualifying assets amounted to approximately $55 million, $31 million and $23 million for the years ended December 31, 2012, 2011 and 2010.

Pipeline Equipment

In October of 2012, Boardwalk Pipeline acquired Louisiana Midstream, a company that provides salt dome storage, pipeline transportation, fractionation and brine supply services for approximately $620 million, of which $550 million was allocated to Pipeline equipment.

In December of 2011, HP Storage acquired seven salt dome natural gas storage caverns and associated assets in Mississippi for approximately $550 million of which $487 million was allocated to Pipeline equipment. See Note 2 for additional information related to these purchases.

Offshore Drilling Equipment

Purchase of Assets

In 2012 and 2011, Diamond Offshore recorded $251 million and $490 million in Construction in process for four new ultra-deepwater drillships. Delivery is expected in the second and fourth quarters of 2013 and in the second and fourth quarters of 2014. In addition, Diamond Offshore recorded $235 million in Construction in process for two new deepwater floaters in 2012. The rigs will be constructed utilizing the hulls of two of Diamond Offshore’s mid-water floaters. Delivery is expected for the third quarter of 2013 and in the second quarter of 2014.

Sale of Assets

In 2012, Diamond Offshore sold six jack-up rigs for total proceeds of $132 million, resulting in a pretax gain of approximately $76 million, recorded in Other revenues.

Asset Impairment

In 2012, Diamond Offshore decided to actively market for sale three mid-water rigs and one jack-up rig. The aggregate net book value of these rigs was transferred to Assets held for sale which is included in Other assets on the Consolidated Balance Sheets. In connection with the reclassification, Diamond Offshore recorded an impairment charge of $62 million related to the three mid-water rigs. The fair value for each rig was measured using an expected present value technique that utilizes significant unobservable inputs, representing a Level 3 fair value measurement, which includes assumptions for estimated proceeds that may be received on disposition of the rig and estimated costs to sell. At December 31, 2012, these assets held for sale amounted to $12 million.

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Natural Gas and Oil Proved and Unproved Properties

Impairment of Natural Gas and Oil Properties

In 2012, HighMount recorded non-cash ceiling test impairment charges of $680 million ($433 million after tax) related to the carrying value of its natural gas and oil properties. The impairments were recorded within Other operating expenses and as credits to Accumulated DD&A. The write-downs were the result of declines in natural gas and NGL prices. Had the effects of HighMount’s cash flow hedges not been considered in calculating the ceiling limitation, the impairments would have been $737 million ($469 million after tax).

Purchase of Assets

In the fourth quarter of 2011, HighMount paid $106 million to acquire working interests in oil and gas properties located in Oklahoma. See Note 2 for additional information related to this purchase.

Costs Not Being Amortized

HighMount excludes from amortization the cost of unproved properties, the cost of exploratory wells in progress and major development projects in progress. Natural gas and oil property and equipment costs not being amortized as of December 31, 2012, are as follows, by the year in which such costs were incurred:


	Total		2012		2011		2010		Prior

(In millions)

Acquisition costs	$	171	$	2	$	56	$	1	$	112
Exploration costs		9		3		4		1		1
Capitalized interest		29		8		9		7		5

Total excluded costs	$	209	$	13	$	69	$	9	$	118

As a result of the decline in natural gas and NGL prices, HighMount changed its drilling program in 2012 to develop properties that produce primarily oil. As a result, during 2012, $130 million of costs associated with unevaluated natural gas prospects were reclassified as evaluated and included in the full cost pool subject to depletion.

Note 8. Claim and Claim Adjustment Expense Reserves

CNA’s property and casualty insurance claim and claim adjustment expense reserves represent the estimated amounts necessary to resolve all outstanding claims, including claims that are incurred but not reported (“IBNR”) as of the reporting date. CNA’s reserve projections are based primarily on detailed analysis of the facts in each case, CNA’s experience with similar cases and various historical development patterns. Consideration is given to such historical patterns as field reserving trends and claims settlement practices, loss payments, pending levels of unpaid claims and product mix, as well as court decisions, economic conditions including inflation and public attitudes. All of these factors can affect the estimation of claim and claim adjustment expense reserves.

Establishing claim and claim adjustment expense reserves, including claim and claim adjustment expense reserves for catastrophic events that have occurred, is an estimation process. Many factors can ultimately affect the final settlement of a claim and, therefore, the necessary reserve. Changes in the law, results of litigation, medical costs, the cost of repair materials and labor rates can all affect ultimate claim costs. In addition, time can be a critical part of reserving determinations since the longer the span between the incidence of a loss and the payment or settlement of the claim, the more variable the ultimate settlement amount can be. Accordingly, short-tail claims, such as property damage claims, tend to be more reasonably estimable than long-tail claims, such as workers’ compensation, general liability and professional liability claims. Adjustments to prior year reserve estimates, if necessary, are reflected in the results of operations in the period that the need for such adjustments is determined. There can be no assurance that CNA’s ultimate cost for insurance losses will not exceed current estimates.

Catastrophes are an inherent risk of the property and casualty insurance business and have contributed to material period-to-period fluctuations in CNA’s results of operations and/or equity. CNA reported catastrophe losses, net of

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reinsurance, of $391 million, $222 million and $121 million for the years ended December 31, 2012, 2011 and 2010. Catastrophe losses in 2012 related primarily to Storm Sandy and other U.S. storms.

The table below provides a reconciliation between beginning and ending claim and claim adjustment expense reserves, including claim and claim adjustment expense reserves of the life company:


Year Ended December 31	2012			2011			2010

(In millions)

Reserves, beginning of year:
Gross	$	24,303		$	25,496		$	26,816
Ceded		5,020			6,122			5,594

Net reserves, beginning of year		19,283			19,374			21,222


Reduction of net reserves due to the Loss Portfolio Transfer transaction								(1,381)


Change in net reserves due to acquisition (disposition) of subsidiaries		291			(277	)		(98)


Net incurred claim and claim adjustment expenses:
Provision for insured events of current year		5,273			4,904			4,741
Decrease in provision for insured events of prior years		(182	)		(429	)		(544)
Amortization of discount		145			135			123

Total net incurred (a)		5,236			4,610			4,320


Net payments attributable to:
Current year events		(988	)		(1,029	)		(908)
Prior year events		(4,280	)		(3,473	)		(3,776)

Total net payments		(5,268	)		(4,502	)		(4,684)


Foreign currency translation adjustment and other		95			78			(5)


Net reserves, end of year		19,637			19,283			19,374
Ceded reserves, end of year		5,126			5,020			6,122

Gross reserves, end of year	$	24,763		$	24,303		$	25,496

(a)

Total net incurred above does not agree to Insurance claims and policyholders’ benefits as reflected in the Consolidated Statements of Income due to amounts related to uncollectible reinsurance and loss deductible receivables, and benefit expenses related to future policy benefits and policyholders’ funds, which are not reflected in the table above.

The changes in provision for insured events of prior years (net prior year claim and claim adjustment expense reserve development) were as follows:


Year Ended December 31	2012			2011			2010

(In millions)

Property and casualty reserve development	$	(180	)	$	(429	)	$	(545)
Life reserve development in life company		(2	)					1

Total	$	(182	)	$	(429	)	$	(544)

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The following tables summarize the gross and net carried reserves:


December 31, 2012	CNA Specialty		CNA Commercial		Life & Group Non-Core		Other		Total

(In millions)

Gross Case Reserves	$	2,292	$	6,146	$	2,690	$	1,540	$	12,668
Gross IBNR Reserves		4,456		5,180		316		2,143		12,095


Total Gross Carried Claim and Claim
Adjustment Expense Reserves	$	6,748	$	11,326	$	3,006	$	3,683	$	24,763


Net Case Reserves	$	2,008	$	5,611	$	2,253	$	484	$	10,356
Net IBNR Reserves		4,104		4,600		275		302		9,281


Total Net Carried Claim and Claim
Adjustment Expense Reserves	$	6,112	$	10,211	$	2,528	$	786	$	19,637


December 31, 2011


Gross Case Reserves	$	2,441	$	6,266	$	2,510	$	1,321	$	12,538
Gross IBNR Reserves		4,399		5,243		315		1,808		11,765


Total Gross Carried Claim and Claim
Adjustment Expense Reserves	$	6,840	$	11,509	$	2,825	$	3,129	$	24,303


Net Case Reserves	$	2,086	$	5,720	$	2,025	$	347	$	10,178
Net IBNR Reserves		3,937		4,670		254		244		9,105


Total Net Carried Claim and Claim
Adjustment Expense Reserves	$	6,023	$	10,390	$	2,279	$	591	$	19,283

A&EP Reserves

On August 31, 2010, Continental Casualty Company (“CCC”) together with several of CNA’s insurance subsidiaries completed a transaction with National Indemnity Company (“NICO”), a subsidiary of Berkshire Hathaway Inc., under which substantially all of CNA’s legacy A&EP liabilities were ceded to NICO (“Loss Portfolio Transfer”).

Under the terms of the NICO transaction, effective January 1, 2010 CNA ceded approximately $1.6 billion of net A&EP claim and allocated claim adjustment expense reserves to NICO under a retroactive reinsurance agreement with an aggregate limit of $4.0 billion. Included in the $1.6 billion of net A&EP claim and allocated claim adjustment expense reserves was approximately $90 million of net claim and allocated claim adjustment expense reserves relating to CNA’s discontinued operations. The $1.6 billion of claim and allocated claim adjustment expense reserves ceded to NICO was net of $1.2 billion of ceded claim and allocated claim adjustment expense reserves under existing third party reinsurance contracts. The NICO aggregate reinsurance limit also covers credit risk on the existing third party reinsurance related to these liabilities.

CNA paid NICO a reinsurance premium of $2.0 billion and transferred to NICO billed third party reinsurance receivables related to A&EP claims with a net book value of $215 million (net of an allowance of $100 million for doubtful accounts on billed third party reinsurance receivables, as discussed further below). As of August 31, 2010, NICO deposited approximately $2.2 billion in a collateral trust account as security for its obligations to CNA. NICO may reduce the collateral by the amount of net A&EP claim and allocated claim adjustment expense payments. In addition, Berkshire Hathaway Inc. guaranteed the payment obligations of NICO up to the full aggregate reinsurance

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limit as well as certain of NICO’s performance obligations under the trust agreement. NICO is responsible for claims handling and billing and collection from third party reinsurers related to CNA’s A&EP claims.

The following table displays the impact of the Loss Portfolio Transfer on the 2010 Consolidated Statement of Income:


	2010

(In millions)

Other operating expenses	$	(529)
Income tax benefit		185

Loss from continuing operations, included in the Other segment		(344)
Loss from discontinued operations		(21)

Net loss		(365)
Amounts attributable to noncontrolling interests		37

Net loss attributable to Loews Corporation	$	(328)

In connection with the transfer of billed third party reinsurance receivables related to A&EP claims and the coverage of credit risk afforded under the terms of the Loss Portfolio Transfer, CNA reduced its allowance for doubtful accounts on billed third party reinsurance receivables and ceded claim and allocated claim adjustment expense reserves by $200 million. This reduction is reflected in Other operating expenses presented above.

The remaining amount available under the $4.0 billion aggregate limit of the Loss Portfolio Transfer was $2.0 billion on an incurred basis at December 31, 2012. This incurred amount includes $399 million of adverse prior year development since the contract effective date of January 1, 2010. Any future adverse prior year development in excess of approximately $230 million would put the Loss Portfolio Transfer into an overall gain position under retroactive reinsurance accounting. The net ultimate paid losses ceded under the Loss Portfolio Transfer were $661 million through December 31, 2012. The fair value of the collateral trust account at December 31, 2012 was $2.5 billion.

Net Prior Year Development

Changes in estimates of claim and allocated claim adjustment expense reserves and premium accruals, net of reinsurance, for prior years are defined as net prior year development. These changes can be favorable or unfavorable. The following tables and discussion include the net prior year development recorded for CNA Specialty, CNA Commercial and Other segments for the years ended December 31, 2012, 2011 and 2010. The net prior year development presented below includes premium development due to its direct relationship to claim and claim adjustment expense reserve development. The net prior year development presented below also includes the impact of commutations and write-offs, but excludes the impact of increases or decreases in the allowance for doubtful accounts on reinsurance receivables. See Note 16 for further discussion of the allowance for doubtful accounts on reinsurance receivables.

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Favorable net prior year development of $11 million, $29 million and $2 million was recorded in the Life & Group Non-Core segment for the years ended December 31, 2012, 2011 and 2010.

