10-Q



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
 
FORM 10-Q

 
ý
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED March 31, 2016
OR
o
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-35700
 
 
Diamondback Energy, Inc.
(Exact Name of Registrant As Specified in Its Charter)
 
 

Delaware
 
45-4502447
(State or Other Jurisdiction of
Incorporation or Organization)
 
(IRS Employer
Identification Number)
 
 
500 West Texas, Suite 1200
Midland, Texas
 
79701
(Address of Principal Executive Offices)
 
(Zip Code)
(432) 221-7400
(Registrant Telephone Number, Including Area Code)
 
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 past 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  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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  ý    No  ¨

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
 
ý
 
Accelerated Filer
 
o
 
 
 
 
Non-Accelerated Filer
 
o
 
Smaller Reporting Company
 
o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
As of April 29, 2016, 71,702,583 shares of the registrant’s common stock were outstanding.





DIAMONDBACK ENERGY, INC
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2016
TABLE OF CONTENTS
 
 
Page
 
 
PART I. FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
PART II. OTHER INFORMATION
 
 
 
 
 
 
 
 








GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):
Basin
A large depression on the earth’s surface in which sediments accumulate.
Bbl
Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
Bbls/d
Bbls per day.
BOE
Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d
BOE per day.
British Thermal Unit
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion
 The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate
 Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Crude oil
 Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Finding and development costs
 Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Gross acres or gross wells
The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling
 A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
Horizontal wells
Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
Mcf
Thousand cubic feet of natural gas.
Mcf/d
 Mcf per day.
Mineral interests
The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu
 Million British Thermal Units.
Net acres or net wells
 The sum of the fractional working interest owned in gross acres.
Oil and natural gas properties
Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Play
 A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Plugging and abandonment
 Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Prospect
 A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves
 The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reserves
 Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

ii



Reservoir
 A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interest
An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
Spacing
 The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Working interest
 An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

iii



GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report.
2012 Plan
The Company’s 2012 Equity Incentive Plan.
Company
 Diamondback Energy, Inc., a Delaware corporation.
Exchange Act
The Securities Exchange Act of 1934, as amended.
GAAP
Accounting principles generally accepted in the United States.
General Partner
Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Indenture
 The indenture relating to the Senior Notes, dated as of September 18, 2013, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
NYMEX
New York Mercantile Exchange.
Partnership
Viper Energy Partners LP, a Delaware limited partnership.
Partnership agreement
The first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering.
SEC
Securities and Exchange Commission.
Securities Act
The Securities Act of 1933, as amended.
Senior Notes
The Company’s 7.625% senior unsecured notes due 2021 in the aggregate principal amount of $450 million.
Viper LTIP
 Viper Energy Partners LP Long Term Incentive Plan.
Viper Offering
 The Partnerships’ initial public offering.
Wells Fargo
Wells Fargo Bank, National Association.


iv



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2015 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

business strategy;

exploration and development drilling prospects, inventories, projects and programs;

oil and natural gas reserves;

acquisitions;

identified drilling locations;

ability to obtain permits and governmental approvals;

technology;

financial strategy;

realized oil and natural gas prices;

production;

lease operating expenses, general and administrative costs and finding and development costs;

future operating results; and

plans, objectives, expectations and intentions.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.


v

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)



 
March 31,
December 31,
 
2016
2015
 
 
 
 
(In thousands, except par values and share data)
Assets
 
 
Current assets:
 
 
Cash and cash equivalents
$
235,810

$
20,115

Restricted cash
500

500

Accounts receivable:
 
 
Joint interest and other
15,211

41,309

Oil and natural gas sales
32,289

36,004

Related party
1,564

1,591

Inventories
1,591

1,728

Derivative instruments
821

4,623

Prepaid expenses and other
3,278

2,875

Total current assets
291,064

108,745

Property and equipment:
 
 
Oil and natural gas properties, based on the full cost method of accounting ($1,090,246 and $1,106,816 excluded from amortization at March 31, 2016 and December 31, 2015, respectively)
4,036,440

3,955,373

Pipeline and gas gathering assets
7,174

7,174

Other property and equipment
49,763

48,621

Accumulated depletion, depreciation, amortization and impairment
(1,485,931
)
(1,413,543
)
Net property and equipment
2,607,446

2,597,625

Derivative instruments
111


Other assets
44,338

44,349

Total assets
$
2,942,959

$
2,750,719

Liabilities and Stockholders’ Equity
 
 
Current liabilities:
 
 
Accounts payable-trade
$
7,131

$
20,008

Accounts payable-related party
206

217

Accrued capital expenditures
36,291

59,937

Other accrued liabilities
50,074

44,293

Revenues and royalties payable
12,998

16,966

Total current liabilities
106,700

141,421

Long-term debt
485,641

487,807

Asset retirement obligations
13,562

12,518

Total liabilities
605,903

641,746

Commitments and contingencies (Note 14)
 
 
Stockholders’ equity:
 
 
Common stock, $0.01 par value, 100,000,000 shares authorized, 71,697,750 issued and outstanding at March 31, 2016; 66,797,041 issued and outstanding at December 31, 2015
717

668

Additional paid-in capital
2,494,467

2,229,664

Accumulated deficit
(387,272
)
(354,360
)
Total Diamondback Energy, Inc. stockholders’ equity
2,107,912

1,875,972

Noncontrolling interest
229,144

233,001

Total equity
2,337,056

2,108,973

Total liabilities and equity
$
2,942,959

$
2,750,719

See accompanying notes to combined consolidated financial statements.

1

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(Unaudited)



 
Three Months Ended March 31,
 
2016
2015
 
 
 
 
(In thousands, except per share amounts)
Revenues:
 
 
Oil sales
$
79,020

$
92,916

Natural gas sales
4,022

4,348

Natural gas liquid sales
4,439

4,137

Total revenues
87,481

101,401

Costs and expenses:
 
 
Lease operating expenses
18,223

22,456

Production and ad valorem taxes
7,962

8,395

Gathering and transportation
2,789

1,030

Depreciation, depletion and amortization
42,069

59,677

Impairment of oil and natural gas properties
30,816


General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $8,350 and $4,924 for the three months ended March 31, 2016 and 2015, respectively)
12,979

8,236

Asset retirement obligation accretion expense
246

170

Total costs and expenses
115,084

99,964

Income (loss) from operations
(27,603
)
1,437

Other income (expense):
 
 
Interest income (expense)
(10,013
)
(10,497
)
Other income
563

515

Gain on derivative instruments, net
1,426

18,354

Total other income (expense), net
(8,024
)
8,372

Income (loss) before income taxes
(35,627
)
9,809

Provision for income taxes

3,370

Net income (loss)
(35,627
)
6,439

Less: Net income (loss) attributable to noncontrolling interest
(2,715
)
590

Net income (loss) attributable to Diamondback Energy, Inc.
$
(32,912
)
$
5,849

 
 
 
Earnings per common share:


Basic
$
(0.46
)
$
0.10

Diluted
$
(0.46
)
$
0.10

Weighted average common shares outstanding:
 
 
Basic
71,026

58,386

Diluted
71,026

58,626


See accompanying notes to combined consolidated financial statements.

2

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
(Unaudited)




 
Common Stock
Additional Paid-in Capital
Retained Earnings (Accumulated Deficit)
Non-Controlling Interest
Total
 
Shares
Amount
 
 
 
 
 
 
 
 
(In thousands)
 
 
 
 
 
 
 
Balance December 31, 2014
56,888

$
569

$
1,554,174

$
196,268

$
234,202

$
1,985,213

Unit-based compensation




939

939

Stock-based compensation


6,125



6,125

Distribution to non-controlling interest




(2,315
)
(2,315
)
Common shares issued in public offering, net of offering costs
2,012

20

119,208



119,228

Exercise of stock options and vesting of restricted stock units
108

1

887



888

Net income



5,849

590

6,439

Balance March 31, 2015
59,008

$
590

$
1,680,394

$
202,117

$
233,416

$
2,116,517

 
 
 
 
 
 
 
Balance December 31, 2015
66,797

$
668

$
2,229,664

$
(354,360
)
$
233,001

$
2,108,973

Unit-based compensation




973

973

Distribution to non-controlling interest




(2,115
)
(2,115
)
Common shares issued in public offering, net of offering costs
4,600

46

254,293



254,339

Exercise of stock options and vesting of restricted stock units
301

3

10,510



10,513

Net loss



(32,912
)
(2,715
)
(35,627
)
Balance March 31, 2016
71,698

$
717

$
2,494,467

$
(387,272
)
$
229,144

$
2,337,056























See accompanying notes to combined consolidated financial statements.

