Crispin Energy Inc.

Crispin Energy Inc.

March 18, 2005 08:30 ET

Crispin Energy Inc. 2004 Year End Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: CRISPIN ENERGY INC.

TSX SYMBOL: CEY

MARCH 18, 2005 - 08:30 ET

Crispin Energy Inc. 2004 Year End Results

CALGARY, ALBERTA--(CCNMatthews - March 18, 2005) - Crispin Energy Inc.
(TSX:CEY) is pleased to announce it financial and operating results for
the three months and year ended December 31, 2004 as follows:



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Three Months Year
Ended Ended
December 31, December 31,
2004 2003 (+/-) 2004 2003 (+/-)
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Financial Highlights (restated(1)) (restated(1))
($ thousands, except
per share)

Production Revenue 7,860 4,076 93 27,938 15,255 83

Cash Flow from
Operations(2) 4,183 1,916 118 14,800 7,256 104
Cash Flow -
basic(2) 0.07 0.04 75 0.26 0.16 63
Cash Flow -
diluted(2) 0.07 0.04 75 0.25 0.15 67

Net Earnings 738 468 58 4,507 2,246 101
Earnings - basic 0.01 0.01 0 0.08 0.05 60
Earnings - diluted 0.01 0.01 0 0.07 0.05 40

Capital
Expenditures, net 6,156 13,228 (53) 22,542 23,386 (4)

Debt, net of
working capital 15,865 8,130 95 15,865 8,130 95

Common Shares
Outstanding
(thousands)
Weighted Average
- Basic 57,870 48,093 20 57,394 45,715 26
Weighted Average
- Diluted 60,708 51,238 18 60,344 48,844 24

Issued 58,121 57,086 2 58,121 57,086 2
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Operating Highlights
(boe conversion -
6 mcf of natural
gas : 1 barrel of
oil equivalent)

Average Daily
Production
Natural gas
(mcf/day) 6,155 1,675 267 5,358 818 555
Oil and natural
gas liquids
(bbls/day) 837 1,087 (23) 803 1,038 (23)
Oil equivalent
(boe/day) 1,863 1,366 36 1,696 1,175 44

Average Product
Prices
Natural gas
($/mcf) 6.83 5.70 20 6.88 6.09 13
Oil and natural
gas liquids
($/bbl) 49.70 31.71 57 46.50 34.53 35
Oil equivalent
($/boe) 44.91 32.15 40 43.76 34.66 26

Cash Flow
($/boe)(2) 24.52 15.27 61 23.84 16.93 41

Drilling (wells)
Gross
Natural gas 23 14 64
Oil 2 7 (71)
Dry & abandoned 11 3 267
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Total 36 24 50

Net
Natural gas 14.5 8.8 65
Oil 1.3 3.0 (57)
Dry & abandoned 8.1 2.9 179
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Total 23.9 14.7 63


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Reserves (NI 51-101 as evaluated by
Gilbert Lausten Jung Associates Ltd.)
Forecast Prices and Costs
(boe conversion - 6 mcf of natural
gas : 1 barrel of oil equivalent)

Proved
Oil & liquids (mbbl) 1,643 1,582 4
Natural gas (mmcf) 13,583 8,844 54
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Total (mboe) 3,907 3,056 28


Proved plus probable
Oil & liquids (mbbl) 2,011 1,942 4
Natural gas (mmcf) 20,183 13,669 48
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Total (mboe) 5,375 4,221 27

Net present value of future cash
flows before income taxes ($ thousands)
Proved
Undiscounted 82,078 46,190 78
@ 10% discount rate 60,257 34,092 77
@ 15% discount rate 53,491 30,270 77

Proved plus probable reserves
Undiscounted 114,591 64,691 77
@ 10% discount rate 77,977 44,873 74
@ 15% discount rate 67,774 39,115 73

Finding, development and
acquisition costs, excluding
future capital expenditures ($/boe)
Proved 15.29 12.04 27
Proved plus probable 12.70 8.60 48

Finding, development and
acquisition costs, including
future capital expenditures ($/boe)
Proved 15.33 12.77 20
Proved plus probable 13.06 9.02 45


Comprehensive public disclosure of Crispin Energy Inc. reserve
information can be found on the SEDAR site located at www.sedar.com.