Year Ended December 31, 2012

CNA
Specialty

CNA
Commercial

Other

Total

(In millions)

Pretax (favorable) unfavorable net prior year claim and allocated claim adjustment expense reserve development

(135)

(46)

(24)

(205)

Pretax (favorable) unfavorable premium development

(15)

(35)

(46)

Total pretax (favorable) unfavorable net prior year development

(150)

(81)

(20)

(251)


Year Ended December 31, 2011


Pretax (favorable) unfavorable net prior year claim and allocated claim adjustment expense reserve development	$	(217)	$	(204)	$	(2)	$	(423)
Pretax (favorable) unfavorable premium development		(28)		21		(1)		(8)

Total pretax (favorable) unfavorable net prior year development	$	(245)	$	(183)	$	(3)	$	(431)


Year Ended December 31, 2010


Pretax (favorable) unfavorable net prior year claim and allocated claim adjustment expense reserve development	$	(341)	$	(304)	$	8	$	(637)
Pretax (favorable) unfavorable premium development		(3)		48		(2)		43

Total pretax (favorable) unfavorable net prior year development	$	(344)	$	(256)	$	6	$	(594)

For the year ended December 31, 2012, favorable premium development was recorded for CNA Commercial primarily due to premium adjustments on auditable policies arising from increased exposures.

For the year ended December 31, 2011, favorable premium development was recorded for CNA Specialty primarily due to changes in estimates of exposures in medical professional liability tail coverages. Unfavorable premium development for CNA Commercial was recorded due to a further reduction of ultimate premium estimates relating to retrospectively rated policies, partially offset by premium adjustments on auditable policies due to increased exposures.

For the year ended December 31, 2010, unfavorable premium development for CNA Commercial was recorded due to a change in ultimate premium estimates relating to retrospectively rated policies and return premium on auditable policies due to reduced exposures.

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CNA Specialty

The following table and discussion provide further detail of the net prior year claim and allocated claim adjustment expense reserve development (“development”) recorded for the CNA Specialty segment:


Year Ended December 31	2012		2011		2010

(In millions)

Medical professional liability	$	(32)	$	(92)	$	(98)
Other professional liability		(22)		(78)		(129)
Surety		(63)		(47)		(103)
Warranty		(5)		(13)
Other		(13)		13		(11)

Total pretax (favorable) unfavorable net prior year claim and allocated claim adjustment expense reserve development	$	(135)	$	(217)	$	(341)

2012

Favorable development for medical professional liability was primarily due to better than expected loss emergence in accident years 2008 and prior.

Overall, favorable development for other professional liability was primarily due to better than expected loss emergence in accident years 2003 through 2007. Unfavorable development was recorded in CNA’s lawyer coverages in accident years 2010 and 2011 primarily due to increased frequency and severity.

Favorable development for surety coverages was primarily due to better than expected loss emergence in accident years 2010 and prior.

Other includes standard property and casualty coverages provided to CNA Specialty customers. Overall, favorable development for other coverages was primarily due to favorable loss emergence in property and workers’ compensation coverages in accident years 2005 and subsequent. Unfavorable development was recorded in accident year 2009 primarily due to an unfavorable outcome on an individual general liability claim.

2011

Favorable development for medical professional liability was primarily due to favorable case incurred emergence in nurses, physicians, excess institutions and primary institutions in accident years 2008 and prior.

Favorable development for other professional liability was driven by better than expected loss emergence in the life agents, accountants, and architects & engineers business in accident years 2008 and prior. In addition, favorable development in CNA’s European book of business was primarily due to favorable outcomes on several large losses in financial directors and officers (“D&O”) and errors and omissions (“E&O”) coverages in accident years 2003 and prior.

Favorable development for surety coverages was primarily due to a decrease in the estimated loss on a large national contractor in accident year 2005 and better than expected loss emergence in accident years 2009 and prior.

Favorable development in warranty was driven by favorable policy year experience on an aggregate stop loss policy covering CNA’s non-insurance warranty subsidiary.

Unfavorable development for other coverages was primarily due to increased frequency of large claims in auto and workers’ compensation coverages in accident years 2009 and 2010.

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2010

Overall, favorable development for medical professional liability was primarily due to lower than expected frequency of large losses, primarily in accident years 2007 and prior. This development amount also included unfavorable development in accident years 2008 and 2009 due to increased frequency of large losses related to medical products.

Overall, favorable development for other professional liability was recorded primarily in accident years 2007 and prior in D&O and E&O coverages due to several factors, including reduced frequency of large claims and the result of reviews of large claims. This development amount also included unfavorable development in employment practices liability, E&O and D&O coverages recorded in accident years 2008 and 2009, driven by the economic recession and higher unemployment.

Favorable development for surety coverages was primarily due to a decrease in the estimated loss on a large national contractor in accident year 2005 and lower than expected claim emergence in accident years 2008 and prior.

CNA Commercial

The following table and discussion provides further detail of development recorded for the CNA Commercial segment:


Year Ended December 31	2012		2011		2010

(In millions)

Commercial auto		$ 27		$ (98)		$ (88)
General liability		(64)		(39)		(59)
Workers’ compensation		15		36		47
Property and other		(24)		(103)		(204)

Total pretax (favorable) unfavorable net prior year claim and allocated claim adjustment expense reserve development		$ (46)		$ (204)		$ (304)

2012

Unfavorable development for commercial auto coverages was primarily due to higher than expected loss emergence in accident years 2007 and subsequent and higher than expected frequency in accident year 2011.

Overall, favorable development for general liability coverages was primarily due to better than expected loss emergence in accident years 2006 and subsequent related to umbrella business and 2003 and prior related to large account business. Unfavorable development was recorded in accident years 2009 through 2011 related to several large losses.

Overall, unfavorable development for workers’ compensation was primarily due to increased medical severity in accident years 2010 and 2011 and the recognition of losses related to favorable premium development in accident year 2011. Favorable development was recorded in accident years 2001 and prior reflecting favorable experience.

Overall, favorable development for property and marine coverages was due to a favorable outcome on an individual claim in accident year 2005 and favorable loss emergence in non-catastrophe losses in accident years 2009 and 2010. Unfavorable development was recorded in accident year 2011 related to several large losses.

2011

Favorable development for commercial auto coverages was due to lower than expected severity on bodily injury claims and favorable claim emergence on umbrella policies in accident years 2006 and prior.

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Favorable development in the general liability coverages was primarily due to favorable claim emergence in accident years 2007 and prior related to both primary and umbrella liability coverages.

Unfavorable development for workers’ compensation was related to increased medical severity in accident year 2010.

Overall, favorable development for property and other coverages was due to decreased frequency of large losses in commercial multi-peril coverages primarily in accident year 2010, favorable loss emergence related to catastrophe claims in accident year 2008 and favorable loss emergence related to non-catastrophe claims in accident years 2010 and prior. This development amount also included unfavorable development related to unallocated claim adjustment expenses.

2010

Favorable development for commercial auto coverages was primarily due to lower than expected frequency and severity trends in accident years 2009 and prior.

Overall, favorable development for general liability and umbrella coverages was primarily due to better than expected loss emergence in accident years 2006 and prior. This development amount also included unfavorable development, primarily driven by increased claim frequency in accident years 2004 and prior for excess workers’ compensation and in accident years 2008 and 2009 for a portion of CNA’s primary casualty surplus lines book. Unfavorable development was also recorded for accident years prior to 2001 related to mass tort claims, primarily as a result of increased defense costs on specific mass tort accounts, including amounts related to unallocated claim adjustment expenses.

Unfavorable development in workers’ compensation was related to increased severity of indemnity losses relative to expectations on claims related to Defense Base Act contractors, primarily in accident years 2008 and prior.

Favorable development was recorded for property and marine coverages. Favorable development on catastrophe claims was due to lower than expected incurred loss emergence, primarily in accident years 2008 and 2009. Favorable non-catastrophe development was due to lower than expected severity in accident years 2009 and prior. Favorable development in marine business was primarily due to decreased claim frequency and favorable cargo salvage recoveries in recent accident years as well as lower than expected severity for excess liability in accident years 2005 and prior. Favorable property and marine development in CNA’s European operation was due to lower than expected frequency of large claims primarily in accident year 2009.

Note 9. Leases

Leases cover office facilities, machinery and computer equipment. The Company’s hotels in some instances are constructed on leased land. Rent expense amounted to $96 million, $91 million and $92 million for the years ended December 31, 2012, 2011 and 2010. The table below presents the future minimum lease payments to be made under non-cancelable operating leases along with lease and sublease minimum receipts to be received on owned and leased properties.


	Future Minimum Lease
Year Ended December 31	Payments		Receipts

(In millions)

2013	$	66	$	2
2014		58
2015		49
2016		45
2017		35
Thereafter		146

Total	$	399	$	2

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Note 10. Income Taxes

The Company and its eligible subsidiaries file a consolidated federal income tax return. The Company has entered into a separate tax allocation agreement with CNA, a majority-owned subsidiary in which its ownership exceeds 80%. The agreement provides that the Company will: (i) pay to CNA the amount, if any, by which the Company’s consolidated federal income tax is reduced by virtue of inclusion of CNA in the Company’s return or (ii) be paid by CNA an amount, if any, equal to the federal income tax that would have been payable by CNA if it had filed a separate consolidated return. The agreement may be canceled by either of the parties upon thirty days written notice.

For 2010 through 2012, the Internal Revenue Service (“IRS”) has accepted the Company into the Compliance Assurance Process (“CAP”), which is a voluntary program for large corporations. Under CAP, the IRS conducts a real-time audit and works contemporaneously with the Company to resolve any issues prior to the filing of the tax return. The Company believes this approach should reduce tax-related uncertainties, if any. Although the outcome of tax audits is always uncertain, the Company believes that any adjustments resulting from audits will not have a material impact on its results of operations, financial position and cash flows. The Company and/or its subsidiaries also file income tax returns in various state, local and foreign jurisdictions. These returns, with few exceptions, are no longer subject to examination by the various taxing authorities before 2008.

Diamond Offshore, which is not included in the Company’s consolidated federal income tax return, files income tax returns in the U.S. federal, various state and foreign jurisdictions. Diamond Offshore’s 2009 and 2011 U.S. federal income tax returns remain subject to examination. The 2010 federal income tax return is currently under examination. Tax years that remain subject to examination by the various other jurisdictions include years 2003 to 2011.

The current and deferred components of income tax expense (benefit), excluding taxes on discontinued operations, are as follows:


Year Ended December 31	2012		2011		2010

(In millions)

Income tax expense (benefit):
Federal:
Current	$	183	$	127	$	154
Deferred		(18)		246		465
State and city:
Current		19		10		21
Deferred		(5)		14		15
Foreign		110		135		239

Total	$	289	$	532	$	894

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The components of U.S. and foreign income before income tax and a reconciliation between the federal income tax expense at statutory rates and the actual income tax expense is as follows:


Year Ended December 31	2012		2011		2010

(In millions)

Income before income tax:
U.S.	$	911	$	1,466	$	2,236
Foreign		488		760		666

Total	$	1,399	$	2,226	$	2,902


Income tax expense at statutory rate	$	490	$	779	$	1,016
Increase (decrease) in income tax expense resulting from:
Exempt investment income		(86)		(76)		(85)
Foreign related tax differential		(152)		(203)		(105)
Amortization of deferred charges associated with intercompany rig sales to other tax jurisdictions		31		30		30
Taxes related to domestic affiliate		25		55		34
Partnership earnings not subject to taxes		(43)		(27)		(33)
Unrecognized tax benefit		6		(8)		31
Other (a)		18		(18)		6

Income tax expense	$	289	$	532	$	894

(a)	Includes state and local taxes, adjustments to prior year estimates and other non-deductible expenses.

Provision has been made for the expected U.S. federal income tax liabilities applicable to undistributed earnings of subsidiaries, except for certain subsidiaries for which the Company intends to invest the undistributed earnings indefinitely to finance foreign activities, or recover such undistributed earnings tax-free. The determination of the amount of the unrecognized deferred tax liability on approximately $2.0 billion of undistributed earnings related to foreign subsidiaries is not practicable.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


Year Ended December 31	2012		2011

(In millions)

Balance at January 1	$	41	$	46
Additions based on tax positions related to the current year		7		1
Additions for tax positions related to a prior year		2
Reductions for tax positions related to a prior year		(2)		(2)
Lapse of statute of limitations				(4)

Balance at December 31	$	48	$	41

At December 31, 2012 and 2011, there were $48 million and $41 million of tax benefits related to Diamond Offshore that if recognized would affect the effective tax rate.

The Company recognizes interest accrued related to: (i) unrecognized tax benefits in Interest expense and (ii) tax refund claims in Other revenues on the Consolidated Statements of Income. The Company recognizes penalties in Income tax expense on the Consolidated Statements of Income. Penalties and interest amounts recorded by the Company were insignificant for the years ended December 31, 2012, 2011 and 2010.