3

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)

 
Three Months Ended March 31,
 
2016
2015
 
 
 
 
(In thousands)
Cash flows from operating activities:
 
 
Net income (loss)
$
(35,627
)
$
6,439

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Provision for (benefit from) deferred income taxes

2,425

Impairment of oil and natural gas properties
30,816


Asset retirement obligation accretion expense
246

170

Depreciation, depletion, and amortization
42,069

59,677

Amortization of debt issuance costs
668

630

Change in fair value of derivative instruments
3,691

25,206

Equity-based compensation expense
8,350

4,924

Changes in operating assets and liabilities:
 
 
Accounts receivable
23,439

7,005

Accounts receivable-related party
27


Inventories
137

(20
)
Prepaid expenses and other
(530
)
(237
)
Accounts payable and accrued liabilities
(5,121
)
(16,226
)
Accounts payable and accrued liabilities-related party
(12
)
14,128

Accrued interest
8,575

8,476

Revenues and royalties payable
(3,968
)
(13,454
)
Net cash provided by operating activities
72,760

99,143

Cash flows from investing activities:
 
 
Additions to oil and natural gas properties
(86,169
)
(144,397
)
Additions to oil and natural gas properties-related party
(164
)
(7,000
)
Acquisition of royalty interests
(2,082
)

Acquisition of leasehold interests
(16,923
)
(2,000
)
Purchase of other property and equipment
(1,142
)
(158
)
Proceeds from sale of assets
123


Equity investments
(800
)

Net cash used in investing activities
(107,157
)
(153,555
)
Cash flows from financing activities:
 
 
Proceeds from borrowings under credit facility
8,500

57,501

Repayment under credit facility
(11,000
)
(119,422
)
Debt issuance costs
(4
)
(8
)
Public offering costs
(179
)
(194
)
Proceeds from public offerings
254,518

119,422

Exercise of stock options
372

888

Distribution to non-controlling interest
(2,115
)
(2,315
)
Net cash provided by financing activities
250,092

55,872

Net increase (decrease) in cash and cash equivalents
215,695

1,460

Cash and cash equivalents at beginning of period
20,115

30,183

Cash and cash equivalents at end of period
$
235,810

$
31,643


4

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows - Continued
(Unaudited)

 
Three Months Ended March 31,
 
2016
2015
 
 
 
 
(In thousands)
Supplemental disclosure of cash flow information:
 
 
Interest paid, net of capitalized interest
$
823

$
1,389

Supplemental disclosure of non-cash transactions:
 
 
Asset retirement obligation incurred
$
132

$
102

Asset retirement obligation revisions in estimated liability
$
88

$
78

Asset retirement obligation acquired
$
796

$
47

Change in accrued capital expenditures
$
(23,646
)
$
(45,854
)
Capitalized stock-based compensation
$
2,764

$
2,139


See accompanying notes to combined consolidated financial statements.

5

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(Unaudited)



1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc. (“Diamondback” or the “Company”), together with its subsidiaries, is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

The wholly-owned subsidiaries of Diamondback, as of March 31, 2016, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, and White Fang Energy LLC, a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), and the Partnership’s wholly-owned subsidiary Viper Energy Partners LLC, a Delaware limited liability company.

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.

The Partnership is consolidated in the financial statements of the Company. As of March 31, 2016, the Company owned approximately 88% of the common units of the Partnership and the Company’s wholly-owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership.

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2015, which contains a summary of the Company’s significant accounting policies and other disclosures.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.


6


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


New Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. This update requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount, to simplify the presentation of debt issuance costs. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early application was permitted for financial statements that have not previously been issued. The Company retrospectively adopted this new standard effective January 1, 2016. Adoption of this standard only affects the presentation of the Company’s consolidated balance sheets and does not have a material impact on its consolidated financial statements.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that hold financial assets or owe financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. This update will be effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. Entities should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. While this update will not have a direct impact on the Company, the Partnership will be required to mark its cost method investment to fair value with the adoption of this update.

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company is currently evaluating the impact that the adoption of this update will have on the Company’s financial position, results of operations and liquidity.

In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-08, “Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on the Company’s financial position, results of operations and liquidity.

In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-09, "Compensation - Stock Compensation". This update applies to all entities that issue share-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company is currently evaluating the impact that the adoption of this update will have on the Company's financial position, results of operations and liquidity.

3.    VIPER ENERGY PARTNERS LP

The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC,

7


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


a fully-consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As of March 31, 2016, the Company owned approximately 88% of the common units of the Partnership.

Partnership Agreement

In connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership.

Tax Sharing

In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period.

Other Agreements

See Note 10—Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”).

The Partnership has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 7—Debt for a description of this credit facility.


8


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


4.    PROPERTY AND EQUIPMENT

Property and equipment includes the following:
 
March 31,
December 31,
 
2016
2015
 
 
 
 
(in thousands)
Oil and natural gas properties:
 
 
Subject to depletion
$
2,946,194

$
2,848,557

Not subject to depletion-acquisition costs
 
 
Incurred in 2016
16,377


Incurred in 2015
433,626

433,769

Incurred in 2014
511,279

543,399

Incurred in 2013
67,666

68,351

Incurred in 2012
61,298

61,297

Total not subject to depletion
1,090,246

1,106,816

Gross oil and natural gas properties
4,036,440

3,955,373

Accumulated depletion
(553,309
)
(512,144
)
Accumulated impairment
(928,778
)
(897,962
)
Oil and natural gas properties, net
2,554,353

2,545,267

Pipeline and gas gathering assets
7,174

7,174

Other property and equipment
49,763

48,621

Accumulated depreciation
(3,844
)
(3,437
)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
$
2,607,446

$
2,597,625


The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $5.0 million and $4.7 million for the three months ended March 31, 2016 and 2015, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

As a result of the decline in prices during the three months ended March 31, 2016, the Company recorded non-cash ceiling test impairments for the three months ended March 31, 2016 of $30.8 million, which is included in

9


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


accumulated depletion. The Company did not have any impairment of its proved oil and gas properties during the three months ended March 31, 2015. The impairment charge affected the Company’s reported net income but did not reduce our cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods.

5.    ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:
 
Three Months Ended March 31,
 
2016
2015
 
 
 
 
(in thousands)
Asset retirement obligation, beginning of period
$
12,711

$
8,486

Additional liability incurred
132

102

Liabilities acquired
796

47

Liabilities settled
(344
)

Accretion expense
246

170

Revisions in estimated liabilities
88

78

Asset retirement obligation, end of period
13,629

8,883

Less current portion
67

39

Asset retirement obligations - long-term
$
13,562

$
8,844


The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

6.    EQUITY METHOD INVESTMENTS

In October 2014, the Company paid $0.6 million for a 25% interest in HMW Fluid Management LLC, which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other counties in the Permian Basin and to pursue other business opportunities. The Company has committed to invest an aggregate amount of $5.0 million in this entity, and several other third parties have committed to invest an aggregate of $15.0 million. During the three months ended March 31, 2016, the Company invested an additional $0.8 million in this entity bringing its total investment to $4.1 million at March 31, 2016. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to a partnership capital account structure. Therefore, the Company accounts for this investment under the equity method of accounting.


10


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


7.    DEBT

Long-term debt consisted of the following as of the dates indicated:
 
March 31,
December 31,
 
2016
2015
 
 
 
 
(in thousands)
7.625 % Senior Notes due 2021
$
450,000

$
450,000

Unamortized debt issuance
(7,359
)
(7,693
)
Revolving credit facility

11,000

Partnership revolving credit facility
43,000

34,500

Total long-term debt
$
485,641

$
487,807


Senior Notes

On September 18, 2013, the Company completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014 and will mature on October 1, 2021. On June 23, 2014, in connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries and, upon such designation, Viper Energy LLC, which was a guarantor under the indenture governing of the Senior Notes, was released as a guarantor under the indenture. As of March 31, 2016, the Senior Notes are fully and unconditionally guaranteed by Diamondback O&G LLC, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The net proceeds from the Senior Notes were used to fund the acquisition of mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin.

The Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association (“Wells Fargo”), as the trustee, as supplemented (the “Indenture”). The Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sells certain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes.

The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company may redeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.

In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a registration rights agreement with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the Senior Notes

11


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


for a new issue of substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on September 15, 2014 and the exchange offer completed on October 23, 2014.

The Company’s Credit Facility

On June 9, 2014, Diamondback O&G LLC, as borrower, entered into a first amendment and on November 13, 2014, Diamondback O&G LLC entered into a second amendment to the second amended and restated credit agreement, dated November 1, 2013 (the “credit agreement”). The first amendment modified certain provisions of the credit agreement to, among other things, allow one or more of the Company’s subsidiaries to be designated as “Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering, the Partnership, the General Partner and Viper Energy Partners LLC were designated as unrestricted subsidiaries under the credit agreement. As of March 31, 2016, the credit agreement was guaranteed by Diamondback, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of the assets of Diamondback O&G LLC, the Company and the other guarantors.

The second amendment increased the maximum amount of the credit facility to $2.0 billion, modified the dates and deadlines of the credit agreement relating to the scheduled borrowing base redeterminations based on the Company’s oil and natural gas reserves and other factors and added new provisions that allow the Company to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of March 31, 2016, the borrowing base was $750.0 million, of which the Company had elected a commitment amount of $500.0 million, and the Company had no outstanding borrowings.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2018.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial Covenant
 
Required Ratio
Ratio of total debt to EBITDAX
Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750.0 million in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of March 31, 2016, the Company had $450.0 million of senior unsecured notes outstanding.

As of March 31, 2016 and December 31, 2015, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect

12


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

The Partnership’s Credit Agreement

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. The credit agreement was further amended on May 22, 2015 to, among other things, increase the borrowing base from $110.0 million to $175.0 million and to provide for certain restrictions on purchasing margin stock. On November 13, 2015, the borrowing base was increased from $175.0 million to $200.0 million. As of March 31, 2016, the borrowing base remained at $200.0 million. The Partnership had $43.0 million outstanding under its credit agreement as of March 31, 2016.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial Covenant
 
Required Ratio
Ratio of total debt to EBITDAX
Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

8.    CAPITAL STOCK AND EARNINGS PER SHARE

During the three months ended March 31, 2016 and 2015, Diamondback completed the following equity offerings:


13


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


In January 2015, the Company completed an underwritten public offering of 2,012,500 shares of common stock, which included 262,500 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $59.34 per share and the Company received proceeds of approximately $119.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In January 2016, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $55.33 per share and the Company received proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

Earnings Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

 
Three Months Ended March 31,
 
2016
2015
 
 
 
Per
 
 
Per
 
Income
Shares
Share
Income
Shares
Share
 
 
 
 
 
 
 
 
(in thousands, except per share amounts)
Basic:
 
 
 
 
 
 
Net income (loss) attributable to common stock
$
(32,912
)
71,026

$
(0.46
)
$
5,849

58,386

$
0.10

Effect of Dilutive Securities:
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
$


 

240

 
Diluted:
 
 
 
 
 
 
Net income (loss) attributable to common stock
$
(32,912
)
71,026

$
(0.46
)
$
5,849

58,626

$
0.10


For the three months ended March 31, 2016, there were 194,737 shares that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods.

9.    EQUITY-BASED COMPENSATION

The following table presents the effects of the equity compensation plans and related costs:
 
Three Months Ended March 31,
 
2016
2015
General and administrative expenses
$
8,350

$
4,924

Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties
2,764

2,139

Related income tax benefit

770



14


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Stock Options

The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the three months ended March 31, 2016.
 
 
Weighted Average
 
 
 
Exercise
Remaining
Intrinsic
 
Options
Price
Term
Value
 
 
 
(in years)
(in thousands)
Outstanding at December 31, 2015
39,500

$
21.66

 
 
Exercised
(17,250
)
$
21.57

 
 
Outstanding at March 31, 2016
22,250

$
21.74

1.62
$
1,234

Vested and Expected to vest at March 31, 2016
22,250

$
21.74

1.62
$
1,234

Exercisable at March 31, 2016
6,500

$
19.35

1.05
$
376


The aggregate intrinsic value of stock options that were exercised during the three months ended March 31, 2016 and 2015 was $0.9 million and $2.1 million, respectively. As of March 31, 2016, the unrecognized compensation cost related to unvested stock options was less than $0.1 million. Such cost is expected to be recognized over a weighted-average period of 0.8 years.

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the 2012 Plan during the three months ended March 31, 2016.
 
Restricted Stock
Awards & Units
Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2015
159,759

$
64.66

Granted
185,320

$
63.44

Vested
(126,825
)
$
59.95

Forfeited
(1,561
)
$
71.25

Unvested at March 31, 2016
216,693

$
66.33


The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2016 and 2015 was $8.2 million and $4.1 million, respectively. As of March 31, 2016, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $11.6 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.

Performance Based Restricted Stock Units

To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a two-year or three-year performance period.

In February 2016, eligible employees received performance restricted stock unit awards totaling 174,325 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2017 and cliff vest at December 31, 2017. Eligible employees received additional performance restricted stock unit awards totaling 87,163 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2018 and cliff vest at December 31, 2018.


15


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the February 2016 awards.
 
2016
 
Two-Year Performance Period
Three-Year Performance Period
Grant-date fair value
$
103.41

$
102.35

Risk-free rate
0.86
%
1.10
%
Company volatility
41.91
%
42.16
%

The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the three months ended March 31, 2016.
 
Performance Restricted Stock Units
Weighted Average Grant-Date Fair Value
Unvested at December 31, 2015
90,249

$
137.14

Granted
261,488

$
103.06

Unvested at March 31, 2016 (1)
351,737

$
111.80

(1)
A maximum of 703,474 units could be awarded based upon the Company’s final TSR ranking.

As of March 31, 2016, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $29.4 million. Such cost is expected to be recognized over a weighted-average period of 1.9 years.

10.    RELATED PARTY TRANSACTIONS

Immediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% of the Company’s outstanding common stock. As of March 31, 2016, Wexford beneficially owned less than 1% of the Company’s outstanding common stock. A partner at Wexford serves as Chairman of the Board of Directors of each of the Company and the General Partner. Another partner at Wexford serves a member of the Board of Directors of the General Partner.


16


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The following table summarizes amounts included in the consolidated statements of operations attributable to related party transactions for the three months ended March 31, 2016 and 2015:

 
Three Months Ended March 31,
 
2016
2015
 
(in thousands)
Revenues:
 
 
Natural gas sales
$

$
2,640

Natural gas liquid sales
$

$
2,544

Total related party revenues
$

$
5,184

Costs and expenses:
 
 
Lease operating expenses
$
266

$

Production and ad valorem taxes
$

$
153

Gathering and transportation
$

$
969

General and administrative expenses
$
442

$
485

Total related party costs and expenses
$
708

$
1,607

Other Income:
 
 
Other income
$
42

$
23

Total other related party income
$
42

$
23


The following table summarizes amounts paid to related parties during the three months ended March 31, 2016 and 2015:
 
Three Months Ended March 31,
 
2016
2015
 
(in thousands)
Wexford:
 
 
Advisory services
$
125

$
137

Advisory services - The Partnership
$

$
125

Total amounts paid to Wexford
$
125

$
262

Wexford related entities:
 
 
Bison Drilling and Field Services LLC
$

$
8

Fasken
$
349

$
184

WT Commercial Portfolio, LLC
$
42

$
39

Total amounts paid to Wexford related entities
$
391

$
231

The Partnership
 
 
Lease Bonus
$
108

$

Total amounts paid to related parties
$
624

$
493




17


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The following table summarizes amounts received from related parties during the three months ended March 31, 2016 and 2015:

 
Three Months Ended March 31,
 
2016
2015
 
(in thousands)
Wexford related entities:
 
 
Bison Drilling and Field Services LLC
$
42

$
23

Coronado Midstream LLC(1)
$

$
4,062

Total amounts received from Wexford related entities
$
42

$
4,085

(1)
As of March 2015, Coronado Midstream LLC is no longer a related party.

