Lightning Energy Ltd.

Lightning Energy Ltd.

March 07, 2005 08:30 ET

Lightning Energy Ltd. Announces 2004 Year-End Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: LIGHTNING ENERGY LTD.

TSX SYMBOL: LEL

MARCH 7, 2005 - 08:30 ET

Lightning Energy Ltd. Announces 2004 Year-End Results

CALGARY, ALBERTA--(CCNMatthews - March 7, 2005) - Not for distribution
to United States newswire services or dissemination in the United States.

Lightning Energy Ltd. ("Lightning" or the "Company") (TSX:LEL) is
pleased to announce its financial and operating results for the year
ended December 31, 2004, its first year as a public company.

Lightning commenced operations as a private company in late 2001,
principally focused on high impact exploration activities with a
multinational integrated energy company. The Company grew to
approximately 1,900 boe/d as a private company by the end of 2003.

Lightning exited 2004 at approximately 4,000 boe/d of production with
incremental behind pipe production capability of 1,000 boe/d. This
compares with 2003 fourth quarter production of 1,940 boe/d. Lightning
drilled 22 wells in 2004 (11.6 net) with an average success rate of 84%
(net).

Revenue for 2004 was $43.7 million, which resulted in cash flow of $20.7
million or $0.59/share basic and $0.56/share fully diluted.

Lightning was very active in 2004 commencing in June with the business
combination with Brooklyn Energy Corporation resulting in a new public
company listed on the Toronto Stock Exchange. Subsequently, in August we
announced the successful acquisition of Archean Oil and Gas Ltd., a
private energy company with a strategic land position in the prolific
Pembina Nisku light oil exploration fairway. This transaction created an
exciting new core area for Lightning and has already resulted in
significant growth in productive capability and reserves.

Finally, on February 2, 2005 Lightning announced a business combination
with Argo Energy Ltd. ("Argo") that will create two new business
entities, Sequoia Oil & Gas Trust, a growth-oriented drilling trust, and
White Fire Energy LTD., a junior exploration company focused in the
Pembina Nisku fairway.

Sequoia Oil & Gas Trust ("Sequoia") will own approximately 95% of
Lightning and Argo's current production concentrated in four core areas:
Pembina, Medicine Lodge and Obed from Lightning and the Sylvan Lake area
from Argo. In each area, Sequoia will be on the leading edge of
development in "resource style" projects that have large undeveloped
land positions, control of infrastructure, good seismic coverage and
multiple years of drilling inventory. This inventory of opportunities is
expected to allow Sequoia to grow, while distributing 60% of its cash
flow to unit holders.

Sequoia expects to average 9,750 boe/d of production for the period May
1, 2005 to December 31, 2005 with estimated 2005 exit production of
10,500 boe/d. Sequoia will be managed by Mr. Bradley Johnson and his
team from Argo, which has extensive experience in sourcing, evaluating
and negotiating acquisition opportunities as well as a track record of
growth in production and production per share since inception at Argo.

White Fire Energy Ltd. ("White Fire") will be focused initially on the
undeveloped land in the Lodge Pole area of the Pembina Nisku play. To
date, 11 drilling opportunities have been identified in the Pembina area
on 3-D seismic and ten of these wells will be operated by White Fire
with an average operating working interest of 50%. In addition to
Pembina, White Fire will have 30,000 undeveloped acres of land in Wilson
Creek, Ferrier and northeastern British Columbia, and will be managed by
current members of Lightning's management team.

We believe the proposed transaction is in the best interest of Lightning
shareholders as it creates a drilling trust with an experienced quality
management team, a resource base to foster sustainable production and
stable, tax efficient monthly cash distributions to unit holders as well
as offering a "ground floor" investment in a growth-oriented exploration
focused junior producer in White Fire, managed by a team with a track
record of creating profitable growth.

I would like to take this opportunity to thank our shareholders who have
provided tremendous support over the past three years as we have made
the transition from start-up through to trust conversion. We believe we
are creating two exciting new businesses in Sequoia and White Fire and
look forward to their continued success in 2005.

All shareholders are invited to attend the Annual and Special Meeting of
Shareholders on Thursday, April 21, 2005 at the Metropolitan Centre, 333
Fourth Avenue S.W., Calgary, Alberta commencing at 10:30 a.m. MST.

RESERVES

The December 31, 2004 reserve report was prepared by Gilbert Laustsen
Jung Associates Ltd. ("GLJ") and utilized definitions as set out under
National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities ("NI 51-101").

Highlights

- Proved reserves increased 199% to 7.64 mmboe, net of production and
revisions. Of the total additions on the proved reserve base of 5.04
mmboe, natural gas and natural gas liquids accounted for 68% of the
increase.

- Proved plus probable reserves increased 285% to 11.63 mmboe, net of
production and revisions. Total additions on the proved plus probable
reserve base were 8.61 mmboe.

The evaluator has reviewed all of the Company's reserves as at December
31, 2004. Both the December 31, 2003 and 2004 reserves include Company
working interests and royalty interests before royalty costs. Where
amounts and volumes are expressed on a barrel of oil equivalent basis,
gas volumes have been calculated using a conversion rate of six thousand
cubic feet of natural gas to one barrel of oil (6:1).



Reserves Summary (includes working interests and royalty interests)

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Natural Crude Oil Total
Gas & NGLs (6:1)
---------------------------------------------------------------------
(bcf) (mbbls) (mboe)

December 31, 2004 (1)
Proved developed producing 24.21 1,518 5,553
Proved developed non-producing 2.50 272 688
Proved undeveloped 2.89 921 1,403
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Total proved 29.60 2,711 7,644
Probable additional 14.54 1,564 3,987
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Total proved plus probable 44.14 4,275 11,631
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---------------------------------------------------------------------

December 31, 2003 (2)
Proved developed producing 12.36 55 2,114
Proved developed non-producing 0.26 -- 43
Proved undeveloped 2.41 -- 402
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Total proved 15.03 55 2,559
Probable additional 2.68 17 465
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Total proved plus probable 17.71 72 3,024
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(1) Using GLJ's January 1, 2005 escalated price forecast.
(2) Using GLJ's January 1, 2004 escalated price forecast.


Reserves Reconciliation (includes working interests and royalty
interests)

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Natural Gas Crude Oil & NGLs Combined BOE
---------------------------------------------------------------------
Total Proved & Total Proved & Total Proved &
Proved Probable Proved Probable Proved Probable
---------------------------------------------------------------------
(bcf) (bcf) (mbbls) (mbbls) (mboe) (mboe)

December 31,
2003 15.03 17.71 55 72 2,559 3,024
Drilling
extensions,
discoveries
and infill
drilling 2.56 3.79 997 1,792 1,423 2,423
Acquisitions 19.22 30.43 1,782 2,521 4,986 7,592
Dispositions -- -- -- -- -- --
Technical
revisions (1.74) (2.32) 33 46 (257) (341)
Production (5.47) (5.47) (156) (156) (1,067) (1,067)
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December 31,
2004 29.60 44.14 2,711 4,275 7,644 11,631
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MANAGEMENT'S DISCUSSION AND ANALYSIS - 2004

Management's discussion and analysis (MD&A) of the financial condition
and the results of operations should be read in conjunction with the
consolidated financial statements for the years ended December 31, 2004
and 2003 together with the accompanying notes.

Production information is commonly reported in units of barrel of oil
equivalent (boe). For purposes of computing such units, natural gas is
converted to equivalent barrels of oil using a conversion factor of six
thousand cubic feet to one barrel of oil. This conversion ratio of 6:1
is based on an energy equivalent wellhead value for the individual
products. Such disclosure of boes may be misleading, particularly if
used in isolation. Readers should be aware that historical results are
not necessarily indicative of future performance.

This MD&A contains the term cash flow from operations, which should not
be considered an alternative to or more meaningful than cash flow from
operating activities, as determined in accordance with Canadian
generally accepted accounting principles (GAAP), as an indicator of the
Company's performance. The Company presents cash flow from operations
per share whereby per share amounts calculated are consistent with the
calculation of earnings per share.

Proposed Business Combination with Argo Energy Ltd.

On February 2, 2005, we entered into an agreement with Argo Energy Ltd.
("Argo") to effect a business combination and create two new public
entities called Sequoia Oil & Gas Trust and White Fire Energy Ltd.
Accordingly, limited forward-looking statements are presented due to the
assumption of a completed Plan of Arrangement. Pursuant to this Plan of
Arrangement, the effect of the transaction is as follows, subsequent to
the proposed 4:1 share consolidation:

The shareholders of Lightning will receive the following for each
Lightning share owned:

- 0.25 of a trust unit of Sequoia Oil & Gas Trust and,

- 0.25 of a share in White Fire Energy Ltd.

The shareholders of Argo will receive the following for each Argo share
owned:

- 0.17125 of a trust unit of Sequoia Oil & Gas Trust

- 0.17125 of a share in White Fire Energy Ltd.

The Plan of Arrangement will require the approval of Lightning and Argo
shareholders, which is planned for April 21, 2005, the Court of Queens
Bench of Alberta and other regulatory approvals. For further details of
this transaction, refer to the February 2, 2005 joint press release by
Argo and Lightning located on SEDAR.

Overall Performance - 2004

During 2004, we saw rapid expansion by way of an active drilling program
and the closing of two strategic business acquisitions, which combined
to increase our production 132% over 2003 levels to average 2,916 boe/d.
In addition to production changes, commodity prices remained strong,
improving 41% over the prior year for liquid sales and 13% over the
prior year for natural gas. Royalty and operating costs on a per unit
basis decreased from 2003 levels as a result of the lower encumbered
production acquired, while administration and current tax costs
increased in line with our Company's expansion. As a result of this
activity, our year-over-year annual cash flow increased 313% to $20.7
million. The growth in operations was funded by a reduction in working
capital along with an increase in the draw on our revolving bank lines
and two private placement equity financings made during the year. We
closed 2004 with fourth quarter production of 4,084 boe/d, estimated
production behind pipe of 1,400 boe/d, an unused line of credit of $32.0
million and a significant inventory of exploration and development
prospects.

On June 3, 2004, we obtained a listing on the Toronto Stock Exchange and
began trading under the symbol LEL. This listing now makes it possible
for all investors to freely trade their shares on the open market.

Brooklyn Acquisition

On March 30, 2004, we entered into a Plan of Arrangement with Brooklyn
Energy Corporation (Brooklyn) to effect a business combination resulting
in our continuation as a public company. On May 31, 2004, the
transaction was approved by our shareholders, the shareholders of
Brooklyn and the Court of Queen's Bench of Alberta. To close this
transaction, 11.3 million shares of the Company were issued from
treasury at a value of $5.00/share and a cash payment of $22.8 million
was made. In addition, transaction costs of $0.8 million were incurred
resulting in a cost of $79.9 million for the acquisition, which is
further detailed in note 4 to the consolidated financial statements.

Archean Acquisition

On August 16, 2004, we entered into a purchase agreement to acquire all
the issued and outstanding shares of Archean Oil & Gas Ltd. (Archean).
On August 31, 2004, this transaction was closed for $80.0 million, the
assumption of $15.0 million in total debt and transaction costs of $0.5
million. This acquisition is further detailed in note 5 to the
consolidated financial statements.

Property Disposition

On September 17, 2004, we entered into a purchase and sale agreement
with a third party involving a number of properties purchased from
Archean. On September 30, 2004, this disposition closed for cash
consideration of $45.3 million, after adjustments and transaction costs.
This disposition is further detailed in note 6 to the consolidated
financial statements.

Operating Results

Capital Expenditures

Capital expenditures, summarized in the following table, include
specific property acquisitions and dispositions as well as land,
seismic, drilling and facility costs incurred in each period, but do not
include the transactions involved in the Brooklyn and Archean purchase
and disposition activities.