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The following table summarizes deferred tax assets and liabilities:


December 31	2012		2011

(In millions)

Deferred tax assets:
Insurance reserves:
Property and casualty claim and claim adjustment expense reserves	$	352	$	419
Unearned premium reserves		162		142
Receivables		62		75
Employee benefits		524		449
Life settlement contracts		45		61
Net loss and tax credits carried forward		178		135
Basis differential in investment in subsidiary		26		29
Other		205		227

Deferred tax assets		1,554		1,537


Deferred tax liabilities:
Deferred acquisition costs		(238)		(241)
Net unrealized gains		(733)		(521)
Property, plant and equipment		(691)		(790)
Basis differential in investment in subsidiary		(565)		(490)
Other liabilities		(167)		(117)

Deferred tax liabilities		(2,394)		(2,159)


Net deferred tax liability	$	(840)	$	(622)

As of December 31, 2012, the Company has federal loss carryforwards with a tax effect of approximately $40 million which expire in 2014 and 2032 and federal tax credit carryforwards of $100 million, of which $95 million expire between 2019 and 2022. Diamond Offshore has foreign operating loss carryforwards with a tax effect of approximately $24 million, of which $8 million have an indefinite life with the remaining benefits expiring between 2013 and 2021.

Although realization of deferred tax assets is not assured, management believes it is more likely than not that the recognized deferred tax assets will be realized through recoupment of ordinary and capital taxes paid in prior carryback years and through future earnings, reversal of existing temporary differences and available tax planning strategies.

The American Taxpayer Relief Act of 2012 was signed into law on January 2, 2013. The act extends, through 2013, several expired or expiring temporary business provisions, commonly referred to as “extenders”, which are retroactively extended to the beginning of 2012. As required by GAAP, the effects of new legislation are recognized when signed into law. The Company expects to reduce the first quarter of 2013 tax expense by approximately $28 million as a result of recognizing the 2012 effect of the extenders.

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Note 11. Debt


December 31	2012		2011

(In millions)

Loews Corporation (Parent Company):
Senior:
5.3% notes due 2016 (effective interest rate of 5.4%) (authorized, $400)	$	400	$	400
6.0% notes due 2035 (effective interest rate of 6.2%) (authorized, $300)		300		300
CNA Financial:
Senior:
8.4% notes due 2012 (effective interest rate of 8.6%) (authorized, $100)				70
5.9% notes due 2014 (effective interest rate of 6.0%) (authorized, $549)		549		549
6.5% notes due 2016 (effective interest rate of 6.6%) (authorized, $350)		350		350
7.0% notes due 2018 (effective interest rate of 7.1%) (authorized, $150)		150		150
7.4% notes due 2019 (effective interest rate of 7.5%) (authorized, $350)		350		350
5.9% notes due 2020 (effective interest rate of 6.0%) (authorized, $500)		500		500
5.8% notes due 2021 (effective interest rate of 5.9%) (authorized, $400)		400		400
7.3% debentures due 2023 (effective interest rate of 7.3%) (authorized, $250)		243		243
Variable rate note due 2036 (effective interest rate of 3.7%)		30
Other senior debt (effective interest rates approximate 2.9%)		13		13
Diamond Offshore:
Senior:
5.2% notes due 2014 (effective interest rate of 5.2%) (authorized, $250)		250		250
4.9% notes due 2015 (effective interest rate of 5.0%) (authorized, $250)		250		250
5.9% notes due 2019 (effective interest rate of 6.0%) (authorized, $500)		500		500
5.7% notes due 2039 (effective interest rate of 5.8%) (authorized, $500)		500		500
Boardwalk Pipeline:
Senior:
Variable rate revolving credit facility due 2017 (effective interest rate of 1.3% and 0.5%)		302		458
8.0% subordinated loan due 2022				100
Variable rate term loan due 2016 (effective interest rate of 1.8%)				200
Variable rate term loan due 2017 (effective interest rate of 2.0%)		225
5.8% notes due 2012 (effective interest rate of 6.0%) (authorized, $225)				225
4.6% notes due 2015 (effective interest rate of 5.1%) (authorized, $250)		250		250
5.1% notes due 2015 (effective interest rate of 5.2%) (authorized, $275)		275		275
5.9% notes due 2016 (effective interest rate of 6.0%) (authorized, $250)		250		250
5.5% notes due 2017 (effective interest rate of 5.6%) (authorized, $300)		300		300
6.3% notes due 2017 (effective interest rate of 6.4%) (authorized, $275)		275		275
5.2% notes due 2018 (effective interest rate of 5.4%) (authorized, $185)		185		185
5.8% notes due 2019 (effective interest rate of 5.9%) (authorized, $350)		350		350
4.5% notes due 2021 (effective interest rate of 5.0%) (authorized, $440)		440		440
4.0% notes due 2022 (effective interest rate of 4.4%) (authorized, $300)		300
3.4% notes due 2023 (effective interest rate of 3.5%) (authorized, $300)		300
7.3% debentures due 2027 (effective interest rate of 8.1%) (authorized, $100)		100		100
HighMount:
Senior:
Variable rate credit facility due 2016 (effective interest rate of 3.4%)		710		700
Loews Hotels:
Senior debt, principally mortgages (effective interest rates approximate 3.9%)		209		213
Elimination of intercompany debt				(100)

		9,256		9,046
Less unamortized discount		46		45

Debt	$	9,210	$	9,001

148

December 31, 2012

Principal

Unamortized
Discount

Net

Short Term
Debt

Long Term
Debt

(In millions)

Loews Corporation

700

693

CNA Financial

2,585

2,570

2,557

Diamond Offshore

1,500

1,489

Boardwalk Pipeline

3,552

3,539

HighMount

710

Loews Hotels

209

203

Total

9,256

9,210

9,191

At December 31, 2012, the aggregate of long term debt maturing in each of the next five years is approximately as follows: $19 million in 2013, $820 million in 2014, $948 million in 2015, $1,712 million in 2016, $1,104 million in 2017 and $4,653 million thereafter. Long term debt is generally redeemable in whole or in part at the greater of the principal amount or the net present value of scheduled payments discounted at the specified treasury rate plus a margin.

CNA Financial

In April of 2012, CNA entered into a $250 million revolving credit agreement. The credit agreement which matures on April 19, 2016 bears interest at London Interbank Offered Rate plus applicable margin and is intended to be used for general business purposes. At CNA’s election the commitments under the unsecured credit facility may be increased from time to time up to an additional aggregate amount of $100 million, and two one-year extensions are available prior to first and second anniversary of the closing. As of December 31, 2012, there were no borrowings under the credit facility and CNA was in compliance with all covenants.

Diamond Offshore

In September of 2012, Diamond Offshore entered into a $750 million revolving credit agreement for general business purposes. The credit agreement, which matures on September 28, 2017, bears interest at Diamond Offshore’s option on either an alternate base rate or Eurodollar rate, as defined in the credit agreement, plus an applicable margin. As of December 31, 2012, there were no borrowings under the credit facility and Diamond Offshore was in compliance with all covenants.

Boardwalk Pipeline

In April of 2012, Boardwalk Pipeline entered into a Second Amended and Restated Revolving Credit Agreement (“Amended Credit Agreement”) with aggregate lending commitments of $1.0 billion. The Amended Credit Agreement has a maturity date of April 27, 2017. As of December 31, 2012, Boardwalk Pipeline had $302 million of loans outstanding under the revolving credit facility with a weighted-average interest rate on the borrowings of 1.3% and had no letters of credit issued. As of December 31, 2012, Boardwalk Pipeline was in compliance with all covenants under the credit facility and had available borrowing capacity of $698 million.

In June of 2012, Boardwalk Pipeline issued $300 million principal amount of 4.0% senior notes due June 15, 2022.

In August of 2012, Boardwalk Pipeline repaid at maturity the entire $225 million principal amount of its 5.8% senior notes. In September of 2012, Boardwalk Pipeline repaid in full its $200 million variable rate term loan due December 1, 2016.

In October of 2012, Boardwalk Pipeline entered into a $225 million variable rate term loan due October 1, 2017 to fund the acquisition of Louisiana Midstream.

149

In November of 2012, Boardwalk Pipeline issued $300 million principal amount of 3.4% senior notes due February 1, 2023. The proceeds were utilized to repay $100 million of borrowings under its subordinated loan agreement with BPHC and to reduce outstanding borrowings under its revolving credit facility.

Note 12. Shareholders’ Equity

The components of Accumulated other comprehensive income (loss) are as follows:


	Unrealized Gains (Losses) on Investments		OTTI Gains/ (Losses)		Cash Flow Hedges		Foreign Currency Translation		Pension Liability		Accumulated Other Comprehensive Income (Loss)

(In millions)

Balance, January 1, 2010	$	173	$	(144)	$	(81)	$	77	$	(444)	$	(419)
Unrealized holding gains on investments, after tax of $(319), $(32) and $(30)		585		59		54						698
Adjustments for items included in Net income, after tax of $48, $(15) and $(4)		(89)		27		7						(55)
Foreign currency translation adjustment								49				49
Pension liability adjustment, after tax of $(15)										29		29
Amounts attributable to noncontrolling interests		(62)		(7)		2		(5)				(72)

Balance, December 31, 2010		607		(65)		(18)		121		(415)		230
Acquisition of CNA Surety noncontrolling interests and disposition of FICOH ownership interest		2								8		10
Unrealized holding gains on investments, after tax of $(211), $23 and $(13)		377		(44)		20						353
Adjustments for items included in Net income, after tax of $8, $(29) and $(10)		(15)		54		19						58
Foreign currency translation adjustment								(14)				(14)
Pension liability adjustment, after tax of $126										(238)		(238)
Issuance of equity securities by subsidiary										1		1
Amounts attributable to noncontrolling interests		(42)		(2)		4		1		23		(16)

Balance, December 31, 2011		929		(57)		25		108		(621)		384
Unrealized holding gains on investments, after tax of $(151), $(54) and $(17)		281		102		26						409
Adjustments for items included in Net income, after tax of $(31), $10 and $20		58		(18)		(34)						6
Foreign currency translation adjustment								39				39
Pension liability adjustment, after tax of $68										(132)		(132)
Issuance of equity securities by subsidiary										5		5
Amounts attributable to noncontrolling interests		(35)		(9)		(1)		(4)		16		(33)

Balance, December 31, 2012	$	1,233	$	18	$	16	$	143	$	(732)	$	678

150

Subsidiary Equity Transactions

In February, August and October of 2012, Boardwalk Pipeline sold 9.2 million, 11.6 million and 11.2 million common units in public offerings and received net proceeds of $250 million, $318 million and $298 million, including $5 million, $7 million and $6 million contributions from us to maintain our 2% general partner interest. The Company’s percentage ownership interest in Boardwalk Pipeline declined as a result of these transactions, from 64% to 55%. The issuance price of the common units exceeded the Company’s carrying value, resulting in an increase to APIC of $115 million and an increase to AOCI of $5 million.

Treasury Share Repurchases

The Company repurchased 5.6 million, 18.2 million and 11.0 million shares of Loews common stock at aggregate costs of $222 million, $718 million and $405 million during the years ended December 31, 2012, 2011 and 2010. Upon retirement, treasury stock is eliminated through a reduction to common stock, APIC and retained earnings.

Note 13. Statutory Accounting Practices

CNA’s insurance subsidiaries are domiciled in various jurisdictions. These subsidiaries prepare statutory financial statements in accordance with accounting practices prescribed or permitted by the respective jurisdictions’ insurance regulators. Domestic prescribed statutory accounting practices are set forth in a variety of publications of the National Association of Insurance Commissioners (“NAIC”) as well as state laws, regulations and general administrative rules. These statutory accounting principles vary in certain respects from GAAP. In converting from statutory accounting principles to GAAP, the more significant adjustments include deferral of policy acquisition costs and the inclusion of net unrealized holding gains or losses in shareholders’ equity relating to certain fixed maturity securities.

CNA’s ability to pay dividends and other credit obligations is significantly dependent on receipt of dividends from CCC as it directly or indirectly owns all significant subsidiaries. The payment of dividends by CNA’s insurance subsidiaries without prior approval of the insurance department of each subsidiary’s domiciliary jurisdiction is generally limited by formula. Dividends in excess of these amounts are subject to prior approval by the respective insurance regulator.

Dividends from CCC are subject to the insurance holding company laws of the State of Illinois, the domiciliary state of CCC. Under these laws, ordinary dividends, or dividends that do not require prior approval by the Department, may be paid only from earned surplus, which is calculated by removing unrealized gains from unassigned surplus. As of December 31, 2012, CCC is in a positive earned surplus position, enabling CCC to pay approximately $550 million of dividend payments during 2013 that would not be subject to the Department’s prior approval. The actual level of dividends paid in any year is determined after an assessment of available dividend capacity, holding company liquidity and cash needs as well as the impact the dividends will have on the statutory surplus of the applicable insurance company.