NOTES:

(1) Net income and net income per share for 2003 have been restated for
the adoption of new accounting standards for asset retirement
obligations. See Note 2 of the consolidated financial statements for
details of this restatement.

(2) Cash flow from operations is used before changes in non-cash working
capital to analyze operating performance and leverage. Cash flow does
not have a standardized measure prescribed by Canadian generally
accepted accounting principles and therefore may not be comparable with
the calculations with similar measures for other entities.


On February 17, 2005 we announced a business combination pursuant to a
Plan of Arrangement with Pengrowth Energy Trust ("Pengrowth"). The Plan
of Arrangement results in Pengrowth acquiring Crispin Energy Inc. by
exchanging our common shares for Pengrowth Trust Units.

In early April our shareholders will receive information circular that
provides detail in respect proposed transaction. Shareholders will have
the right to vote on the Plan of Arrangement at a shareholder meeting to
be held on April 28, 2005 at 9:00AM in the Dining Room of The Bow Valley
Club in Calgary, Alberta.

For further information please see our February 17, 2005 news release.
You can access a copy of the news release on the SEDAR website or on our
website located at www.crispinenergy.com.

Management Discussion and Analysis

The management discussion and analysis (MD&A) of financial conditions
and results of operations should be read in conjunction with Crispin
Energy Inc.'s ("Crispin") consolidated financial statements for the year
ended December 31, 2004 and consolidated financial statements and MD&A
for the year ended December 31, 2003. The information provided in this
MD&A is given as at March 17, 2005.

In this MD&A, the calculation of boe is based on the conversion rate of
six thousand cubic feet of natural gas for one barrel of crude oil
(6:1), unless otherwise stated. This conversion conforms to National
Instrument 51-101 - Standards for Oil and Gas Activities of the Canadian
Securities Administrators (NI 51-101). Calculations of boe for the
previously reported years have been adjusted from a 10:1 basis to the
current 6:1 standard. Boe's may be misleading particularly if used in
isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. All comparisons
refer to the period ended December 31, 2004 compared with the period
ended December 31, 2003, unless otherwise indicated. All production
volumes quoted in this MD&A refer to our working interest share, unless
otherwise indicated. Estimates of future operating and financial
performance are based on information currently available.

Certain information set forth in this document, including Crispin's
management's ("Management) assessment of Crispin's 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 Crispin'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. Crispin's actual results, performance or
achievement could differ materially from those expressed in, or implied
by, these forward-looking statements, or if any of them do so, what
benefits Crispin will derive therefrom. Crispin disclaims any intention
to update or revise any forward-looking statements, whether as a result
of new information, future events or otherwise.

This MD&A contains certain terms such as "cash flow", "cash flow per
share", "funds from operations", "netback analysis" and "netbacks per
boe". These measurements should not be considered to be an alternative
to, or more meaningful than, net earnings or cash flow from operating
activities, determined in accordance with Canadian generally accepted
accounting principles (GAAP), as indicators of our financial performance
or liquidity. Our funds from operations, netback analysis and netbacks
per boe may not be comparable to those reported by other companies, and
are included as supplemental information only. The reconciliation
between net earnings and cash flow from operations can be found in our
consolidated statements of cash flows contained in our financial
statements. Further, when presenting funds from operations per share, we
have calculated per share amounts using the weighted average shares
outstanding in a manner that is consistent with our calculation of
earnings per share.



When used in this MD&A, the following abbreviations have the meanings
set forth below:

Oil Natural Gas
bbl barrel of oil mcf thousand cubic feet
boe barrels of oil equivalent mcfpd thousand cubic feet per day
boepd barrels of oil equivalent AECO-C reference point for Alberta
per day natural gas pricing
bopd barrels of oil per day Other
NGL natural gas liquids ARTC Alberta Royalty Tax Credit


This MD&A and all of our other public filings can be found on the SEDAR
site located at www.sedar.com.