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Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
($000s) (%)

Acquisitions 2,807 14,631 (81) --
Dispositions (2,000) (3,000) (33) --
Drilling and completions 30,307 16,105 88 8,164
Equipment and facilities 7,876 13,758 (43) 1,588
Geological and geophysical 400 1,750 (77) 1,257
Land and lease retention 1,478 1,387 7 911
Capitalized G&A and other 1,428 811 76 562
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Total 42,296 45,442 (7) 12,482
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---------------------------------------------------------------------


During 2004, we incurred $42.3 million in net capital expenditures
compared to $45.4 million a year ago. Acquisitions of $2.8 million
included the purchase of the Baysel/Karr property for $2.0 million. To
diversify our risk profile, we farmed out an interest in the same Baysel
property, but remained as operator, for a buy-in fee of $2.0 million.

The drilling and completions expenditures totaled $30.3 million and
involved the participation in 12 gross (7.4 net) exploration plays and
10 gross (4.2 net) development wells. Of the 12 exploration wells, 4
gross (1.8 net) wells were abandoned, while the remaining 8 gross (5.6
net) wells were cased for production or further evaluation. Of the 10
development wells, 5 gross (1.5 net) oil wells and 5 gross (2.7 net) gas
wells were cased for production. The following table summarizes the
drilling activity performed in 2004 and 2003:



Drilling Activity

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Exploration Development Total
Gross Net Gross Net Gross Net
---------------------------------------------------------------------
2004
Oil and NGLs -- -- 5 1.5 5 1.5
Natural gas 8 5.6 5 2.7 13 8.3
Dry and abandoned 4 1.8 -- -- 4 1.8
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Total wells 12 7.4 10 4.2 22 11.6
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Success rate (%) 67 76 100 100 82 84
Average working interest (%) 62 42 53
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---------------------------------------------------------------------
2003
Oil and NGLs -- -- -- -- -- --
Natural gas 7 3.7 -- -- 7 3.7
Dry and abandoned 3 0.8 -- -- 3 0.8
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Total wells 10 4.5 -- -- 10 4.5
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Success rate (%) 70 82 -- -- 70 82
Average working interest (%) 45 -- -- 45
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---------------------------------------------------------------------


Our expenditures on facilities in 2004 totaled $7.9 million, the largest
component involved the purchase of a 1.5% interest in the Edson gas
plant for $1.6 million. In 2005, we anticipate spending over $9.5
million on facilities to accommodate the additional production
anticipated from the Pembina, Medicine Lodge and Obed areas.

We incurred $0.4 million on seismic related expenditures to support the
drilling activity incurred during the year and that anticipated in 2005.
An independent evaluation of our seismic database has assessed the fair
market value of these assets at $7.9 million.

Land purchases and retention costs incurred in 2004 were $1.5 million as
the majority of the increases in our land base were obtained as a result
of the Brooklyn and Archean transactions. The cost of these undeveloped
lands are included in the corporate acquisition costs of the respective
transactions. An independent evaluation of our land holdings has
assessed the fair market value of our undeveloped land base at $17.3
million as at November 1, 2004.



Financial Results
Production, Price and Revenue

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Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
(%)

Oil and NGL sales (bbls/d) 398 60 563 --
Natural gas sales (mmcf/d) 15.1 7.2 110 0.5
Total sales (boe/d) 2,916 1,259 132 86
Total sales (000 boes) 1,067 460 132 31
Liquid sales price ($/bbl) 50.47 35.75 41 --
Natural gas sales price ($/mcf) 6.56 5.82 13 5.18
Total revenue ($000s) 43,654 16,061 172 979
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---------------------------------------------------------------------


Production, Price and Revenue

Our production profile continues to reflect our focus on natural gas,
which accounted for over 86% of total production in 2004. Natural gas
production increased 110% to average 15.1 mmcf/d versus 7.2 mmcf/d in
2003. Liquids production improved 563% to average 398 bbls/d compared to
60 bbls/d a year ago. On a boe basis, production in 2004 increased 132%
to average 2,916 versus 1,259 in 2003. This production growth was the
result of successful drilling and completion activities performed late
in 2003 and throughout 2004, the purchase of Brooklyn effective May 31,
2004 and the acquisition of Archean, net of disposition, made effective
August 31, 2004.

Commodity prices in the year averaged $50.47/bbl for liquids and
$6.56/mcf for natural gas compared to $35.75/bbl and $5.82/mcf,
respectively, received in 2003. Included in the natural gas price is the
effect of hedging gains received in the period, which increased the
average gas price by $0.13/mcf in the year.

Revenue increased 172% to $43.7 million in 2004 from $16.1 million in
2003 due primarily to increased production. Included in revenue is
natural gas hedging gains of $0.7 million and $0.15 million received in
2004 and 2003, respectively.

In 2005, we anticipate production to grow as oil and natural gas behind
pipe comes on stream and the results of the drilling program are
realized. Commodity prices are expected to remain strong, resulting in
continued revenue growth for the upcoming period.



Royalties

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Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
($000s) (%)

Revenue 43,654 16,061 172 979
Royalties
Crown 7,796 3,854 102 264
Other 1,371 842 63 142
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Total royalties 9,167 4,696 95 406
---------------------------------------------------------------------
---------------------------------------------------------------------
Percentage of revenue (%)
Crown 18 24 (25) 27
Other 3 5 (40) 14
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Total 21 29 (28) 41
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---------------------------------------------------------------------


For the year ended December 31, 2004, royalties increased 95% to $9.2
million from $4.7 million in 2003 due to improved revenue received in
the year. As a percentage of revenue, royalties were 21% in 2004
compared to 29% a year ago. This decrease was a result of the purchase
of a farm-in based royalty in 2003, lower burdens attached to 2004
production additions, a gas cost allowance credit recorded in the second
quarter of 2004 and the effect of hedging gains realized in the year.



Operating Expenses

---------------------------------------------------------------------
Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
($000s) (%)

Operating expense 7,984 5,521 45 195
Operating expense ($/boe) 7.48 12.01 (38) 6.20
---------------------------------------------------------------------
---------------------------------------------------------------------


Operating expenses increased 45% to $8.0 million compared to $5.5
million in 2003 due to production growth offset by the lower per unit
costs in the period. On a per unit basis, operating costs decreased 38%
to $7.48/boe from $12.01/boe in 2003 due to lower processing fees
charged to Obed and Medicine Lodge production and lower cost production
from the Brooklyn and Archean properties.

In 2005, we anticipate operating expenses to increase in relation to the
growth in production. On a per unit basis, we expect Lightning
properties to follow the trend that was realized in the fourth quarter
of 2004 of $7.02/boe.



General and Administrative Expenses (G&A)

---------------------------------------------------------------------
Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
($000s) (%)

G&A expenses (gross) 5,870 1,819 223 862
G&A non-cash items
Stock-based compensation 2,691 240 1021 --
Litigation settlement 1,448 -- -- --
G&A capitalized (1,344) (748) 80 (423)
G&A recoveries (564) (405) 39 (23)
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G&A expenses (net) 8,101 906 794 416
---------------------------------------------------------------------
---------------------------------------------------------------------
G&A expenses ($/boe) 7.59 1.97 285 13.21
---------------------------------------------------------------------
---------------------------------------------------------------------


Gross G&A expenses rose 223% to $5.9 million versus $1.8 million in
2003. On a per boe basis, this reflects an increase of 39% to $5.50/boe
from $3.96/boe incurred in 2003. Included in this change are $1.2
million in finance fees for the term facility obtained to support the
purchase of Archean. After removing these one-time charges, gross G&A
expense increased 11% to $4.38/boe reflecting the administration
requirements that followed our growth over the past year as well as the
costs of entering the public market.

The non-cash item of stock-based compensation expense increased to $2.7
million from $0.2 million in 2003 due to the amortization of the vested
portion of the fair value of options granted, as determined by using the
Black-Scholes option valuation model. The non-cash litigation settlement
item involved the value of property transferred to a third party to
clear a statement of claim made upon our Company during the acquisition
of Archean. Capitalized G&A for the period increased 80% to $1.3 million
from $0.7 million in 2003. This increase reflected the growth in
exploration staff since 2003. G&A recoveries for 2004 remained
relatively unchanged, reflecting the similar balance of capital
expenditures incurred in 2003.

In summary, net G&A expenses for the year ended December 31, 2004
increased 794% to $8.1 million from $0.9 million a year ago due to the
general growth in Company activities, bank commitment fees and the
increase in the stock-based compensation recorded during the year. In
2005, we expect G&A to decrease on an absolute and on a per boe basis as
such costs will exclude these non-routine expenses previously discussed.

Interest Income and Expense

Interest income totaled $0.1 million compared to $0.2 million received
in 2003. This 50% reduction reflected the lower balance of cash on
deposit in the year.

Interest expense in 2004 was $1.5 million versus $0.3 million in 2003.
The 400% year-over-year increase was a result of the increased draw on
our expanded revolving line of credit and a short-term loan required to
support the acquisition of Archean. In addition, the capital lease
associated with the Obed compressor was in place for a full year in 2004
compared to only half the year in 2003.

Current Taxes

During 2004, current and large corporations tax increased to $0.4
million versus $0.1 million recorded in 2003. The 300% increase was
directly attributable to the year-over-year increase in our
capitalization, which included equity raised in May and November 2004
and the purchases of Brooklyn and Archean during the year.

In 2005, we expect current and large corporations tax will increase in
relation to the expansion of our Company.



Cash Flow and Netbacks

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Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
($/boe) (%)

Sales prices 40.90 34.95 17 31.10
Royalties (8.59) (10.22) (16) (12.91)
Operating (7.48) (12.01) (38) (6.20)
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Operating netback 24.83 12.72 95 11.99
G&A (net of non-cash items) (3.71) (1.45) 156 (13.21)
Interest and taxes (1.71) (0.37) 362 5.98
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Corporate netback 19.41 10.90 78 4.76
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Cash flow from operations ($000s) 20,714 5,010 313 150
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This MD&A refers to cash flow from operations and operating netback,
terms that do not have a standardized measuring prescribed by GAAP.
Management believes that in addition to net income, cash flow from
operations and operating netback are useful supplemental measures as
they demonstrate our ability to generate the cash necessary to repay
debt or fund future growth through capital investment. Investors are
cautioned, however, that these measures should not be construed as an
alternative to net income determined in accordance with GAAP as an
indication of our performance. Our method of calculating these measures
may differ from other companies, and accordingly, may not be comparable
to measures used by other companies. For these purposes, we define cash
flow from operations as cash provided by operations before changes in
non-cash operating working capital and define operating netback as
revenue less royalties and operating expenses.

During the year ended December 31, 2004, cash flow from operations
increased 313% to $20.7 million or $0.59/share from $5.0 million or
$0.26/share in 2003. This change was primarily due to the 132% increase
in production. On a cash netback basis, cash flow increased 78% to
$19.41/boe due to a 17% increase in the average equivalent sales price
received to $40.90/boe, a 16% decrease in royalty costs to $8.59/boe and
a 38% decrease in operating costs to $7.48/boe.



Depletion, Depreciation and Accretion (DD&A)

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Years Ended December 31, 2004 2003 Change 2002
---------------------------------------------------------------------
(%)

DD&A provision ($000s) 18,600 5,424 243 183
DD&A provision ($/boe) 17.43 11.80 48 5.83
---------------------------------------------------------------------
---------------------------------------------------------------------


The DD&A provision increased 243% to $18.6 million in 2004 from $5.4
million recorded in 2003, reflecting the cost associated with the
year-over-year increase in production. On a per boe basis, DD&A grew to
$17.43/boe from $11.80/boe a year ago reflecting the purchase of the
Brooklyn and Archean assets at fair market value, the effect of new
asset retirement accounting rules and the discontinuation of a number of
prospects in the period. In the final quarter of 2004, we recorded DD&A
at $19.36/boe.

Future Taxes

A future tax recovery of $0.3 million was recognized in 2004 versus a
$0.1 million expense recorded a year ago. This non-cash item is the
anticipated future tax effect of the period's activity, after
reconciling recorded assets with our tax pool assets at the end of the
period.