CNA’s domestic insurance subsidiaries are subject to risk-based capital requirements. Risk-based capital is a method developed by the NAIC to determine the minimum amount of statutory capital appropriate for an insurance company to support its overall business operations in consideration of its size and risk profile. The formula for determining the amount of risk-based capital specifies various factors, weighted based on the perceived degree of risk, which are applied to certain financial balances and financial activity. The adequacy of a company’s actual capital is evaluated by a comparison to the risk-based capital results, as determined by the formula. Companies below minimum risk-based capital requirements are classified within certain levels, each of which requires specified corrective action. As of December 31, 2012 and 2011, all of CNA’s domestic insurance subsidiaries exceeded the minimum risk-based capital requirements.

Subsidiaries with insurance operations outside the United States are also subject to insurance regulation in the countries in which they operate. CNA has legal entity and branch operations in other countries, primarily the United Kingdom, Canada and Bermuda. CNA’s foreign legal entities and branch met or exceeded their respective regulatory and other capital requirements.

151

Combined statutory capital and surplus and net income (loss), determined in accordance with accounting practices prescribed or permitted by insurance and/or other regulatory authorities for the Combined Continental Casualty Companies and the life company, were as follows:


	Statutory Capital and Surplus				Statutory Net Income (Loss)

	December 31				Year Ended December 31

	2012 (b)		2011		2012 (b)		2011		2010

(In millions)

Combined Continental Casualty Companies (a)		$ 9,998		$ 9,888		$ 391		$ 954		$ 258
Life company		556		519		44		29		86

(a)	Represents the combined statutory surplus of CCC and its subsidiaries, including the life company.

(b)	Information derived from the statutory-basis financial statements to be filed with insurance regulators.

The Hardy insurance entities are not owned by CCC, therefore their regulatory capital is not included in the Statutory Capital and Surplus of the Combined Continental Casualty Companies presented in the table above. At December 31, 2012, Hardy’s capital requirement was approximately $330 million, which included $66 million of capital provided by CCC and included in Combined Continental Casualty Companies’ Statutory Capital and Surplus above.

Note 14. Supplemental Natural Gas and Oil Information (Unaudited)

Users of this information should be aware that the process of estimating quantities of proved natural gas, NGLs and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent quantities of natural gas, NGLs and oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods.

Estimates of reserves as of December 31, 2012, 2011 and 2010 are based upon studies for each of HighMount’s properties prepared by HighMount staff engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. HighMount’s reserve estimates for 2012 were audited by Netherland, Sewell & Associates, Inc., (“NSAI”). NSAI is an independent third party petroleum engineering consulting firm, and the audit was performed in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. All proved reserves are located in the United States of America.

152

Reserves

Estimated net quantities of proved natural gas and oil (including condensate and NGLs) reserves at December 31, 2012, 2011 and 2010 and changes in the reserves during 2012, 2011 and 2010 are shown in the schedule below:


Proved Developed and Undeveloped Reserves	Natural Gas		NGLs and Oil		Natural Gas Equivalents

	(Bcf)		(thousands		(Bcfe)
			of barrels)

January 1, 2010		1,521		73,838		1,964
Changes in reserves:
Extensions, discoveries and other additions (a)		251		13,370		331
Revisions of previous estimates (b)		(407)		(24,518)		(554)
Production		(57)		(3,263)		(77)
Sales of reserves in place		(363)		(232)		(364)
Purchases of reserves in place

December 31, 2010		945		59,195		1,300
Changes in reserves:
Extensions, discoveries and other additions		26		3,556		48
Revisions of previous estimates (c)		(107)		(7,540)		(152)
Production		(45)		(2,976)		(63)
Sales of reserves in place				(11)
Purchases of reserves in place				167		1

December 31, 2011		819		52,391		1,134
Changes in reserves:
Extensions, discoveries and other additions (d)		22		8,960		75
Revisions of previous estimates (e)		(244)		(13,902)		(328)
Production		(39)		(2,858)		(56)
Sales of reserves in place
Purchases of reserves in place

December 31, 2012		558		44,591		825


Proved developed reserves at:
December 31, 2010		741		45,804		1,016
December 31, 2011		623		37,951		851
December 31, 2012		491		33,781		694

(a)

HighMount added 238 Bcfe of proved undeveloped reserves from non-proved categories in 2010. These additions pertain to locations HighMount expects to drill during the next five years. Additionally, HighMount added 42 Bcfe primarily through drilling and the remaining 51 Bcfe in additions were associated with the Alabama and Michigan properties prior to sale.

(b)

During 2010, HighMount reclassified 208 Bcfe of proved undeveloped reserves to a non-proved category due to certain wells reaching their five year maturity as a result of reduced drilling activity in 2009 and 2010. Additionally, HighMount reduced its proved developed and proved undeveloped reserves by 346 Bcfe as a result of higher production declines on its producing wells than previously anticipated.

(c)	During 2011, HighMount reduced its proved developed and proved undeveloped reserves by 152 Bcfe as a result of recent higher decline rates of producing wells and economic factors such as lower gas prices and higher operating expenses.

(d)	During 2012, HighMount converted 27 Bcfe from probable reserves to proved developed and converted another 48 Bcfe from probable reserves to proved undeveloped as a result of new drilling activity.

(e)

During 2012, HighMount reclassified 199 Bcfe of proved undeveloped reserves to a non-proved category as a result of economic factors such as lower gas prices and higher operating expenses. Lower gas prices also resulted in the 80 Bcfe reduction in proved developed reserves due to wells reaching their economic limit sooner than previously anticipated. Additionally, HighMount reduced its proved developed reserves by 49 Bcfe as a result of higher production declines on its producing wells, partly due to the suspension of uneconomic maintenance and recompletion work.

153

Capitalized Costs

The aggregate amounts of costs capitalized for natural gas and oil producing activities, and related aggregate amounts of accumulated depletion follow:


December 31	2012		2011		2010

(In millions)

Subject to depletion	$	3,497	$	3,002	$	2,818
Costs excluded from depletion		209		384		272

Gross natural gas, NGL and oil properties		3,706		3,386		3,090
Less accumulated depletion		2,813		2,056		1,991

Net natural gas, NGL and oil properties	$	893	$	1,330	$	1,099

The following costs were incurred in natural gas and oil producing activities:


Year Ended December 31	2012		2011		2010

(In millions)

Acquisition of properties:
Proved			$	12
Unproved	$	16		128	$	29

Subtotal		16		140		29
Exploration costs		6		11		5
Development costs (a)		308		159		143

Total	$	330	$	310	$	177

(a)	Development costs incurred for proved undeveloped reserves were $14, $25 and $23 in 2012, 2011 and 2010.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

The following table represents a calculation of the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities that HighMount owns:


December 31	2012		2011		2010

(In millions)

Future cash inflows (a) (b)	$	3,405	$	5,688	$	6,044
Less:
Future production costs		1,446		1,969		2,073
Future development costs		359		636		580
Future income tax expense		6		456		571

Future cash flows		1,594		2,627		2,820
Less annual discount (10% a year)		948		1,725		1,863

Standardized measure of discounted future net cash flows	$	646	$	902	$	957

(a)	2012, 2011 and 2010 amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year end.

(b)	The following prices were used in the determination of standardized measure:


December 31	2012		2011		2010


Gas (per million British thermal units)	$	2.76	$	4.12	$	4.38
NGL (per barrel)		41.11		55.18		43.75
Oil (per barrel)		94.71		96.19		79.43

154

In the foregoing determination of future cash inflows, sales prices for natural gas and oil represent average prices determined as an unweighted arithmetic average of the first-day-of-the-month price for each month, changed for contractual arrangements with customers. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of HighMount’s proved reserves. HighMount cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate. In addition, costs and prices as of the measurement date are used in the determinations, and no value was assigned to probable or possible reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

The following table is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:


Year Ended December 31	2012		2011		2010

(In millions)

Standardized measure, beginning of period	$	902	$	957	$	1,098
Changes in the year resulting from:
Sales and transfers of natural gas and oil produced during the year, less production costs		(213)		(291)		(345)
Net changes in prices and development costs		(644)		164		890
Extensions, discoveries and other additions, less production and development costs		183		82		67
Previously estimated development costs incurred during the period		14		25		23
Revisions of previous quantity estimates		181		(173)		(346)
Net changes in purchases and sales of proved reserves in place				3		(446)
Accretion of discount		100		107		114
Income taxes		131		20		(77)
Net changes in production rates and other		(8)		8		(21)

Standardized measure, end of period	$	646	$	902	$	957

Note 15. Benefit Plans

Pension Plans – The Company has several non-contributory defined benefit plans for eligible employees. Benefits for certain plans are determined annually based on a specified percentage of annual earnings (based on the participant’s age or years of service) and a specified interest rate (which is established annually for all participants) applied to accrued balances. The benefits for another plan which covers salaried employees are based on formulas which include, among others, years of service and average pay. The Company’s funding policy is to make contributions in accordance with applicable governmental regulatory requirements.

Other Postretirement Benefit Plans – The Company has several postretirement benefit plans covering eligible employees and retirees. Participants generally become eligible after reaching age 55 with required years of service. Actual requirements for coverage vary by plan. Benefits for retirees who were covered by bargaining units vary by each unit and contract. Benefits for certain retirees are in the form of a Company health care account.

Benefits for retirees reaching age 65 are generally integrated with Medicare. Other retirees, based on plan provisions, must use Medicare as their primary coverage, with the Company reimbursing a portion of the unpaid amount; or are reimbursed for the Medicare Part B premium or have no Company coverage. The benefits provided by the Company are basically health and, for certain retirees, life insurance type benefits.

155

The Company funds certain of these benefit plans, and accrues postretirement benefits during the active service of those employees who would become eligible for such benefits when they retire. The Company uses December 31 as the measurement date for its plans.

Weighted-average assumptions used to determine benefit obligations:

Pension Benefits

Other Postretirement Benefits

December 31

2012

2011

2010

2012

2011

2010

Discount rate

3.6%

4.5%

5.3%

3.5%

4.3%

5.0%

Expected long term rate of return on plan assets

7.5% to 7.8%

7.5% to 8.0%

5.3%

5.3%

4.6%

Rate of compensation increase

3.5% to 5.5%

4.0% to 5.5%

Weighted-average assumptions used to determine net periodic benefit cost:

Pension Benefits

Other Postretirement Benefits

Year Ended December 31

2012

2011

2010

2012

2011

2010

Discount rate

4.5%

5.3%

5.7%

4.4%

5.0%

5.6%

Expected long term rate of return on plan assets

7.5% to 8.0%

7.5% to 8.0%

5.3%

4.6%

5.4%

Rate of compensation increase

4.0% to 5.5%

4.0% to 5.5%

The expected long term rate of return for plan assets is determined based on widely-accepted capital market principles, long term return analysis for global fixed income and equity markets as well as the active total return oriented portfolio management style. Long term trends are evaluated relative to market factors such as inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan. Consideration of diversification needs and rebalancing is maintained.

Assumed health care cost trend rates:

December 31

2012

2011

2010

Health care cost trend rate assumed for next year

4.0% to 8.5%

4.0% to 8.5%

4.0% to 9.0%

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)

4.0% to 5.0%

4.0% to 5.0%

Year that the rate reaches the ultimate trend rate

2013-2021

2012-2020

2011-2020

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. An increase or decrease in the assumed health care cost trend rate of 1% in each year would not have a significant impact on the Company’s service and interest cost as of December 31, 2012. An increase of 1% in each year would increase the Company’s accumulated postretirement benefit obligation as of December 31, 2012 by $4 million and a decrease of 1% in each year would decrease the Company’s accumulated postretirement benefit obligation as of December 31, 2012 by $6 million.

