UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
6-K
Report
of Foreign Private Issuer Pursuant to Rule 13a-16 or 15d-16 under the
Securities
Exchange Act of 1934
For
the
month of February
2006
Commission
File Number 0-29586
EnerNorth
Industries Inc.
(Address
of Principal executive offices)
2
Adelaide Street West, Suite 301, Toronto, Ontario, M5H 1L6,
Canada
(Address
of principal executive offices)
Indicate
by check mark whether the registrant files or will file annual reports under
cover of Form 20-F or Form 40-F:
Form
20-F
X
Form
40-F
Indicate
by check mark if the registrant is submitting the Form 6-K in paper as permitted
by Regulation S-T Rule 101(b)(7):
Yes No
X
Indicate
by check mark whether the registrant by furnishing the information contained
in
this Form is also thereby furnishing the information to the Commission pursuant
to Rule 12g3-2(b) under the Securities Exchange Act of 1934:
Yes No
X
If
“Yes”
is marked, indicate below the file number assigned to the registrant in
connection with Rule 12g3- 2(b):
82-
_________
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant
has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
EnerNorth
Industries Inc.
Date:
February 14, 2006 By:____”Sandra
J. Hall”____ ______
Sandra
J.
Hall,
President,
Secretary & Director
Management's
Discussion and Analysis
of
Financial Condition and Operating Results
Second
Quarter
December
31, 2005
(unaudited)
1
King
Street West, Suite 1502, Toronto, Ontario M5H 1A1 Telephone: 416-861-1484
Facsimile: 416 861-9623 www.enernorth.com
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 and notes thereto for the six and three
month
period ended December 31, 2005 and the Company’s Audited Consolidated Financial
Statements for the fiscal years ended June 30, 2005 and notes thereto. This
Management Discussion and Analysis is dated February 10, 2006. Unless otherwise
indicated, the following discussion is based on Canadian dollars and presented
in accordance with Canadian Generally Accepted Accounting Principles
("GAAP").
Certain
measures in this Management’s Discussion and Analysis do not have any
standardized meaning as prescribed by Canadian generally accepted accounting
principles such as netback and other production figures and therefore are
considered non-GAAP measures. Therefore these measures may not be comparable
to
similar measures presented by other issuers. These measures have been described
and presented in this management discussion and analysis in order to provide
shareholders an potential investors with additional information regarding
the
Company’s liquidity an its ability to generate funds to finance its operations.
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 was 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 and M&M assigned to the Company 100% of 10915
Newfoundland Limited, and 100% of 11123 Newfoundland Limited. Effective June
29,
2005 the Company sold its 100% interest in 10915 Newfoundland Limited and
11123
Newfoundland Limited for cash proceeds of $175,000.
The
unaudited consolidated financial results for the six and three month periods
ending December 31, 2005 and 2004 include the accounts of the Company as
well as
an investment in Konaseema Gas Power Limited (formerly 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 through its wholly-owned subsidiary EPS Karnataka
Power
Corp. (“EPS Karnataka”) an Ontario corporation, holds 97% of Euro India Power
Canara Private Limited (“EIPCL”) an Indian corporation 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
unaudited consolidated financial statements of the Company at December 31,
2005
and December 31, 2004 and concluded that such amounts would be insignificant
under GAAP.
The
Company’s oil and gas operations are located in Alberta, British Columbia 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 deliver crude oil and natural
gas;
demand for and ability to deliver natural gas; government regulations and
cost
of capital.
The
unaudited consolidated financial statements have been prepared on the basis
of a
going concern, which contemplates that the Company will be able to realize
assets and discharge liabilities in the normal course of business.
The
Company’s ability to continue as a going concern is dependent upon the
enforceability of the Oakwell Claim (See Note 21 of the Company’s Audited
Consolidated Financial Statements for the period ending June 30, 2005). If
the
application of the Judgment becomes enforceable in Canada then there would
be a
material and adverse impact on the Company’s financial condition. The Company’s
unaudited consolidated financial statements do not include any adjustments
to
the amounts and classification of assets and liabilities that might be necessary
should the Company not be able to continue in the normal course of operations.
If the “going concern” assumption is not appropriate for these unaudited
consolidated financial statements then adjustments may be necessary to the
carrying value of assets and liabilities, the reported revenues and expenses,
and the balance sheet classifications used.
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)(1)
|
|
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 six months ended December 31, 2005 can be
highlighted by an increase of 46% in gross oil and gas revenue of $705,112
for
the six month period ending December 31, 2005 versus $482,109 for the
comparative six month period ending December 31, 2004. As a result net oil
and
gas revenue increased by 57% to $613,196 compared to $390,165 for the
comparative six month period ending December 31, 2004.
Net
loss
from continuing operations decreased 76% to $163,583 for the six month period
ended December 31, 2005 compared to a net loss of $684,644 for the six month
period ending December 31, 2004. During the six month period ended December
31,
2005, the Company incurred $233,634 in litigation expenses and accrued $197,961
related to the Oakwell Claim. During the same period in 2004, the Company
incurred $540,204 of litigation expenses and nil related to the Oakwell Claim.
(See “Critical
Accounting Estimates - Oakwell Claim”
below).