Advisory Services Agreement - The Company

The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement had an initial term of two years commencing on October 18, 2012, and continues for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term.

Advisory Services Agreement- The Partnership

In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement has an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term.

Drilling Services

Bison Drilling and Field Services LLC (“Bison”) has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. During the three months ended March 31, 2016, the Company did not utilize any Bison rigs.

Coronado Midstream

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC, formerly known as MidMar Gas LLC, an entity that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. An entity controlled by Wexford had owned an approximately 28% equity interest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is no longer a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a related party.


18


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Midland Corporate Lease

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with an initial five-year term, which was extended for an additional ten-years in November 2014. The office space is owned by Fasken, which is controlled by an affiliate of Wexford.


Field Office Lease

The Company leased field office space in Midland, Texas from an unrelated third party commencing on March 1, 2011. On March 1, 2014, the building was purchased by WT Commercial Portfolio, LLC, which is controlled by an affiliate of Wexford. The term of the lease expires on February 28, 2018. During the third quarter of 2014, the Company entered into a sublease with Bison, in which Bison leased the field office space on the same terms as the Company’s lease for the remainder of the lease term.

The Partnership - Lease Bonus
During the three months ended March 31, 2016, the Company paid the Partnership $0.1 million in lease bonus payments under one lease to extend the term of the lease, reflecting an average bonus of $2,500 per acre.
11.    INCOME TAXES

The Company incurred a tax net operating loss ("NOL") for the three months ended March 31, 2016 due principally to the ability to expense certain intangible drilling and development costs under current regulations. There is no tax refund available to the Company, nor is there any current income tax payable. In light of the impairment of oil and gas properties, management has recorded a $10.1 million valuation against the Company's federal NOLs, bringing the total valuation allowance to $71.2 millionThe valuation reduces the Company’s deferred assets to a zero value, as management does not believe that it is more-likely-than-not that this portion of the Company's NOLs are realizable. Management believes that the balance of the Company's NOLs are realizable only to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

12. DERIVATIVES

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the combined consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing.

By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.


19


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


As of March 31, 2016, the Company had open crude oil derivative positions with respect to future production as set forth in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed.
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap
Production Period
 
Volume (Bbls)
 
Fixed Price Swap (per Bbl)
April 2016 - December 2016
 
550,000

 
$
42.68

January 2017 - December 2017
 
730,000

 
$
45.45


Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of March 31, 2016 and December 31, 2015.
 
March 31, 2016
December 31, 2015
 
(in thousands)
Gross amounts of recognized assets
$
932

$
4,623

Gross amounts offset in the Consolidated Balance Sheet


Net amounts of assets presented in the Consolidated Balance Sheet
$
932

$
4,623


The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
 
March 31, 2016
December 31, 2015
 
(in thousands)
Current Assets: Derivative instruments
$
821

$
4,623

Noncurrent Assets: Derivative instruments
111


Total Assets
$
932

$
4,623


None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the combined consolidated statements of operations:
 
Three Months Ended March 31,
 
2016
2015
 
(in thousands)
Change in fair value of open non-hedge derivative instruments
$
(3,691
)
$
(25,206
)
Gain on settlement of non-hedge derivative instruments
5,117

43,560

Gain on derivative instruments
$
1,426

$
18,354


13.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.


20


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
 
Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015.
 
March 31, 2016
December 31, 2015
 
(in thousands)
Fixed price swaps:
 
 
Quoted prices in active markets level 1
$

$

Significant other observable inputs level 2
932

4,623

Significant unobservable inputs level 3


Total
$
932

$
4,623


Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets.
 
March 31, 2016
December 31, 2015
 
Carrying
 
Carrying
 
 
Amount
Fair Value
Amount
Fair Value
 
(in thousands)
Debt:
 
 
 
 
Revolving credit facility
$

$

$
11,000

$
11,000

7.625% Senior Notes due 2021
450,000

465,750

450,000

450,000

Partnership revolving credit facility
43,000

43,000

34,500

34,500


The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the March 31, 2016 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the Partnership’s revolving credit facility approximates its carrying value

21


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.

14.    COMMITMENTS AND CONTINGENCIES

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

15.    SUBSEQUENT EVENTS

Commodity Contracts

Subsequent to March 31, 2016, the Company entered into new commodity contracts. The contracts are fixed price oil swaps that will settle against the weighted average price per barrel of NYMEX West Texas Intermediate during the calculation period.

The following table presents the terms of the contracts:
 
Volumes (Bbls)
 
Fixed Swap Price (per Bbl)
 
Production Periods
Crude Oil–NYMEX West Texas Intermediate Fixed Price Swap
184,000

 
$
45.22

 
July 1, 2016
-
December 31, 2016
Crude Oil–NYMEX West Texas Intermediate Fixed Price Swap
365,000

 
$
46.68

 
January 1, 2017
-
December 31, 2017

The Company’s Credit Facility

In connection with the Company’s spring 2016 redetermination, the agent lender under the credit agreement has recommended that the Company’s borrowing base be reduced to $700.0 million due to a decline in pricing. This reduction is subject to the approval of the required other lenders. Regardless of such adjustment, the Company has elected to continue to limit the lenders’ aggregate commitment to $500.0 million.

The Partnership’s Credit Facility

In connection with the Partnership’s spring 2016 redetermination, the agent lender under the credit agreement has recommended that the Partnership’s borrowing base be reduced to $175.0 million due to a decline in pricing. This reduction is subject to the approval of the required other lenders.

16.    GUARANTOR FINANCIAL STATEMENTS

Diamondback E&P LLC, Diamondback O&G LLC and White Fang Energy LLC (the “Guarantor Subsidiaries”) are guarantors under the Indenture relating to the Senior Notes. On June 23, 2014, in connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy Partners LLC (the “Non-Guarantor Subsidiaries”) as unrestricted subsidiaries under the Indenture and, upon such designation, Viper Energy Partners LLC, which was a guarantor under the Indenture prior to such designation, was released as a guarantor under the Indenture. Viper Energy Partners LLC is a limited liability company formed on September 18, 2013 to own and acquire mineral and other oil and natural gas interests in properties in the Permian Basin in West Texas. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 16 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the

22


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.

Condensed Consolidated Balance Sheet
March 31, 2016
(In thousands)
 
 
 
 
 
Non–
 
 
 
 
 
 
 
Guarantor
 
Guarantor
 
 
 
 
 
Parent
 
Subsidiaries
 
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
218,235

 
$
12,912

 
$
4,663

 
$

 
$
235,810

Restricted cash

 

 
500

 

 
500

Accounts receivable

 
41,046

 
6,454

 

 
47,500

Accounts receivable - related party

 
1,564

 

 

 
1,564

Intercompany receivable
2,301,767

 
206,900

 

 
(2,508,667
)
 

Inventories

 
1,591

 

 

 
1,591

Other current assets
397

 
3,497

 
205

 

 
4,099

Total current assets
2,520,399

 
267,510

 
11,822

 
(2,508,667
)
 
291,064

Property and equipment:
 
 
 
 
 
 
 
 
 
Oil and natural gas properties, at cost, based on the full cost method of accounting

 
3,479,460

 
557,088

 
(108
)
 
4,036,440

Pipeline and gas gathering assets

 
7,174

 

 

 
7,174

Other property and equipment

 
49,763

 

 

 
49,763

Accumulated depletion, depreciation, amortization and impairment

 
(1,386,731
)
 
(105,820
)
 
6,620

 
(1,485,931
)
Net property and equipment

 
2,149,666

 
451,268

 
6,512

 
2,607,446

Investment in subsidiaries
47,555

 

 

 
(47,555
)
 

Other assets
102

 
8,923

 
35,424

 

 
44,449

Total assets
$
2,568,056

 
$
2,426,099

 
$
498,514

 
$
(2,549,710
)
 