156

Net periodic benefit cost components:


	Pension Benefits						Other Postretirement Benefits

Year Ended December 31	2012		2011		2010		2012		2011		2010

(In millions)

Service cost		$ 24		$ 24		$ 26		$ 1		$ 2		$ 2
Interest cost		151		164		168		5		6		11
Expected return on plan assets		(188)		(188)		(176)		(4)		(3)		(4)
Amortization of unrecognized net gain		47		29		28				1		2
Amortization of unrecognized prior service benefit								(25)		(27)		(24)
Regulatory asset decrease										4		5

Net periodic benefit cost		$ 34		$ 29		$ 46		$ (23)		$ (17)		$ (8)

The following provides a reconciliation of benefit obligations and plan assets:


	Pension Benefits				Other Postretirement Benefits

	2012		2011		2012		2011

(In millions)

Change in benefit obligation:

Benefit obligation at January 1	$	3,393	$	3,146	$	118	$	159
Service cost		24		24		1		2
Interest cost		151		164		5		6
Plan participants’ contributions						6		7
Amendments								(11)
Actuarial (gain) loss		303		295		8		(15)
Benefits paid from plan assets		(190)		(182)		(16)		(17)
Foreign exchange		19
Reduction of benefit obligations due to disposition of subsidiary				(54)				(13)

Benefit obligation at December 31		3,700		3,393		122		118


Change in plan assets:

Fair value of plan assets at January 1		2,435		2,468		82		73
Actual return on plan assets		269		90		8		11
Company contributions		141		113		7		8
Plan participants’ contributions						6		7
Benefits paid from plan assets		(190)		(182)		(16)		(17)
Foreign exchange		17
Reduction of plan assets due to disposition of subsidiary				(54)

Fair value of plan assets at December 31		2,672		2,435		87		82


Funded status	$	(1,028)	$	(958)	$	(35)	$	(36)

157


	Pension Benefits				Other Postretirement Benefits

	2012		2011		2012		2011

(In millions)

Amounts recognized in the Consolidated Balance Sheets consist of:

Other assets					$	27	$	28
Other liabilities	$	(1,028)	$	(958)		(62)		(64)

Net amount recognized	$	(1,028)	$	(958)	$	(35)	$	(36)


Amounts recognized in Accumulated other comprehensive income (loss), not yet recognized in net periodic (benefit) cost:

Prior service cost (credit)	$	3	$	3	$	(140)	$	(166)
Net actuarial loss		1,348		1,174		24		20

Net amount recognized	$	1,351	$	1,177	$	(116)	$	(146)


Information for plans with projected and accumulated benefit obligations in excess of plan assets:

Projected benefit obligation	$	3,700	$	3,328
Accumulated benefit obligation		3,509		3,218	$	62	$	64
Fair value of plan assets		2,672		2,370

The accumulated benefit obligation for all defined benefit pension plans was $3.6 billion and $3.3 billion at December 31, 2012 and 2011.

The Company employs a total return approach whereby a mix of equity and fixed maturity securities are used to maximize the long term return of plan assets for a prudent level of risk and to manage cash flows according to plan requirements. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established after careful consideration of the plan liabilities, plan funded status and corporate financial conditions. The investment portfolio contains a diversified blend of fixed maturity, equity and short term securities. Alternative investments, including limited partnerships, are used to enhance risk adjusted long term returns while improving portfolio diversification. At December 31, 2012, the Company had committed $44 million to future capital calls from various third party limited partnership investments in exchange for an ownership interest in the related partnerships. Investment risk is monitored through annual liability measurements, periodic asset/liability studies and quarterly investment portfolio reviews.

The table below presents the estimated amounts to be recognized from Accumulated other comprehensive income into net periodic cost (benefit) during 2013.


	Pension Benefits	Other Postretirement Benefits

(In millions)

Amortization of net actuarial loss	$ 56
Amortization of prior service credit		$ (24)

Total estimated amounts to be recognized	$ 56	$ (24)

158

The table below presents the estimated future minimum benefit payments at December 31, 2012.


Expected future benefit payments	Pension Benefits		Other Postretirement Benefits

(In millions)

2013	$	220	$	10
2014		218		10
2015		222		10
2016		227		9
2017		233		9
Thereafter		1,201		39

	$	2,321	$	87

In 2013, it is expected that contributions of approximately $93 million will be made to pension plans and $7 million to postretirement health care and life insurance benefit plans.

Pension plan assets measured at fair value on a recurring basis are summarized below.


December 31, 2012	Level 1		Level 2		Level 3		Total

(In millions)

Fixed maturity securities:
Corporate and other bonds			$	436	$	11	$	447
States, municipalities and political subdivisions				91				91
Asset-backed				269				269

Total fixed maturity securities	$	-		796		11		807
Equity securities		424		102		5		531
Short term investments		41		82				123
Fixed income mutual funds		110						110
Limited partnerships:
Hedge funds				591		391		982
Private equity						69		69

Total limited partnerships		-		591		460		1,051
Other assets				40				40
Investment contracts with insurance company						10		10

Total	$	575	$	1,611	$	486	$	2,672


December 31, 2011


Fixed maturity securities:
Corporate and other bonds			$	377	$	10	$	387
States, municipalities and political subdivisions				104				104
Asset-backed				276				276

Total fixed maturity securities	$	-		757		10		767
Equity securities		386		75		5		466
Short term investments		77		35				112
Fixed income mutual funds		98						98
Limited partnerships:
Hedge funds				533		355		888
Private equity						73		73

Total limited partnerships		-		533		428		961
Other assets				21				21
Investment contracts with insurance company						10		10

Total	$	561	$	1,421	$	453	$	2,435

159

The limited partnership investments are recorded at fair value, which represents the plans’ share of the net asset value of each partnership. The share of the net asset value of each partnership is determined by the General Partner and is based upon the fair value of the underlying investments, which are valued using varying market approaches. Level 2 includes limited partnership investments which can be redeemed at net asset value in 90 days or less. Level 3 includes limited partnership investments with withdrawal provisions greater than 90 days, or for which withdrawals are not permitted until the termination of the partnership. Within hedge fund strategies, approximately 54% are equity related, 35% pursue a multi-strategy approach and 11% are focused on distressed investments at December 31, 2012.

The fair value of the guaranteed investment contracts is an estimate of the amount that would be received in an orderly sale to a market participant at the measurement date. The amount the plan would receive from the contract holder if the contracts were terminated is the primary input and is unobservable. The guaranteed investment contracts are therefore classified as Level 3 investments.

For a discussion of the valuation methodologies used to measure fixed maturity securities, equities and short term investments, see Note 4.

The tables below present reconciliations for all pension plan assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2012 and 2011:

Actual Return on Assets

Net
Purchases,

Net Transfers

Balance at

Still Held at

Sold During

Sales, and

In (Out) of

Balance at

2012

January 1,

December 31,

the Year

Settlements

Level 3

December 31,

(In millions)

Fixed maturity securities:

Corporate and other bonds

$ 10

$ 1

$ 11

Equity securities

Limited partnerships:

Hedge funds

355

$ 3

$ (12)

391

Private equity

(12)

Total limited partnerships

428

(24)

$ -

460

Investment contracts with insurance company

Total

$ 453

$ 54

$ 3

$ (24)

$ -

$ 486


2011


Fixed maturity securities:
Corporate and other bonds	$ 10					$ 10
Asset-backed	10			$ (10)		-

Total fixed maturity securities	20	$ -	$ -	(10)	$ -	10
Equity securities	6	(1)				5
Limited partnerships:
Hedge funds	427	5	5	(82)		355
Private equity	66	10		(3)		73

Total limited partnerships	493	15	5	(85)	-	428
Investment contracts with insurance company	9	1				10

Total	$ 528	$ 15	$ 5	$ (95)	$ -	$ 453

160

Other postretirement benefits plan assets measured at fair value on a recurring basis are summarized below.


December 31, 2012	Level 1		Level 2		Level 3		Total

(In millions)

Fixed maturity securities:
Corporate and other bonds			$	20			$	20
States, municipalities and political subdivisions				38				38
Asset-backed				21				21

Total fixed maturity securities	$	-		79	$	-		79
Short term investments		4						4
Fixed income mutual funds		4						4

Total	$	8	$	79	$	-	$	87


December 31, 2011


Fixed maturity securities:
Corporate and other bonds			$	20			$	20
States, municipalities and political subdivisions				35				35
Asset-backed				20				20

Total fixed maturity securities	$	-		75	$	-		75
Short term investments		3						3
Fixed income mutual funds		4						4

Total	$	7	$	75	$	-	$	82

There were no Level 3 assets at December 31, 2012 and 2011.

Savings Plans – The Company and its subsidiaries have several contributory savings plans which allow employees to make regular contributions based upon a percentage of their salaries. Matching contributions are made up to specified percentages of employees’ contributions. The contributions by the Company and its subsidiaries to these plans amounted to $117 million, $100 million and $104 million for the years ended December 31, 2012, 2011 and 2010.

Stock Option Plans – In 2012, shareholders approved the amended and restated Loews Corporation 2000 Stock Option Plan (the “Loews Plan”). The aggregate number of shares of Loews common stock for which options or SARs may be granted under the Loews Plan increased from 12,000,000 shares to 18,000,000 shares, and the maximum number of shares of Loews common stock with respect to which options or SARs may be granted to any individual in any calendar year is 1,200,000 shares. The exercise price per share may not be less than the fair market value of the common stock on the date of grant. Generally, options and SARs vest ratably over a four-year period and expire in ten years.

161

A summary of the stock option and SAR transactions for the Loews Plan follows:


	2012					2011

	Number of Awards			Weighted Average Exercise Price		Number of Awards			Weighted Average Exercise Price





Awards outstanding, January 1		6,624,609		$	34.447		6,104,501		$	33.082
Granted		970,800			39.605		910,200			39.957
Exercised		(985,359	)		22.517		(370,789	)		25.502
Canceled		(74,900	)		38.701		(19,303	)		34.692

Awards outstanding, December 31		6,535,150			36.963		6,624,609			34.447


Awards exercisable, December 31		4,566,021		$	36.521		4,599,587		$	33.405

The following table summarizes information about the Company’s stock options and SARs outstanding in connection with the Loews Plan at December 31, 2012:

Awards Outstanding

Awards Exercisable

Range of exercise prices

Number of

Shares

Weighted

Average

Remaining

Contractual

Life

Weighted

Average

Exercise

Price

Number of

Shares

Weighted

Average

Exercise

Price

$10.01-20.00

233,778

1.0

18.529

233,778

18.529

20.01-30.00

952,506

4.2

24.733

814,683

24.631

30.01-40.00

3,212,716

6.5

36.742

1,873,805

35.967

40.01-50.00

1,931,400

6.0

44.095

1,439,005

44.825

50.01-60.00

204,750

4.1

51.080

204,750

51.080

In 2012, the Company awarded SARs totaling 970,800 shares. In accordance with the Loews Plan, the Company has the ability to settle SARs in shares or cash and has the intention to settle in shares. The SARs balance at December 31, 2012 was 5,740,208 shares. There were 7,129,900 shares and 1,813,211 shares available for grant as of December 31, 2012 and 2011.

The weighted average remaining contractual terms of awards outstanding and exercisable as of December 31, 2012, were 5.7 years and 4.7 years. The aggregate intrinsic values of awards outstanding and exercisable at December 31, 2012 were $33 million and $27 million. The total intrinsic value of awards exercised was $18 million, $6 million and $9 million for the years ended 2012, 2011 and 2010. The total fair value of shares vested was $11 million, $11 million and $12 million for the years ended 2012, 2011 and 2010.

The Company recorded stock-based compensation expense of $8 million, $10 million and $11 million related to the Loews Plan for the years ended December 31, 2012, 2011 and 2010. The related income tax benefits recognized were $3 million, $4 million and $4 million. At December 31, 2012, the compensation cost related to nonvested awards not yet recognized was $10 million, and the weighted average period over which it is expected to be recognized is 2.3 years.

162

The fair value of granted options and SARs for the Loews Plan were estimated at the grant date using the Black-Scholes pricing model with the following assumptions and results:


Year Ended December 31	2012		2011		2010


Expected dividend yield		0.6%		0.6%		0.7%
Expected volatility		19.0%		24.1%		24.7%
Weighted average risk-free interest rate		0.8%		1.7%		2.0%
Expected holding period (in years)		5.0		5.0		5.0
Weighted average fair value of awards	$	6.53	$	8.92	$	8.57

Note 16. Reinsurance

CNA cedes insurance to reinsurers to limit its maximum loss, provide greater diversification of risk, minimize exposures on larger risks and to exit certain lines of business. The ceding of insurance does not discharge the primary liability of CNA. A credit exposure exists with respect to property and casualty and life reinsurance ceded to the extent that any reinsurer is unable to meet its obligations or to the extent that the reinsurer disputes the liabilities assumed under reinsurance agreements. Property and casualty reinsurance coverages are tailored to the specific risk characteristics of each product line and CNA’s retained amount varies by type of coverage. Reinsurance contracts are purchased to protect specific lines of business such as property and workers’ compensation. Corporate catastrophe reinsurance is also purchased for property and workers’ compensation exposure. Currently most reinsurance contracts are purchased on an excess of loss basis. CNA also utilizes facultative reinsurance in certain lines. In addition, CNA assumes reinsurance, primarily through Hardy and as a member of various reinsurance pools and associations.

The following table summarizes the amounts receivable from reinsurers:


December 31	2012		2011

(In millions)

Reinsurance receivables related to insurance reserves:
Ceded claim and claim adjustment expenses	$	5,126	$	5,020
Ceded future policy benefits		759		792
Ceded policyholders’ funds		35		36
Reinsurance receivables related to paid losses		311		244

Reinsurance receivables		6,231		6,092
Less allowance for doubtful accounts		73		91


Reinsurance receivables, net of allowance for doubtful accounts	$	6,158	$	6,001

CNA has established an allowance for doubtful accounts on reinsurance receivables. CNA reviews the allowance quarterly and adjusts the allowance as necessary to reflect changes in estimates of uncollected balances. The allowance may also be reduced related to write-offs of reinsurance receivable balances.