Significant Event

On February 17, 2005 we announced a business combination pursuant to a
Plan of Arrangement with Pengrowth Energy Trust ("Pengrowth"). The Plan
of Arrangement results in Pengrowth acquiring Crispin Energy Inc. by
exchanging our common shares for Pengrowth Trust Units. Our Canadian
resident shareholders will receive 0.0725 Pengrowth Class B Trust Units
for each Crispin common share, our non-resident Canadian shareholders
will receive 0.512 Pengrowth Class A Trust Units for each Crispin common
share. The issue of Pengrowth Class A Trust Units on the exchange is
limited to a maximum equal to 25% of the Pengrowth Class B Trust Units
issued on the exchange of our common shares to Canadian resident
shareholders. Should the number of Pengrowth Class A shares exceed this
limit then non-resident shareholders will receive a cash payment equal
to 95% of 0.0725 (0.068875) multiplied by the weighted average trading
price of the Pengrowth Class B Trust Units for the five days prior to
the effective date of the arrangement.

In early April our shareholders will receive information circular
(including amongst other relevant documents, a notice of shareholder
meeting, shareholder proxy voting materials and the Plan of Arrangement)
which provides detail in respect proposed transaction. Shareholders will
have the right to vote on the Plan of Arrangement at the April 28, 2005
shareholder meeting.

For further information please see our February 17, 2005 news release.
You can access a copy of the news release on the SEDAR website or on our
website located at www.crispinenergy.com.

Overview

The following table summarizes field and operating netbacks, funds
generated from operations and net earnings for the three months and year
ended December 31, 2004 and December 31, 2003:



Three months Twelve months
$000's ended December 31 ended December 31
2004 2003 % 2004 2003 %
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Petroleum and
natural gas revenue $7,860 $4,076 93 $27,938 $15,255 83
Royalties, net
of ARTC (1,719) (812) 112 (6,188) (3,206) 93
Operating expense (1,127) (871) 29 (4,062) (2,909) 40
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Field netback 5,014 2,393 110 17,688 9,140 94
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Hedging (200) (41) 388 (772) (397) 94
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Operating netback 4,814 2,352 105 16,916 8,743 93
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Other income 5 13 (62) 21 33 (36)
General and
administrative (490) (315) 56 (1,628) (1,126) 45
Interest (146) (93) 57 (509) (346) 47
Capital taxes - (41) (100) - (48) (100)
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Funds from operations 4,183 1,916 118 14,800 7,256 104
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Stock-based
compensation (173) (35) 394 (303) (106) 186
Accretion expense (71) (50) 42 (203) (156) 30
Depletion, depreciation,
amortization (2,019) (1,310) 54 (7,273) (4,061) 79
Future income taxes (1,182) (53) 2,130 (2,514) (687) 266
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Net earnings $ 738 $ 468 58 $4,507 $2,246 101
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Production

Three months Twelve months
Daily production ended December 31 ended December 31
2004 2003 % 2004 2003 %
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Light oil and
NGL (bopd) 837 833 - 803 775 4
Heavy oil (bopd) - 254 (100) - 263 (100)
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Total oil and
NGL (bopd) 837 1,087 (23) 803 1,038 (23)
Natural gas (mcfpd) 6,155 1,675 267 5,358 818 555
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Total daily
production (boepd) 1,863 1,366 36 1,696 1,175 44
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For the quarter ended December 31, 2004, our average daily production
increased by 36% to 1,863 boepd relative to the 1,366 boepd recorded
during the same quarter of 2003. Average daily production of oil and
liquids decreased 23% to 837 bopd from 1,087 bopd, primarily reflecting
the disposition of the Mann Lake heavy oil property at the end of 2003.
Daily production of natural gas was up by 267% for the quarter, the
result of both the late December 2003 acquisition of the Mikwan natural
gas properties and the natural gas production added through drilling in
the Three Hills project.

For the year ended December 31, 2004 production averaged 1,696 boepd, up
44% from the same period in 2003. Average daily production of light
crude oil and natural gas liquids decreased by 23%, reflecting the
disposition of the heavy oil properties in 2003 noted above. Average
daily production of natural gas increased by 555% to 5,358 mcfpd for
2004. This increase is the result of additional natural gas production
from the Mikwan and Three Hills project areas.