$
2,942,959

Liabilities and Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable-trade
$
19

 
$
7,112

 
$

 
$

 
$
7,131

Accounts payable-related party
2

 
204

 

 

 
206

Intercompany payable

 
2,508,672

 

 
(2,508,672
)
 

Other current liabilities
17,482

 
80,971

 
910

 

 
99,363

Total current liabilities
17,503

 
2,596,959

 
910

 
(2,508,672
)
 
106,700

Long-term debt
442,641

 

 
43,000

 

 
485,641

Asset retirement obligations

 
13,562

 

 

 
13,562

Total liabilities
460,144

 
2,610,521

 
43,910

 
(2,508,672
)
 
605,903

Commitments and contingencies

 

 

 

 

Stockholders’ equity
2,107,912

 
(184,422
)
 
454,604

 
(270,182
)
 
2,107,912

Noncontrolling interest

 

 

 
229,144

 
229,144

Total equity
2,107,912

 
(184,422
)
 
454,604

 
(41,038
)
 
2,337,056

Total liabilities and equity
$
2,568,056

 
$
2,426,099

 
$
498,514

 
$
(2,549,710
)
 
$
2,942,959


23


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Balance Sheet
December 31, 2015
(In thousands)
 
 
 
 
 
Non–
 
 
 
 
 
 
 
Guarantor
 
Guarantor
 
 
 
 
 
Parent
 
Subsidiaries
 
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
148

 
$
19,428

 
$
539

 
$

 
$
20,115

Restricted cash

 

 
500

 

 
500

Accounts receivable

 
67,942

 
9,369

 
2

 
77,313

Accounts receivable - related party

 
1,591

 

 

 
1,591

Intercompany receivable
2,246,846

 
205,915

 

 
(2,452,761
)
 

Inventories

 
1,728

 

 

 
1,728

Other current assets
450

 
6,572

 
476

 

 
7,498

Total current assets
2,247,444

 
303,176

 
10,884

 
(2,452,759
)
 
108,745

Property and equipment:
 
 
 
 
 
 
 
 
 
Oil and natural gas properties, at cost, based on the full cost method of accounting

 
3,400,381

 
554,992

 

 
3,955,373

Pipeline and gas gathering assets

 
7,174

 

 

 
7,174

Other property and equipment

 
48,621

 

 

 
48,621

Accumulated depletion, depreciation, amortization and impairment

 
(1,347,296
)
 
(71,659
)
 
5,412

 
(1,413,543
)
Net property and equipment

 
2,108,880

 
483,333

 
5,412

 
2,597,625

Investment in subsidiaries
79,417

 

 

 
(79,417
)
 

Other assets
102

 
8,733

 
35,514

 

 
44,349

Total assets
$
2,326,963

 
$
2,420,789

 
$
529,731

 
$
(2,526,764
)
 
$
2,750,719

Liabilities and Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable-trade
$

 
$
20,007

 
$
1

 
$

 
$
20,008

Accounts payable-related party
1

 
212

 
4

 

 
217

Intercompany payable

 
2,452,759

 

 
(2,452,759
)
 

Other current liabilities
8,683

 
112,431

 
82

 

 
121,196

Total current liabilities
8,684

 
2,585,409

 
87

 
(2,452,759
)
 
141,421

Long-term debt
442,307

 
11,000

 
34,500

 

 
487,807

Asset retirement obligations

 
12,518

 

 

 
12,518

Total liabilities
450,991

 
2,608,927

 
34,587

 
(2,452,759
)
 
641,746

Commitments and contingencies

 

 

 

 

Stockholders’ equity
1,875,972

 
(188,138
)
 
495,144

 
(307,006
)
 
1,875,972

Noncontrolling interest

 

 

 
233,001

 
233,001

Total equity
1,875,972

 
(188,138
)
 
495,144

 
(74,005
)
 
2,108,973

Total liabilities and equity
$
2,326,963

 
$
2,420,789

 
$
529,731

 
$
(2,526,764
)
 
$
2,750,719




24


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2016
(In thousands)
 
 
 
 
 
Non–
 
 
 
 
 
 
 
Guarantor
 
Guarantor
 
 
 
 
 
Parent
 
Subsidiaries
 
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
Oil sales
$

 
$
66,095

 
$

 
$
12,925

 
$
79,020

Natural gas sales

 
3,409

 

 
613

 
4,022

Natural gas liquid sales

 
3,891

 

 
548

 
4,439

Royalty income

 

 
14,086

 
(14,086
)
 

Lease bonus income

 

 
108

 
(108
)
 

Total revenues

 
73,395

 
14,194

 
(108
)
 
87,481

Costs and expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses

 
18,223

 

 

 
18,223

Production and ad valorem taxes

 
6,660

 
1,302

 

 
7,962

Gathering and transportation

 
2,701

 
86

 
2

 
2,789

Depreciation, depletion and amortization

 
35,128

 
8,150

 
(1,209
)
 
42,069

Impairment of oil and natural gas properties

 
4,805

 
26,011

 

 
30,816

General and administrative expenses
8,307

 
2,923

 
1,749

 

 
12,979

Asset retirement obligation accretion expense

 
246

 

 

 
246

Total costs and expenses
8,307

 
70,686

 
37,298

 
(1,207
)
 
115,084

Income (loss) from operations
(8,307
)
 
2,709

 
(23,104
)
 
1,099

 
(27,603
)
Other income (expense)
 
 
 
 
 
 
 
 
 
Interest expense
(8,858
)
 
(725
)
 
(430
)
 

 
(10,013
)
Other income
57

 
307

 
199

 

 
563

Gain (loss) on derivative instruments, net

 
1,426

 

 

 
1,426

Total other income (expense), net
(8,801
)
 
1,008

 
(231
)
 

 
(8,024
)
Income (loss) before income taxes
(17,108
)
 
3,717

 
(23,335
)
 
1,099

 
(35,627
)
Benefit from income taxes

 

 

 

 

Net income (loss)
(17,108
)
 
3,717

 
(23,335
)
 
1,099

 
(35,627
)
Less: Net loss attributable to noncontrolling interest

 

 

 
(2,715
)
 
(2,715
)
Net income (loss) attributable to Diamondback Energy, Inc.
$
(17,108
)
 
$
3,717

 
$
(23,335
)
 
$
3,814

 
$
(32,912
)


25


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2015
(In thousands)
 
 
 
 
 
Non–
 
 
 
 
 
 
 
Guarantor
 
Guarantor
 
 
 
 
 
Parent
 
Subsidiaries
 
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
 
 
Oil sales
$

 
$
77,384

 
$

 
$
15,532

 
$
92,916

Natural gas sales

 
3,779

 

 
569

 
4,348

Natural gas liquid sales

 
3,693

 

 
444

 
4,137

Royalty income

 

 
16,545

 
(16,545
)
 

Total revenues

 
84,856

 
16,545

 

 
101,401

Costs and expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses

 
22,456

 

 

 
22,456

Production and ad valorem taxes

 
7,067

 
1,328

 

 
8,395

Gathering and transportation

 
1,030

 

 

 
1,030

Depreciation, depletion and amortization

 
50,307

 
8,901

 
469

 
59,677

Impairment of oil and natural gas properties

 

 

 

 

General and administrative expenses
4,518

 
2,166

 
1,552

 

 
8,236

Asset retirement obligation accretion expense

 
170

 

 

 
170

Total costs and expenses
4,518

 
83,196

 
11,781

 
469

 
99,964

Income (loss) from operations
(4,518
)
 
1,660

 
4,764

 
(469
)
 
1,437

Other income (expense)
 
 
 
 
 
 
 
 
 
Interest expense
(8,910
)
 
(1,419
)
 
(168
)
 

 
(10,497
)
Other income

 
29

 
486

 

 
515

Gain (loss) on derivative instruments, net

 
18,354

 

 

 
18,354

Total other income (expense), net
(8,910
)
 
16,964

 
318

 

 
8,372

Income (loss) before income taxes
(13,428
)
 
18,624

 
5,082

 
(469
)
 
9,809

Provision for income taxes
3,370

 

 

 

 
3,370

Net income (loss)
(16,798
)
 
18,624

 
5,082

 
(469
)
 