Net Earnings

For the year ended December 31, 2004, we recorded a net loss of $1.7
million or $0.05/share compared to the restated net loss of $0.8 million
or $0.04/share in 2003. Although we recorded higher revenue and lower
royalties and operating expenses relative to sales, increased general
and administration and depletion expenses resulted in increased net
losses over those recorded in 2003. Included in the net earnings for the
periods were the effects of the new accounting requirements for
stock-based compensation adopted in 2003, asset retirement obligations
adopted in 2004 and the effects of the Brooklyn and Archean acquisitions.

Tax Pools

The following table summarizes our estimated tax pool balance by
classification as at December 31, 2004, 2003 and 2002:



---------------------------------------------------------------------
Maximum
Years Ended December 31, 2004 2003 2002 Deduction
---------------------------------------------------------------------
($000s) (%)

Canadian exploration expenses 18,483 7,188 710 100
Canadian development expenses 23,701 3,496 -- 30
Canadian oil and gas property
expenses 24,143 8,140 820 10
Undepreciated capital costs 27,272 13,319 1,497 25
Share issue costs and other 6,630 1,550 11 20
---------------------------------------------------------------------
Total tax pools 100,229 33,693 3,038 --
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Liquidity and Capital Resources

Working Capital

The following table summarizes the continuity of working capital
activity over the past three fiscal years:

---------------------------------------------------------------------
Years Ended December 31, 2004 2003 2002
---------------------------------------------------------------------
($000s)

Working capital (deficiency),
beginning of year 7,631 14,630 6,613
Cash flow from operations 20,714 5,010 150
Issue of capital stock (net) 40,919 30,396 20,349
Capital expenditures (42,296) (48,442) (12,482)
Cash paid on business combination (23,525) -- --
Cash paid on asset purchase (79,960) -- --
Working capital deficiency assumed on
business combination (7,719) -- --
Working capital deficiency assumed on
asset purchase (14,741) -- --
Proceeds on asset disposition 45,268 3,000 --
Capital lease obligations and other (644) 3,037 --
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Working capital (deficiency),
end of year (54,353) 7,631 14,630
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For the year ended December 31, 2004, we opened with working capital of
$7.6 million. Increases in the period involved cash flow from operations
of $20.7 million along with $40.9 million in additional equity received
from private placements made in May and November and options exercised
during the year. Finally, $45.3 million was injected into working
capital as a result of the property dispositions made in March and late
September. Decreases in working capital involved net capital
expenditures of $42.3 million, cash payments to close the purchase of
Brooklyn and Archean of $103.5 million and the assumption of a working
capital deficit from the purchases of $22.5 million. As a result, we
closed the year with a working capital deficit of $54.4 million.

Debt

During the year, bridge financing was arranged with a mezzanine lending
institution to support the purchase of Archean. As a result of the
subsequent sale of properties to a third party and the equity issue in
November, the balance of this term financing at December 31, 2004 was
retired. In conjunction with the purchase of Brooklyn and Archean and
the asset disposition, our credit facilities were increased to $75.0
million. The balance drawn on this demand loan facility at year-end
totaled $43.0 million. Our next review date on this facility is April 1,
2005.

Equity

On May 6, 2004 and May 17, 2004, respectively, we closed an equity
financing that included the issue of 3,750,000 special warrants and
1,000,000 flow-through common shares for net proceeds of $25.0 million.
In July 2004, these special warrants were converted to common shares
pursuant to a prospectus dated July 6, 2004. Under the terms of this
flow-through agreement, we are required to expend $6.6 million on
qualifying oil and gas expenditures prior to December 31, 2005. As at
December 31, 2004, we had incurred qualifying expenditures in the amount
of $2.8 million towards this commitment. We anticipate the balance of
this commitment will be expended in the first and second quarters of
2005. Cash flow from operations will fund these commitments. As of the
date of this report, in 2005 we have incurred an additional $1.3 million
in qualifying expenditures towards this commitment.

On November 30, 2004, we closed an equity financing that included the
issue of 2,250,000 common shares and 1,070,000 flow-through common
shares for net proceeds of $15.1 million. Under the terms of this
flow-through agreement, we are required to expend $6.0 million on
qualifying oil and gas expenditures prior to December 31, 2005. As at
December 31, 2004, no qualifying expenditures had been incurred under
the terms of the agreement. We anticipate this commitment will be
expended in the second and third quarters of 2005. Cash flow from
operations will fund these commitments.

The proceeds of these private placements were used to fund the purchase
of Brooklyn and pay off the temporary term loan used to finance the
Archean acquisition.

The following table is a summary of our share information as at the
periods indicated:



---------------------------------------------------------------------
February December December December
28, 2005 31, 2004 31, 2003 31, 2002
---------------------------------------------------------------------
(000s)

Common shares 45,093 45,093 17,464 17,464
Special purchase warrants -- -- 6,581 --
Flow-through special warrants -- -- 1,200 --
---------------------------------------------------------------------
Total shares outstanding 45,093 45,093 25,245 17,464
---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted average common shares
outstanding
Basic -- 35,377 19,190 13,555
Diluted -- 36,977 20,191 13,608
---------------------------------------------------------------------
---------------------------------------------------------------------
Common share purchase warrants
outstanding 4,000 4,000 2,630 2,630
---------------------------------------------------------------------
---------------------------------------------------------------------
Stock options outstanding 3,624 3,624 1,513 1,006
---------------------------------------------------------------------
---------------------------------------------------------------------


Off-Balance Sheet Arrangements

We have a number of normal course operating leases in place on vehicles,
office equipment and office space. These leases require periodic lease
payments and are recorded as general and administrative expenses.

Contractual Obligations

The following table summarizes the contractual obligations we have
committed to as at December 31, 2004:



---------------------------------------------------------------------
Maturity
----------------------------------------
Within Years Years After
1 Year 1 - 3 4 - 5 5 Years
---------------------------------------------------------------------
($000s)

Capital lease obligations 815 1,630 1,019 --
Operating and office lease 709 541 16 --
Flow-through share obligations 9,754 -- -- --
---------------------------------------------------------------------
---------------------------------------------------------------------


Related Party Transactions

During 2004, we paid $433,832 in legal costs to a law firm of which one
of our Directors is a partner. This compares to $35,286 paid in 2003.
These transactions were measured at market value rates.

Financial Instruments

On September 29, 2004, we entered into a natural gas financial costless
collar hedging arrangement. Under this arrangement, 5,000 GJ/d has been
hedged at a put price of CDN$7.00/GJ and a call price of CDN$9.15/GJ for
the period November 1, 2004 to March 31, 2005.

On October 7, 2004, we entered into a natural gas put option hedging
arrangement. Under this arrangement, 2,500 GJ/d has been hedged at a
price of CDN$8.50/GJ for a price of CDN$0.90/GJ for the period November
1, 2004 to March 31, 2005.

On October 22, 2004, we entered into a natural gas put option hedging
arrangement. Under this arrangement, 2,500 GJ/d has been hedged at a
strike price of CDN$9.10/GJ for a price of CDN$0.82/GJ for the period
November 1, 2004 to April 1, 2005.

On October 28, 2004, we entered into a natural gas fixed price swap
arrangement. Under this arrangement, 2,500 GJ/d has been sold at a
strike price of CDN$7.43/GJ for the period April 1, 2005 to October 31,
2005.

In addition to the previously described financial hedges, we enter into
firm physical swap arrangements, each of one-month duration, with a
purchaser of the Company's gas production. These arrangements
effectively convert the price on the portion of the sales volume to a
price based on the monthly AECO/NIT index from an average daily AECO/NIT
index, thereby improving the correlation between the physical revenue
and the floating price index used to settle the financial hedges noted
above.

The gain or loss realized on the hedge transactions noted above are
included in the 'oil and gas revenues' classification within the
statements of operations and deficit. The amount of the gain recorded in
2004 was $699,397. At December 31, 2004, we had unrealized
market-to-market hedging gains of $1,660,825.

Litigation and Contingent Liabilities

In September 2004, we were served with a statement of claim relating to
a lawsuit naming the Company as a defendant. In December 2004, this
litigation was settled with the exchange of our working interest in
three mineral leases and a wellbore. The $1.4 million value of this
settlement has been accounted for as a charge to general and
administration expense in the period.

Quarterly Financial Information

The operational and financial results of Lightning over the past eight
quarters are highlighted by aggressive capital programs, steady growth
in production volumes and continuous improvement in cash flow from
operations. During 2004, we expanded the production base by way of a
business combination with Brooklyn and the corporate acquisition of
Archean.

Production volumes per day, as a result of our capital program, business
combination and acquisitions, have increased from an average 516 boe/d
in the first quarter of 2003 to an average 4,084 boe/d in the fourth
quarter of 2004. Oil and liquid production improved from nil bbls/d in
the first quarter of 2003 to 678 bbls/d in the fourth quarter of 2004,
while natural gas production rose 558% from 3.1 mmcf/d in the first
quarter of 2003 to 20.4 mmcf/d in the fourth quarter of 2004.

The steady increase in production volumes in combination with strong but
volatile commodity prices over the past two years produced significant
growth in quarterly operating cash flow. Cash flow from operations
increased 630% from $1.0 million in the first quarter of 2003 to $7.3
million in the fourth quarter of 2004.

The Company's capital programs have been financed by internally
generated cash flow from operations, equity financings and bank debt.
During the past two years, the Company has issued 15.9 million common
shares and raised $70.4 million in three private placements of common
shares and flow-through common shares. In addition, 11.3 million common
shares were issued from treasury to complete the business combination
with Brooklyn. At the end of the fourth quarter of 2004, the Company had
a working capital deficit of $54.4 million that included bank debt of
$43.0 million.

The following table sets forth certain quarterly information of the
Company for the last two fiscal years:



---------------------------------------------------------------------
Quarters Ended Mar.31 Jun.30 Sep.30 Dec.31 Total
---------------------------------------------------------------------
($000s, except
per share data)

2004

Oil and gas
revenues 6,145 7,767 13,491 16,251 43,654
Cash flow from
operations 2,805 4,380 6,208 7,321 20,714
Per share - basic 0.11 0.14 0.15 0.17 0.59
Per share - diluted 0.10 0.13 0.14 0.17 0.56
Net earnings (loss) (215) 935 (995) (1,430) (1,705)
Per share - basic (0.01) 0.03 (0.02) (0.03) (0.05)
Per share - diluted (0.01) 0.03 (0.02) (0.03) (0.05)
Capital expenditures
(net) 16,535 5,947 10,754 9,060 42,296
Bank debt and
working capital
deficiency 9,134 14,283 66,046 54,353 54,353
Shareholders'
equity 49,746 133,248 134,034 149,678 149,678
Production
Oil and NGLs
(bbls/d) 103 179 627 678 398
Natural gas
(mmcf/d) 10.0 11.1 18.8 20.4 15.1
Total (boe/d) 1,763 2,029 3,766 4,084 2,916
---------------------------------------------------------------------
---------------------------------------------------------------------


---------------------------------------------------------------------
Quarters Ended Mar.31 Jun.30 Sep.30 Dec.31 Total
---------------------------------------------------------------------
($000s, except
per share data)

2003

Oil and gas
revenues 2,186 1,873 6,384 5,618 16,061
Cash flow from
operations 983 508 1,954 1,565 5,010
Per share - basic 0.06 0.03 0.11 0.06 0.26
Per share - diluted 0.06 0.03 0.11 0.05 0.25
Net earnings (loss) 281 163 (238) (1,001) (795)
Per share - basic 0.02 0.01 (0.01) (0.06) (0.04)
Per share - diluted 0.02 0.01 (0.01) (0.06) (0.04)
Capital expenditures
(net) 14,640 8,112 16,707 5,983 45,442
Bank debt and working
capital deficiency 953 3,284 18,190 7,631 7,631
Shareholders'
equity 21,743 21,928 21,781 49,722 49,722
Production
Oil and NGLs
(bbls/d) -- 5 165 68 60
Natural gas (mmcf/d) 3.1 3.2 11.1 11.2 7.2
Total (boe/d) 516 545 2,012 1,940 1,259
---------------------------------------------------------------------
---------------------------------------------------------------------


2004 Fourth Quarter

During the fourth quarter of 2004, production rose 2,144 boe/d to 4,084
boe/d from 1,940 boe/d recorded in the same quarter of 2003. This 111%
increase was primarily the result of the purchases of Brooklyn and
Archean made effective May 31 and August 31, 2004, respectively.