Production revenue

Production revenues Three months Twelve months
- $000's ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Light oil and NGL $4,026 $2,772 45 $14,443 11,207 29
Heavy oil - 433 (100) - 2,229 (100)
Hedging (200) (41) 388 (772) (397) 94
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Total crude oil 3,826 3,164 21 13,670 13,039 5
Natural gas 3,834 871 340 13,495 1,819 642
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Total production
revenue, net of
hedging $7,660 $4,035 90 $27,166 $14,858 83
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The increase in 2004 our production revenue is attributable to the 44%
increase in production volumes, to an average of 1,696 boepd, and a 26%
increase in the average selling price per boe, resulting from increased
commodity due to market supply concerns and the change in our commodity
mix for 2004. The 2004 sales volumes are made up of 47% light oil and
natural gas liquids (66% - 2003), 0% heavy oil (22% - 2003) and 53%
natural gas (12% - 2003).

Our gross oil and natural gas revenue, net of losses on physical hedging
contracts, for the fourth quarter of 2004 amounted to $7,659,825, up 90%
when compared to the $4,034,926 recorded for the same period in 2003.
The fourth quarter sales volumes were comprised of 45% light oil and
natural gas liquids (61% - Q4 2003), 0% heavy oil (19% - Q4 2003) and
55% natural gas (20% - Q4 2003).



Three months Twelve months
ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Light oil and
NGL ($/bbl) $ 52.30 $ 36.15 45 $ 49.12 $ 39.59 24
Heavy oil ($/bbl) - 18.53 (100) - 23.26 (100)
Hedging ($/bbl) (2.60) (0.41) 534 (2.62) (1.05) 150
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Total crude oil
($/bbl) 49.70 31.71 57 46.50 34.53 35
Natural gas ($/mcf) 6.83 5.70 20 6.88 6.09 13
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Total production
revenue ($/boe) $ 44.91 $ 32.15 40 $ 43.76 $ 34.66 26
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Sales revenues for the year ended December 31, 2004 were made up of
light oil 50% with an average price of $46.50/bbl (73% averaging
$38.54/bbl - 2003), heavy oil 0% (15% averaging $23.26/bbl - 2003) and
natural gas 50% at an average $6.88/mcf (12% averaging $6.09/mcf -
2003). The Company's blended average field commodity price, net of
hedging adjustments, for 2004 was up 26% to $43.76/boe as compared to
$34.66/boe in 2003.

Sales in the fourth quarter were made up of light oil 50% at an average
of $49.70/bbl (68% averaging $35.74/bbl - Q4 2003), heavy oil 0% (11%
averaging $18.53/bbl - Q4 2003) and natural gas 50% at an average
$6.83/mcf (21% averaging $5.70/mcf - Q4 2003). The Company's blended
average field commodity price, net of hedging adjustments for Q4 2004
was up 40% to $44.91/boe as compared to $32.15/boe in Q4 2003.

Risk management

In aggregate, our hedging adjustments have resulted in a downward
revenue adjustment of $772,397 ($1.24 per boe) during 2004 compared to
$397,345 ($0.93 per boe) during 2003. The contracts entered into were
all based on physical production and thus not a derivative financial
instrument. The hedging losses recorded in both 2004 and 2003 were in
respect of contracts tied to light oil production.

During the first quarter of 2004 we entered into two natural gas
collars, each for 1,000 gigajoules per day and both running from April
1, 2004 to October 31, 2004. The first natural gas collar established a
floor price of C$5.00 and a ceiling price of C$7.00 per gigajoule. The
second natural gas collar established a floor price of C$5.00 and a
ceiling price of C$6.75 per gigajoule. During the second quarter of
2004, we entered into a new crude oil collar for 200 bopd providing a
floor price of US$30.00 and a ceiling price of US$39.40. This contract
ran from July 1, 2004 to December 31, 2004. As of December 31, 2004
there are not any outstanding commodity pricing contracts.

