Management's
Discussion & Analysis of Financial Condition and Operating
Results
The
following discussion and analysis of EnerNorth Industries Inc. ("EnerNorth" or
the "Company") should be read in conjunction with the Company’s Unaudited
Consolidated Financial Statements for the third quarter ending March 31, 2005
and notes thereto and the Company’s Audited Consolidated Financial Statements
for the fiscal years ended June 30, 2004, 2003 and 2002 and notes thereto.
This Management Discussion and Analysis is dated May 13, 2005. Unless otherwise
indicated, the following discussion is based on Canadian dollars and presented
in accordance with Canadian Generally Accepted Accounting Principles ("GAAP").
Certain
statements contained herein constitute “forward-looking statements” within the
meaning of the Private Securities Litigation Reform Act of 1995 (the “Reform
Act”), which reflect the Company’s current expectations regarding the future
results of operations, performance and achievements of the Company. The Company
has tried, wherever possible, to identify these forward-looking statements by,
among other things, using words such as “anticipate,” “believe,” “estimate,”
“expect” and similar expressions. These statements reflect the current beliefs
of management of the Company, and are based on current available information.
Accordingly, these statements are subject to known and unknown risks,
uncertainties and other factors which could cause the actual results,
performance or achievements of the Company to differ materially from those
expressed in, or implied by, these statements. (See the Company’s Annual
Information Form and Annual Form 20 F for Risk Factors. The Company's public
filings can be accessed and viewed through the Company's website,
www.enernorth.com under the heading "Investor Relations", and by clicking on
"Corporate Filings". A link to the Company's Canadian Securities Commissions
filings can be viewed via the System for Electronic Data Analysis and Retrieval
(SEDAR) at www.sedar.com, and the Company's United States Securities and
Exchange Commission filings can be viewed through the Electronic Data Gathering
Analysis and Retrieval System (EDGAR) at www.sec.gov. The Company is not
obligated to update or revise these “forward-looking” statements to reflect new
events or circumstances.
OVERVIEW
The
Company is a corporation amalgamated under the laws of the Province of Ontario
and is provincially registered in the Provinces of Alberta, British Columbia and
Newfoundland. The Company’s primary activities are investment in, exploration
and development and production of oil and gas.
Effective
February 1, 2005 the Company divested of its interest in M&M Engineering
Limited (“M&M”) for cash proceeds of $7,361,999. The transaction is a sale
of 100% of the common shares and 100% of the preferred shares of M&M held by
the Company. Prior to closing, the Company retracted preferred shares of M&M
for Cdn $1,000,000 cash. The Company received shareholder approval for the
transaction at a special meeting of shareholders held on January 26, 2005. For
the purpose of financial presentation, the operations of M&M and its
subsidiaries have been accounted for as discontinued operations.
The
unaudited consolidated financial results for the nine and three month periods
ending March 31, 2005 and 2004 include the accounts of the Company and its
wholly owned subsidiaries 10915 Newfoundland Limited and 11123 Newfoundland
Limited. The Company’s accounts also include an investment in Konaseema EPS
Oakwell Power Limited (“KEOPL”) a company incorporated in India that is
developing a power project in Andhra Pradesh, India, and investments in
marketable securities. The Company also holds a 97% interest in Euro India Power
Canara Private Limited (“EIPCL”) that is carried at Nil on the balance sheet and
consolidated statement of operations of the Company. Management has evaluated
the effect that EIPCL accounts would have on the audited consolidated financial
statements of the Company at June 30, 2004 and the unaudited consolidated
financial statements for the third quarter ending March 31, 2005 and concluded
that such amounts would be insignificant under GAAP.
The
Company’s oil and gas operations are located in Alberta and Ontario, Canada. The
Company’s financial results are influenced by its business environment. Risks
include, but are not limited to: crude oil and natural gas prices, cost to find,
develop, produce and delivered crude oil and natural gas; demand for and ability
to deliver natural gas; government regulations and cost of capital.
GLOSSARY
OF ABBREVIATIONS
Bbl barrel
Bbl/d barrels
per day
Boe barrels
of oil equivalent (6 thousand cubic feet of gas is equivalent to one barrel of
oil)
Boe/d barrels
of oil equivalent per day
Mcf 1,000
cubic feet of natural gas
Mcf/d 1,000
cubic feet of natural gas per day
NGL’s Natural
Gas Liquids
NGL’s/d Natural
Gas Liquids per day
|
TO
CONVERT |
|
|
|
From |
To |
Multiply
By |
|
Mcf |
cubic
meters |
28.317 |
|
Meters |
cubic
feet |
35.494 |
|
Bbls |
cubic
meters |
0.159 |
|
Cubic
meters
Hectares |
Bbls
Acres |
6.289
2.471 |
(1)
A BOE
conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. Disclosure provided herein in respect of BOEs may
be misleading, particularly if used in isolation.