6,439

Less: Net loss attributable to noncontrolling interest

 

 

 
590

 
590

Net income (loss) attributable to Diamondback Energy, Inc.
$
(16,798
)
 
$
18,624

 
$
5,082

 
$
(1,059
)
 
$
5,849



26


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2016
(In thousands)
 
 
 
 
 
Non–
 
 
 
 
 
 
 
Guarantor
 
Guarantor
 
 
 
 
 
Parent
 
Subsidiaries
 
Subsidiaries
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities
$
(526
)
 
$
57,400

 
$
15,886

 
$

 
$
72,760

Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties

 
(86,333
)
 

 

 
(86,333
)
Acquisition of leasehold interests

 
(16,923
)
 

 

 
(16,923
)
Acquisition of royalty interests

 

 
(2,082
)
 

 
(2,082
)
Purchase of other property and equipment

 
(1,142
)
 

 

 
(1,142
)
Proceeds from sale of assets

 
123

 

 

 
123

Equity investments

 
(800
)
 

 

 
(800
)
Intercompany transfers
(41,161
)
 
41,161

 

 

 

Net cash used in investing activities
(41,161
)
 
(63,914
)
 
(2,082
)
 

 
(107,157
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from borrowing on credit facility

 

 
8,500

 

 
8,500

Repayment on credit facility

 
(11,000
)
 

 

 
(11,000
)
Debt issuance costs

 
(2
)
 
(2
)
 

 
(4
)
Public offering costs
(179
)
 

 

 

 
(179
)
Proceeds from public offerings
254,518

 

 

 

 
254,518

Distribution from subsidiary
16,063

 

 

 
(16,063
)
 

Exercise of stock options
372

 

 

 

 
372

Distribution to non-controlling interest

 

 
(18,178
)
 
16,063

 
(2,115
)
Intercompany transfers
(11,000
)
 
11,000

 

 

 

Net cash provided by (used in) financing activities
259,774

 
(2
)
 
(9,680
)
 

 
250,092

Net increase (decrease) in cash and cash equivalents
218,087

 
(6,516
)
 
4,124

 

 
215,695

Cash and cash equivalents at beginning of period
148

 
19,428

 
539

 

 
20,115

Cash and cash equivalents at end of period
$
218,235

 
$
12,912

 
$
4,663

 
$

 
$
235,810


27


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2015
(In thousands)
 
 
 
 
 
Non–
 
 
 
 
 
 
 
Guarantor
 
Guarantor
 
 
 
 
 
Parent
 
Subsidiaries
 
Subsidiaries
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities
$
(1,970
)
 
$
86,560

 
$
14,553

 
$

 
$
99,143

Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Additions to oil and natural gas properties

 
(150,963
)
 
85

 

 
(150,878
)
Acquisition of leasehold interests

 
(2,519
)
 

 

 
(2,519
)
Purchase of other property and equipment

 
(158
)
 

 

 
(158
)
Intercompany transfers
(16,280
)
 
16,280

 

 

 

Net cash provided by (used in) investing activities
(16,280
)
 
(137,360
)
 
85

 

 
(153,555
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from borrowing on credit facility

 
57,501

 

 

 
57,501

Repayment on credit facility

 
(119,422
)
 

 

 
(119,422
)
Proceeds from public offerings
119,422

 

 

 

 
119,422

Distribution from subsidiary
17,612

 

 

 
(17,612
)
 

Distribution to non-controlling interest

 

 
(19,927
)
 
17,612

 
(2,315
)
Intercompany transfers
(119,422
)
 
119,422

 

 

 

Other financing activities
686

 

 

 

 
686

Net cash provided by (used in) financing activities
18,298

 
57,501

 
(19,927
)
 

 
55,872

Net increase (decrease) in cash and cash equivalents
48

 
6,701

 
(5,289
)
 

 
1,460

Cash and cash equivalents at beginning of period
6

 
15,067

 
15,110

 

 
30,183

Cash and cash equivalents at end of period
$
54

 
$
21,768

 
$
9,821

 
$

 
$
31,643




28



ITEM 2.         MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations which we refer to as the Wolfberry play. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. Our production was approximately 76% oil, 13% natural gas liquids and 11% natural gas for the three months ended March 31, 2016, and was approximately 77% oil, 13% natural gas liquids and 10% natural gas for the three months ended March 31, 2015. On March 31, 2016, our net acreage position in the Permian Basin was approximately 85,816 net acres.

The challenging commodity price environment that we experienced in 2015 has continued in the first quarter of 2016, with the posted price of WTI dropping to as low as $26.68 in January 2016. Commodity prices improved at the end of the first quarter 2016, but continue to be volatile. We believe we remain well-positioned in this environment. During 2015, we again demonstrated our operational focus on achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to reduce drilling days, well costs and operating expenses while maintaining what we believe to be a peer leading leverage ratio. We intend to continue our operational focus in 2016, emphasizing financial discipline over growth. With recent improvement in oil prices, we have retained our third horizontal rig and added a second dedicated completion crew to decrease our backlog of drilled but uncompleted wells. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions. We are prepared to add a fourth horizontal rig early in the third quarter of 2016 in the event oil prices continue to strengthen and we are prepared to remain at three horizontal drilling rigs or decelerate our drilling program if commodity prices deteriorate.

2016 Highlights

Common stock transactions

In January 2016, we completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $55.33 per share and we received proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

Operational Update

During the three months ended March 31, 2016, we drilled 16 gross (13 net) horizontal wells and one gross (one net) vertical well and participated in the drilling of two gross (one net) non-operated wells in the Permian Basin. We completed a total of eight horizontal wells, which included our initial five wells in Glasscock County. A three well pad targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B horizons came on line in January 2016. The combined 30-day initial production rate for the three laterals was 3,644 BOE/d (75% oil) from an average lateral length of 7,396 feet. A second two well pad targeting the Wolfcamp A and Wolfcamp B horizons was brought on line in February 2016. The combined 30-day initial production rate for the two laterals was 2,312 BOE/d (84% oil) from an average lateral length of 7,465 feet. We have drilled another two-well pad in Glasscock County that is waiting on completion.


29



In Howard County we have two three-well pads waiting on completion. Both pads target the Lower Spraberry, Wolfcamp A and Wolfcamp B intervals. We intend to begin completing the first pad in May 2016 and the second pad in June 2016.

We entered 2016 drilling with three horizontal rigs and were prepared to release one of the rigs in early February. However, with recent improvement in oil prices, we have retained our third horizontal rig and are prepared to add a fourth horizontal rig early in the third quarter of 2016 in the event oil prices continue to strengthen. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down accordingly.

During the first quarter of 2016, we slowed our completion schedule in response to lower commodity prices. However, we have recently contracted a second completion crew to begin to reduce our inventory of drilled but uncompleted wells.

During the three months ended March 31, 2016, our average daily production was approximately 38,308 BOE/d, consisting of 28,951 Bbls/d of oil, 25,458 Mcf/d of natural gas and 5,114 Bbls/d of natural gas liquids, an increase of 7,672 BOE/d, or 25.0%, from average daily production of 30,636 BOE/d for the three months ended March 31, 2015, consisting of 23,687 Bbls/d of oil, 17,765 Mcf/d of natural gas and 3,988 Bbls/d of natural gas liquids.

Sources of Our Revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended March 31, 2016, our revenues were derived 90% from oil sales, 5% from natural gas liquids sales and 5% from natural gas sales and for the three months ended March 31, 2015, our revenues were derived 92% from oil sales, 4% from natural gas liquids sales and 4% from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.

Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2015, West Texas Intermediate posted prices ranged from $34.55 to $61.36 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.63 to $3.32 per MMBtu. On March 31, 2016, the West Texas Intermediate posted price for crude oil was $36.94 per Bbl and the Henry Hub spot market price of natural gas was $1.98 per MMBtu. Lower commodity prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

As a result of the decline in prices during the three months ended March 31, 2016, the Company recorded non-cash ceiling test impairment for the three months ended March 31, 2016 of $30.8 million.

Although commodity prices improved at the end of the first quarter 2016, they remain volatile. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, we will incur an additional non-cash full cost impairment in the second quarter of 2016, which will have an adverse effect on our results of operations.