For the three-month period ended December 31, 2004, liquids prices
averaged $50.12/bbl and natural gas prices averaged $6.98/mcf compared
to $35.58/bbl and $5.22/mcf, respectively, received in 2003.

Revenue increased to $16.3 million for the fourth quarter of 2004 from
$5.6 million a year ago. This 191% improvement was due to the increase
in both production and prices received for the same period in 2003.
Included in this revenue are natural gas hedging gains of $0.7 million
and $0.1 million for 2004 and 2003, respectively.

Total royalties increased 169% to $3.5 million in the 2004 three-month
period from $1.3 million in 2003 due to increased revenue received for
the period. Total royalties, as a percentage of revenue, were 21% in the
fourth quarter versus 24% a year ago.

Operating expenses increased 18% to $2.6 million in the fourth quarter
of 2004 compared to $2.2 million in 2003 due to increased production
offset by a reduction in per unit costs in the period. On a per unit
basis, operating costs decreased 43% to $7.02/boe due to the benefit of
Brooklyn's and Archean's lower operating expense rate for the full
quarter plus decreased processing fees realized in the Obed and Medicine
Lodge areas versus that of the prior year.

Gross G&A expenses increased 257% to $2.5 million in the fourth quarter
of 2004 versus $0.7 million in the same period of 2003. On a per unit
basis, this reflects an increase of 84% to $6.71/boe from $3.65/boe
incurred in the same period in 2003. Included in this change are $0.8
million in financing fees for the term facility obtained to support the
purchase of Archean. After removing these one-time fees, gross G&A
expense increased 22% to $4.47/boe reflecting the administration
requirements that followed our growth during the period as well as the
cost of entering the public market.

Stock-based compensation expense, a non-cash item, increased to $1.4
million in the quarter. Included in net G&A expense was a non-cash
litigation settlement item in the amount of $1.4 million. This one-time
charge involved the value of property transferred to a third party to
clear a statement of claim made upon our Company during the acquisition
of Archean. In the three-month period ended December 31, 2004,
capitalized G&A increased 33% to $0.4 million compared to the $0.3
million incurred in 2003. G&A recoveries increased 155% in the period,
reflecting the year-over-year increase in drilling and completion
activity. In summary, net G&A expenses increased to $4.8 million in the
fourth quarter from $0.4 million in 2003.

Interest income in the fourth quarter of 2004 was $nil compared to $0.1
million in 2003, reflecting the balance of cash on deposit in the
respective periods. Interest expense in the 2004 three-month period
totaled $0.8 million versus $0.1 million a year ago.

Current and large corporations tax increased to $0.1 million for the
fourth quarter of 2004 compared to $0.1 million recorded during the same
period of 2003.

Cash flow from operations increased 356% to $7.3 million or $0.17/share
in the fourth quarter of 2004 from $1.6 million or $0.06/share recorded
in 2003. This change was the result of increases in production and
commodity prices along with reduced per unit royalty and operating cost
expenditures. On a per unit basis, cash flow decreased 122% to
$19.49/boe in the fourth quarter from $8.77/boe received in the same
period in 2003.

DD&A provision increased 170% to $7.3 million in the fourth quarter of
2004 from $2.7 million in 2003, reflecting the cost associated with the
increase in production. On a per boe basis, DD&A grew to $19.36 from
$14.92 a year ago reflecting the fair value of the Brooklyn and Archean
purchases, the effect of new asset retirement accounting rules and the
discontinuation of a number of prospects in the period.

Future tax recovery increased to $1.4 million in the three-month period
from a recovery of $0.2 million a year ago. The change in this non-cash
item is the anticipated future tax effect of the period's activity,
after reconciling recorded net assets with our tax pool assets at the
end of the period.

For the three months ended December 31, 2004, we recorded a net loss of
$1.4 million or $0.03/share compared to a restated net loss of $1.0
million or $0.06/share a year ago.

During the three-month period ended December 31, 2004, our capital
program totaled $7.6 million versus $6.0 million in the same period in
2003. Drilling and completions cost of $6.6 million was incurred as a
result of drilling 7 gross (2.6 net) wells. Equipment and facility
expenditures totaled $1.7 million, while geological and geophysical
costs were $0.2 million.

Critical Accounting Policies

The notes to the consolidated financial statements outline our
significant accounting policies. The policies discussed below are
considered particularly important as they require management to make
informed judgements, some of which may relate to matters that are
inherently uncertain.

Financial Statements and Use of Estimates

The financial statements have been prepared in accordance with Canadian
GAAP. In preparing financial statements, management makes certain
assumptions, judgements and estimates that affect the reported amounts
of assets, liabilities, revenues and expenses. The amounts recorded for
depletion and depreciation of petroleum and natural gas property, plant
and equipment and the provision for asset retirement obligations are
based on estimates. The cost recovery ceiling test is based on estimates
of proved reserves, production rates, petroleum and natural gas prices,
future costs and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the effect on the
financial statements of changes in such estimates in future periods
could be significant.

Accounting Reclassification and Restatement

Effective January 1, 2004 and consistent with the adoption of Canadian
Institute of Chartered Accountants (CICA) Handbook Section 1100
"Generally Accepted Accounting Principles", transportation costs are
included in operating costs in the statement of operations. Previously,
these costs were netted against revenue. This accounting
reclassification affected both revenue and operating costs by less than
1% of the reported balance.

In addition, as a result of adopting new accounting guidelines for asset
retirement obligations, certain information provided for the prior
periods has been reclassified or restated to conform to the presentation
required.

New Accounting Policies

There have been several changes in the financial reporting environment
in 2003 and 2004 that have impacted our Company. Canadian securities
regulators and the CICA are undertaking these measures to increase
investor confidence through increased transparency, consistency and
comparability of financial statements and financial information. As
well, the changes have been brought about by a goal of aligning Canadian
standards more closely with those in the United States.

We implemented the following new and amended standards in 2004 and their
impact is reflected in the 2003 financial statements:

Asset Retirement Obligations

In January 2004, we retroactively adopted the recommendations of the
CICA on accounting for asset retirement obligations. The new
pronouncement requires that we recognize the fair value of a liability
for an asset retirement obligation in the period in which it is incurred
and a corresponding increase in the carrying value of the related
long-lived asset. This increase is amortized using the unit of
production method based on estimated gross proven reserves as determined
by independent engineers.

Full Cost Accounting

In January 2004, we adopted the CICA's Accounting Guideline 16 "Oil and
Gas Accounting - Full Cost." In applying the new full cost guideline, we
calculate our ceiling test by comparing the carrying value of property
and equipment to the sum of undiscounted cash flows expected to result
from the future production of proved reserves and the sale of unproved
properties. Should the ceiling test result in an excess of carrying
value, we would then measure the amount of impairment by comparing the
carrying amounts of property and equipment to an amount equal to the
estimated net present value of future cash flows from proved plus
probable reserves and the sale of unproved properties. Any excess is
recorded as a permanent impairment. As a result of the adoption of this
guideline, there has been no impact on current financial statements. As
at December 31, 2004, the estimated sum of undiscounted cash flows
exceeded the carrying value of property and equipment by $20.3 million.

An acceptable alternative accounting policy to full cost accounting is
successful efforts accounting. Under this policy, capital expenditures
relating to unsuccessful projects are expensed to the income statement.
This policy was not chosen as it is not the standard for Canadian based
junior sized exploration and development companies. Successful efforts
accounting would not have affected the financial condition of our
Company but it may have changed the results of operations, and the
balance of property, plant and equipment. It would not have affected the
results of the ceiling test calculation.

Stock-Based Compensation

During the fourth quarter of 2003, we early adopted the new
recommendations of the CICA with respect to accounting for stock-based
compensation. We adopted this accounting policy prospectively without
restating the consolidated financial statements of prior periods. If we
had elected to apply this policy retroactively, the effect would have
been a $355,000 increase in our net general and administration expense
and net loss for the period. Under this policy, known as the "fair
value" method, we record a compensation expense to the financial
statements for granted share options. Prior to this policy change, we
elected to follow the "intrinsic value" method where no costs were
charged to income but were disclosed in a note to the consolidated
financial statements.

The effect of this change in accounting policy has resulted in an
increase in general and administration expense in the amount of $2.7
million for 2004, which caused an increase in the net loss and deficit
by the same amount. No future tax effect was incurred on this
transaction, as the expense is not deductible for corporate tax purposes.

Financial Instruments

During 2003, the CICA modified Accounting Guideline 13 ("AcG-13")
"Hedging Relationships," effective January 1, 2004, to clarify
circumstances in which hedge accounting is appropriate. For 2004, we
have elected to designate all of our current risk management activities
as accounting hedges under AcG-13 and will account for all gains and
losses in the same period as the hedged items. The impact on our
financial statements at January 1, 2005 was an unrecorded
market-to-market gain of $1,660,825 and a recorded hedging gain of
$699,397 as at December 31, 2004.

Critical Accounting Estimates

Under Canadian GAAP, a number of accounting estimates are required to
account and report on the operations of an oil and gas company. Critical
accounting estimates are discussed below.

Reserve Estimates and Value

The process of estimating reserves is complex. It requires significant
judgements and decisions based on available geological, geophysical,
engineering and economic data. These estimates may change substantially
as additional data from ongoing development activities and production
performance becomes available and as economic conditions affecting oil
and gas prices and costs change. The reserve estimates contained herein
are based on current production forecasts, prices and economic
conditions. Our reserves are evaluated by Gilbert Laustsen Jung
Associates Ltd., an independent engineering firm.

Although every reasonable effort is made to ensure that reserve
estimates are accurate, reserve estimation is an inferential science. As
a result, the subjective decisions, new geological or production
information and a changing environment may affect these estimates.
Revisions to reserve estimates can arise from changes in year-end oil
and gas prices and reservoir performance. Such revisions can be either
positive or negative.

In accordance with full cost accounting, capital costs associated with
developed or abandoned properties are charged to the income statement in
the form of a depletion and depreciation provision. This provision is a
direct function of the relative portion of reserves that have been
produced in the period. Accordingly, a 20% variance in the reserve
estimate will have a corresponding effect in the depletion and
depreciation provision for the period.

The final component of the consolidated financial statements affected by
the reserve estimation and value is the determination of the lower of
the carrying value or fair value of our developed asset base. This is
determined using a ceiling test analysis of the underlying asset base.
This test compares the cash flows expected from future production plus
the undeveloped capital asset base with the carrying value of property
and equipment. Where the net book value exceeds the fair value, a write
down of assets is the result. This reduces earnings before tax and
therefore affects the future tax provision based on our Company's tax
rate during the period. The net results flow directly to retained
earnings.

Undeveloped Capital Asset Base

In accordance with full cost accounting, the undeveloped capital asset
base remains on the balance sheet at cost and is not depleted. This
inventory of prospects assumes that the estimated future value of these
properties will equal or exceed the base. These costs represent the
accumulated costs on undeveloped lands and prospect costs in progress,
and as at December 31, 2004, these costs totaled $39.1 million.

During the course of our Company's growth, capital continues to be
invested in the prospects until they are considered uneconomic to be
continued or succeed as a developed property. In both cases, the costs
become part of the depletion base referred to above. This transfer may
increase or decrease the depletion provision and it may or may not cause
a ceiling test write down referred to in the reserve estimate notation.
The effect of the transfer is subject to the reserve additions made to
the base.

Useful Life of Depreciable Assets

In 2003, we constructed a gas compressor for use in the Obed property.
To finance the cost of the facilities, a sale lease back arrangement was
made with a financial institution. In line with reporting requirements,
this asset was depreciated over 70 months, the life of the lease. The
actual rate of depreciation is a function of the reserve base, discussed
above, the reserve life index and the actual useful life of the facility
itself.