RISKS
AND UNCERTAINTIES
The
Company’s producing wells are subject to normal levels of decline and
unavoidable changes in operating conditions in facilities operated by third
parties. The Company’s production revenue is subject to commodity price
fluctuations over which the Company has no control. Some of the business risks
could include:
·
volatility
in market prices for oil and natural gas;
·
reliance
on third party operators;
·
ability
to find or produce commercial quantities of oil and natural gas;
·
liabilities
inherent in oil and natural gas operations;
·
dilution
of interests in oil and natural gas properties;
·
uncertainties
associated with estimating oil and natural gas reserves;
| |
· new prospects and
exploration activities may have inherent risks; |
· competition
for, among other things, financings, acquisitions of reserves, undeveloped lands
and skilled personnel; and
·
governmental
regulation and environmental legislation.
OVERALL
PERFORMANCE
The
Company’s overall performance for the nine months ended March 31, 2005 can be
highlighted by an increase of 77% in total average production volume to 69 boe/d
compared to 39 boe/d for the nine month period in 2004. As a result, net
revenues increased by 63% to $596,209 for the nine month period ending March 31,
2005 versus $365,017 for the nine month period ending March 31, 2004.
RESULTS
OF OPERATIONS
Net loss
from continuing operations decreased 61% to $1,456,530 for the nine month period
ending March 31, 2005 versus a net loss from continuing operations of $3,777,988
for the nine month period ending March 31, 2004. Net loss from continuing
operations for the nine month period ended March 31, 2005 were effected by
increased legal and support costs related to litigation. This was partially
offset by a reduction in the amounts owing on the Oakwell Claim due to changes
in foreign exchange. Net loss from continuing operations for the nine month
period ended March 31, 2004 was primarily affected a $2,150,000 provision
related to the Oakwell Claim. (See Critical
Accounting Estimates - Oakwell Claim,
below).
OPERATING
RESULTS
Production
Volumes. For the
nine months ending March 31, 2005 average production volumes increased 77% to 69
boe/d compared to 39 boe/d for the same nine month period in 2004. For the three
months ending March 31, 2005 production volumes increased 113% to 66 boe/d
compared to 31 boe/d for the same three month period in 2004.
For the
nine month period ending March 31, 2005 average gas production increased 77% to
292 mcf/d compared to 165 mcf/d for the same nine month period in 2004.
Increased gas production was due to additions from the Company’s Sibbald and
Olds-Davey properties, Alberta. For the three month period ending March 31, 2005
average gas production increased 85% to 233 mcf/d compared to 126 mcf/d for the
same three month period in 2004.
For the
nine month period ending March 31, 2005 average natural gas liquids production
increased 43% to 10 bbls/d compared to 7 bbls/d for the same nine month period
in 2004. For the three month period ending March 31, 2005 average natural gas
liquids production increased 75% to 14 bbls/d compared to 8 bbls/d for the same
three month period in 2004.
For the
nine month period ending March 31, 2005 average oil production increased 120% to
11 bbls/d compared to 5 bbls/d for the same nine month period in 2004. For the
three month period ending March 31, 2005 average oil production increased 600%
to 14 bbls/d compared to 2 bbls/d for the same three month period in 2004.
Increased oil production was due to additions from the Company’s Farrow and
Sibbald properties, Alberta.
The
following table provides a comparative summary of production sales volumes for
2005 and 2004:
|
|
For
the Nine Month Period Ending |
For
the Three Month Period Ending |
|
Average
Daily Production |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
|
Natural
gas (mcf per day) |
292 |
165 |
77% |
233 |
126 |
85% |
|
Natural
gas liquids (bbls per day) |
10 |
7 |
43% |
14 |
8 |
75% |
|
Crude
oil (bbls per day) |
11 |
5 |
120% |
14 |
2 |
600% |
|
Total
(boe per day) |
69 |
39 |
77% |
66 |
31 |
113% |
Commodity
Prices. During
the nine month period ending March 31, 2005, commodity prices decreased by 1% to
an average of $40.12 per boe compared to $40.49 per boe for the nine month
period in 2004. For the three months ended March 31, 2005 average commodity
prices per boe increased by 6% to $45.68 compared to $43.29 for the three month
period ended March 31, 2004.
Average
gas prices per mcf decreased by 8% to $6.50 during the nine month period ending
March 31, 2005 compared to $7.07 per mcf for the nine month period ending March
31, 2004. For the three months ended March 31, 2005 average gas prices per mcf
decreased by 1% to $7.97 compared to $8.02 for the three month period ended
March 31, 2004.
Average
natural gas liquids prices per barrel increased by 5% to $33.77 during the nine
month period ending March 31, 2005 compared to $32.04 per barrel for the nine
month period ending March 31, 2004. For the three months ended March 31, 2005
average natural gas liquids prices per barrel increased by 6% to $32.67 compared
to $30.78 for the three month period ended March 31, 2004.