SUMMARY
OF INTERIM FINANCIAL INFORMATION
|
Six
Months Ending December 31
|
Three
Month Ending December 31
|
|||||
|
|
2005
|
2004
|
%
Change
|
2005
|
2004
|
%
Change
|
|
FINANCIAL
INFORMATION:
|
|
|
|
|
|
|
|
Oil
and gas revenue
|
705,112
|
482,109
|
46%
|
379,865
|
261,352
|
45%
|
|
Less:
royalties
|
91,916
|
91,944
|
0%
|
53,751
|
34,597
|
55%
|
|
Net
revenue
|
613,196
|
390,165
|
57%
|
326,114
|
226,755
|
44%
|
|
Net
loss from operations before discontinued operations
|
(163,583)
|
(684,644)
|
-76%
|
(158,974)
|
(470,909)
|
-66%
|
|
Income
and gain on disposition of discontinued operations
|
-
|
224,988
|
-100%
|
-
|
(77,945)
|
-100%
|
|
Net
loss
|
(163,583)
|
(459,656)
|
-64%
|
(158,974)
|
(548,854)
|
-71%
|
|
Net
loss from continuing operations per share
|
(0.04)
|
(0.17)
|
-76%
|
(0.04)
|
(0.12)
|
-66%
|
|
Net
loss per share
|
(0.04)
|
(0.11)
|
-64%
|
(0.04)
|
(0.14)
|
-71%
|
|
Total
assets
|
15,538,336
|
13,184,292
|
18%
|
15,538,336
|
13,184,292
|
18%
|
|
Total
financial liabilities
|
8,621,945
|
12,891,356
|
-33%
|
8,621,945
|
12,891,356
|
-33%
|
|
OPERATIONS:
|
|
|
|
|
|
|
|
Average
Daily Production
|
|
|
|
|
|
|
|
Natural
gas (mcf per day)
|
211
|
320
|
-34%
|
212
|
342
|
-38%
|
|
Natural
gas liquids (bbls per day)
|
15
|
8
|
88%
|
16
|
8
|
100%
|
|
Crude
oil (bbls per day)
|
11
|
9
|
22%
|
11
|
16
|
-31%
|
|
Total
(boe per day)
|
62
|
70
|
-11%
|
62
|
81
|
-23%
|
|
Average
Commodity Prices
|
|
|
|
|
|
|
|
Natural
gas ($/mcf)
|
$
11.23
|
$
5.97
|
88%
|
$
12.95
|
$
5.98
|
117%
|
|
Natural
gas liquids ($/bbl)
|
$
46.14
|
$
41.26
|
12%
|
$
45.52
|
$
32.14
|
42%
|
|
Crude
oil ($/bbl)
|
$
67.28
|
$
44.42
|
51%
|
$
67.28
|
$
42.19
|
59%
|
|
Total
($/boe)
|
$
62.03
|
$
37.54
|
65%
|
$
66.32
|
$
36.77
|
80%
|
|
Royalties
|
|
|
|
|
|
|
|
Natural
gas ($/mcf)
|
$
1.20
|
$
1.11
|
8%
|
$
1.42
|
$
1.48
|
-4%
|
|
Natural
gas liquids ($/bbl)
|
$
10.83
|
$
12.00
|
-10%
|
$
11.39
|
$
11.23
|
1%
|
|
Crude
oil ($/bbl)
|
$
7.01
|
$
5.44
|
29%
|
$
8.61
|
$
6.07
|
42%
|
|
Total
royalties ($/boe)
|
$
8.09
|
$
7.16
|
13%
|
$
9.38
|
$
8.58
|
9%
|
|
Production
costs
|
|
|
|
|
|
|
|
Natural
gas ($/mcf)
|
$
3.28
|
$
4.08
|
-20%
|
$
3.15
|
$
4.27
|
-26%
|
|
Natural
gas liquids ($/bbl)
|
$
6.61
|
$
7.92
|
-17%
|
$
7.34
|
$
5.71
|
29%
|
|
Crude
oil ($/bbl)
|
$
25.14
|
$
8.89
|
183%
|
$
26.49
|
$
34.03
|
-22%
|
|
Total
production costs ($/boe)
|
$
17.39
|
$
20.75
|
-16%
|
$
16.98
|
$
24.93
|
-32%
|
|
Netback
by Product
|
|
|
|
|
|
|
|
Natural
gas ($/mcf)
|
$
6.75
|
$
0.78
|
765%
|
$
8.38
|
$
0.23
|
3543%
|
|
Natural
gas liquids ($/bbl)
|
$
28.70
|
$
21.34
|
34%
|
$
26.79
|
$
15.20
|
76%
|
|
Crude
oil ($/bbl)
|
$
35.13
|
$
30.09
|
17%
|
$
32.18
|
$
2.09
|
1440%
|
|
Netback
($/boe)
|
$
36.55
|
$
9.63
|
280%
|
$
39.96
|
$
3.26
|
1126%
|
OPERATING
RESULTS
Second
Quarter 2005 versus Second Quarter 2004
Production
Volumes. For
the
six month period ending December 31, 2005 average production volumes decreased
11% to 62 boe/d compared to 70 boe/d for the same six month period in 2004.
For
the three months ending December 31, 2005 production volumes decreased 23%
to 62
boe/d compared to 81 boe/d for the same three month period in 2004. Decreases
were primarily related to two depleted gas wells on the Company’s Sibbald
property, Alberta. These decreases were partially offset by additional
production from the Company’s Farrow, Kaybob and Olds-Davey
properties.