Should it be determined that the reserves have a materially different
life than previously determined or that the facility depreciates at a
different rate than anticipated, the future depreciation provision may
also change on a material basis. This change will directly affect
earnings before tax and the future tax provision. The net effect of
these adjustments will flow directly to retained earnings.

Asset Retirement Obligation

Under current reporting requirements, we must determine the fair value
of the asset retirement obligation by estimating site reclamation costs,
inflating these costs to the estimated time of expenditure, then
discount this amount back to the reporting date. The primary estimate
involves determining the total of these future costs. The accuracy of
this amount is subject to a number of other unknown variables including
inflation, time, economics and location. Adjustments in the estimated
cost may materially affect the depletion and accretion provision charged
to the statement of operations and deficit before taxes by the same
amount. Future taxes will be the effective tax rate applied to this
adjustment. The net of the depletion and accretion adjustment and the
offsetting tax provision effect will directly change earnings and
retained earnings by the same amount.

Future Income Tax Rate

Due to the difference between accounting and tax regulations, a timing
of deductions results in arriving at the tax expense of a company. This
timing and tax rate estimations gives rise to a future tax provision
recorded to the statement of operations and deficit, offset by a future
tax liability or receivable on the balance sheet.

In order to determine this provision, the tax rates of future taxation
periods must be estimated. Typically, the rate used corresponds to the
current taxation year being examined. From time to time, these rates
change as prescribed by the Canada Revenue Agency. Accordingly, during
the remaining life of a company, the liability shown on the balance
sheet may materially differ from that reported in the financial
statements of the company.

Stock-Based Compensation

In 2003, we early adopted the recommendations of the CICA with respect
to accounting for stock-based compensation. Under this directive, the
fair value of options granted is charged to operations in the period.

To determine the amount of the adjustment, the fair value of each option
granted was estimated on the date of grant using the Black-Scholes
option pricing model. This model required the estimation of the hold
period prior to the exercise of our Company stock as well as the
volatility in the price of our Company's shares. A significant
adjustment in either assumption may materially affect general and
administration expense, earnings before tax, net earnings and retained
earnings by the same amount.

Business Risks and Risk Mitigation

Our operations are subject to risks normally associated with the
exploration, development, production and marketing of oil and natural
gas. The most important of these risks are set out below, together with
the strategies we employ to mitigate and minimize these risks.

Inherent Industry Risks - Risk of Failing to Discover Economic Reserve
Additions

Our strategies include focusing on gas prone selected areas in Western
Canada, utilizing a team of highly qualified professionals with
expertise and experience in these areas, expanding operations in core
areas, continuously assessing new exploration opportunities to
complement existing activities and striving for a balance between deep,
high cost, sulphur prone areas and shallow, low cost, dry gas areas of
interest.

Financial Risk - Commodity Price Risk and Capital Expenditures Risk

Commodity prices are driven by supply, demand and market conditions
outside our influence and control. We manage this risk by constantly
monitoring the forecasted price given by aggregators. In addition, from
time to time we will employ a commodity hedging program that has a
primary goal of minimizing significant downward movements in commodity
prices. At December 31, 2004, we had four hedging contracts in place.
Capital expenditures are a controllable risk and include cost control of
individual capital items and the tracking of cumulative capital
expenditures throughout the budget period. We manage capital
expenditures by two separate tracking systems: a historical accounting
system that records the actual costs and a perpetual forecasting model
that is constantly updated based on real time information.

It is likely that in the future we will be required to raise additional
capital through debt and equity financings in order to fully realize our
strategic goals and business plans. Our ability to raise additional
capital will depend on a number of factors, such as general economic and
market conditions that are beyond our control. If we are unable to
obtain additional financing or to obtain it on favourable terms, we may
be required to forego attractive business opportunities. We are
committed to maintaining a strong balance sheet combined with a flexible
capital expenditure program that can be adjusted to capitalize on or
reflect acquisition opportunities or a tightening of liquidity sources
if necessary.

We manage operational risks by employing skilled professionals utilizing
leading-edge technology and conducting regular maintenance and training
programs. We have an operational emergency response plan and an
operational safety manual is currently being prepared. In addition, a
comprehensive insurance program is maintained to mitigate risks and
protect against significant losses where possible.

We operate in accordance with all applicable environmental legislation.
We strive to maintain compliance with such regulations.

Sensitivities

The table below indicates the impact of changes to key variables on our
cash flow.



---------------------------------------------------------------------
Variable
-------------------------------------------------------
Natural Gas Liquid Sales Canadian
---------------------------------- Prime Foreign
Price Volumes Price Volumes Rate Exchange
---------------------------------------------------------------------
(CDN$/mcf) (mmcf/d) (CDN$/bbl)(bbl/d) (%) (US$/CDN$)

Assumption
change (+/-) 0.10 0.6 1.00 100 1.00 0.05
---------------------------------------------------------------------
Cash flow from
operations
($000s) 668 1,085 686 1,339 628 4,539
Cash flow per
share
Basic 0.02 0.03 0.02 0.04 0.02 0.13
Diluted 0.02 0.03 0.02 0.04 0.02 0.12
---------------------------------------------------------------------
---------------------------------------------------------------------


SEDAR Filing

Effective June 1, 2004, Lightning became a Toronto Stock Exchange listed
company. As a result, additional information, including the Company's
Annual Information Form, is available on the Canadian Securities
Administrators' System for Electronic Document Analysis and Retrieval
(SEDAR) at www.sedar.com.



CONSOLIDATED BALANCE SHEETS

---------------------------------------------------------------------
As at December 31, 2004 2003
---------------------------------------------------------------------
($000s) (restated-note 3)

Assets
Current assets
Cash and cash equivalents -- 14,854
Accounts receivable and other 14,508 5,050
---------------------------------------------------------------------
14,508 19,904
Property and equipment (note 7) 178,263 56,213
Goodwill (notes 4, 5 and 6) 62,900 --
---------------------------------------------------------------------
255,671 76,117
---------------------------------------------------------------------
---------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable 25,220 11,667
Bank loan (note 10) 42,996 --
Current portion of capital lease
obligation (note 11) 645 606
---------------------------------------------------------------------
68,861 12,273
Capital lease obligation (note 11) 2,393 3,037
Asset retirement obligations (note 12) 6,579 3,895
Future income taxes (note 13) 28,160 7,190
---------------------------------------------------------------------
105,993 26,395
Shareholders' equity
Share capital (note 8) 149,451 50,373
Contributed surplus (note 9) 2,823 240
Deficit (2,596) (891)
---------------------------------------------------------------------
149,678 49,722
---------------------------------------------------------------------
255,671 76,117
---------------------------------------------------------------------
---------------------------------------------------------------------
Commitments (note 16)
Subsequent event (note 18)

See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

---------------------------------------------------------------------
Years Ended December 31, 2004 2003
---------------------------------------------------------------------
($000s, except per share data) (restated-note 3)

Revenue
Oil and gas revenues 43,654 16,061
Royalty expense, net of Alberta Royalty
Tax Credit (9,167) (4,696)
Interest revenue 98 228
---------------------------------------------------------------------
34,585 11,593
---------------------------------------------------------------------
Expenses
Operating 7,984 5,521
General and administrative 8,101 906
Interest on capital lease 209 119
Interest and bank charges 1,297 189
Depletion and depreciation 18,167 5,303
Accretion of asset retirement
obligations (note 12) 433 121
---------------------------------------------------------------------
36,191 12,159
---------------------------------------------------------------------
Loss before income taxes (1,606) (566)
---------------------------------------------------------------------
Income taxes
Current 419 88
Future (reduction) (note 13) (320) 141
---------------------------------------------------------------------
99 229
---------------------------------------------------------------------
Net loss (1,705) (795)
---------------------------------------------------------------------
---------------------------------------------------------------------
Deficit, beginning of year (693) (79)
Change in accounting policies (note 3) (198) (17)
---------------------------------------------------------------------
Deficit, beginning of year - restated (891) (96)
---------------------------------------------------------------------
Deficit, end of year (2,596) (891)
---------------------------------------------------------------------
---------------------------------------------------------------------
Net loss per share (note 8(d))
Basic (0.05) (0.04)
Diluted (0.05) (0.04)
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS

---------------------------------------------------------------------
Years Ended December 31, 2004 2003
---------------------------------------------------------------------
($000s) (restated-note 3)
Operating
Net loss (1,705) (795)
Items not involving cash
Depletion and deprecation 18,167 5,303
Accretion of asset retirement obligations 433 121
Future taxes (320) 141
Stock based compensation 2,691 240
Litigation settlement 1,448 --
---------------------------------------------------------------------
20,714 5,010
Change in non-cash working capital (3,198) 1,644
---------------------------------------------------------------------
17,516 6,654
---------------------------------------------------------------------
Financing
Capital lease payments (605) (357)
Demand loan 23,822 13,401
Demand loan repayment -- (13,401)
Term loan 50,000 --
Term loan repayment (50,000) --
Issue of share capital 43,435 32,324
Share issue costs (2,516) (1,928)
Proceeds from sale leaseback -- 4,000
Change in non-cash working capital -- 101
---------------------------------------------------------------------
64,136 34,140
---------------------------------------------------------------------
Investing
Property and equipment additions (44,296) (48,442)
Property disposition 2,000 3,000
Cash paid on business combination
and corporate purchase (notes 4, 5 and 6) (103,006) --
Disposition of property and equipment 45,268 --
Change in non-cash working capital 3,528 1,873
---------------------------------------------------------------------
(96,506) (43,569)
---------------------------------------------------------------------
Decrease in cash and cash equivalents (14,854) (2,775)
---------------------------------------------------------------------
Cash and cash equivalents
Beginning of year 14,854 17,629
End of year -- 14,854
---------------------------------------------------------------------
---------------------------------------------------------------------
Supplementary information
Interest received 179 203
Interest paid 1,439 372
Taxes paid 292 71
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2004 and 2003
(tabular information presented in 000s unless otherwise stated)


1. Nature of Operations

Lightning Energy Ltd. ("Lightning" or the "Company") is primarily
engaged in the exploration, development, production and marketing of oil
and gas in the Western Canadian Sedimentary Basin.

On May 31, 2004, the Company purchased all the outstanding common shares
of Brooklyn Energy Corporation, following which the two companies were
amalgamated.

On August 31, 2004, the Company purchased all the outstanding common
shares of Archean Oil & Gas Ltd. On December 31, 2004 this company was
amalgamated with Lightning.

2. Significant Accounting Policies

(a) Basis of Presentation

The consolidated financial statements of the Company have been prepared
in accordance with Canadian generally accepted accounting principles
within the framework of the accounting policies summarized below.

Consolidation

The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries from the respective dates of
acquisition. All inter-company transactions and balances are eliminated
upon consolidation.

(b) Measurement Uncertainty

The amounts recorded for depletion and depreciation of petroleum and
natural gas property, plant and equipment and the provision for asset
retirement obligations are based on estimates. The cost recovery ceiling
test is based on estimates of proved reserves, production rates,
petroleum and natural gas prices, future costs and other relevant
assumptions. By their nature, these estimates are subject to measurement
uncertainty and the effect on the financial statements of changes in
such estimates in future periods could be significant.

(c) Cash and Cash Equivalents

The Company considers deposits in banks, certificates of deposit and
short-term investments with original maturities of three months or less
as cash and cash equivalents. Bank borrowings are considered to be
financing activities.

(d) Property and Equipment

The Company follows the full cost method of accounting for petroleum and
natural gas operations, whereby all costs related to the acquisition,
exploration and development of petroleum and natural gas reserves are
capitalized. Such costs include lease acquisition costs, geological and
geophysical costs, carrying charges of non-producing properties, costs
of drilling both productive and non-productive wells, the cost of
petroleum and natural gas production equipment and overhead charges
related to exploration and development activities.