30




Results of Operations

The following table sets forth selected historical operating data for the periods indicated.
 
Three Months Ended March 31,
 
2016
2015
 
(in thousands, except Bbl, Mcf and BOE amounts)
Revenues
 
 
Oil, natural gas liquids and natural gas
$
87,481

$
101,401

Operating Expenses
 
 
Lease operating expense
18,223

22,456

Production and ad valorem taxes
7,962

8,395

Gathering and transportation expense
2,789

1,030

Depreciation, depletion and amortization
42,069

59,677

Impairment of oil and natural gas properties
30,816


General and administrative
12,979

8,236

Asset retirement obligation accretion expense
246

170

Total expenses
115,084

99,964

Income (loss) from operations
(27,603
)
1,437

Net interest expense
(10,013
)
(10,497
)
Other income
563

515

Gain on derivative instruments, net
1,426

18,354

Total other income (expense), net
(8,024
)
8,372

Income (loss) before income taxes
(35,627
)
9,809

Income tax provision

3,370

Net income (loss)
(35,627
)
6,439

Less: Net income (loss) attributable to noncontrolling interest
(2,715
)
590

Net income (loss) attributable to Diamondback Energy, Inc.
$
(32,912
)
$
5,849



31




 
Three Months Ended March 31,
 
2016
2015
 
(in thousands, except Bbl, Mcf and BOE amounts)
Production Data:
 
 
Oil (Bbls)
2,634,511

2,131,829

Natural gas (Mcf)
2,316,649

1,598,810

Natural gas liquids (Bbls)
465,391

358,924

Combined volumes (BOE)
3,486,010

2,757,221

Daily combined volumes (BOE/d)
38,308

30,636

 
 
 
Average Prices:
 
 
Oil (per Bbl)
$
29.99

$
43.59

Natural gas (per Mcf)
1.74

2.72

Natural gas liquids (per Bbl)
9.54

11.53

Combined (per BOE)
25.09

36.78

Oil, hedged($ per Bbl)(1)
31.94

64.01

Average price, hedged($ per BOE)(1)
26.56

52.57

 
 
 
Average Costs per BOE:
 
 
Lease operating expense
$
5.23

$
8.14

Production and ad valorem taxes
2.28

3.04

Gathering and transportation expense
0.80

0.37

General and administrative - cash component
1.33

1.20

Total operating expense - cash
9.64

12.75

 
 
 
General and administrative - non-cash component
2.39

1.79

Depreciation, depletion, and amortization
12.07

21.64

Interest expense
2.87

3.81

Total expenses
17.33

27.24

(1)
Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

Comparison of the Three Months Ended March 31, 2016 and 2015

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues decreased by approximately $13.9 million, or 14%, to $87.5 million for the three months ended March 31, 2016 from $101.4 million for the three months ended March 31, 2015. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 7,672 BOE/d to 38,308 BOE/d during the three months ended March 31, 2016 from 30,636 BOE/d during the three months ended March 31, 2015. The total decrease in revenue of approximately $13.9 million is largely attributable to lower average sales prices partially offset by higher oil, natural gas liquids and natural gas production volumes for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 502,682 Bbls of oil, 106,467 Bbls of natural gas liquids and 717,839 Mcf of natural gas for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015.

32




The net dollar effect of the decreases in prices of approximately $39.0 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $25.1 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
 
Change in prices
Production volumes(1)
Total net dollar effect of change
 
 
 
(in thousands)
Effect of changes in price:
 
 
 
Oil
$
(13.60
)
2,634,511

$
(35,823
)
Natural gas liquids
(1.99
)
465,391

(926
)
Natural gas
(0.98
)
2,316,649

(2,270
)
Total revenues due to change in price
 
 
$
(39,019
)
 
 
 
 
 
Change in production volumes(1)
Prior period Average Prices
Total net dollar effect of change
 
 
 
(in thousands)
Effect of changes in production volumes:
 
 
 
Oil
502,682

$
43.59

$
21,918

Natural gas liquids
106,467

11.53

1,228

Natural gas
717,839

2.72

1,953

Total revenues due to change in production volumes
 
 
25,099

Total change in revenues
 
 
$
(13,920
)
(1)
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.

Lease Operating Expense. Lease operating expense was $18.2 million ($5.23 per BOE) for the three months ended March 31, 2016, a decrease of $4.2 million, or 19%, from $22.5 million ($8.14 per BOE) for the three months ended March 31, 2015. The decrease is due to a reduction in service costs resulting from decreased commodity prices.

Production and Ad Valorem Tax Expense. Production and ad valorem taxes were $8.0 million for the three months ended March 31, 2016, a decrease of $0.4 million, or 5%, from $8.4 million for the three months ended March 31, 2015. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. During the three months ended March 31, 2016, our production taxes per BOE decreased by $0.76 as compared to the three months ended March 31, 2015, primarily reflecting the impact of lower oil and natural gas prices on production taxes in 2016, offset by an increase in ad valorem taxes primarily as a result of increased production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $17.6 million, or 30%, to $42.1 million for the three months ended March 31, 2016 from $59.7 million for the three months ended March 31, 2015.

The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:
 
Three Months Ended March 31,
 
2016
2015
 
 
 
 
(in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties
$
41,648

$
59,255

Depreciation of other property and equipment
421

422

Depreciation, depletion and amortization expense
$
42,069

$
59,677

 
 
 
Oil and natural gas properties depreciation, depletion and amortization per BOE
$
11.95

$
21.49

Total depreciation, depletion and amortization per BOE
$
12.07

$
21.64


33





The decreases in depletion of proved oil and natural gas properties of $17.6 million for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015 resulted primarily from the impairment of oil and gas properties recorded in the first quarter of 2016.

Impairment of Oil and Gas Properties. During the three months ended March 31, 2016, we recorded an impairment of oil and gas properties of $30.8 million as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil and natural gas reserves.

General and Administrative Expense. General and administrative expense increased $4.8 million from $8.2 million for the three months ended March 31, 2015 to $13.0 million for the three months ended March 31, 2016. The increase was primarily due to an increase in non-cash equity compensation of $ 4.0 million and an increase in salaries and benefits of $0.8 million.

Net Interest Expense. Net interest expense for the three months ended March 31, 2016 was $10.0 million as compared to $10.5 million for the three months ended March 31, 2015, a decrease of $0.5 million. This decrease was due primarily to the lower average level of outstanding borrowings under our credit facility during the three months ended March 31, 2016 as compared to the three months ended March 31, 2015.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the three months ended March 31, 2016 and 2015, we had a cash gain on settlement of derivative instruments of $5.1 million and $43.6 million, respectively. For the three months ended March 31, 2016 and 2015, we had a negative change in the fair value of open derivative instruments of $3.7 million and $25.2 million, respectively.

Income Tax Expense (Benefit). We had no income tax benefit or expense for the three months ended March 31, 2016 as compared to income tax expense of $3.4 million for the three months ended March 31, 2015. Our effective tax rate was 34.4% for the three months ended March 31, 2015. During the three months ended March 31, 2016, we recorded a valuation allowance as management does not believe that it is more-likely-than-not that its net operating losses are realizable.

Liquidity and Capital Resources

Our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

Liquidity and Cash Flow

Our cash flows for the three months ended March 31, 2016 and 2015 are presented below:
 
Three Months Ended March 31,
 
2016
2015
 
(in thousands)
Net cash provided by operating activities
$
72,760

$
99,143

Net cash used in investing activities
(107,157
)
(153,555
)
Net cash provided by financing activities
250,092

55,872

Net change in cash
$
215,695

$
1,460



34




Operating Activities

Net cash provided by operating activities was $72.8 million for the three months ended March 31, 2016 as compared to $99.1 million for the three months ended March 31, 2015. The decrease in operating cash flows is primarily the result of the decrease in our oil and natural gas revenues due to a 32% decrease in our net realized sales prices.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “—Sources of our revenue” above.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. Net cash used in investing activities was $107.2 million and $153.6 million during the three months ended March 31, 2016 and 2015, respectively.