For
the
six month period ending December 31, 2005 average gas production decreased
34%
to 211 mcf/d compared to 320 mcf/d for the same six month period in 2004.
For
the three month period ending December 31, 2005 average gas production decreased
38% to 212 mcf/d compared to 342 mcf/d for the same three month period in
2004.
Decreased gas production was a result of depletion from the Company’s Sibbald
property, Alberta.
For
the
six month period ending December 31, 2005 average natural gas liquids production
increased 88% to 15 bbls/d compared to 8 bbls/d for the same six month period
in
2004. For the three month period ending December 31, 2005 average natural
gas
liquids production increased 100% to 16 bbls/d compared to 8 bbls/d for the
same
three month period in 2004. Increases in natural gas liquids was primarily
attributed to a workover of the Company’s Kaybob property, Alberta.
For
the
six month period ending December 31, 2005 average oil production increased
22%
to 11 bbls/d compared to 9 bbls/d for the same six month period in 2004.
Increased oil production was due to additions from the Company’s Farrow
property, Alberta. For the three month period ending December 31, 2005 average
oil production decreased 31% to 11 bbls/d compared to 16 bbls/d for the same
three month period in 2004. Average oil production decreased during this
period
due to a depleted oil well that was in production the previous
year.
Commodity
Prices. During
the six month period ending December 31, 2005, commodity prices increased
by 65%
to an average of $62.03 per boe compared to $37.54 per boe for the six month
period in 2004. For the three months ended December 31, 2005 average commodity
prices per boe increased by 80% to $66.32 compared to $36.77 for the three
month
period ended December 31, 2004. These price increases reflect general price
increases in the respective commodities.
Average
gas prices per mcf increased by 88% to $11.23 during the six month period
ending
December 31, 2005 compared to $5.97 per mcf for the six month period ending
December 31, 2004. For the three months ended December 31, 2005 average gas
prices per mcf increased by 117% to $12.95 compared to $5.98 for the three
month
period ended December 31, 2004.
Average
natural gas liquids prices per barrel increased by 12% to $46.14 during the
six
month period ending December 31, 2005 compared to $41.26 per barrel for the
six
month period ending December 31, 2004. For the three months ended December
31,
2005 average natural gas liquids prices per barrel increased by 42% to $45.52
compared to $32.14 for the three month period ended December 31,
2004.
Average
oil prices per barrel increased by 51% to $67.28 during the six month period
ending December 31, 2005 compared to $44.42 per barrel for the six month
period
ending December 31, 2004. For the three months ended December 31, 2005 average
oil prices per barrel increased by 59% to $67.28 compared to $42.19 for the
three month period ended December 31, 2004.
Gross
oil and gas revenue.
The
Company's gross oil and gas revenue of $705,112 for the six month period
ending
December 31, 2005 increased by 46% from $482,109 for the comparative six
month
period ending December 31, 2004. Gross revenue of $379,865 for the three
month
period ending December 31, 2005 increased by 45% compared to $261,352 for
the
comparable period in 2004. Revenue growth was driven by increases in commodity
prices partially offset by lower production volumes.
Royalties.
Royalties remained constant at $91,916 for the six month period ending December
31, 2005 compared to $91,944 for the six month period ended December 31,
2004.
For the six month period royalties increased by 13% to $8.09 per boe compared
to
$7.16 per boe in 2004. For the three month period ending December 31, 2005
royalties increased by 55% to $53,751 compared to $34,597 for the comparable
period in 2004. For the three month period royalties increased by 9% to $9.38
per boe compared to $8.58 per boe in 2004.
Net
Revenue.
The
Company’s net revenues for the six month period ending December 31, 2005
increased by 57% to $613,196 compared to $390,165 for the comparative six
month
period ending December 31, 2004. Net revenues of $326,114 for the three month
period ending December 31, 2005 increased by 44% compared to $226,755 for
the
comparable period in 2004.
Operating
and transportation.
Operating and transportation costs were $197,681 for the six month period
ending
December 31, 2005, 26% lower than operating and transportation costs of $266,494
during the comparable six month period in 2004. For the three month period
ended
December 31, 2005 operating and transportation costs were $97,248, 48% lower
compared to $187,658 during the comparable three month period in 2004. Lower
costs were a result of decreased production volumes. During the six month
period
ended December 31, 2005 production cost per boe decreased by 16% to $17.39
per
boe compared to $20.75 per boe during the same period in 2004. During the
three
month period ended December 31, 2005 production cost per boe decreased by
32% to
$16.98 per boe compared to $24.93 per boe during the same period in
2004.
Depletion
and Accretion. For
the
six month period ending December 31, 2005, depletion and accretion expense
was
$390,480, 8% higher compared to $361,613 for the six month period in 2004.
For
the three month period ending December 31, 2005 depletion and accretion expense
was $204,062, 6% lower compared to $218,029 for the comparative three month
period in 2004. The increased depletion and accretion was a result of additional
capitalized costs.
Administrative
Expenses.
Administrative expenses of $736,997 for the six month period ending December
31,
2005 were 34% less than administrative expenses of $1,123,974 the previous
year.
Administrative expenses for the three month period ending December 31, 2005
were
$311,540, 41% lower than $527,522 for the comparable period in 2004. The
primary
component of administrative expenses for the six month period ending December
31, 2005 was related to litigation expenses of $233,634 versus $540,204 for
the
previous six month period ending December 31, 2004.