Average
oil prices per barrel increased by 23% to $50.98 during the nine month period
ending March 31, 2005 compared to $41.61 per barrel for the nine month period
ending March 31, 2004. For the three months ended March 31, 2005 average oil
prices per barrel increased by 30% to $52.71 compared to $40.68 for the three
month period ended March 31, 2004.
The
following tables provides a comparative summary of sale prices received for 2005
and 2004:
|
|
For
the Nine Month Period Ending |
For
the Three Month Period Ending |
|
Average
Commodity Prices |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
|
Natural
gas ($/mcf) |
$
6.50 |
$
7.07 |
-8% |
$
7.97 |
$
8.02 |
-1% |
|
Natural
gas liquids ($/bbl) |
$
33.77 |
$
32.04 |
5% |
$
32.67 |
$
30.78 |
6% |
|
Crude
oil ($/bbl) |
$
50.98 |
$
41.61 |
23% |
$
52.71 |
$
40.68 |
30% |
|
Total
($/boe) |
$
40.12 |
$
40.49 |
-1% |
$
45.68 |
$
43.29 |
6% |
Gross
Revenue. The
Company's gross revenue of $753,987 for the nine month period ending March 31,
2005 increased by 74% from $433,108 for the comparative nine month period ending
March 31, 2004. Gross revenue of $271,878 for the three month period ending
March 31, 2005 increased by 128% compared to $119,422 for the comparable period
in 2004. Revenue growth was driven by production increases as commodity prices
remained relatively constant. Production increases stemmed primarily from
re-completed wells in Sibbald, Alberta, commencement of production from
previously drilled gas wells in the Olds area of Alberta and the re-completion
of an oil well in Farrow, Alberta.
Royalties.
Royalties increased by 132% to $157,778 for the nine month period ending March
31, 2005 compared to $68,091 for the nine month period ended March 31, 2004. For
the three month period ending March 31, 2005 royalties increased by 435% to
$65,834 compared to $12,311 for the comparable period in 2004. Increased
royalties were a result of increased production volumes.
Net
Revenue. The
Company’s net revenues for the nine month period ending March 31, 2005 increased
by 63% to $596,209 compared to $365,017 for the comparative nine month period
ending March 31, 2004. Net revenues of $206,044 for the three month period
ending March 31, 2005 increased by 92% compared to $107,111 for the comparable
period in 2004.
The
following table provides a comparative summary of sales revenues for 2005 and
2004:
|
|
For
the Nine Month Period Ending |
For
the Three Month Period Ending |
|
Revenues |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
|
Natural
gas |
$
517,347 |
$
318,916 |
62% |
$167,376
|
$
90,691 |
85% |
|
Natural
gas liquids |
$
88,552 |
$
60,291 |
47% |
$
40,450 |
$
21,105 |
92% |
|
Crude
oil |
$148,088
|
$
53,901 |
175% |
$
64,052 |
$
7,626 |
740% |
|
Total
revenue |
$
753,987 |
$433,108
|
74% |
$271,878
|
$119,422
|
128% |
|
less:
royalties |
$157,778
|
$
68,091 |
132% |
65,834
|
$
12,311 |
435% |
|
Net
revenue |
$596,209
|
$365,017
|
63% |
$206,044
|
$107,111
|
92% |
Operating
and transportation.
Operating and transportation costs were $354,811 for the nine month period
ending March 31, 2005, 56% higher than operating and transportation costs of
$228,032 during the comparable nine month period in 2004. For the three month
period ended March 31, 2005 operating and transportation costs were $88,317, 23%
higher compared to $71,817 during the comparable three month period in 2004.
Higher production expenses were a result of increased production volumes and
increased operations primarily on the Company’s Sibbald, Olds and Farrow,
Alberta properties.
The
following table provides a comparative financial summary per boe for 2005 and
2004:
|
|
For
the Nine Month Period Ending |
For
the Three Month Period Ending |
|
Summary
Per boe |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
March
31, 2005 |
March
31, 2004 |
Percent
Change |
|
Sales
($/boe) |
$
40.12 |
$
40.49 |
-1% |
$
45.68 |
$
43.29 |
6% |
|
Royalties
($/boe) |
$
8.39 |
$
6.37 |
32% |
$
11.06 |
$
4.46 |
148% |
|
Operation
cost ($/boe) |
$
18.88 |
$
21.32 |
-11% |
$
14.84 |
$
26.03 |
-43% |
|
Netbacks
($/boe) |
$
12.85 |
$
12.80 |
0% |
$
19.78 |
$
12.80 |
55% |
Depletion
and Accretion. For the
nine month period ending March 31, 2005 depletion and accretion expense was
$546,448, 71% higher compared to $319,746 for the nine month period in 2004. For
the three month period ending March 31, 2005 depletion and accretion expense was
$184,835, 121% higher compared to $83,534 for the comparative three month period
in 2004. The increased depletion and accretion was a result of higher production
volumes.
Administrative
Expenses.