CNA attempts to mitigate its credit risk related to reinsurance by entering into reinsurance arrangements with reinsurers that have credit ratings above certain levels and by obtaining collateral. On a limited basis, CNA may enter into reinsurance agreements with reinsurers that are not rated, primarily captive reinsurers. The primary methods of obtaining collateral are through reinsurance trusts, letters of credit and funds withheld balances. Such collateral was approximately $3.7 billion and $3.6 billion at December 31, 2012 and 2011.

CNA’s largest recoverables from a single reinsurer at December 31, 2012, including prepaid reinsurance premiums, were approximately $2.7 billion from subsidiaries of Berkshire Hathaway Group, $900 million from subsidiaries of Swiss Re Group and $350 million from subsidiaries of the Hartford Insurance Group. The recoverable from the Berkshire Hathaway Group includes amounts related to third party reinsurance for which a

163

subsidiary of Berkshire Hathaway has assumed the credit risk under the terms of the Loss Portfolio Transfer as discussed in Note 8.

The effects of reinsurance on earned premiums are shown in the following table:


	Direct		Assumed		Ceded		Net		Assumed/ Net %

(In millions)

Year Ended December 31, 2012

Property and casualty	$	8,354	$	197	$	2,229	$	6,322		3.1%
Accident and health		514		47		1		560		8.4
Life		51				51

Earned premiums	$	8,919	$	244	$	2,281	$	6,882		3.5%


Year Ended December 31, 2011

Property and casualty	$	7,858	$	95	$	1,919	$	6,034		1.6%
Accident and health		521		50		2		569		8.8
Life		55				55

Earned premiums	$	8,434	$	145	$	1,976	$	6,603		2.2%


Year Ended December 31, 2010

Property and casualty	$	7,716	$	66	$	1,849	$	5,933		1.1%
Accident and health		534		49		2		581		8.4
Life		60				59		1

Earned premiums	$	8,310	$	115	$	1,910	$	6,515		1.8%

Included in the direct and ceded earned premiums for the years ended December 31, 2012, 2011 and 2010 are $1.8 billion, $1.5 billion and $1.4 billion related to business that is 100% reinsured as a result of a significant captive program.

Life and accident and health premiums are primarily from long duration contracts; property and casualty premiums are primarily from short duration contracts.

Insurance claims and policyholders’ benefits reported on the Consolidated Statements of Income are net of reinsurance recoveries of $1.5 billion, $1.3 billion and $1.1 billion for the years ended December 31, 2012, 2011 and 2010, including $814 million, $790 million and $735 million related to the significant captive program discussed above.

The impact of reinsurance on life insurance inforce is shown in the following table:


December 31	Direct		Assumed		Ceded		Net

(In millions)

2012	$	5,713		-	$	5,702	$	11
2011		6,528		-		6,515		13
2010		8,015		-		8,001		14

As of December 31, 2012 and 2011, CNA has ceded $1.1 billion and $1.2 billion of claim and claim adjustment expense reserves, future policy benefits and policyholders’ funds as a result of business operations sold in prior years. Subject to certain exceptions, the purchasers assumed the third party reinsurance credit risk of the sold business.

164

Note 17. Quarterly Financial Data (Unaudited)

2012 Quarter Ended

Dec. 31

Sept. 30

June 30

March 31

(In millions, except per share data)

Total revenues

3,705

3,715

3,388

3,744

Net income (loss) (a)

(32

)

177

367

Per share-basic

(0.08

)

0.45

0.14

0.93

Per share-diluted

(0.08

)

0.45

0.14

0.92


2011 Quarter Ended


Total revenues	$	3,481	$	3,438	$	3,542	$	3,668

Net income (b)		271		162		250		379
Per share-basic		0.68		0.41		0.61		0.92
Per share-diluted		0.68		0.40		0.61		0.92

The sum of the quarterly per share amounts may not equal per share amounts reported for year-to-date periods. This is due to changes in the number of weighted average shares outstanding and the effects of rounding for each period.

(a)

Net income (loss) for the fourth quarter of 2012 includes an after tax non-cash ceiling test impairment charge of $97 million at HighMount related to the carrying value of its natural gas and oil properties and catastrophe impacts incurred, net of reinsurance and including reinstatement premiums, of $171 million (after tax and noncontrolling interests) recorded at CNA related to Storm Sandy.

(b)	Net income for the fourth quarter of 2011 was impacted by CNA unlocking assumptions related to its payout annuity contracts, resulting in a loss recognition of $104 million (after tax and noncontrolling interests), as further discussed in Note 1.

Note 18. Legal Proceedings

The Company and its subsidiaries are parties to litigation arising in the ordinary course of business. The outcome of this litigation will not, in the opinion of management, materially affect the Company’s results of operations or equity.

165

Note 19. Commitments and Contingencies

Guarantees

In the course of selling business entities and assets to third parties, CNA has agreed to indemnify purchasers for losses arising out of breaches of representation and warranties with respect to the business entities or assets being sold, including, in certain cases, losses arising from undisclosed liabilities or certain named litigation. Such indemnification provisions generally survive for periods ranging from nine months following the applicable closing date to the expiration of the relevant statutes of limitation. As of December 31, 2012, the aggregate amount of quantifiable indemnification agreements in effect for sales of business entities, assets and third party loans was $725 million.

In addition, CNA has agreed to provide indemnification to third party purchasers for certain losses associated with sold business entities or assets that are not limited by a contractual monetary amount. As of December 31, 2012, CNA had outstanding unlimited indemnifications in connection with the sales of certain of its business entities or assets that included tax liabilities arising prior to a purchaser’s ownership of an entity or asset, defects in title at the time of sale, employee claims arising prior to closing and in some cases losses arising from certain litigation and undisclosed liabilities. These indemnification agreements survive until the applicable statutes of limitation expire, or until the agreed upon contract terms expire.

Offshore Rig Purchase Obligations

Diamond Offshore has entered into four turnkey contracts with Hyundai Heavy Industries, Co. Ltd., (“Hyundai”) for the construction of four dynamically positioned, ultra-deepwater drillships, with deliveries scheduled in the second and fourth quarters of 2013 and in the second and fourth quarters of 2014. The aggregate cost of the four drillships, including commissioning, spares and project management, is expected to be approximately $2.6 billion, of which approximately $650 million has been paid. These amounts are included in Construction in process within Property, plant and equipment in the Consolidated Balance Sheets. The remaining $2.0 billion will be paid upon delivery of the drillships in 2013 and 2014.

In December of 2011 and August of 2012, Diamond Offshore entered into agreements for the construction of two moored semisubmersible rigs designed to operate in water depths up to 6,000 feet with expected completion dates in the third quarter of 2013 and the second quarter of 2014. The rigs will be constructed utilizing the hulls of two of Diamond Offshore’s mid-water floaters and the aggregate cost of the two rigs, including commissioning, spares and project management costs, is estimated to be approximately $680 million, of which approximately $93 million has been paid.

Loews Hotels

Loews Hotels has commitments aggregating approximately $520 million for acquisitions, development and renovation of hotel properties.

Note 20. Business Segments

The Company’s reportable segments are primarily based on its individual operating subsidiaries. Each of the principal operating subsidiaries are headed by a chief executive officer who is responsible for the operation of its business and has the duties and authority commensurate with that position. Investment gains (losses) and the related income taxes, excluding those of CNA, are included in the Corporate and other segment.

CNA’s results are reported in four business segments: CNA Specialty, CNA Commercial, Life & Group Non-Core and Other. CNA Specialty provides a broad array of professional, financial and specialty property and casualty products and services, primarily through insurance brokers and managing general underwriters. CNA Commercial includes property and casualty coverages sold to small businesses and middle market entities and organizations primarily through an independent agency distribution system. CNA Commercial also includes commercial insurance and risk management products sold to large corporations primarily through insurance brokers. Life & Group Non-

166

Core primarily includes the results of the life and group lines of business that are in run-off. Other includes the operations of Hardy since its acquisition date of July 2, 2012, corporate expenses, including interest on corporate debt, and the results of certain property and casualty business primarily in run-off, including CNA Re and A&EP. Hardy is a specialized Lloyd’s underwriter primarily of short-tail exposures in marine and aviation, non-marine property, specialty lines and property treaty reinsurance.

Diamond Offshore owns and operates offshore drilling rigs that are chartered on a contract basis for fixed terms by companies engaged in exploration and production of hydrocarbons. Offshore rigs are mobile units that can be relocated based on market demand. Diamond Offshore’s fleet consists of 44 drilling rigs, including four new-build rigs which are under construction and two rigs being constructed utilizing the hulls of Diamond Offshore’s existing mid-water floaters. On December 31, 2012, Diamond Offshore’s drilling rigs were located offshore 12 countries in addition to the United States.

Boardwalk Pipeline is engaged in the interstate transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas. This segment consists of interstate natural gas pipeline systems originating in the Gulf Coast region, Oklahoma and Arkansas, and extending north and east through the midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio, natural gas storage facilities in four states and NGL pipelines and storage facilities in Louisiana, with approximately 14,410 miles of pipeline.

HighMount is engaged in the exploration, production and marketing of natural gas and oil (including condensate and NGLs), primarily located in the Permian Basin in West Texas, as well as in the Oklahoma Mississippian Lime and Texas Panhandle regions.

Loews Hotels operates a chain of 19 hotels, 17 of which are in the United States and two are in Canada.

The Corporate and other segment consists primarily of corporate investment income, corporate interest expense and other unallocated expenses.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 1. In addition, CNA does not maintain a distinct investment portfolio for each of its insurance segments, and accordingly, allocation of assets to each segment is not performed. Therefore, net investment income and investment gains (losses) are allocated based on each segment’s carried insurance reserves, as adjusted.

167

The following tables set forth the Company’s consolidated revenues and income (loss) by business segment:


Year Ended December 31	2012			2011			2010

(In millions)

Revenues (a):

CNA Financial:
CNA Specialty	$	3,742		$	3,512		$	3,516
CNA Commercial		4,238			4,073			4,174
Life & Group Non-Core		1,395			1,334			1,357
Other		172			44			161

Total CNA Financial		9,547			8,963			9,208
Diamond Offshore		3,072			3,334			3,361
Boardwalk Pipeline		1,187			1,144			1,129
HighMount		297			390			455
Loews Hotels		397			337			308
Corporate and other		52			(39	)		154

Total	$	14,552		$	14,129		$	14,615


Income (loss) before income tax and noncontrolling interests (a)(b):

CNA Financial:
CNA Specialty	$	788		$	805		$	1,046
CNA Commercial		451			591			777
Life & Group Non-Core		(222	)		(386	)		(127)
Other		(137	)		(131	)		(575)

Total CNA Financial		880			879			1,121
Diamond Offshore		917			1,177			1,333
Boardwalk Pipeline		304			211			283
HighMount		(636	)		99			136
Loews Hotels		14			17			2
Corporate and other		(80	)		(157	)		27

Total	$	1,399		$	2,226		$	2,902


Net income (loss) (a)(b):

CNA Financial:
CNA Specialty	$	465		$	462		$	579
CNA Commercial		273			343			450
Life & Group Non-Core		(81	)		(191	)		(51)
Other		(87	)		(57	)		(322)

Total CNA Financial		570			557			656
Diamond Offshore		337			451			446
Boardwalk Pipeline		111			77			114
HighMount		(407	)		62			77
Loews Hotels		7			13			1
Corporate and other		(50	)		(98	)		14

Income from continuing operations		568			1,062			1,308
Discontinued operations, net								(19)

Total	$	568		$	1,062		$	1,289

168

(a)	Investment gains (losses) included in Revenues, Income (loss) before income tax and noncontrolling interests and Net income (loss) are as follows:


Year Ended December 31	2012			2011			2010


Revenues and Income (loss) before income tax and noncontrolling interests:

CNA Financial:
CNA Specialty	$	22		$	(5	)	$	30
CNA Commercial		39			14			(15)
Life & Group Non-Core					(8	)		53
Other		(1	)		(20	)		18

Total CNA Financial		60			(19	)		86
Corporate and other		(3	)		(33	)		(30)

Total	$	57		$	(52	)	$	56


Net income (loss):

CNA Financial:
CNA Specialty	$	12		$	(3	)	$	18
CNA Commercial		23			10			(14)
Life & Group Non-Core					(4	)		30
Other					(13	)		12

Total CNA Financial		35			(10	)		46
Corporate and other		(2	)		(21	)		(19)

Total	$	33		$	(31	)	$	27

(b)	Income taxes and interest expense are as follows:


Year Ended December 31	2012					2011					2010

	Income Taxes			Interest Expense		Income Taxes			Interest Expense		Income Taxes			Interest Expense


CNA Financial:
CNA Specialty	$	271				$	279		$	1	$	351		$	1
CNA Commercial		148					206					262
Life & Group Non-Core		(132	)	$	23		(173	)		23		(71	)		23
Other		(40	)		147		(68	)		161		(207	)		133

Total CNA Financial		247			170		244			185		335			157
Diamond Offshore		223			46		250			73		413			91
Boardwalk Pipeline		70			166		57			173		73			151
HighMount		(229	)		14		36			46		59			61
Loews Hotels		7			11		4			9		1			10
Corporate and other		(29	)		33		(59	)		36		13			47

Total	$	289		$	440	$	532		$	522	$	894		$	517

169

Note 21. Consolidating Financial Information

The following schedules present the Company’s consolidating balance sheet information at December 31, 2012 and 2011, and consolidating statements of income information for the years ended December 31, 2012, 2011 and 2010. These schedules present the individual subsidiaries of the Company and their contribution to the consolidated financial statements. Amounts presented will not necessarily be the same as those in the individual financial statements of the Company’s subsidiaries due to adjustments for purchase accounting, income taxes and noncontrolling interests. In addition, many of the Company’s subsidiaries use a classified balance sheet which also leads to differences in amounts reported for certain line items.