Foreign
Exchange. For
the
six month period ending December 31, 2005 the gain on foreign exchange was
$152,440 compared to a foreign exchange gain of $503,831 for the six month
period in 2004. For the three month period ending December 31, 2005 the loss
on
foreign exchange was $96,311 compared to a foreign exchange gain of $65,066
during the comparable period in 2004. The foreign exchange gain during fiscal
2005 and fiscal 2004 was partially attributed to the appreciation in the
Canadian dollar relating to the Oakwell Claim. This gain was partially offset
by
a foreign exchange loss relating to Company’s investment in KEOPL.
Oakwell
Claim.
For the
six month period ending December 31, 2005 the provision on the Oakwell Claim
increased by $197,961 versus nil
for
the six month period ending December 31, 2004. For
the
three month period ending December 31, 2005 the provision on the Oakwell
Claim
increased by $99,388 versus a recovery of $97,642
for the three month period ending December 31, 2004. The provision in both
cases
related to accrued interest and changes in the estimate of the provision
on the
Singapore Judgment (See
“Critical
Accounting Estimates - Oakwell Claim”
below).
Interest
income.
For the
six months ending December 31, 2005 interest income was $203,383, 23% higher
compared to $164,849 for the comparable six month period in 2004. For the
three
month period ending December 31, 2005 interest income was $97,534 compared
to
$80,817, 21% higher compared to the three month period in 2004. The increase
in
interest income was related to interest payments accrued on the Company’s KEOPL
investment as well as interest on cash held in short maturity investments.
Cash
distributions from marketable securities.
At
December 31, 2005 the Company held a portfolio of marketable securities,
which
contains a portion of oil and gas related trust units. These trust units
have a
fixed yield distribution to owners of the units. For the six month period
ending
December 31, 2005 the Company earned $109,647 in cash distributions from
trust
units versus nil for the previous six month period in 2004. For the three
month
period ending December 31, 2005 the Company earned $59,463 in cash distributions
from trust units versus nil for the previous three month period in
2004.
Gain
on sale of marketable securities. For
the
six month period ending December 31, 2005 the Company sold a portion of its
portfolio of marketable securities resulting in a gain on disposition of
$282,137. For the three month period ending December 31, 2005 the Company
sold a
portion of its portfolio of marketable securities resulting in a gain on
disposition of $167,110. For the comparable three and six month period ending
December 31, 2004 there was only a minor disposition of marketable securities
which resulted in a gain on disposition of $9,775.
Net
loss from continuing operations. Net
loss
from continuing operations decreased 76% to $163,583 for the six month period
ended December 31, 2005 compared to a net loss of $684,644 for the six month
period ending December 31, 2004. Net loss from continuing operations decreased
66% to $158,974 for the three month period ended December 31, 2005 compared
to a
net loss of $470,909 for the three month period ending December 31, 2004.
Net
loss from continuing operations were lower due to increased cash flow from
the
Company’s oil and gas operations, decreased administration expenses, gain on
sale of marketable securities, interest and cash distributions which was
partially offset by reduced foreign exchange gain.
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 1, 2005. Net
income from discontinued operations was nil for the six month period ending
December 31, 2005 versus $224,988 for the same period ended in 2004. Net
income
from discontinued operations was nil for the three month period ended December
31, 2005 compared to a net loss from discontinued operations of $77,945 for
the
three month period ended December 31, 2004.
Net
loss.
The net
loss was $163,583 for the six month period ending December 31, 2005 compared
to
a net loss of $459,656 for the comparable six month period ending December
31,
2004. For the three month period ending December 31, 2005 net loss was $158,974
compared to a net loss of $548,854 for the three month period ending December
31, 2004.
Net
loss from continuing operations per share and net loss per
share. Net
loss
from continuing operations per share for the six month period ending December
31, 2005 decreased 76% to $0.04 per share from $0.17 per share for the same
six
month period 2004. Net loss per share for the six month period ending December
31, 2005 decreased 64% to $0.04 per share compared to a net loss of $0.11
per
share for the same six month period 2004.
Net
loss
from continuing operations per share for the three month period ending December
31, 2005 decreased 66% to $0.04 per share from $0.12 per share for the same
three month period 2004. Net loss per share for the three month period ending
December 31, 2005 decreased 71% to $0.04 per share compared to a net loss
of
$0.14 per share for the same three month period 2004.
Capital
Expenditures. Capital
expenditures totaled
$2,137,395 for the six months period ending December 31, 2005 compared to
$476,705 for the same six month period in 2004. During the three month period
ending December 31, 2005 capital expenditures were $948,194 compared to $315,959
for the comparable period in 2004. During the six and three month periods
ending
December 31, 2005 the Company’s primary expenditures related to drilling and
completion costs of four wells in Buick Creek, North East British
Columbia.
SUMMARY
OF QUARTERLY RESULTS
|
Unaudited
|
|||||||||||||||||||||||||
|
Fiscal
2006
|
Fiscal
2005
|
Fiscal
2004
|
|||||||||||||||||||||||
|
|
Dec.
31/05
|
Sept.
30/05
|
|
|
June
30/05
|
|
|
Mar.
31/05
|
|
|
Dec.
31/04
|
|
|
Sept.
30/04
|
|
|
June
30/04
|
|
|
Mar.