Administrative expenses of $1,873,946 for the nine month period ending March 31,
2005 were 37% higher than administrative expenses of $1,372,839 the previous
year. Administrative expenses for the three month period ending March 31, 2005
were $749,972, 1% lower than $755,275 for the comparable period in 2004. The
primary increase in administrative expenses for the nine month period ending
March 31, 2005 was related to increased litigation expenses of $1,000,148.
Litigation expenses were $194,663 during the three month period ending March 31,
2005.
Foreign
Exchange. For the
nine months period ending March 31, 2005 the gain on foreign exchange was
$492,781 compared to a foreign exchange loss of $159,070 for the nine month
period in 2004. For the three month period ending March 31, 2005 the loss on
foreign exchange was $11,050 compared to a foreign exchange loss of $6,246
during the comparable period in 2004. The foreign exchange gain during fiscal
2005 related to appreciation in the Canadian dollar relating to the Oakwell
Claim. This gain was partially offset by a foreign exchange loss of relating to
Company’s investment in KEOPL. (See
Critical
Accounting Estimates - Oakwell Claim and Valuation of the Company's Investment
in KEOPL,
below).
Interest
income. For the
nine months ending March 31, 2005 interest income was $221,452, 191% higher
compared to $76,156 for the
comparable nine month period in 2004. For
the three month period ending March 31, 2005 interest income was $56,603
compared to $17,089, 231% higher compared to the three month period in 2004. The
increase in interest income was related to interest payments received on the
Company’s KEOPL investment.
Current
and Future Income Taxes. During
the nine month period ended March 31, 2005 a net future income tax charge of Nil
was recognized compared to a net future income tax charge of $160,018 for the
nine month period ended March 31, 2004. During the three month period ended
March 31, 2005 a net future income tax charge of Nil was recognized compared to
a net future income tax charge of $461,101 for the three month period ended
March 31, 2004. During the current year a future tax recovery was absorbed by an
increase in the valuation allowance. During the previous year the future income
tax charge was fully offset by utilization of tax loss carryforwards. During
fiscal 2005, the statutory tax rate for the Company was 36% versus 38% for
fiscal 2004.
Net
loss from continuing operations. Net loss
from continuing operations decreased 61% to $1,456,530 for the nine month period
ended March 31, 2005 compared to a net loss of $3,777,988 for the nine month
period ending March 31, 2004. Net loss from continuing operations decreased 42%
to $771,886 for the three month period ended March 31, 2005 compared to a net
loss of $1,340,132 for the three month period ending March 31, 2004. Net loss
from continuing operations were significantly higher in the previous year due to
a $2,150,000 provision for the Oakwell Claim (See Critical
Accounting Estimates - Oakwell Claim,
below).
Net
income (loss) from discontinued operations. Net
income from discontinued operations resulted from the Company’s disposition of
its Industrial & Offshore Division which was sold February 2005. Net income
from discontinued operations decreased 60% to $337,355 for the nine month period
ended March 31, 2005 compared to $835,677 for the nine month period ended March
31, 2004. On disposition of the operations of the Industrial & Offshore
Division the Company recorded a gain of $1,847,642.
Net
income from discontinued operations was $112,367 for the three month period
ended March 31, 2005 compared to a net loss from discontinued operations of
$420,291 for the three month period ended March 31, 2004. The reduction in net
income from discontinued operations was due to a significant contract performed
during 2003 and 2004 by NECL which did not recur during fiscal
2005.
Net
income (loss). As a
result of the above net income was $728,467 for the nine month period ending
March 31, 2005 compared to a loss of $2,942,311 for the comparable nine month
period ending March 31, 2004. For the three month period ending March 31, 2005
net income was $1,188,123 compared to a net loss of $1,760,423 for the three
month period ending March 31, 2004.
Net
loss from continuing operations per share and fully diluted net loss from
continuing operations per share. Net loss
from continuing operations per share and fully diluted net loss per share from
continuing operations for the nine month period ending March 31, 2005 decreased
by 61% to $0.36 per share from $0.93 per share for the same nine month period
2004. Net loss from continuing operations per share and fully diluted net loss
per share from continuing operations for the three month period ending March 31,
2005 decreased by 42% to $0.19 per share from $0.33 per share for the same three
month period 2004.
Net
income (loss) per share and fully diluted net income (loss) per
share. Net
income per share for the nine month period ending March 31, 2005 was $0.18 per
share compared to a net loss of $0.72 per share for the same nine month period
2004. Net income per share for the three month period ending March 31, 2005 was
$0.29 compared to a net loss of $0.43 per share for the same three month period
2004.
Fully
diluted net income per share for the nine month period ending March 31, 2005 was
$0.16 per share. Fully diluted net income per share for the three month period
ending March 31, 2005 was $0.26 per share. During fiscal 2004 both figures were
antidilutive.