The Corporate and Other column primarily reflects the parent company’s investment in its subsidiaries, invested cash portfolio and corporate long term debt. The elimination adjustments are for intercompany assets and liabilities, interest and dividends, the parent company’s investment in capital stocks of subsidiaries, and various reclasses of debit or credit balances to the amounts in consolidation. Purchase accounting adjustments have been pushed down to the appropriate subsidiary.

170

Loews Corporation

Consolidating Balance Sheet Information

December 31, 2012

CNA
Financial

Diamond
Offshore

Boardwalk
Pipeline

HighMount

Loews
Hotels

Corporate
and Other

Eliminations

Total

(In millions)

Assets:

Investments

47,636

1,435

3,935

53,048

Cash

156

228

Receivables

8,516

503

183

(19)

9,366

Property, plant and equipment

297

4,870

7,252

1,136

333

13,935

Deferred income taxes

119

734

(853)

Goodwill

118

271

584

996

Investments in capital stocks of subsidiaries

16,936

(16,936)

Other assets

730

366

330

1,538

Deferred acquisition costs of insurance subsidiaries

598

Separate account business

312

Total assets

58,482

7,247

7,946

2,555

488

21,109

(17,806)

80,021

Liabilities and Equity:

Insurance reserves

40,005

Payable to brokers

134

205

Short term debt

Long term debt

2,557

1,489

3,539

710

203

693

9,191

Deferred income taxes

483

619

552

(851)

840

Other liabilities

3,260

675

432

120

263

(19)

4,773

Separate account business

312

Total liabilities

46,208

2,647

4,590

840

288

1,642

(870)

55,345

Total shareholders’ equity

11,058

2,331

1,624

1,715

200

19,467

(16,936)

19,459

Noncontrolling interests

1,216

2,269

1,732

5,217

Total equity

12,274

4,600

3,356

1,715

200

19,467

(16,936)

24,676

Total liabilities and equity

58,482

7,247

7,946

2,555

488

21,109

(17,806)

80,021

171

Loews Corporation

Consolidating Balance Sheet Information


December 31, 2011	CNA Financial		Diamond Offshore		Boardwalk Pipeline		HighMount		Loews Hotels		Corporate and Other		Eliminations		Total

(In millions)

Assets:

Investments	$	44,372	$	1,206	$	10	$	85	$	71	$	3,284			$	49,028
Cash		75		30		13				10		1				129
Receivables		8,302		594		114		109		33		226	$	(119)		9,259
Property, plant and equipment		272		4,674		6,713		1,576		338		45				13,618
Deferred income taxes		444						499						(943)		-
Goodwill		86		20		215		584		3						908
Investments in capital stocks of subsidiaries												16,807		(16,807)		-
Other assets		544		453		307		19		23		11				1,357
Deferred acquisition costs of insurance subsidiaries		552														552
Separate account business		417														417

Total assets	$	55,064	$	6,977	$	7,372	$	2,872	$	478	$	20,374	$	(17,869)	$	75,268


Liabilities and Equity:

Insurance reserves	$	37,554													$	37,554
Payable to brokers		72	$	8	$	1	$	36			$	45				162
Short term debt		83							$	5						88
Long term debt		2,525		1,488		3,398		700		208		694	$	(100)		8,913
Deferred income taxes				530		493				51		491		(943)		622
Other liabilities		2,971		594		373		104		20		266		(19)		4,309
Separate account business		417														417

Total liabilities		43,622		2,620		4,265		840		284		1,496		(1,062)		52,065

Total shareholders’ equity		10,315		2,209		1,951		2,032		194		18,878		(16,807)		18,772
Noncontrolling interests		1,127		2,148		1,156										4,431

Total equity		11,442		4,357		3,107		2,032		194		18,878		(16,807)		23,203

Total liabilities and equity	$	55,064	$	6,977	$	7,372	$	2,872	$	478	$	20,374	$	(17,869)	$	75,268

172

Loews Corporation

Consolidating Statement of Income Information

Year Ended December 31,
2012

CNA
Financial

Diamond
Offshore

Boardwalk
Pipeline

HighMount

Loews
Hotels

Corporate
and Other

Eliminations

Total

(In millions)

Revenues:

Insurance premiums

6,882

Net investment income

2,282

2,349

Intercompany interest and dividends

683

(683)

Investment gains (losses)

(3)

Contract drilling revenues

2,936

Other

323

131

1,187

297

396

(7)

2,328

Total

9,547

3,072

1,184

297

397

745

(690)

14,552

Expenses:

Insurance claims and policyholders’ benefits

5,896

Amortization of deferred acquisition costs

1,274

Contract drilling expenses

1,537

Other operating expenses

1,327

572

717

919

372

106

(7)

4,006

Interest

170

166

(7)

440

Total

8,667

2,155

883

933

383

146

(14)

13,153

Income (loss) before income tax

880

917

301

(636

)

599

(676)

1,399

Income tax (expense) benefit

(247

)

(223

)

(70

)

229

)

(289)

Net income (loss)

633

694

231

(407

)

628

(676)

1,110

Amounts attributable to noncontrolling interests

(63

)

(357

)

(122

)

(542)

Net income (loss) attributable to Loews Corporation

570

337

109

(407

)

628

(676)

568

173

Loews Corporation

Consolidating Statement of Income Information


Year Ended December 31, 2011	CNA Financial			Diamond Offshore			Boardwalk Pipeline		HighMount			Loews Hotels			Corporate and Other			Eliminations			Total

(In millions)

Revenues:

Insurance premiums	$	6,603																			$	6,603
Net investment income		2,054		$	7							$	1		$	1						2,063
Intercompany interest and dividends																624		$	(624	)		-
Investment gains (losses)		(19	)		1				$	(34	)											(52)
Contract drilling revenues					3,254																	3,254
Other		325			73		$	1,144		390			336			(2	)		(5	)		2,261

Total		8,963			3,335			1,144		356			337			623			(629	)		14,129


Expenses:

Insurance claims and policyholders’ benefits		5,489																				5,489
Amortization of deferred acquisition costs		1,176																				1,176
Contract drilling expenses					1,549																	1,549
Other operating expenses		1,234			535			760		245			311			87			(5	)		3,167
Interest		185			73			173		46			9			44			(8	)		522

Total		8,084			2,157			933		291			320			131			(13	)		11,903

Income before income tax		879			1,178			211		65			17			492			(616	)		2,226
Income tax (expense) benefit		(244	)		(250	)		(57)		(24	)		(4	)		47						(532)

Net income		635			928			154		41			13			539			(616	)		1,694
Amounts attributable to noncontrolling interests		(78	)		(477	)		(77)														(632)

Net income attributable to Loews Corporation	$	557		$	451		$	77	$	41		$	13		$	539		$	(616	)	$	1,062

174

Loews Corporation

Consolidating Statement of Income Information


Year Ended December 31, 2010	CNA Financial		Diamond Offshore		Boardwalk Pipeline		HighMount		Loews Hotels		Corporate and Other		Eliminations		Total

(In millions)

Revenues:

Insurance premiums	$	6,515													$	6,515
Net investment income		2,316	$	3	$	1			$	1	$	187				2,508
Intercompany interest and dividends												720	$	(720)		–
Investment gains (losses)		86					$	(30)								56
Contract drilling revenues				3,230												3,230
Other		291		128		1,128		455		307		(3)				2,306

Total		9,208		3,361		1,129		425		308		904		(720)		14,615


Expenses:

Insurance claims and policyholders’ benefits		4,985														4,985
Amortization of deferred acquisition costs		1,168														1,168
Contract drilling expenses				1,391												1,391
Other operating expenses		1,777		546		695		258		296		80				3,652
Interest		157		91		151		61		10		55		(8)		517

Total		8,087		2,028		846		319		306		135		(8)		11,713

Income before income tax		1,121		1,333		283		106		2		769		(712)		2,902
Income tax expense		(335)		(413)		(73)		(48)		(1)		(24)				(894)

Income from continuing operations		786		920		210		58		1		745		(712)		2,008
Discontinued operations, net		(20)														(20)

Net income		766		920		210		58		1		745		(712)		1,988
Amounts attributable to noncontrolling interests		(129)		(474)		(96)										(699)

Net income attributable to Loews Corporation	$	637	$	446	$	114	$	58	$	1	$	745	$	(712)	$	1,289

175

This Page Intentionally Left Blank

176

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

The Company maintains a system of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) which is designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the federal securities laws, including this Report is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Company under the Exchange Act is accumulated and communicated to the Company’s management on a timely basis to allow decisions regarding required disclosure.

The Company’s principal executive officer (“CEO”) and principal financial officer (“CFO”) undertook an evaluation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Report. The CEO and CFO have concluded that the Company’s controls and procedures were effective as of December 31, 2012.

Internal Control Over Financial Reporting

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the implementing rules of the Securities and Exchange Commission, the Company included a report of management’s assessment of the design and effectiveness of its internal controls as part of this Annual Report on Form 10-K for the year ended December 31, 2012. The independent registered public accounting firm of the Company reported on the effectiveness of internal control over financial reporting as of December 31, 2012. Management’s report and the independent registered public accounting firm’s report are included in Item 8 of this Report under the captions entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.

There were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the foregoing evaluation that occurred during the quarter ended December 31, 2012, that have materially affected or that are reasonably likely to materially affect the Company’s internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

Except as set forth below and under Executive Officers of the Registrant in Part I of this Report, the information called for by Part III (Items 10, 11, 12, 13 and 14) has been omitted as Registrant intends to include such information in its definitive Proxy Statement to be filed with the Securities and Exchange Commission not later than 120 days after the close of its fiscal year.

177

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) 1. Financial Statements:

The financial statements above appear under Item 8. The following additional financial data should be read in conjunction with those financial statements. Schedules not included with these additional financial data have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes to consolidated financial statements.