31/04
|
|||||
|
Financial
Information:
|
|||||||||||||||||||||||||
|
Net
oil and gas revenue
|
$
|
326,114
|
$
|
287,082
|
$
|
149,274
|
$
|
206,044
|
$
|
226,755
|
$
|
163,410
|
$
|
294,439
|
$
|
107,111
|
|||||||||
|
Loss
from continuing
|
|||||||||||||||||||||||||
|
operations
|
$
|
(158,974
|
)
|
$
|
(4,609
|
)
|
$
|
(741,216
|
)
|
$
|
(771,886
|
)
|
$
|
(470,909
|
)
|
$
|
(213,735
|
)
|
$
|
17,429
|
$
|
(1,340,132
|
)
|
||
|
Net
income (loss)
|
$
|
(158,974
|
)
|
$
|
(4,609
|
)
|
$
|
(891,216
|
)
|
$
|
1,188,123
|
$
|
(548,854
|
)
|
$
|
89,198
|
$
|
724,369
|
$
|
(1,760,423
|
)
|
||||
|
Loss
from continuing
|
|||||||||||||||||||||||||
|
operations
per share
|
$
|
(0.04
|
)
|
$
|
(0.001
|
)
|
$
|
(0.18
|
)
|
$
|
(0.19
|
)
|
$
|
(0.12
|
)
|
$
|
(0.05
|
)
|
$
|
0.00
|
$
|
(0.33
|
)
|
||
|
Net
income (loss) per share
|
$
|
(0.04
|
)
|
$
|
(0.001
|
)
|
$
|
(0.22
|
)
|
$
|
0.29
|
$
|
(0.14
|
)
|
$
|
0.02
|
$
|
0.18
|
$
|
(0.43
|
)
|
||||
|
Fully
diluted net income
|
|||||||||||||||||||||||||
|
(loss)
per share
|
$
|
(0.04
|
)
|
$
|
(0.001
|
)
|
$
|
(0.22
|
)
|
$
|
0.26
|
$
|
(0.14
|
)
|
$
|
0.02
|
$
|
0.16
|
$
|
(0.43
|
)
|
||||
|
Operating
Information:
|
|||||||||||||||||||||||||
|
Average
Daily Production
|
|||||||||||||||||||||||||
|
Natural
gas (mcf per day)
|
212
|
231
|
270
|
233
|
342
|
171
|
369
|
126
|
|||||||||||||||||
|
Natural
gas liquids (bbls per day)
|
16
|
13
|
10
|
14
|
8
|
5
|
9
|
8
|
|||||||||||||||||
|
Crude
oil (bbls per day)
|
11
|
11
|
13
|
14
|
16
|
1
|
3
|
2
|
|||||||||||||||||
|
Total
(boe per day)
|
62
|
62
|
69
|
67
|
81
|
34
|
74
|
31
|
|||||||||||||||||
|
Average
Commodity Prices
|
|||||||||||||||||||||||||
|
Natural
gas ($/mcf)
|
$
|
12.95
|
$
|
9.73
|
$
|
7.41
|
$
|
7.97
|
$
|
5.98
|
$
|
6.07
|
$
|
6.05
|
$
|
8.02
|
|||||||||
|
Natural
gas liquids ($/bbl)
|
$
|
45.52
|
$
|
47.01
|
$
|
41.81
|
$
|
32.67
|
$
|
32.14
|
$
|
37.95
|
$
|
22.76
|
$
|
30.78
|
|||||||||
|
Crude
oil ($/bbl)
|
$
|
67.28
|
$
|
68.30
|
$
|
65.76
|
$
|
52.71
|
$
|
42.19
|
$
|
55.91
|
$
|
33.02
|
$
|
40.68
|
|||||||||
|
Total
($/boe)
|
$
|
66.32
|
$
|
57.67
|
$
|
48.15
|
$
|
45.68
|
$
|
36.77
|
$
|
37.29
|
$
|
33.97
|
$
|
43.29
|
|||||||||
|
Royalties
|
|||||||||||||||||||||||||
|
Natural
gas ($/mcf)
|
$
|
1.42
|
$
|
0.98
|
$
|
1.69
|
$
|
1.18
|
$
|
1.48
|
$
|
1.77
|
$
|
0.72
|
$
|
1.46
|
|||||||||
|
Natural
gas liquids ($/bbl)
|
$
|
11.39
|
$
|
10.84
|
$
|
9.48
|
$
|
10.03
|
$
|
11.23
|
$
|
19.83
|
$
|
3.95
|
$
|
5.78
|
|||||||||
|
Crude
oil ($/bbl)
|
$
|
8.61
|
$
|
4.95
|
$
|
8.55
|
$
|
9.07
|
$
|
6.07
|
$
|
4.92
|
$
|
1.85
|
$
|
2.13
|
|||||||||
|
Total
royalties ($/boe)
|
$
|
9.38
|
$
|
6.77
|
$
|
9.75
|
$
|
8.07
|
$
|
8.58
|
$
|
11.72
|
$
|
4.14
|
$
|
7.50
|
|||||||||
|
Production
costs
|
|||||||||||||||||||||||||
|
Natural
gas ($/mcf)
|
$
|
3.15
|
$
|
3.36
|
$
|
2.80
|
$
|
1.60
|
$
|
4.27
|
$
|
2.77
|
$
|
2.54
|
$
|
3.35
|
|||||||||
|
Natural
gas liquids ($/bbl)
|
$
|
7.34
|
$
|
5.71
|
$
|
7.28
|
$
|
5.86
|
$
|
5.71
|
$
|
10.94
|
$
|
15.37
|
$
|
14.08
|
|||||||||
|
Crude
oil ($/bbl)
|
$
|
26.49
|
$
|
24.07
|
$
|
37.00
|
$
|
21.12
|
$
|
34.03
|
$
|
35.82
|
$
|
13.11
|
$
|
13.41
|
|||||||||
|
Total
production costs ($/boe)
|
$
|
16.98
|
$
|
17.81
|
$
|
19.24
|
$
|
10.99
|
$
|
24.93
|
$
|
16.52
|
$
|
15.18
|
$
|
18.10
|
|||||||||
|
Netback
by Product
|
|||||||||||||||||||||||||
|
Natural
gas ($/mcf)
|
$
|
8.38
|
$
|
5.39
|
$
|
2.92
|
$
|
5.19
|
$
|
0.23
|
$
|
1.53
|
$
|
2.79
|
$
|
3.21
|
|||||||||
|
Natural
gas liquids ($/bbl)
|
$
|
26.79
|
$
|
30.46
|
$
|
25.05
|
$
|
16.78
|
$
|
15.20
|
$
|
7.18
|
$
|
3.44
|
$
|
10.92
|
|||||||||
|
Crude
oil ($/bbl)
|
$
|
32.18
|
$
|
39.28
|
$
|
20.21
|
$
|
22.52
|
$
|
2.09
|
$
|
15.17
|
$
|
18.06
|
$
|
25.14
|
|||||||||
|
Netback
($/boe)
|
$
|
39.96
|
$
|
33.09
|
$
|
19.16
|
$
|
26.62
|
$
|
3.26
|
$
|
9.05
|
$
|
14.65
|
$
|
17.69
|
|||||||||
Net
revenues from the Company’s oil and gas operations have increased over the past
eight quarters due to general increases in commodity prices (See “Trend
Information”
below).
Earnings from oil and gas activities tend to be a function of changes in
production volumes or changes in commodity prices.. Higher administrative
expenses are generally related to increased litigation costs and the accrual
of