Capital
Expenditures. Capital
expenditures totaled
$589,270 for the nine months of fiscal 2005 compared to $1,253,926 for the nine
months of fiscal 2004. During the three month period ending March 31, 2005
capital expenditures were $112,565 compared to $463,705 for the comparable
period in 2004. During nine month period ending March 31, 2005 the Company’s
primary expenditures related to drilling and completion costs of approximately
$85,242 for the Doe Property, Alberta, $273,969 in re-completion and tie-ins at
Olds, Alberta, and $73,360 in re-completions in the Sibbald area of Alberta.
SUMMARY
OF QUARTERLY RESULTS
|
|
|
Unaudited |
|
|
|
Fiscal
2005 |
|
Fiscal
2004 |
|
Fiscal
2003 |
|
|
|
|
|
Mar.1/05 |
|
|
Dec.
31/04 |
|
|
Sept.
30/04 |
|
|
June
30/04 |
|
|
Mar.
31/04 |
|
|
Dec.
31/03 |
|
|
Sept.
30/03 |
|
|
June
30/03 |
|
|
Net
oil and gas revenue |
|
|
206,044 |
|
|
226,755 |
|
|
163,410 |
|
|
294,439 |
|
|
107,111 |
|
|
125,668 |
|
|
132,238 |
|
|
145,770 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations |
|
|
(771,886 |
) |
|
(470,909 |
) |
|
(213,735 |
) |
|
(67,618 |
) |
|
(1,340,132 |
) |
|
(2,252,480 |
) |
|
(270,423 |
) |
|
(6,970,162 |
) |
|
Net
income (loss) |
|
|
1,188,123
|
|
|
(548,854 |
) |
|
89,198
|
|
|
724,369
|
|
|
(1,760,423 |
) |
|
(1,356,962 |
) |
|
175,074
|
|
|
(7,069,541 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
per share |
|
$ |
(0.19 |
) |
$ |
(0.12 |
) |
$ |
(0.05 |
) |
$ |
(0.02 |
) |
$ |
(0.33 |
) |
$ |
(0.55 |
) |
$ |
(0.07 |
) |
$ |
(1.72 |
) |
|
Net
income (loss) per share |
|
$ |
0.29 |
|
$ |
(0.14 |
) |
$ |
0.02 |
|
$ |
0.16 |
|
$ |
(0.43 |
) |
$ |
(0.33 |
) |
$ |
0.04 |
|
$ |
(2.09 |
) |
|
Fully
diluted net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(loss)
per share |
|
$ |
0.26 |
|
$ |
(0.14 |
) |
$ |
0.02 |
|
$ |
0.16 |
|
$ |
(0.43 |
) |
$ |
(0.33 |
) |
$ |
0.04 |
|
$ |
(2.09 |
) |
Gross
revenues from the Company’s oil and gas operations have steadily increased over
the past eight quarters due to changes in production rates and commodity prices
(see “Trend
Information” below).
Earnings have tended to recede during the winter months of both fiscal 2004 and
2003 and during the first and second quarter of fiscal 2005 due to increased
litigation expenditures related to the Oakwell Claim and the accrual of the
Singapore Judgments. These expenditures and accruals were tied to the timing of
court hearings and decisions and do not represent a normal business trend.
LIQUIDITY
AND CAPITAL RESOURCES
Cash and
cash equivalents as of March 31, 2005 was $6,064,431, compared to $600,313 at
June 30, 2004. During the nine month period ending March 31, 2005 the Company’s
cash flows from operating activities were $1,556,075. Many of the changes in
balance sheet accounts are represented by the disposal of the Company’s
Industrial & Offshore Division. The Company’s Oil & Gas Division
expended $589,270 on development of oil and gas properties during the nine month
period ended March 31, 2005. The Company has the resources to meet its present
working capital requirements.
The
Company's primary sources of liquidity and capital resources historically have
been cash flows from the operations of the Industrial & Offshore Division
and the Oil & Gas Division, the issuance of share capital and advances from
shareholders. During fiscal 2000 and 2001 the Company recovered part of its
investment in KEOPL. During fiscal 2005, it is expected that primary sources of
liquidity and capital resources will be derived from the operations of the Oil
& Gas Division, proceeds from the sale of M&M and a further recovery in
connection with an arbitration award (See “Critical
Accounting Estimates - Valuation of the Company’s Investment in
KEOPL”
below).
Outlook
and Prospective Capital Requirements. Effective
February 1, 2005 the Company divested of its interest in M&M for cash
proceeds of $7,361,999. In addition, EnerNorth retracted preferred shares of
M&M for Cdn $1,000,000 cash. At present the Company intends to apply
significant cash to further develop the activities and operations of its Oil
& Gas Division. As part of the Company's oil and gas exploration and
development program management of the Company anticipates further expenditures
to expand its existing portfolio of proved and probable oil and gas reserves.
Amounts expended on future oil and gas exploration and development is dependent
on the nature of future opportunities evaluated by the Company. These
expenditures could be funded through cash held by the Company or through cash
flow from operations. Any expenditure which exceeds available cash will be
required to be funded by additional share capital or debt issued by the Company,
or by other means. With respect to other potential expenditures of the Company
see “Critical
Accounting Estimates -
Oakwell Claim” below.