Petroleum and natural gas assets are evaluated at least annually to
determine that the costs are recoverable and do not exceed the fair
value of the properties. The costs are assessed to be recoverable if the
sum of the undiscounted cash flows expected from the production of
proved reserves and the lower of cost and market of unproved properties
exceed the carrying value of the petroleum and natural gas assets. If
the carrying value of the petroleum and natural gas assets is not
assessed to be recoverable, an impairment loss is recognized to the
extent that the carrying value exceeds the sum of the discounted cash
flows expected from the production of proved and probable reserves and
the lower of cost and market of unproved properties. The cash flows are
estimated using the future product prices and costs and are discounted
using the risk-free rate.

Proceeds from the disposition of petroleum and natural gas properties
are applied against capitalized costs except for dispositions that would
change the rate of depletion and depreciation by 20% or more, in which
case a gain or loss would be recorded.

Depletion and Depreciation

Capitalized costs, together with estimated future capital costs
associated with proven reserves, are depleted and depreciated using the
unit-of-production method based on estimated gross proven reserves of
petroleum and natural gas as determined by independent engineers. For
purposes of this calculation, reserves and production are converted to
equivalent units of oil based on relative energy content of six thousand
cubic feet of gas to one barrel of oil. Costs of significant unproven
properties, net of impairments, are excluded from the depletion and
depreciation calculation.

Other assets, which is comprised of office equipment and furniture and
fixtures, are recorded at cost and are depreciated over their useful
life on a declining balance basis at rates ranging from 25% to 50%.

(e) Interest in Joint Ventures

Substantially all of the Company's oil and gas exploration and
development activities are conducted jointly with others, and
accordingly, the financial statements reflect only the Company's
proportionate interest in such activities.

(f) Asset Retirement Obligations

An asset retirement obligation is recorded as a liability in the period
in which a legal obligation is incurred as a result of an acquisition,
construction, development and/or normal use of the assets.

The associated asset retirement costs are capitalized as part of the
carrying amount of the long-lived asset and depleted and depreciated
using a unit-of-production method over the estimated gross proved
reserves. Subsequent to the initial measurement of the asset retirement
obligations, the obligations are adjusted at the end of each period to
reflect the passage of time and changes in the estimated future cash
flows underlying the obligation.

(g) Flow-Through Shares

The resource expenditure deductions for income tax purposes related to
exploratory and development activities funded by flow-through share
arrangements are renounced to investors in accordance with tax
legislation. Future tax liabilities and share capital are adjusted by
the estimated cost of the tax deductions when the expenditures are
renounced.

(h) Foreign Currency Translation

Monetary items denominated in foreign currency are translated to
Canadian dollars at the rate in effect at the balance sheet date, and
non-monetary items are translated at rates of exchange in effect when
the assets were acquired or obligations incurred. Revenue and expenses
are translated at rates in effect at the time of the transactions.
Foreign exchange gains and losses are included in income.

(i) Income Taxes

The Company uses the liability method of accounting for income taxes.
Under this method, future tax assets and liabilities are recognized for
the future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and liabilities
and their respective tax bases. Future tax assets and liabilities are
measured using enacted or substantively enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on
future tax assets and liabilities of a change in tax rates is recognized
in income in the period that includes the date of enactment or
substantive enactment.

(j) Goodwill

Goodwill, at the time of acquisition, represents the excess of purchase
price of a business over the fair value of net assets acquired.
Thereafter, goodwill is assessed by the Company for impairment in the
fourth quarter of each year. If the fair value of the business is less
than the book value, a second test is performed to determine the amount
of the impairment. The amount of the impairment is determined by
deducting the fair value of the business' assets and liabilities from
the fair value of the business to determine the implied fair value of
goodwill and comparing that amount to the book value of goodwill. Any
excess of the book value of goodwill over the implied fair value is the
impairment amount and will be charged to income in the period of the
impairment.

(k) Per Share Information

Per share information is calculated on the basis of the weighted average
number of common shares outstanding during the fiscal year. Diluted per
share information reflects the potential dilution that could occur if
securities or other contracts to issue common shares were exercised or
converted to common shares. Diluted per share information is calculated
using the treasury stock method that assumes any proceeds received by
the Company upon the exercise of in-the-money stock options plus the
unamortized stock compensation cost would be used to buy back common
shares at the average market price for the period.

(l) Stock-Based Compensation Plans

The Company has one stock-based compensation plan described in detail in
note 9. The fair value for each stock option granted is estimated on the
date of the grant using the modified Black-Scholes option pricing model.
These fair value costs are recognized in general and administrative
expenses with a corresponding increase to contributed surplus over the
vesting period of the grant. As the options are exercised, the
consideration paid together with the amount previously recognized in
contributed surplus is recorded as an increase to share capital.

(m) Financial Instruments

Financial instruments consist primarily of accounts receivable and
other, accounts payable, bank and term loans and capital lease
obligations. There are no significant differences between the carrying
value of these financial instruments and their estimated fair value.

The Company uses financial instruments for non-trading purposes to
manage fluctuations in commodity prices, as described in note 17. Hedge
accounting is used when there is a high degree of correlation between
price movements in the financial instrument and the item designated as
being hedged. Gains and losses are recognized in the same period as the
hedged item. If correlation ceases, hedge accounting is terminated and
future changes in the market value of the financial instrument are
recognized as gains or losses in the period.

(n) Revenue Recognition

Crude oil and natural gas revenues are recognized in earnings when title
passes from the Company to its customer.

(o) Comparative Figures

Certain prior period balances have been reclassified to conform to the
current period's presentation.

3. Changes in Accounting Policies

(a) Asset Retirement Obligations

Effective January 1, 2004, the Company adopted the new Canadian
accounting standard for asset retirement obligations. The effect of this
change in accounting policy has been recorded retroactively with
restatement of prior periods. The effect of the adoption is presented
below as increases (decreases).



------------------------------------------------------------------------
As at December 31, 2003
------------------------------------------------------------------------
($000s)
Balance Sheet
Property and equipment 3,113
Asset retirement obligations 3,895
Future site restoration liability (460)
Future income taxes (124)
Deficit (198)
------------------------------------------------------------------------
Income Statement
Accretion expense 121
Depletion and depreciation on asset
retirement obligations 627
Future site restoration expense (455)
Future income taxes (112)
Net earnings impact (181)
Net loss per share - basic and diluted (0.01)
------------------------------------------------------------------------


(b) Stock-Based Compensation

During 2003, the Company early adopted the new Canadian accounting
standards with respect to accounting for stock-based compensation. Under
the transitional provisions of the standard, the Company is required to
record compensation expense in the statements of loss and deficit for
options issued on or after January 1, 2003. As a result of the
implementation of this amended standard, previously reported December
31, 2003 amounts have been restated to give effect of the standard as at
January 1, 2003.

(c) Petroleum and Natural Gas Interest ("P&NG")

Effective January 1, 2004, the Company adopted new Canadian accounting
guidelines for full cost accounting that modifies how impairment is
tested. Impairment is recognized if the carrying amount of the P&NG
assets exceeds the sum of the undiscounted cash flows expected to result
from the Company's proved reserves plus the cost of unproved properties.

Previously, impairment was tested based on undiscounted future net
revenues using proved reserves at constant prices and costs and
providing for future general and administrative expenses, carrying costs
and income taxes. The adoption of the new guideline had no effect on the
Company's financial position and the results of operations.

(d) Financial Instruments

In 2004, in accordance with new Canadian accounting standards, the
Company has elected to designate all of its current risk management
activities as accounting hedges and will account for all gains and
losses in the same period as the hedged items.

4. Acquisition of Brooklyn Energy Corporation

On March 30, 2004, the Company entered into an agreement with Brooklyn
Energy Corporation ("Brooklyn"), a company primarily engaged in the
exploration, development and production of oil and gas, to effect a
business combination and create a new public company. On May 31, 2004,
the transaction was approved by the shareholders of Brooklyn and the
Court of Queen's Bench of Alberta. To close this transaction, 11,273,508
shares of the Company were issued from treasury and a cash payment of
$22,766,919 was made to the shareholders of Brooklyn. Costs of $757,748
were required to complete the transaction. The acquisition was accounted
for using the purchase method. For purposes of the purchase price
equation, the Company used an adjusted share price of $5.00 per share.
The results of operations of the Company include those of Brooklyn
effective May 31, 2004, the closing date of the business combination.
The purchase price equation is as follows:



---------------------------------------------------------------------
($000s)
Cost of acquisition
Common shares issued 56,368
---------------------------------------------------------------------
Cash consideration (including transaction costs of $758) 23,525
---------------------------------------------------------------------
79,893
---------------------------------------------------------------------
---------------------------------------------------------------------
Allocated
Accounts receivable and other assets 5,666
Property and equipment 60,525
Goodwill 33,700
Accounts payable (9,360)
Bank loan (4,025)
Asset retirement obligation (1,209)
Future income taxes (5,404)
---------------------------------------------------------------------
79,893
---------------------------------------------------------------------
---------------------------------------------------------------------


5. Acquisition of Archean Oil & Gas Ltd.

On August 16, 2004, the Company entered into a share purchase agreement
with Archean Oil & Gas Ltd. ("Archean"), a company primarily engaged in
the exploration, development and production of oil and gas. On August
31, 2004, this transaction was closed for $79,417,329 in cash, the
assumption of $15,149,011 in debt and transaction costs of $542,192. The
results of operations of the Company include those of Archean effective
August 31, 2004, the closing date of the purchase. The acquisition was
accounted for using the purchase method, the effect of which is as
follows:



---------------------------------------------------------------------
($000s)
Cost of acquisition
Cash consideration (including transaction costs of $542) 79,960
---------------------------------------------------------------------
---------------------------------------------------------------------
Allocated
Cash 479
Accounts receivable and other assets 3,695
Property and equipment 87,697
Goodwill 33,436
Accounts payable (3,766)
Bank loan (15,149)
Asset retirement obligation (5,427)
Future income taxes (21,005)
---------------------------------------------------------------------
79,960
---------------------------------------------------------------------
---------------------------------------------------------------------


6. Property Disposition

On September 17, 2004, the Company entered into a purchase and sale
agreement with a third party involving properties purchased from Archean
(see note 5). On September 30, 2004, this disposition closed for cash
consideration of $46,000,000 before adjustments. The effect of this
disposition is as follows:



---------------------------------------------------------------------
($000s)
Proceeds on disposition
Cash consideration
(less transaction costs and closing adjustments of $732) 45,268
---------------------------------------------------------------------
Allocated
Property and equipment (50,121)
Goodwill (4,236)
Asset retirement obligation 4,853
Future income taxes 4,236
---------------------------------------------------------------------
(45,268)
---------------------------------------------------------------------
---------------------------------------------------------------------


7. Property and Equipment
------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------------------------------------------
($000s)
2004
Exploration and development costs 157,302 16,430 140,872
Production equipment and facilities 44,253 7,102 37,151
Office equipment 353 113 240
------------------------------------------------------------------------
201,908 23,645 178,263
------------------------------------------------------------------------
2003 (restated-note 3)
Exploration and development costs 42,150 2,710 39,440
Production equipment and facilities 19,339 2,710 16,629
Office equipment 202 58 144
------------------------------------------------------------------------
61,691 5,478 56,213
------------------------------------------------------------------------
------------------------------------------------------------------------


For the year ended December 31, 2004, the Company capitalized indirect
general and administrative overhead costs of $1,343,698 (2003 -
$747,955) relating to exploration and development activity.

Unevaluated and undeveloped properties with a cost of $39,060,000
included in property and equipment have not been subject to depletion.
The unproved properties consist of $9,350,000 in land and related
seismic expenditures and $29,710,000 related to unproved exploration
projects in progress.