interest relating to the Oakwell Claim. 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 December 31, 2005 was $1,994,932 compared to $5,286,315
at June 30, 2005. During the six month period ending December 31, 2005 the
Company’s cash used in operating activities from continuing operations was
$848,911 versus cash provided by operating activities of $533,654 during
the
comparable six month period in 2004.
The
Company expended $2,137,395 related to oil and gas properties during the
six
month period ended December 31, 2005 versus $476,705 during the previous
six
month period ending December 31, 2004. The Company also invested $286,327
in
marketable securities during the six month period ending December 31, 2005
versus proceeds on disposition of $11,375 in the previous period.
The
Company has the resources to meet its present working capital requirements
with
the exception of the Oakwell Claim.
The
Company's primary sources of liquidity and capital resources historically
have
been cash flows from oil and gas operations, the issuance of share capital,
advances from shareholders and cash flows from discontinued operations. The
Company expects that primary sources of liquidity and capital resources will
be
derived from the oil and gas operations, the sale of marketable securities
and
cash distributions from trust units. (See “Critical
Accounting Estimates - Valuation of the Company’s Investment in KEOPL”
below).
With
respect to specific estimates that could have a material affect on future
operations and cash flows see “Critical
Accounting Estimates - Oakwell Claim and the 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. The Company retracted preferred shares of M&M for
Cdn $1,000,000 cash. The Company also sold its interest in 10915 Newfoundland
Limited and 11123 Newfoundland Limited for cash proceeds of
$175,000.
The
Company’s oil and gas operations have increased since its inception in 2001. At
present, the Company intends to apply significant cash to further develop
its
oil and gas properties. 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
and
exploration properties. Amounts expended on future oil and gas exploration
and
development is dependent on the results of its ongoing exploration activities
and 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
against the enforceability of the Oakwell Claim in Canada, there will be
a
material and adverse impact on the Company’s financial position and operations
may be curtailed.
The
Company anticipates further capital expenditures related to its Buick Creek,
North East British Columbia property and fund any future exploration activities.
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.
There
are
a number of trends that have been developing in the oil and gas industry
during
the past several years that appear to be shaping the near future of the
business. The first trend is the volatility of commodity prices. Natural
gas is
a commodity influenced by factors within North America. The continued tight
supply demand balance for natural gas is causing significant elasticity in
pricing. Despite record drilling activity, a strong economy, weather, fuel
switching and demand for electrical generation there still exists a tight
supply
causing prices to remain high.
Crude
oil
is influenced by the world economy and OPEC's ability to adjust supply to
world
demand. Recently crude oil prices have been kept high by political events
causing disruptions in the supply of oil, and concern over potential supply
disruptions triggered by unrest in the Middle East.
Political
events trigger large fluctuations in price levels. The impact on the oil
and gas
industry from commodity price volatility is significant. During periods of
high
prices, producers generate sufficient cash flows to conduct active exploration
programs without external capital. Increased commodity prices frequently
translate into very busy periods for service suppliers triggering premium
costs
for their services. Purchasing land and properties similarly increase in
price
during these periods. During low commodity price periods, acquisition costs
drop, as do internally generated funds to spend on exploration and development
activities. With decreased demand, the prices charged by the various service
suppliers also decline.