We include our hedging gains and losses as adjustments to gross
petroleum and natural gas sales and use hedging only as a tool to help
underpin our expected near term capital expenditures (by ensuring
minimum cash flows) and to maintain the debt to cash flow ratio within
our stated objectives. We maintain a corporate policy regarding our
hedging activities that limits commodity hedging activities to a maximum
of 50% of forward production and the time period for commodity hedging
to not more than 18 months. Hedging activities outside these limits, or
that involve the fixing of prices or currency exchange rates, require
the approval of our board of directors.



Royalties

Three months Twelve months
Royalties -$000's ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Light oil and NGL $ 982 $ 647 52 $3,534 $2,923 21
Heavy oil - 4 (100) - 21 (100)
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Total crude oil 982 651 51 3,534 2,944 20
Natural gas 829 139 496 2,877 266 982
ARTC (92) 22 518 (223) (4) 5,475
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Royalties (net) $ 1,719 $ 812 112 $6,188 $3,206 93
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---------------------------------------------------------------------


Our royalty expense, net of ARTC, increased 93% to $6,188,133 for 2004
from $3,206,160 during 2003. For the twelve months ended December 31,
2004 the increase in royalty expenses is the combined result of the 83%
increase in production revenues and a 44% increase in production volumes
during 2004.

Exclusive of ARTC our overall effective royalty rate averaged 22% during
2004 as compared to 21% for 2003. The average royalty rate on crude oil
was 24% (22% - 2003). The slight increase in the average crude oil
royalty rate is the result of the change in our crude oil production
mix. The natural gas royalty rate averaged 21% (15% - 2003) for the
period reflecting higher average production rates per well on the
production added during 2004.

For the fourth quarter of 2004 the royalty expense increased 112% to
$1,719,166 from $811,951 in the fourth quarter of 2003. The fourth
quarter increase in royalty expenses is the combined result of the 93%
increase in production revenues and a 36% increase in production volumes
during the fourth quarter of 2004 when compared to the fourth quarter of
2003.



Three months Twelve months
ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Light oil and
NGL ($/bbl) $ 12.76 $ 8.44 51 $ 12.02 $ 10.33 16
Heavy oil ($/bbl) - 0.16 (100) - 0.21 (100)
---------------------------------------------------------------------
Total crude oil
($/bbl) 12.76 6.51 96 12.02 7.77 55
---------------------------------------------------------------------
Natural gas ($/mcf) 1.48 0.91 63 1.47 0.89 65
ARTC ($/boe) (0.54) 0.17 417 (0.36) (0.01) 359
---------------------------------------------------------------------
Total royalties
($/boe) $ 10.08 $ 6.47 56 $ 9.97 $ 7.48 33
---------------------------------------------------------------------
---------------------------------------------------------------------


Our 2004 royalty cost per boe increased 33% to $9.97/boe compared to
$7.48/boe in 2003 which is the combined result of a 26% increase in
average net boe selling prices, a 40% increase in the average natural
gas royalty rate net of the benefits from the ARTC program. For the
fourth quarter the royalty cost per boe increased 56% to $10.08/boe from
$6.47/boe which reflects the average 40% increase in average commodity
prices and the change in the existing production commodity mix.



Operating expense

Operating expense Three months Twelve months
-$000's ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Light oil and NGL $ 544 $ 473 15 $ 2,051 $1,664 23
Heavy oil - 187 (100) - 775 (100)
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Total crude oil 544 660 (18) 2,051 2,439 (16)
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Natural gas 583 211 176 2,011 470 328
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Total Operating
expense $1,127 $ 871 29 $4,062 $2,909 40
---------------------------------------------------------------------
---------------------------------------------------------------------

Total operating expenses were up 40% to $4,062,066 for 2004 from the
$2,909,473 recorded in 2003. The increase recorded in the total
operating expenses reflects the 44% production volume growth achieved
during 2004.