		Page Number
2. Financial Statement Schedules:

Loews Corporation and Subsidiaries:
Schedule I–Condensed financial information of Registrant as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010		L–1

Schedule II–Valuation and qualifying accounts for the years ended December 31, 2012, 2011 and 2010		L–3

Schedule V–Supplemental information concerning property and casualty insurance operations as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010		L–4


	Description	Exhibit Number

	3. Exhibits:

(3)	Articles of Incorporation and By-Laws

	Restated Certificate of Incorporation of the Registrant, dated August 11, 2009, incorporated herein by reference to Exhibit 3.1 to Registrant’s Report on Form 10-Q for the quarter ended September 30, 2009		3.01

	By-Laws of the Registrant as amended through October 9, 2007, incorporated herein by reference to Exhibit 3.1 to Registrant’s Report on Form 10-Q filed October 31, 2007		3.02

(4)	Instruments Defining the Rights of Security Holders, Including Indentures

	The Registrant hereby agrees to furnish to the Commission upon request copies of instruments with respect to long term debt, pursuant to Item 601(b)(4)(iii) of Regulation S-K

(10)	Material Contracts

	Loews Corporation Deferred Compensation Plan amended and restated as of January 1, 2008, incorporated herein by reference to Exhibit 10.01 to Registrant’s Report on Form 10-K for the year ended December 31, 2008		₊ 10.01

178


Description	Exhibit Number

Loews Corporation Incentive Compensation Plan for Executive Officers, as amended through October 30, 2009, incorporated herein by reference to Exhibit 10.02 to Registrant’s Report on Form 10-K for the year ended December 31, 2009		₊ 10.02

Loews Corporation Amended and Restated Stock Option Plan, incorporated herein by reference to Exhibit A to Registrant’s Proxy Statement filed with the Commission on March 26, 2012		₊ 10.03

Separation Agreement, dated as of May 7, 2008, by and among Registrant, Lorillard, Inc., Lorillard Tobacco Company, Lorillard Licensing Company LLC, One Park Media Services, Inc. and Plisa, S.A., incorporated herein by reference to Exhibit 10.1 to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2008		10.04

Amended and Restated Employment Agreement dated as of February 14, 2012 between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.05 to Registrant’s Report on Form 10-K for the year ended December 31, 2011		₊ 10.05

Amendment dated as of February 15, 2013 to Amended and Restated Employment Agreement between Registrant and Andrew H. Tisch		₊ 10.06 *

Supplemental Retirement Agreement dated January 1, 2002 between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.30 to Registrant’s Report on Form 10-K for the year ended December 31, 2001		₊ 10.07

Amendment No. 1 dated January 1, 2003 to Supplemental Retirement Agreement between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.33 to Registrant’s Report on Form 10-K for the year ended December 31, 2002		₊ 10.08

Amendment No. 2 dated January 1, 2004 to Supplemental Retirement Agreement between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.27 to Registrant’s Report on Form 10-K for the year ended December 31, 2003		₊ 10.09

Amended and Restated Employment Agreement dated as of February 14, 2012 between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.09 to Registrant’s Report on Form 10-K for the year ended December 31, 2011		₊ 10.10

Amendment dated as of February 15, 2013 to Amended and Restated Employment Agreement between Registrant and James S. Tisch		₊ 10.11*

Supplemental Retirement Agreement dated January 1, 2002 between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.31 to Registrant’s Report on Form 10-K for the year ended December 31, 2001		₊ 10.12

Amendment No. 1 dated January 1, 2003 to Supplemental Retirement Agreement between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.35 to Registrant’s Report on Form 10-K for the year ended December 31, 2002		₊ 10.13

Amendment No. 2 dated January 1, 2004 to Supplemental Retirement Agreement between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.34 to Registrant’s Report on Form 10-K for the year ended December 31, 2003		₊ 10.14

179


Description	Exhibit Number

Amended and Restated Employment Agreement dated as of February 14, 2012 between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.13 to Registrant’s Report on Form 10-K for the year ended December 31, 2011		₊ 10.15

Amendment dated as of February 15, 2013 to Amended and Restated Employment Agreement between Registrant and Jonathan M. Tisch		₊ 10.16*

Supplemental Retirement Agreement dated January 1, 2002 between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.32 to Registrant’s Report on Form 10-K for the year ended December 31, 2001		₊ 10.17

Amendment No. 1 dated January 1, 2003 to Supplemental Retirement Agreement between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.37 to Registrant’s Report on Form 10-K for the year ended December 31, 2002		₊ 10.18

Amendment No. 2 dated January 1, 2004 to Supplemental Retirement Agreement between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.41 to Registrant’s Report on Form 10-K for the year ended December 31, 2003		₊ 10.19

Supplemental Retirement Agreement dated March 24, 2000 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10.01 to Registrant’s Report on Form 10-Q for the quarter ended March 31, 2000		₊ 10.20

First Amendment to Supplemental Retirement Agreement dated June 30, 2001 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10 to Registrant’s Report on Form 10-Q for the quarter ended March 31, 2002		₊ 10.21

Second Amendment to Supplemental Retirement Agreement dated March 25, 2003 between Registrant and Peter W. Keegan and Third Amendment to Supplemental Retirement Agreement dated March 31, 2004 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10.44 to Registrant’s Report on Form 10-K for the year ended December 31, 2005		₊ 10.22

Fourth Amendment to Supplemental Retirement Agreement dated December 6, 2005 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10.1 to Registrant’s Report on Form 8-K filed December 7, 2005		₊ 10.23

Form of Stock Option Certificate for grants to executive officers and other employees and to non-employee directors pursuant to the Loews Corporation Amended and Restated Stock Option Plan, incorporated herein by reference to Exhibit 10.27 to Registrant’s Report on Form 10-K for the year ended December 31, 2009		₊ 10.24

Form of Award Certificate for grants of stock appreciation rights to executive officers and other employees pursuant to the Loews Corporation Amended and Restated Stock Option Plan, incorporated herein by reference to Exhibit 10.28 to Registrant’s Report on Form 10-K for the year ended December 31, 2009		₊ 10.25

Lease agreement dated November 20, 2001 between 61^st & Park Ave. Corp. and Preston R. Tisch and Joan Tisch, incorporated herein by reference to Exhibit 10.1 to Registrant’s Report on Form 10-Q filed August 4, 2009		10.26

180


	Description	Exhibit Number

(18)	Preferability letter, dated February 22, 2013, from Independent Registered Public Accounting firm	18.01*

(21)	Subsidiaries of the Registrant

	List of subsidiaries of the Registrant	21.01*

(23)	Consent of Experts and Counsel

	Consent of Deloitte & Touche LLP	23.01*

	Consent of Netherland, Sewell & Associates, Inc.	23.02*

	Audit Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Consultants	23.03*

(31)	Rule 13a-14(a)/15d-14(a) Certifications

	Certification by the Chief Executive Officer of the Company pursuant to Rule 13a-14(a) and Rule 15d-14(a)	31.01*

	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a-14(a) and Rule 15d-14(a)	31.02*

(32)	Section 1350 Certifications

	Certification by the Chief Executive Officer of the Company pursuant to 18 U.S.C. Section 1350 (as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)	32.01*

	Certification by the Chief Financial Officer of the Company pursuant to 18 U.S.C. Section 1350 (as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)	32.02*

(100)	XBRL - Related Documents

	XBRL Instance Document	101.INS **

	XBRL Taxonomy Extension Schema	101.SCH **

	XBRL Taxonomy Extension Calculation Linkbase	101.CAL **

	XBRL Taxonomy Extension Definition Linkbase	101.DEF **

	XBRL Taxonomy Label Linkbase	101.LAB **

	XBRL Taxonomy Extension Presentation Linkbase	101.PRE **


*		Filed herewith.
**		The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this Report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections.
+		Management contract or compensatory plan or arrangement.

181

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


	LOEWS CORPORATION
Dated: February 22, 2013	By	/s/ Peter W. Keegan
		(Peter W. Keegan, Senior Vice President and
		Chief Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Dated: February 22, 2013	By	/s/ James S. Tisch
		(James S. Tisch, President,
		Chief Executive Officer and Director)

Dated: February 22, 2013	By	/s/ Peter W. Keegan
		(Peter W. Keegan, Senior Vice President and
		Chief Financial Officer)

Dated: February 22, 2013	By	/s/ Mark S. Schwartz
		(Mark S. Schwartz, Controller)

Dated: February 22, 2013	By	/s/ Lawrence S. Bacow
		(Lawrence S. Bacow, Director)

Dated: February 22, 2013	By	/s/ Ann E. Berman
		(Ann E. Berman, Director)

Dated: February 22, 2013	By	/s/ Joseph L. Bower
		(Joseph L. Bower, Director)

182


Dated: February 22, 2013	By	/s/ Charles M. Diker
		(Charles M. Diker, Director)

Dated: February 22, 2013	By	/s/ Jacob A. Frenkel
		(Jacob A. Frenkel, Director)

Dated: February 22, 2013	By	/s/ Paul J. Fribourg
		(Paul J. Fribourg, Director)

Dated: February 22, 2013	By	/s/ Walter L. Harris
		(Walter L. Harris, Director)

Dated: February 22, 2013	By	/s/ Philip A. Laskawy
		(Philip A. Laskawy, Director)

Dated: February 22, 2013	By	/s/ Ken Miller
		(Ken Miller, Director)

Dated: February 22, 2013	By	/s/ Gloria R. Scott
		(Gloria R. Scott, Director)

Dated: February 22, 2013	By	/s/ Andrew H. Tisch
		(Andrew H. Tisch, Director)

Dated: February 22, 2013	By	/s/ Jonathan M. Tisch
		(Jonathan M. Tisch, Director)

183

SCHEDULE I

Condensed Financial Information of Registrant

LOEWS CORPORATION

BALANCE SHEETS

ASSETS


December 31			2012		2011

(In millions)

Current assets, principally investment in short term instruments			$	2,556	$	2,267
Investments in securities				1,332		1,140
Investments in capital stocks of subsidiaries, at equity				16,936		16,807
Other assets				34		25

Total assets			$	20,858	$	20,239


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities			$	67	$	233
Long term debt				693		694
Deferred income tax and other				639		540

Total liabilities				1,399		1,467
Shareholders’ equity				19,459		18,772

Total liabilities and shareholders’ equity			$	20,858	$	20,239


STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Year Ended December 31	2012		2011		2010

(In millions)

Revenues:
Equity in income of subsidiaries (a)	$	653	$	1,193	$	1,346
Interest and other		51		(17)		134

Total		704		1,176		1,480

Expenses:
Administrative		101		81		80
Interest		40		44		55

Total		141		125		135

		563		1,051		1,345
Income tax (expense) benefit		5		11		(56)

Net income		568		1,062		1,289
Equity in other comprehensive income of subsidiaries		289		143		646

Total comprehensive income	$	857	$	1,205	$	1,935

L-1

SCHEDULE I

(Continued)

Condensed Financial Information of Registrant

LOEWS CORPORATION

STATEMENTS OF CASH FLOWS


Year Ended December 31	2012		2011		2010

(In millions)

Operating Activities:
Net income	$	568	$	1,062	$	1,289
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Undistributed (earnings) losses of affiliates		14		(571)		(631)
Provision for deferred income taxes		67		(21)		92
Changes in operating assets and liabilities–net:
Receivables		2		(37)		(154)
Accounts payable and accrued liabilities		(42)		(3)		(13)
Trading securities		(396)		420		(1,931)
Other, net		(13)		16		(39)

		200		866		(1,387)


Investing Activities:
Investments and advances to subsidiaries		262		(848)		508
Change in investments, primarily short term		(158)		1,003		375
Redemption of CNA preferred stock						1,000
Other		(10)		(18)		(1)

		94		137		1,882


Financing Activities:
Dividends paid		(99)		(101)		(105)
Issuance of common stock		13		4		8
Purchases of treasury shares		(212)		(732)		(405)
Principal payments on debt				(175)
Other		4		1		2

		(294)		(1,003)		(500)


Net change in cash						(5)
Cash, beginning of year						5

Cash, end of year	$	-	$	-	$	-

(a)	Cash dividends paid to the Company by affiliates amounted to $676, $616 and $712 for the years ended December 31, 2012, 2011 and 2010.

L-2

SCHEDULE II

LOEWS CORPORATION AND SUBSIDIARIES

Valuation and Qualifying Accounts

Column A

Column B

Column C

Column D

Column E

Additions

Description

Balance at
Beginning
of Period

Charged to
Costs and
Expenses

Charged
to Other
Accounts

Deductions

Balance at
End of
Period

(In millions)

For the Year Ended December 31, 2012

Deducted from assets:

Allowance for doubtful accounts

$ 241

$ 1

$ 9

$ 38

$ 213

Total

$ 241

$ 1

$ 9

$ 38

$ 213

For the Year Ended December 31, 2011

Deducted from assets:

Allowance for doubtful accounts

$ 404

$ 6

$ 69

$ 238

$ 241

Total

$ 404

$ 6

$ 69

$ 238

$ 241

For the Year Ended December 31, 2010

Deducted from assets:

Allowance for doubtful accounts

$ 614

$ 1

$ 69

$ 280

$ 404

Total

$ 614

$ 1

$ 69

$ 280

$ 404

L-3

SCHEDULE V

LOEWS CORPORATION AND SUBSIDIARIES

Supplemental Information Concerning Property and Casualty Insurance Operations


Consolidated Property and Casualty Operations


December 31			2012		2011

(In millions)

Deferred acquisition costs			$	598	$	552
Reserves for unpaid claim and claim adjustment expenses				24,696		24,228
Discount deducted from claim and claim adjustment expense reserves above (based on interest rates ranging from 3.0% to 9.7%)				1,850		1,569
Unearned premiums				3,610		3,250

Year Ended December 31	2012		2011		2010

(In millions)

Net written premiums	$	6,964	$	6,798	$	6,471
Net earned premiums		6,881		6,603		6,514
Net investment income		2,074		1,845		2,097
Incurred claim and claim adjustment expenses related to current year		5,266		4,901		4,737
Incurred claim and claim adjustment expenses related to prior years		(180)		(429)		(545)
Amortization of deferred acquisition costs		1,274		1,176		1,168
Paid claim and claim adjustment expenses		5,257		4,499		4,667

L-4