A
second
trend within the Canadian oil and gas industry is recent growth in the number
of
private and small junior oil and gas companies starting up business. These
companies often have experienced management teams from previous industry
organizations that have disappeared as a part of the ongoing industry
consolidation. Many are able to raise capital and recruit well qualified
personnel.
A
third
trend currently affecting the oil and gas industry is the impact on capital
markets caused by investor uncertainty in the North American economy. The
capital market volatility in Canada has also been affected by uncertainties
surrounding the economic impact that the Kyoto Protocol will have on the
sector.
Generally during the past year, the economic recovery combined with increased
commodity prices has caused an increase in new equity financings in the oil
and
gas industry. The Company must compete with the numerous new companies and
their
new management teams and development plans in its access to capital. The
competitive nature of the oil and gas industry will cause opportunities for
equity financings to be selective. Some companies will have to rely on
internally generated funds to conduct their exploration and developmental
programs.
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, 2005, 2004, 2003. 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 relate to oil and
gas
accounting and reserve estimates, future income tax assets and liabilities,
foreign currency translation 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 5% 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, 2005 the Company had
$6,944,172 of non-capital losses, Cumulative Canadian oil and gas property
expenses of $7,778,236 and capital losses of $10,449,015.
Foreign
Currency Translation: Foreign
currency accounts are translated to Canadian dollars as follows: At the
transaction date, each asset, liability, revenue or expense is translated
into
Canadian dollars by the use of the exchange rate in effect at that date.
At the
year end date, monetary assets and liabilities are translated into Canadian
dollars by using the exchange rate in effect at that date and the resulting
foreign exchange gains and losses are included in Consolidated Statement
of
Operations and Deficit in the current period.
Stock
based compensation.
The
Company has established a stock option plan (the "Plan") for directors,
officers, employees, consultants and service providers. During
fiscal 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
the six months ended December 31, 2005 the Company recorded $3,736 of
compensation expense related to the issuance of stock options.
Critical
Accounting Estimates
Oakwell
Claim. In
March
1997, Oakwell Engineering Limited (“Oakwell”) and the Andhra Pradesh State
Electricity Board (“APSEB”) executed two identical Power Purchase Agreements
(“PPA”), providing for Oakwell and/or its sponsors to build, own and operate two
identical 100 MW net capacity diesel generator Barge Mounted Power Plants
(“BMPP”), fueled by furnace oil (total 200 MW net capacity) and sell
electricity to APSEB on a take-or-pay basis for 15 years. In June 1997, the
Company and Oakwell formed an 87.5%/12.5% joint venture and incorporated
an
Indian company, EPS Oakwell Power Limited (“EOPL”) (now known as KEOPL), to
implement the provisions of the PPA’s. Disputes rose between the Company and
Oakwell and a Settlement Agreement was reached in December 1998 under which
Oakwell sold the Company all of Oakwell's interest in the PPA’s and in EOPL.
In
July
2002, Oakwell claimed the Company was in breach of the Settlement Agreement
and
in August 2002, the Company was named as a defendant in the High Court of
the
Republic of Singapore, in the matter of Oakwell vs. the Company. On October
16,
2003 the High Court of Singapore ordered the Company to pay Oakwell US
$5,657,000 (approximately CDN $6,595,546 at December 31, 2005) plus costs
(the
“Judgment”). On November 13, 2003 the Company appealed the Judgment to the Court
of Appeal of the Republic of Singapore. That Court, which is the final Court
of
Appeal for Singapore, dismissed the appeal on April 27, 2004.
On
June
21, 2004, Oakwell filed an Application with the Superior Court of Justice
for
the Province of Ontario (“Superior Court”) seeking to enforce the Judgment in
Ontario. On August 30, 2004, the Company filed an Application with the Superior
Court for a declaration that the Judgment is not enforceable in the Province
of
Ontario. The hearing of the Applications was held December 6-9, 2004. On
June
27, 2005 the Superior Court judge rendered his decision that the Judgment
was
enforceable in Ontario with costs and on August 2, 2005 the Superior Court
issued the formal Order.
On
July
13, 2005, the Company filed a Notice of Appeal (Court File No. 04-CV-271121CM3
and 04-CV-2748 60CM2) of the August 2, 2005 Order of the Superior Court with
the
Court of Appeal for the Province of Ontario. The appeal hearing has been
set for
April 10, 2006.
On
January 12, 2005, Oakwell filed an Execution Petition before the Hon’ble High
Court of Delhi, India against the Company for enforcement of the Judgment
and an
application for interim relief seeking attachment of the Company’s 11,848,200
KEOPL Shares, 100% of the shares of EPS Karnataka which owns 97% of EIPCL.
EIPCL
has a PPA secured by a cash deposit in the amount of INR 10,000,000
(approximately CDN $259,100 at December 31, 2005) with the Karnataka State
Electricity Board.
On
September 9, 2005 the Hon’ble High Court of Delhi, India adjourned Oakwell’s
Execution Petition to attach the Company’s KEOPL Shares, EPS Karnataka shares
and EIPCL but ordered that if the Company receives any payments from the
sale of
its KEOPL Shares, then the proceeds shall be deposited in the Company’s account
held in a Public Sector Bank in India or invested only in Government of India
securities until the disposal of Oakwell’s Execution Petition. The Execution
Petition is ongoing and has been adjourned to May 16, 2006.