The future commodity prices used in the ceiling test prepared on initial
adoption were based on December 31, 2004 commodity price forecasts of
the Company's independent reserve engineers adjusted for differentials
specific to the Company's reserves. The following table summarizes the
future benchmark prices the Company used in the ceiling test:



------------------------------------------------------------------------
Crude Oil Natural Gas
------------------------------------------------------------------------
West Texas Edmonton AECO Gas Spec
Intermediate Par Price Price Ethane
------------------------------------------------------------------------
(CDN$/bbl)(1) (CDN$/bbl) (CDN$/mmbtu) (CDN$/bbl)
2005 51.22 50.25 6.60 22.00
2006 48.78 47.75 6.35 21.25
2007 46.34 45.50 6.15 20.50
2008 43.90 43.25 6.00 20.00
2009 41.46 40.75 6.00 20.00
2010 40.24 39.50 6.00 20.00
2011 40.24 39.50 6.00 20.00
2012 40.24 39.50 6.00 20.00
2013 40.85 40.00 6.10 20.25
2014 41.46 40.75 6.20 20.75
2015 42.07 41.25 6.30 21.00
Thereafter(2) 2.00% 2.00% 2.00% 2.00%
------------------------------------------------------------------------

------------------------------------------------------------------------
Natural Gas Liquids
------------------------------------------------------------------------
Edmonton Edmonton Edmonton
Propane Butane Pentanes
------------------------------------------------------------------------
(CDN$/bbl) (CDN$/bbl) (CDN$/bbl)
2005 32.25 37.25 50.75
2006 30.50 35.25 48.25
2007 29.00 33.75 46.00
2008 27.75 32.00 43.75
2009 26.00 30.25 41.25
2010 25.25 29.25 40.00
2011 25.25 29.25 40.00
2012 25.25 29.25 40.00
2013 25.50 29.50 40.50
2014 26.00 30.25 41.25
2015 26.50 30.50 41.75
Thereafter(2) 2.00% 2.00% 2.00%
------------------------------------------------------------------------

(1) Future prices incorporated a $0.82 US/CDN exchange rate.

(2) Percentage change of 2.00% represents the change in future prices
each year after 2015 to the end of the reserve life.


8. Share Capital

(a) Authorized
Unlimited number of common shares, without par value.

(b) Issued and Outstanding

---------------------------------------------------------------------
Years Ended December 31, 2004 2003
---------------------------------------
Shares Amount Shares Amount
---------------------------------------------------------------------
(000s) (#) ($) (#) ($)

Common Shares
Balance, beginning of year 17,464 21,545 17,464 21,545
Warrants converted
Special purchase 11,531 47,889 -- --
Common shares 130 130 -- --
Business combination (note 4) 11,273 56,368 -- --
Options exercised 374 825 -- --
Private placement
Flow-through shares 2,070 12,592 -- --
Common shares 2,250 10,013 -- --
Share issue costs -- (1,268) -- --
Tax benefit of issue costs -- 449 -- --
Stock based compensation
Options exercised -- 108 -- --
---------------------------------------------------------------------
Balance, end of year 45,092 148,651 17,464 21,545
---------------------------------------------------------------------
---------------------------------------------------------------------


On May 17, 2004, the Company closed the private placement of 1,000,000
flow-through common shares for cash proceeds of $6,600,000. Under the
terms of these flow-through shares, the Company is required to expend
$6,600,000 on qualifying oil and gas expenditures prior to December 31,
2005. As at December 31, 2004, the Company had incurred approximately
$2,800,000 of the qualifying expenditures as required under the terms of
the agreement.

On November 30, 2004, the Company closed the private placement of
2,250,000 common shares and 1,070,000 flow-through common shares for
total gross cash proceeds of $16,004,500. Under the terms of the
flow-through shares, the Company is required to expend $5,992,000 on
qualifying oil and gas expenditures prior to December 31, 2005. As at
December 31, 2004, no qualifying expenditures had been incurred under
the terms of the agreement.



---------------------------------------------------------------------
Years Ended December 31, 2004 2003
---------------------------------------
Shares Amount Shares Amount
---------------------------------------------------------------------
(000s) (#) ($) (#) ($)

Warrants
Balance, beginning of year 7,781 28,828 -- --
Private placement of special
Purchase warrants 3,750 19,875 6,581 26,324
Flow-through warrants -- -- 1,200 6,000
Tax on flow-through -- -- -- (2,310)
Share issue costs -- (1,248) -- (1,928)
Tax benefit of issue costs -- 434 -- 742
Purchase warrants exercised (11,531) (47,889) -- --
---------------------------------------------------------------------
Balance, end of year, before: -- -- 7,781 28,828
Common share purchase warrants -- 800 -- --
---------------------------------------------------------------------
---------------------------------------------------------------------
Total share capital 45,092 149,451 25,245 50,373
---------------------------------------------------------------------
---------------------------------------------------------------------


On May 6, 2004, the Company closed the private placement of 3,750,000
special warrants for cash proceeds of $19,875,000. On July 6, 2004, the
Company filed a final prospectus with the Alberta Securities Commission
qualifying the issuance of common shares on the exercise of these
special warrants.

On May 31, 2004, the Company closed the purchase of Brooklyn. As a
result of this transaction, the 7,781,000 special warrants issued in
October 2003 were qualified for the issuance of common shares on a
one-to-one basis.



(c) Common Share Purchase Warrants

Common share purchase warrants have been issued as set out below.

---------------------------------------------------------------------
Years Ended December 31, 2004 2003
-----------------------------------------
Weighted Weighted
Average Average
Purchase Exercise Purchase Exercise
Warrants Price Warrants Price
---------------------------------------------------------------------
(000s) ($) (000s) ($)

Balance, beginning of year 2,630 1.95 2,630 1.95
Warrants issued 1,500 6.00 -- --
Warrants exercised (130) 1.00 -- --
---------------------------------------------------------------------
Balance, end of year 4,000 3.50 2,630 1.95
---------------------------------------------------------------------
---------------------------------------------------------------------

All warrants expire between December 31, 2006 and April 22, 2007.

(d) Per Share Amounts
------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
(000s)

Weighted average shares outstanding
Basic 35,377 19,190
Shares issued pursuant to options 236 231
Shares issued pursuant to warrants 1,364 770
------------------------------------------------------------------------
36,977 20,191
------------------------------------------------------------------------
------------------------------------------------------------------------


In calculating diluted common share amounts for the year ended December
31, 2004 (2003 - nil), the Company excluded 60,000 options and 1,500,000
warrants because the exercise price was greater than the average market
price of its common shares.

In 2004 and 2003, loss per share calculated on a diluted weighted
average basis, is the same as that presented for basic, as all factors
are anti-dilutive.

9. Stock-Based Compensation Plans

The Company grants stock options to its directors, officers and
employees. The Board has a policy of reserving up to 10% of the
outstanding common shares for issuance to eligible participants. At
December 31, 2004, there were 3,938,968 (2003 - 2,524,450) common shares
reserved for this purpose.

At December 31, 2004, 3,623,500 (2003 - 1,513,000) options with exercise
prices between $2.00 and $5.30 were outstanding and exercisable at
various dates to June 30, 2009. The exercise price of each option
equaled the estimated market price of the Company's common shares on the
date of the grant. The vesting period of each option ranges from
immediate to evenly over three years from the date of grant. The term
period of each option ranges from four to five years from the date of
grant.

The following table summarizes the information about the share options
as at December 31, 2004 and 2003:



------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
Weighted Weighted
Average Average
Share Exercise Share Exercise
Options Price Options Price
------------------------------------------------------------------------
(000s) ($) (000s) ($)
Outstanding, beginning
of year 1,513 2.42 1,006 2.19
Granted 2,626 4.21 682 2.71
Exercised (374) 2.20 -- --
Cancelled (141) 3.06 (175) 2.21
------------------------------------------------------------------------
Outstanding,
end of year 3,624 3.72 1,513 2.42
------------------------------------------------------------------------
Exercisable,
end of year 1,069 3.25 466 2.11
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------------------------------------------------------------

Weighted Weighted
Weighted Average Weighted Average
Range of Number Average Remaining Average Remaining
Exercise of Exercise Contractual Number of Exercise Contractual
Prices Options Price Life Options Price Life
------------------------------------------------------------------------
($) (000s) ($) (years) (000s) ($) (years)
2004
2.00 295 2.00 2.5 295 2.00 2.5
2.50 656 2.50 3.4 222 2.50 3.3
4.00 594 4.00 4.1 182 4.00 4.1
4.15 1,149 4.15 4.5 -- -- --
4.34 870 4.34 4.0 370 4.34 4.0
5.30 60 5.30 4.3 -- -- --
------------------------------------------------------------------------
Total 3,624 3.72 3.9 1,069 3.25 3.4
------------------------------------------------------------------------
------------------------------------------------------------------------


The weighted average fair market value of options granted during the
year ended December 31, 2004 was $2.72 (2003 - $2.00) per option. The
fair value of each option granted was estimated on the date of grant
using the Black-Scholes option pricing model with the following
assumptions:



------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
Risk free interest rate (%) 3.84 4.23
Estimated hold period prior to exercise (years) 4 5
Volatility in the price of the Company's
common shares (%) 87.32 94.90
------------------------------------------------------------------------


Prospectively from January 1, 2003, the Company has elected to follow
the fair value method of accounting for stock-based compensation
arrangements. Under this accounting policy, the compensation cost for
each stock option granted was estimated on the date of grant using the
modified Black-Scholes option pricing model.

Had the fair value method been applied for options granted prior to
January 1, 2003, the Company's net loss and net loss per share for the
years ended December 31 would have been increased to the pro-forma
amounts as follows:



Stock-Based Compensation Plans
------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
($000s, except per share data)
Net Loss
As reported 1,705 795
Less fair value of options 355 568
------------------------------------------------------------------------
Pro-forma 2,060 1,363
------------------------------------------------------------------------
------------------------------------------------------------------------
Net loss per common share - basic
As reported 0.05 0.04
Pro-forma 0.06 0.07
Net loss per common share - diluted
As reported 0.05 0.04
Pro-forma 0.06 0.07
------------------------------------------------------------------------

------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
($000s, except per share data)
Contributed Surplus
Balance, beginning of year 240 --
Stock-based compensation 2,691 240
Stock-based compensation on options exercised (108) --
------------------------------------------------------------------------
Balance, end of year 2,823 240
------------------------------------------------------------------------
------------------------------------------------------------------------


10. Revolving Demand and Term Loan

(a) The Company has a revolving line of credit of $75,000,000. This line
is secured by a general security agreement on all real property of the
Company and bears interest at the bank's prime lending rate. At December
31, 2004, the Company had drawn $42,995,561 from this line of credit.
The next review of this line of credit is April 1, 2005.

(b) In August 2004, the Company entered into a term debt facility to
assist in the financing of the Archean acquisition. The Company had
drawn 50,000,000 of this non-revolving secured facility and was retired
prior to December 31, 2004. The interest rate on this facility was the
bank's prime rate plus 3%.

11. Capital Leases

In June 2003, the Company entered into a capital lease arrangement with
a major lending institution, involving various gas processing equipment,
for an aggregate principal amount of $4,000,000. This facility requires
monthly lease payments of $67,928 over a period of 70 months. The
implicit rate of interest in the lease arrangement is 6.22%. After a
total of 48 lease payments had been made, a purchase option of
$1,400,000 exists. At December 31, 2004, 29 payments remain before this
option may be exercised.


The capitalized cost of the capital lease is depreciated on a
straight-line basis over the life of the lease. At December 31, 2004,
the net book value of petroleum and natural gas properties under the
capital lease obligation was $5,183,520 (2003 - $6,403,240). During the
year, $1,219,659 (2003 - $606,316) had been recognized as depreciation
in the statement of operations, which related to the capital lease.



The principal portion of the capital lease obligation repayments
required for the remainder of the lease are as follows:
------------------------------------------------------------------------
($000s)
2005 815
2006 815
2007 815
2008 815
2009 205
------------------------------------------------------------------------
3,465
Less: interest portion (427)
------------------------------------------------------------------------
3,038
Less: current portion (645)
------------------------------------------------------------------------
2,393
------------------------------------------------------------------------
------------------------------------------------------------------------


12. Asset Retirement Obligations

The Company's asset retirement obligations result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Company estimates the
total undiscounted amount of cash flows required to settle its asset
retirement obligations is approximately $9,500,000, which the majority
will be incurred between 2010 and 2015. A credit-adjusted risk-free rate
of 8.0% was used to calculate the fair value of the asset retirement
obligations.