Three months Twelve months
ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Light oil and
NGL ($/bbl) $ 7.07 $ 6.17 15 $ 6.98 $ 5.88 19
Heavy oil ($/bbl) - 8.00 (100) - 8.08 (100)
---------------------------------------------------------------------
Total crude oil
($/bbl) 7.07 6.60 7 6.98 6.44 8
Natural gas ($/mcf) 1.04 1.38 (25) 1.03 1.58 (35)
---------------------------------------------------------------------

Total operating
expense ($/boe) $ 6.61 $ 6.94 (5) $ 6.54 $ 6.79 (4)
---------------------------------------------------------------------
---------------------------------------------------------------------


On a boe basis, the 2004 average operating expenses decreased by 4% to
$6.54/boe from $6.79/boe in 2003. The modest decrease in the overall
operating expense per boe is attributable to the disposition of our
heavy oil production in favor of lower cost natural gas production.

The 2004 light oil operating expenses were up 19% to $6.98/bbl for 2004
compared to $5.88/bbl for 2003, while the light oil operating expenses
for the fourth quarter of 2004 averaged $7.07/bbl up 15% from the fourth
quarter of 2003. The year-to-date increases in these costs are primarily
the result of normal production decline at Sousa and Ewing Lake that
negatively impacted the per boe amounts due to the level of fixed costs
associated with operating these properties.

Operating expenses associated with natural gas averaged $1.03/mcf during
2004, compared to $1.58/mcf in 2003. The decrease in the per mcf
operating expense for natural gas is the result of significant growth in
our natural gas production base during 2004, which has had a positive
effect on the per mcf fixed operating expenses recorded in 2003. Looking
forward we expect that the overall per boe operating costs will decrease
will decrease by about 10%, this is due lower cost natural gas
production further increasing its relative share of our production. The
impact of reduced overall operating expenses from higher natural gas
production will be tempered by higher oil unit operating costs as a
result of natural production declines.



General and administrative expense

Three months Twelve months
G&A expense -$000's ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Gross G&A $ 787 $ 551 43 $ 2,649 $1,850 43
Overhead recoveries (154) (109) 41 (604) (343) 76
Capitalized G&A (143) (127) 13 (417) (381) 9
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General and
administrative
expense $ 490 $ 315 56 $1,628 $ 1,126 45
---------------------------------------------------------------------
---------------------------------------------------------------------


Our general and administrative expenses (G&A), net of recoveries and
capitalized costs, increased 47% to $1,627,587 for 2004 from $1,1125,414
for 2003. The increase in G&A expenses for the year includes
approximately $303,000 in costs incurred to list the Company on the
Toronto Stock Exchange, costs to establish a corporate partnership and
related corporate matters. G&A expenses for the fourth quarter of 2004
amounted to $489,965 compared to $314,467 for the fourth quarter of
2003. The 2004 increase can be largely attributed to bonuses determined
and paid to employees in respect of 2004 performance.



Three months Twelve months
ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Gross G&A $ 4.59 $ 4.39 5 $ 4.26 $ 4.31 (1)
Overhead recoveries (0.83) (0.87) (5) (0.97) (0.80) 21
Capitalized G&A (0.90) (1.01) (11) (0.67) (0.88) (24)
---------------------------------------------------------------------
G&A expense ($/boe) $ 2.86 $ 2.51 14 $ 2.62 $ 2.63 -
---------------------------------------------------------------------
---------------------------------------------------------------------


On a $/boe of production basis, 2004 G&A expense of $2.62 is about the
same as the $2.63 recorded in 2003 G&A expenses increased by 14% to
average $2.86/boe ($2.51/boe - Q4 2003) for the fourth quarter of 2004
caused primarily by the determination and payment of year-end employee
bonuses.

Interest expense

Our interest expense increased to $508,843 ($0.82/boe) for 2004 from
$345,597 ($0.81/boe) in 2003. Increased average borrowings by the
Company during 2004, as compared to 2003 have resulted in an increase in
the total interest expense during 2004. Management elected to use debt
to make up the difference between exploration and development spending
of $22.5 million and $14.8 million in funds from operations ("Cash
Flow"). Given the low cost of bank debt Management felt that
shareholders would be better served utilizing leverage rather than
suffering dilution from an equity offering. At December 31, 2004
annualized fourth quarter cash flow to bank debt was 1:1.1 which is
within acceptable limits for a public exploration and development oil
and gas entity.