In
the
event that Oakwell is successful in India in attaching the Company’s KEOPL
Shares, EPS Karnataka shares and EIPCL, the Company may not enjoy any potential
future gains resulting from its investment in EIPCL, which has been accounted
for as discontinued operations.
A
provision of CDN $7,785,579 at December 31, 2005 has been made to the Company’s
financial statements in relation to the Judgment.
If
the
Judgment is ultimately enforced in Canada, the Company’s financial condition
would be materially and adversely affected.
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 $214,757 (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 unaudited 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
December 31, 2005 the Company owns 11,848,200 KEOPL Shares formerly known
as
EOPL. Pursuant to an Arbitration Agreement between the Company and VBC Ferro
Alloys Ltd. (“VBC”), the parent company of KEOPL, an Arbitration Award was
passed on October 11, 2003 by Hon’ble Arbitral Tribunal, India (the “Award or
Decree”) requiring as follows (i) VBC transfer an additional 500,000 equity
shares in KEOPL to the Company,
and (ii)
VBC to buy the original KEOPL Shares for INR 113,482,000 (approximately CDN
$2,940,321 million at December 31, 2005) on or before the earlier of: (a)
60
days after the first disbursal of funds on financial closure for the KEOPL
Project, and, (b) in any event no later than March 31, 2004. Further, the
Company may, upon written notice to VBC, require that VBC purchase, and VBC
is
then required to buy, an additional 500,000 equity shares of KEOPL at a par
value of INR 5,000,000 (approximately CDN $129,550 at December 31, 2005)
on or
before the same dates. If VBC does not buy the 11,348,200 KEOPL Shares before
March 31, 2004 then 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 on June 24,
2004
the Company filed an Execution Petition against VBC in the Court of the Chief
Judge, City Civil Court, Hyderabad, India (“City Civil Court”) to enforce the
Award. The next hearing has been listed for March 16, 2006.
On
November 30, 2004 the Company also filed a Company Petition against VBC in
the
High Court of Judicature of Andhra Pradesh, India (the “High Court”) to pass an
order for the winding up of VBC under the provisions of the Companies Act,
1956
(India). On April 29, 2005 the High Court passed an Order for the winding
up of
VBC and awarded the Company costs of the Petition. The Company Petition is
ongoing and the next hearing is expected to be held in March, 2006.
VBC
appealed before the Division Bench in the High Court of Andhra Pradesh, India
to
set aside the Order of the High Court dated April 29, 2005. On June 8, 2005
the
Division Bench of the High Court of Andhra Pradesh, India passed an Order
granting VBC an interim stay of publication of the winding up of VBC only
subject to the condition of VBC depositing one-third of the amount of the
Decree
passed in pursuance of the Award along with the interest earned on the principal
amount to the credit of Execution Petition on the file of Chief Judge, City
Civil Court, Hyderabad, India on or before July 30, 2005. On September 6,
2005
the High Court passed a further Order extending the date for deposit of
one-third of the amount of the Decree to September 30, 2005. VBC complied
by
depositing Rs. 48,437,900 (Cdn$ 1,279,246) representing one-third of the
amount
of the Decree plus interest.
On
August
1, 2005, the Company filed a Special Leave Petition in the Supreme Court
of
India seeking special leave to appeal the Order of the Division Bench in
the
High Court of Andhra Pradesh, India dated June 8, 2005. The hearing was held
October 3, 2005 and the Supreme Court of India declined to set aside the
June 8,
2005 order of the Division Bench in the High Court of Andhra Pradesh, India
but
ordered that court to expedite the hearing.
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 December 31, 2004
and
July 1, 2004 to September 30, 2004 in the amount of CDN $84,142 (US $62,800)
and
CDN $76,366 (US $63,990) respectively.
The
investment in KEOPL is recorded at expected net recoverable amount of CDN
$3,069,872 at December 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 including the deposit of one-third of
the
amount of the Decree plus the interest due into the City
Civil Court, Hyderabad, India.
The
actual recoverable amount is dependent upon future events including foreign
exchange fluctuations 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.
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.
Management
evaluated
the effectiveness of the Company's disclosure controls and procedures as
of December 31, 2005, and concluded that, as of that date, the
Company's disclosure controls and procedures were effective. During the period
covered by this report there have been no changes in the Company’s internal
control over financial reporting that is expected to materially affect or
is
reasonably likely to materially affect the Company’s internal control over
financial reporting.
Share
Capital
At
the
date of this Management’s Discussion and Analysis:
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, 2005 and December 31, 2005
|
4,059,009
|
$43,339,132
|
|
Issued
on exercise of options
|
15,000
|
13,169
|
|
4,074,009
|
43,352,301
|
Contributed
Surplus
|
Value
|
||
|
Balance, as
at June 30, 2005
|
|
$149,109
|
|
Issuance
of options
|
3,736
|
|
|
Balance,
as at December 31, 2005
|
|
$152,845
|
Common
share purchase options
|
Exercise
|
Expiry
|
2005
|
2004
|
|
Price
|
Date
|
#
|
#
|
|
US$0.75
|
February
28, 2010
|
585,000
|
-
|
|
US$1.77
|
July
15, 2008
|
15,000
|
-
|
|
Balance,
as at February 10, 2006
|
600,000
|
-
|
|
Of
the
options priced at US$0.75, 5,000 vest March 1, 2006. Of the options priced
at
US$1.77, 10,000 vest July 15, 2006 and 5,000 vest on July 15, 2007.