The
Company's long-term profitability will depend upon its ability to successfully
implement its business plan. Also, if the Company is not successful in defending
the enforceability of the Oakwell Claim in Canada then there will be a material
and adverse impact on the Company’s financial position and operations may be
curtailed.
TREND
INFORMATION
Seasonality. The
Company's Oil & Gas Division is not a seasonal business, but increased
consumer demand or changes in supply in certain months of the year can influence
the price of produced hydrocarbons, depending on the circumstances. Production
from the Company's oil and gas properties is the primary determinant for the
volume of sales during the year.
TABABULAR
DISCLOSURE OF CONTRACTUAL OBLIGATIONS
Below is
a listing of contractual commitments for future payments for the company by
fiscal year to 2010:
|
Schedule
of Contractual Obligations |
|
June
30, 2004 |
| |
|
|
|
|
|
|
|
| |
2005 |
2006 |
2007 |
2008 |
2009 |
2010
onward |
TOTAL |
| |
|
|
|
|
|
|
|
|
Operating
leases |
$21,800
|
$0
|
$0
|
$0
|
$0
|
$0
|
$21,800
|
|
Other |
$0
|
$0
|
$0
|
$0
|
$0
|
$0
|
$0
|
| |
|
|
|
|
|
|
|
| |
$21,800
|
$0
|
$0
|
$0
|
$0
|
$0
|
$21,800
|
Critical
Accounting Policies and Estimates and Newly Adopted Accounting
Policies
The
Company's significant accounting policies, estimates and changes to accounting
policies are also described in the Notes to the audited Consolidated Financial
Statements for the fiscal years ended June 30, 2004, 2003, 2002. It is
increasingly important to understand that the application of generally accepted
accounting principles involves certain assumptions, judgments and estimates that
affect reported amounts of assets, liabilities, revenues and expenses. The
application of principles can cause varying results from company to
company.
The most
significant accounting policies that impact the Company and its subsidiaries
relate to oil and gas accounting and reserve estimates, future income tax assets
and liabilities, and stock based compensation.
The most
significant accounting estimates that impact the Company and its subsidiaries
relate to the Oakwell Claim and the valuation of the Company's investment in
KEOPL.
During
fiscal 2005 the Company adopted the
recommendations of the new CICA Handbook Section 3870, stock-based compensation
and other stock-based payments. The only
new accounting policy that was adopted by the Company during the 2004 fiscal
year was a new accounting policy guideline for oil and gas accounting according
to the new Canadian Institute of Chartered Accountants (“CICA”) Handbook
guideline ACG-16.
Critical
Accounting Policies
Oil
and gas accounting and reserve estimates. The
Company follows the full cost method of accounting for oil and gas operations
under which all costs of exploring for and developing oil and gas reserves are
initially capitalized. Such costs include land acquisition costs, geological and
geophysical expenses, carrying charges on non-producing properties, costs of
drilling and overhead charges directly related to acquisition and exploration
activities.
Under the
full cost method all of the costs noted above are capitalized, together with the
costs of production equipment, and are depleted on the unit-of-production method
based on the estimated gross proved reserves. Petroleum products and reserves
are converted to equivalent units of natural gas at 6,000 cubic feet to 1 barrel
of oil.
Under the
full cost method costs of acquiring and evaluating unproved properties are
initially excluded from depletion calculations. These unevaluated properties are
assessed periodically to ascertain whether impairment in value has occurred.
When reserves are identified as “proven” by independent engineers, or the
property is considered to be impaired, then the cost of the property or the
amount of the impairment is added to costs subject to depletion
calculations.
Proceeds
from a sale of petroleum and natural gas properties are applied against
capitalized costs, with no gain or loss recognized, unless such a sale would
significantly alter the rate of depletion. Alberta Royalty Tax Credits are
included in oil and gas sales.
In
applying the full cost method, under Canadian GAAP, the Company performs a
ceiling test which restricts the capitalized costs less accumulated depletion
and amortization from exceeding an amount equal to the estimated fair market
value undiscounted value of future net revenues from proved and probable oil and
gas reserves, as determined by independent engineers, based on sales prices
achievable under forecast prices existing contracts and posted average reference
prices in effect at the end of the year and forecast current costs, and after
deducting estimated future general and administrative expenses, production
related expenses, financing costs, future site restoration costs and income
taxes. For calculating the fair value the company utilizes a 10% discount
factor.
In
comparison, in applying the full cost method under US GAAP, the Company performs
a ceiling test based on the same calculations used for Canadian GAAP except the
Company is required to discount future net revenues at 10% as opposed to
utilizing the fair market value. Also, probable reserves are
excluded.
Future
Income Tax Assets and Liabilities. The
Company uses the asset and liability method of accounting for income taxes.