Interest expense for the fourth quarter of 2004 amounted to $145,581
($0.85/boe) and $93,220 ($0.74/boe) for the fourth quarter of 2003. The
increase fourth quarter interest expenses are due to increased bank debt.

Income and capital taxes

Our 2004 provision for future income tax expense was $2,513,379
($4.05/boe) and the balance sheet reflected a future income tax
liability of $3,609,989. We have approximately $40.7 million in various
tax pools available to shelter future income. As such Crispin, in its
current structure, will not pay cash income taxes for the next two
fiscal years.

As a result of changes in the tax regime by the federal government
during 2004 we are not currently subject to the Large Corporations
Capital Tax.



Depletion, depreciation and accretion expenses

Three months Twelve months
Depletion, depreciation ended December 31 ended December 31
and accretion - $000's 2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Depletion & depreciation
of P&NG assets $2,015 $1,301 55 $7,240 $4,028 80
Depreciation - other 4 9 (56) 33 33 -
Accretion expense 71 50 42 203 156 30
---------------------------------------------------------------------
DD&A expense $2,090 $1,360 54 $7,476 $4,217 77
---------------------------------------------------------------------


Our depletion, depreciation and accretion ("DD&A") charges for 2004
increased to $7,476,023 from $4,217,339 for 2003 this is due to a
combination of our 44% growth in production volumes and an increase in
the DD&A rate per unit of production. On a boe basis, the 2004 DD&A rate
was $12.04 per boe about 22% higher than the 2003 DD&A rate of $9.84 per
boe. The increase in our DD&A rate results from a combination of higher
service industry costs, 2004 investment in oil and gas facilities and
pipeline and safety and environmental spending. The relative increase in
our DD&A rate is similar to that of other entities active in the
Canadian oil and gas exploration, development and production industry.



Three months Twelve months
ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Depletion & depreciation
of P&NG assets $11.82 $10.36 14 $11.66 $9.40 24
Depreciation - other 0.02 0.07 (71) 0.05 0.08 (37)
Accretion expense 0.41 0.39 5 0.33 0.36 (8)
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DD&A expense (boe @ 6:1) $12.25 $10.82 13 $12.04 $9.84 22
---------------------------------------------------------------------


Funds from operations

Funds from operations is defined as cash flow from operating activities,
as calculated in the "Consolidated Statement of Cash Flows" before
adjustments for changes in non-cash working capital.



Three months Twelve months
Funds from operations ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Funds from
operations ($) $4,182,729 $1,916,313 118 $14,800,205 $7,256,343 104
Funds from
operations
per share
- basic ($) 0.07 0.04 75 0.26 0.16 63
Funds from
operations
per share
- diluted ($) 0.07 0.04 75 0.25 0.15 67
Funds from
operations
per boe ($) 24.52 15.27 61 23.84 16.93 41
---------------------------------------------------------------------


Our funds from operations increased 104 % to $14,800,205 for 2004
compared to $7,256,343 for 2003. Our 2004 funds from operations per boe
improved by 41% to $23.84/boe relative to the $16.93/boe recorded in
2003. These increases are primarily due to our 44% growth in production
volumes and the 26% increase in our average product price, on a boe
basis.

Basic funds from operations per share increased by 63% to $0.26 ($0.25
diluted) for 2004; basic funds from operations per share were $0.16
($0.15 diluted) for 2003. The 2004 per share performance reflects
Crispin's 2004 growth financed largely by bank debt.

Funds from operations for the fourth quarter of 2004 increased by 118%
to $4,182,729 versus the $1,916,313 recorded for the fourth quarter of
2003. Fourth quarter basic funds from operations per share increased by
75% to $0.07 ($0.07 diluted) for the fourth quarter of 2004; basic funds
from operations per share were $0.04 ($0.04 diluted) for 2003. For the
fourth quarter of 2004, funds from operations averaged $24.52/boe, an
increase of 61% over the $15.27/boe recorded in the fourth quarter of
2003. These changes in fourth quarter figures are due to the same
reasons as discussed for the annual figures above.