During the three months ended March 31, 2016, we spent $86.3 million on capital expenditures in conjunction with our drilling program, in which we drilled 16 gross (13 net) horizontal wells and one gross (one net) vertical well and participated in the drilling of two gross (one net) non-operated wells, $16.9 million on leasehold acquisitions, $2.1 million on royalty interest acquisitions and $1.1 million for the purchase of other property and equipment.

During the three months ended March 31, 2015, we spent $151.4 million on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 15 gross (13 net) horizontal wells and two gross (one net) vertical wells. We spent an additional $2.0 million on leasehold costs and $0.2 million for the purchase of other property and equipment.

Our investing activities for the three months ended March 31, 2016 and 2015 are summarized in the following table:
 
Three Months Ended March 31,
 
2016
2015
 
(in thousands)
Drilling, completion and infrastructure
$
(86,333
)
$
(151,397
)
Acquisition of leasehold interests
(16,923
)
(2,000
)
Acquisition of royalty interests
(2,082
)

Purchase of other property and equipment
(1,142
)
(158
)
Proceeds from sale of property and equipment
123


Equity investments
(800
)

Net cash used in investing activities
$
(107,157
)
$
(153,555
)

Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2016 and 2015 was $250.1 million and $55.9 million, respectively. During the three months ended March 31, 2016, the amount provided by financing activities was primarily attributable to proceeds from our January 2016 equity offering of $254.5 million partially offset by repayments of net borrowings of $2.5 million under our credit facility. The 2015 amount provided by financing activities was primarily attributable to the proceeds from our January 2015 equity offering of $119.4 million partially offset by repayments of net borrowings of $61.9 million under our credit facility

Second Amended and Restated Credit Facility

Our second amended and restated credit agreement, dated November 1, 2013, as amended on June 9, 2014 and November 13, 2014, with a syndicate of banks, including Wells Fargo, as administrative agent, sole book runner and lead arranger, provides for a revolving credit facility in the maximum amount of $2.0 billion, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves

35




and other factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, we may request up to three additional redeterminations of the borrowing base during any 12-month period. As of March 31, 2016, the borrowing base was $750.0 million, although we had elected a commitment amount of $500.0 million. As of March 31, 2016, we had no outstanding borrowings and $500.0 million available for future borrowings under this facility. As of March 31, 2016, the loan was guaranteed by us, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any of our future restricted subsidiaries. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors. In connection with our spring 2016 redetermination, the agent lender under our credit agreement has recommended that our borrowing base be reduced to $700.0 million due to a decline in pricing. This reduction is subject to the approval of the required other lenders. Regardless of such adjustment, we have elected to continue to limit the lenders’ aggregate commitment to $500.0 million.
    
The outstanding borrowings under the credit agreement bear interest at a rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2018.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.

Financial Covenant
Required Ratio
Ratio of total debt to EBITDAX
Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750.0 million in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of March 31, 2016, we had $450.0 million of senior notes outstanding.

As of March 31, 2016, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Viper’s Facility-Wells Fargo Bank

On July 8, 2014, Viper entered into a secured revolving credit agreement with Wells Fargo Bank, as the administrative agent, sole book runner and lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on Viper’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. The credit agreement was further amended on May 22, 2015 to, among other things, increase the borrowing base from $110.0 million to $175.0 million and to provide for certain restrictions on purchasing margin stock. On November 13, 2015, the borrowing base was increased from $175.0 million to $200.0 million. As of March 31, 2016, the borrowing base was set at $200.0 million. The Partnership had $43.0 million

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outstanding under its credit agreement with a weighted average interest rate of 1.94%. In connection with the Partnership’s spring 2016 redetermination, the agent lender under the credit agreement has recommended that the Partnership’s borrowing base be reduced to $175.0 million due to a decline in pricing. This reduction is subject to the approval of the required other lenders.

The outstanding borrowings under Viper’s credit agreement bear interest at a rate elected by Viper that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. Viper is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of Viper and its subsidiaries.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial Covenant
Required Ratio
Ratio of total debt to EBITDAX
Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under Viper’s revolving credit facility upon the occurrence and during the continuance of any event of default. Viper’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2016 capital budget for drilling and infrastructure of $250.0 million to $375.0 million, representing a decrease of 26% over our 2015 capital budget. We estimate that, of these expenditures, approximately:

$210.0 million to $315.0 million will be spent on drilling and completing 30 to 70 gross (25 to 58 net) operated horizontal wells focused in Midland, Andrews, Upton, Martin and Dawson Counties;

$25.0 million to $35.0 million will be spent on infrastructure; and

$15.0 million to $25.0 million will be spent on non-operated activity and other expenditures.

During the three months ended March 31, 2016, our aggregate capital expenditures for drilling and infrastructure were $86.3 million. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. During the three months ended March 31, 2016, we spent approximately $16.9 million on acquisitions of leasehold interests.     

The amount and timing of these capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. With recent

37




improvement in oil prices, we have retained our third horizontal rig and are prepared to add a fourth horizontal rig early in the third quarter of 2016 in the event oil prices continue to strengthen. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas price and production expectations for 2016, we believe that our cash flow from operations and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2016. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2016 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

We monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is further decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Security Ratings
 
Moody's Investors Services
 
Standard & Poor's Ratings Services
Diamondback Senior Notes
B1
 
B+

Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. The impact of any future downgrade could include an increase in the costs of the Company's short- and long-term borrowings.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Contractual Obligations

Except as discussed in Note 14 of the Notes to the Consolidated Financial Statements of this report, there were no material changes to our contractual obligations and other commitments, as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2016. Please read Note 14 included in Notes to the Combined Consolidated Financial Statements set forth in Part I, Item 1 of this report, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.


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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing.

At March 31, 2016, we had a net asset derivative position of $0.9 million, related to our price swap derivatives, as compared to a net asset derivative position of $4.6 million as of December 31, 2015 related to our price swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps as of March 31, 2016, a 10% increase in forward curves associated with the underlying commodity would have decreased the net liability position to $4.6 million, a decrease of $5.6 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position to $6.5 million, an increase of $5.6 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Subsequent to March 31, 2016, we entered into additional commodity contracts, which consisted of fixed price oil swaps covering 184,000 Bbls of our production for the production period from July 1, 2016 to December 31, 2016 and 365,000 Bbls of our production for the production period from January 1, 2017 to December 31, 2017. These fixed price oil swaps will settle against the weighted average price per barrel of NYMEX West Texas Intermediate during the calculation periods.
Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $15.2 million at March 31, 2016) and receivables from the sale of our oil and natural gas production (approximately $33.9 million at March 31, 2016).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the three months ended March 31, 2016, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company (57%); and Enterprise Crude Oil LLC (14%). For the year ended three months ended March 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (68%); and Enterprise Crude Oil LLC (11%). No other customer accounted for more than 10% of our revenue during these periods.
 
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At March 31, 2016, we had two customers that represented approximately 72% of our total joint operations receivables. At December 31, 2015, we had five customer that represented approximately 73% of our total joint operations receivables.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges

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from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of March 31, 2016, we had no borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 1.92% on January 19, 2016, the last day on which borrowings were outstanding under such facility. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $0.1 million based on the $11.0 million outstanding in the aggregate under our revolving credit facility as of such date.

ITEM 4.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of March 31, 2016, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of March 31, 2016, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II
ITEM 1. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
 
ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

In addition to the information set forth in this report, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2015.


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ITEM 6.    EXHIBITS
EXHIBIT INDEX
Exhibit Number
Description
3.1
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
3.2
Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.1
Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
4.2
Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC (incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.3
Investor Rights Agreement, dated as of October 11, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 4.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS*
XBRL Instance Document.
101.SCH*
XBRL Taxonomy Extension Schema Document.
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document.
______________
*
Filed herewith.
**
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
 
DIAMONDBACK ENERGY, INC.
 
 
Date:
May 5, 2016
/s/ Travis D. Stice
 
 
Travis D. Stice
 
 
Chief Executive Officer
 
 
(Principal Executive Officer)
 
 
Date:
May 5, 2016
/s/ Teresa L. Dick
 
 
Teresa L. Dick
 
 
Chief Financial Officer
 
 
(Principal Financial and Accounting Officer)



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