Under this method, future income tax assets and liabilities are determined based
on differences between the financial statement carrying amounts and their
respective income tax bases (temporary differences). Management regularly
reviews its tax assets for recoverability and establishes a valuation allowance
based on (i) historical taxable income; (ii) projected future taxable income;
and (iii) the accounting treatment reflected in Note 11 of the Company’s Audited
Consolidated Financial Statements. As of June 30, 2004 the Company had $9.0
million of non-capital losses, Cumulative Canadian oil and gas property expenses
of $6.8 million and capital losses of $10.2 million.
Stock
based compensation. The
Company has established a stock option plan (the "Plan") for directors,
officers, employees, consultants and service providers During
2005, the Company adopted the recommendations of the new CICA Handbook Section
3870, stock-based compensation and other stock-based payments. The primary
difference between this new accounting policy and the former policy is that the
company calculates the fair value of stock options issued to directors and
employees. The Company has chosen to adopt the recommendation
prospectively.
As a
result of adopting the new accounting policy the Company records compensation
expense on all stock options granted. The fair value is recorded at their fair
value at date of issuance and the amount is estimated using the Black-Scholes
Option Pricing Model. During
fiscal 2005 the Company recorded $149,446 of compensation expense related to the
issuance of stock options.
Critical
Accounting Estimates
Oakwell
Claim. On
October 16, 2003 the High Court of the Republic of Singapore ordered the Company
to pay Oakwell US $5,657,000 (approximately CDN $7,149,899) plus costs (the
“Judgment”) (Singapore Suit No. 997 of 2002/V). The Company appealed the
Judgment to the Court of Appeal of the Republic of Singapore (Singapore Civil
Appeal No. 129 of 2003/Y). That Court dismissed the appeal on April 27, 2004 and
is the final Court of Appeal for Singapore.
On June
21, 2004, Oakwell filed an Application with the Superior Court of Justice for
the Province of Ontario seeking to enforce the Judgment in Ontario (Ontario
Court File No.04-CV-271121 CM3). The hearing of that Application commenced
December 6, 2004 and a decision has yet to be determined.
The
Company is of the view that the Judgment was improperly granted against it and
is vigorously defending the application to prevent the enforcement of the
Judgment in Ontario. The Company has provided a substantive response to the
application and has brought its own application against Oakwell for a
declaration that the Judgment is unenforceable in the Province of Ontario.
If the
Judgment is enforced in Ontario, the Company’s financial condition would be
materially and adversely affected.
A
provision of CDN $7,328,460 has been made to the unaudited consolidated
financial statements for the nine month period ending March 31, 2005 in relation
to the Judgment.
HB
Capital contingent liability.
A
statement of claim has been filed in the Supreme Court of Newfoundland and
Labrador, Trial Division, Suit # 1998 St. J. No. 3233 against the Company
by a
former financial adviser alleging breach of contract. The plaintiff has claimed
for special damages in the amount of approximately $230,000 (US $184,197) and a
success fee equal to 1% of the gross debt/equity financing of the Andhra Pradesh
project less up to 20% of any corporate contributions to the project by the
Company or its affiliates. Management believes that the claim is without merit
and has filed a counter claim. No correspondence or activity has occurred since
2000 and management believes that the plaintiff has abandoned the litigation. No
provision has been made in the Company’s audited Consolidated Financial
Statements for this claim.
The
Company estimates the range of liability related to pending litigation where the
amount and range of loss can be estimated. Where there is a range of loss, the
Company records the minimum estimated liability related to those claims. As
additional information becomes available, we assess the potential liability
related to our pending litigation and revise our estimates accordingly.
Revisions of our estimates of the potential liability could materially impact
our results of future operations. If the final outcome of such litigation and
contingencies differ adversely from those currently expected, it would result in
a charge to earnings when determined.
Valuation
of the Company's Investment in KEOPL. As of
March 31, 2005, the Company owns 11,848,200 common shares (2004 - 11,848,200) of
Rs. 10 each, of KEOPL (the "KEOPL Shares"), a company incorporated in India,
which is developing a power project in Andhra Pradesh, India.
Pursuant
to an Arbitration Agreement and Award between the Company and VBC, an Indian
corporation, the parent company of KEOPL and an Arbitration Award passed and
dated October 11, 2003 by Hon’ble Arbitral Tribunal, India (the “Award”) (i) VBC
transferred an additional 500,000 equity shares in KEOPL to the Company (valued
at approximately CDN $138,000 as at March 31, 2005), and (ii) VBC is required to
buy the 11,348,200 KEOPL Shares for INR 113,482,000 (approximately CDN $3.1
million as at March 31, 2005) on or before the earlier of (a) 60 days after the
first disbursal of funds on financial closure of the KEOPL Project, and (b)
March 31, 2004. VBC is liable to pay the Company interest at 12% per annum on
the value of the unredeemed shares from the earlier of (a) and (b) above. The
Company may, upon written notice to VBC, require that VBC purchase, and VBC is
required to buy, the additional 500,000 equity shares of KEOPL at a par value of
INR 5 million on or before the same dates. VBC is liable to pay the Company
interest at 12% per annum on the value of the unredeemed shares from March 31,
2004 to the date of actual payment thereof.