A reconciliation of the asset retirement obligations is provided below.



------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
($000s)
Asset Retirement Obligations
Balance, beginning of year 3,895 213
Liabilities assumed due to Brooklyn acquisition 1,209 --
Liabilities assumed due to Archean acquisition 5,427 --
Liabilities released due to disposition (4,853) --
Liabilities incurred in year 468 3,562
Accretion expense 433 120
------------------------------------------------------------------------
Balance, end of year 6,579 3,895
------------------------------------------------------------------------
------------------------------------------------------------------------


13. Income Taxes

The provision for income tax differs from the expected amount calculated
by applying the Canadian combined federal and provincial corporate
income tax rate to loss before taxes. The major components of these
differences are explained as follows:



------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
($000s)
Loss before income taxes (1,606) (566)
Corporate income tax rate (%) 38.6 40.6
------------------------------------------------------------------------
Expected tax reduction (620) (230)
Increase (decrease) in income taxes resulting from:
Non-deductible crown charges (net of ARTC) 2,258 1,426
Non-deductible stock-based compensation 1,039 97
Resource allowance (1,720) (647)
Enacted rate change (899) (239)
Other (378) (266)
------------------------------------------------------------------------
Future income tax expense (reduction) (320) 141
------------------------------------------------------------------------
------------------------------------------------------------------------


The components of the future income tax liability are as follows:
------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
($000s)
Property and equipment 31,900 8,088
Share issue costs (1,514) (597)
Asset retirement obligation (2,226) (301)
------------------------------------------------------------------------
Future income tax liability 28,160 7,190
------------------------------------------------------------------------
------------------------------------------------------------------------


14. Cash Flow
Changes in non-cash working capital items increased (decreased) cash
and cash equivalents as follows:

------------------------------------------------------------------------
Years Ended December 31, 2004 2003
------------------------------------------------------------------------
($000s)
Accounts receivable and other (97) (1,834)
Accounts payable 427 5,452
------------------------------------------------------------------------
330 3,618
------------------------------------------------------------------------
Operating activities (3,198) 1,644
Financing activities -- 101
Investing activities 3,528 1,873
------------------------------------------------------------------------
330 3,618
------------------------------------------------------------------------
------------------------------------------------------------------------


15. Related Party Transactions

During 2004, the Company paid $433,832 in costs (2003 - $35,286) to a
law firm, a partner of which is a Director of the Company. These
transactions were measured at market value rates.

16. Commitments

The Company is party to operating lease agreements for its premises, a
field vehicle lease and a capital lease agreement for certain petroleum
and natural gas equipment (see note 11).

The Company has committed to office and vehicle lease payments over the
next five years and thereafter as follows:



------------------------------------------------------------------------
($000s)
2005 709
2006 531
2007 10
2008 10
2009 6
Thereafter nil
------------------------------------------------------------------------


17. Financial Instruments

Credit Risk Management

Accounts receivable and other include amounts receivable for oil and gas
sales, which are generally made to large credit worthy purchasers and
amounts receivable from joint venture partners, which are recoverable
from production. Accordingly, the Company views credit risks on these
amounts as low.

The Company is exposed to losses in the event of non-performance by
counter-parties to these financial instruments. The Company deals with
major institutions and believes these risks are minimal.

Fair Value of Financial Assets and Liabilities

The carrying values of cash and cash equivalents, accounts receivable
and other, accounts payable and bank loan approximate their value due to
the relatively short period to maturity of the instrument.

Commodity Price Risk Management

Periodically, the Company enters into derivative financial instruments
to manage exposure related to commodity prices associated with the sale
of its natural gas. The agreements' forward transactions provided the
Company with more certainty of prices on commodities sold.

In 2004, oil and gas revenues increased $699,397 (2003 - $150,585) due
to natural gas risk management activities. At December 31, 2004, the
Company had unrealized market-to-market hedging gains of $1,660,825 with
respect to the following hedging contracts outstanding:

(a) On September 29, 2004, the Company entered into a natural gas
financial costless collar hedging arrangement. Under this arrangement,
5,000 GJ/d has been hedged at a put price of CDN$7.00/GJ and a call
price of CDN$9.15/GJ for the period November 1, 2004 to March 31, 2005.

(b) On October 7, 2004, the Company entered into a natural gas put
option hedging arrangement. Under this arrangement, 2,500 GJ/d has been
hedged at a price of CDN$8.50/GJ for a price of CDN$0.90/GJ for the
period November 1, 2004 to March 31, 2005.

(c) On October 22, 2004, the Company entered into a natural gas put
option hedging arrangement. Under this arrangement, 2,500 GJ/d has been
hedged at a strike price of CDN$9.10/GJ for a price of CDN$0.82/GJ for
the period November 1, 2004 to April 1, 2005.

(d) On October 28, 2004, the Company entered into a natural gas fixed
price swap arrangement. Under this arrangement, 2,500 GJ/d has been sold
at a strike price of CDN$7.43/GJ for the period April 1, 2005 to October
31, 2005.

Interest Rate Risk

The Company is exposed to interest rate risk to the extent that changes
in market interest rates will impact the Company's debts that have a
floating interest rate.

18. Subsequent Events

On February 2, 2005, the Company entered into an agreement with Argo
Energy Ltd. ("Agro") to effect a business combination and create two new
public entities, called Sequoia Oil & Gas Trust and White Fire Energy
Ltd. Pursuant to the Plan of Arrangement, the effect of the transaction
is as follows, subsequent to the proposed 4:1 share consolidation:

The shareholders of Lightning will receive the following for each
Lightning share owned:

- 0.25 of a trust unit of Sequoia Oil & Gas Trust, and

- 0.25 of a share in White Fire Energy Ltd.

The shareholders of Argo will receive the following for each Argo share
owned:

- 0.17125 of a trust unit of Sequoia Oil & Gas Trust

- 0.17125 of a share in White Fire Energy Ltd.

The Plan of Arrangement will require the approval of Lightning and Argo
shareholders, the Court of Queens Bench of Alberta and other regulatory
approvals.



HISTORICAL REVIEW

------------------------------------------------------------------------
Years Ended December 31, 2004 2003 2002
------------------------------------------------------------------------
($000s, except per share data)
Financial
Oil and gas revenues 43,654 16,061 979
Cash flow from operations 20,714 5,010 150
Per share - basic 0.59 0.26 0.01
Per share - diluted 0.56 0.25 0.01
Loss (1,705) (795) (94)
Per share - basic (0.05) (0.04) (0.01)
Per share - diluted (0.05) (0.04) (0.01)
Capital expenditures (net) 42,296 45,442 12,482
Bank debt and working capital deficiency 54,353 7,631 14,631
Shares outstanding (#000s)
At end of year 45,092 25,245 17,464
Weighted average - basic 35,377 19,190 13,555
Weighted average - diluted 36,977 20,191 13,608
Share trading
High ($) 5.30 -- --
Low ($) 3.40 -- --
Close ($) 4.33 -- --
Volume (#000s) 20,986 -- --
------------------------------------------------------------------------
Operating
Production
Oil and NGLs (bbls/d) 398 60 --
Natural gas (mmcf/d) 15.1 7.2 0.5
Total (boe/d) 2,916 1,259 86
Average wellhead prices
Oil and NGLs ($/bbl) 50.47 35.75 --
Natural gas ($/mcf) 6.56 5.82 5.18
Total ($/boe) 40.90 34.95 31.08
Gross (net) wells drilled
Oil 5 (1.5) -- (--) -- (--)
Gas 13 (8.3) 7 (3.7) 3 (1.1)
Dry and abandoned 4 (1.8) 3 (0.8) 1 (0.3)
------------------------------------------------------------------------
Total 22 (11.6) 10 (4.5) 4 (1.4)
Average working interest (%) 53 45 35
------------------------------------------------------------------------
------------------------------------------------------------------------



CORPORATE INFORMATION

Board of Directors

Gary R. Bugeaud(3)
Partner
Burnet, Duckworth & Palmer LLP

James Finkbeiner(1)(2)(3)
Independent Businessman

Garry A. Tanner(1)(2)
Senior Vice President & Chief Operating Officer
Enerplus Resources Corporation

Graham M. Wilson(1)(2)(3)
Independent Businessman

Ken S. Woolner
President & Chief Executive Officer
Lightning Energy Ltd.

(1) Audit Committee Member
(2) Reserve Committee Member
(3) Corporate Governance/Compensation Committee Member

Officers

Ken S. Woolner
President & Chief Executive Officer

Robert W. Rosine
Chief Operating Officer

Stuart C. Symon
Chief Financial Officer

Martin D. Rude
Vice President, Finance

Darrell Brown
Vice President, Production & Operations

Robert B. Fryk
Vice President, Engineering & Acquisitions

Tony Izzo
Vice President, Exploitation

D. James Doig
Vice President, Exploration & Land


Head Office

Lightning Energy Ltd.
Suite 850, 400 Third Avenue S.W.
Calgary, Alberta T2P 4H2
Phone: (403) 296-4772
Fax: (403) 296-4777
Website: www.lightning-energy.com

Auditors

KPMG LLP
Calgary, Alberta

Banker

RBC Royal Bank of Canada
Calgary, Alberta

Evaluation Engineers

Gilbert Laustsen Jung Associates Ltd.
Calgary, Alberta

Legal Counsel

Burnet, Duckworth & Palmer LLP
Calgary, Alberta

Transfer Agent

Inquiries regarding change of address, registered shareholdings,
stock transfers or lost certificates should be directed to:

Valiant Trust Company
Suite 310, 606 Fourth Street S.W.
Calgary, Alberta T2P 1T1
Telephone: (403) 233-2801

Stock Exchange Listing

Toronto Stock Exchange
Trading Symbol: LEL


ABBREVIATIONS

3-D three dimensional
bbls barrels
bbls/d barrels per day
bcf billion cubic feet
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
GJ gigajoule
GJ/d gigajoule per day
mcf thousand cubic feet
mcfe thousand cubic feet equivalent
mcf/d thousand cubic feet per day
mmboe million barrels of oil equivalent
mmcf million cubic feet
mmcf/d million cubic feet per day
NGLs natural gas liquids


CONVERSION OF UNITS

1.0 acre equals 0.40 hectares
2.5 acres equals 1.0 hectare
1.0 bbl equals 0.159 cubic metres
6.29 bbls equals 1.0 cubic meter
1.0 foot equals 0.3048 metres
3.281 feet equals 1.0 meter
1.0 mcf equals 28.2 cubic metres
0.035 mcf equals 1.0 cubic metres
1.0 mile equals 1.61 kilometres
0.62 miles equals 1.0 kilometres
Natural gas is equated to oil on the basis
of 6 mcf equals 1 boe


Cautionary Statements

Disclosure provided herein in respect of boe units may be misleading,
particularly if used in isolation. A boe conversion ratio of six
thousand cubic feet of natural gas to one barrel of oil is based on an
energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.

Certain information set forth in this document, including management's
assessment of future plans and operations, contains forward-looking
statements. By their nature, forward-looking statements are subject to
numerous risks and uncertainties, some of which are beyond this party's
control, including the impact of general economic conditions, industry
conditions, volatility of commodity prices, currency fluctuations,
imprecision of reserve estimates, environmental risks, competition from
other industry participants, the lack of availability of qualified
personnel or management, stock market volatility and ability to access
sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation,
may prove to be imprecise and, as such, undue reliance should not be
placed on forward-looking statements. Lightning's actual results,
performance or achievement could differ materially from those expressed
in, or implied by, these forward-looking statements, and accordingly, no
assurance can be given that any of the events anticipated by the
forward-looking statements will transpire or occur, or if any of them do
so, what benefits that Lightning will derive there from. Lightning
disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information,
future events or otherwise.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Lightning Energy Ltd.
    Ken Woolner
    President & Chief Executive Officer
    (403) 296-4770
    or
    Lightning Energy Ltd.
    Stuart Symon
    Chief Financial Officer
    (403) 232-4851