On
February 28, 2004 the Company provided written notice to effect the purchase by
VBC of the 11,348,200 KEOPL Shares held by the Company. VBC raised a dispute
regarding the purchase of the KEOPL Shares and the Company commenced legal
proceedings against VBC in the Hon'ble Chief Judge City Civil Court, Hyderabad,
India (Execution Petition No. 46/2004) to enforce the Award and the purchase and
sale of 11,348,200 KEOPL Shares to VBC. On November 30, 2004 the Company
commenced legal proceedings against VBC in the High Court of Judicature of
Andhra Pradesh, India (Company Petition No. 199/2004) to pass an order for the
winding up of VBC under the provisions of the Companies Act, 1956 (India). The
Company estimates that the carrying amounts of the investment in KEOPL will be
fully recovered.
On
September 20, 2004 and November 17, 2004 the Company received interest payments
from VBC, net of India tax for the period March 31, 2004 to June 30, 2004 and
July 1, 2004 to September 30, 2004 in the amount of CDN $84,182 (US $62,800) and
CDN$76,366 (US $63,990) respectively. During the nine month period ending March
31, 2005 the company incurred a foreign exchange loss of $83,050 on the KEOPL
investment.
The
investment in KEOPL is recorded at expected net recoverable amount of CDN
$3,281,950 at March 31, 2005. Management of the Company assessed the amount
recoverable based on (i) the par value of the shares, (ii) an assessment of
VBC's ability to pay, (iii) financial closure of the KEOPL project, (iv) the
provisions of the Arbitration Award, (v) the pending legal proceedings, and (vi)
the likelihood and timing of payment. The actual recoverable amount is dependent
upon future events, foreign exchange fluctuations and subject to certain
sovereign risks such as political instability and economic conditions, and could
differ materially from the amount estimated by management.
Newly
Adopted Accounting Policies
Stock
Based Compensation: During
2005, the Company adopted the recommendations of the new CICA Handbook Section
3870, stock-based compensation and other stock-based payments. The primary
difference between this new accounting policy and the former policy is that the
company calculates the fair value of stock options issued to directors and
employees. The Company has chosen to adopt the recommendation
prospectively.
As a
result of adopting the new accounting policy the Company records compensation
expense on all stock options granted. The fair value is recorded at their fair
value at date of issuance and the amount is estimated using the Black-Scholes
Option Pricing Model.
Oil
and gas accounting: During
2004, the Company adopted the recommendations of the new CICA Handbook guideline
AcG-16. The primary difference related to this new accounting standard relates
to the application of the ceiling test. Under the new standard the capitalized
costs less accumulated depletion and amortization are restricted to the fair
value of proved and probable reserves as opposed to the undiscounted value of
proved reserves less general and administrative expenses, tax and financing
costs. As a result of applying the new standards, management determined that a
transitional impairment loss of $1,945,786 be recorded as at July 1, 2003.
In
comparison, in applying the full cost method under US GAAP, the Company performs
a ceiling test based on the same calculations used for Canadian GAAP except the
Company is required to discount future net revenues at 10% as opposed to
utilizing the fair market value. Also, probable reserves are
excluded.
Other
Information
The
Company's public filings can be accessed and viewed through the Company's
website, www.enernorth.com under the heading "Investor Relations", and by
clicking on "Corporate Filings". A link to the Company's Canadian Securities
Commissions filings, including the Company’s Annual Form 20F filed as its Annual
Information Form, can be viewed via the System for Electronic Data Analysis and
Retrieval (SEDAR) at www.sedar.com and the Company's United States Securities
and Exchange Commission filings can be viewed through the Electronic Data
Gathering Analysis and Retrieval System (EDGAR) at www.sec.gov).
Share
Capital
As of
March 31, 2005 and the date of this Management Discussion and Analysis:
| (a) |
Authorized
and Issued: |
Authorized:
Unlimited
number of Common Shares, without par value
Unlimited
number of Class A Preference Shares, Series I
Unlimited
number of Class A Preference Shares, Series II
Issued
Common
shares
# Consideration
Balance, as at
June 30, 2004 4,059,009 $43,339,132
Balance,
as at May 13, 2005 4,059,009 $43,488,578
| (b) |
Common
share purchase warrants outstanding consist of the
following: |
|
Exercise
|
Expiry |
2005 |
2004 |
|
Price
|
Date |
# |
# |
|
US$
1.80 |
December
31, 2004 |
- |
533,332 |
| |
|
- |
533,332 |
At the
date of this filing no common share purchase warrants were
outstanding.
| (c) |
Common
share purchase options outstanding consist of the
following: |
|
Exercise
|
Expiry |
2005 |
2004 |
|
Price
|
Date |
# |
# |
|
US$0.75 |
February
28, 2010 |
600,000 |
- |
| |
|
600,000
|
- |
At the
date of this filing 600,000 common share purchase options were
outstanding.