Net earnings

Our net earnings increased 82% to $4,507,422 ($0.08 per share basic and
diluted) for 2004 from $2,246,309 ($0.05 per share basic and diluted) in
2003. Net earnings for the fourth quarter of 2004 totaled $737,980
($0.01 per share basic and diluted) compared to $468,376 ($0.01 per
share basic and diluted) for the fourth quarter of 2003.



Three months Twelve months
Net earnings ended December 31 ended December 31
2004 2003 % 2004 2003 %
---------------------------------------------------------------------
Net earnings ($) $737,980 $468,376 58 $4,507,422 $2,246,309 101
Earnings per share
- basic ($) 0.01 0.01 0 0.08 0.05 60
Earnings per share
- diluted ($) 0.01 0.01 0 0.07 0.05 40
Earnings per boe ($) 4.33 3.73 16 7.26 5.24 39
Return on average
equity (%) annualized 10.7 11.3 (5) 17.6 14.3 23


Per share amounts

The following table summarizes the common shares used in calculating
funds from operations and net earnings per common shares:



Three months Twelve months
Weighted average ended December 31 ended December 31
Common Shares 2004 2003 2004 2003
---------------------------------------------------------------------
Basic 57,870,491 48,092,297 57,394,232 45,715,200
Diluted 60,707,824 51,238,299 60,344,225 48,844,039
End of period 58,120,776 57,085,776 58,120,776 57,085,776


Ceiling test

The ceiling test is a cost recovery test and is not intended as an
estimate of fair market value. Effective January 1, 2004 the CICA
adopted Accounting Guideline 16 entitled "Oil and Gas Accounting - Full
Cost" to replace CICA Accounting Guideline 5. CICA Accounting Guideline
16 amends the calculation of the ceiling test we apply. The test
compares the value of our total proven reserves, calculated pursuant to
the National Policy 51-101 reserve standards, to the net book value of
those reserves.

If the value of the future net revenues from the total proved reserves
is determined to be less than the book value of the reserves, a write
down of the book value of the reserves must be taken. At December 31,
2004, we had a ceiling test cushion of $41.8 million (no impairment) in
the carrying value of our property and equipment net book values. Note 3
to the consolidated financial statements provides the details of the
independent external engineering evaluator price forecasts used to
estimate the value of future net revenues.

Capital expenditures

The 2004 capital expenditure program has been financed through a
combination of the bank credit facility and cash flow generated from
operations. Net capital expenditures totaled $22,541,647 for 2004.
Capital expenditures during 2004 have been primarily focused on the
continued development of the Three Hills and Mikwan natural gas
prospects.



Capital expenditures Three months Twelve months
- $000's ended December 31 ended December 31
2004 2003 2004 2003
---------------------------------------------------------------------
Land and retention costs 1,106 272 2,753 1,058
Seismic 216 58 415 584
Acquisitions 50 13,685 (14) 14,816
Dispositions - (5,234) - (5,385)
Drilling and completions 3,353 3,400 13,466 8,422
Facility and equipment 1,253 900 5,412 3,467
Capitalized G&G 154 127 417 381
Administrative assets 24 20 93 43
---------------------------------------------------------------------
Total capital expenditures $ 6,156 $ 13,228 $ 22,542 $23,386
---------------------------------------------------------------------
---------------------------------------------------------------------


Liquidity and capital resources

At the end of 2004, we were in a net debt position of $15.9 million,
consisting of $14.7 million in bank debt and a working capital
deficiency of $1.2 million. Our net debt levels remain well within our
target of less than 1:1 debt to cash flow during the high commodity
price cycle. Our debt to cash flow ratio is estimated at 0.95:1.0 which
is based on net debt of $15.9 million at the end of the current year and
our annualized fourth quarter funds flow of $4.2 million.

Management will continue to employ bank debt and cash flow to finance
its 2005 capital expenditure program. These sources should provide
sufficient and timely financial resources to meet contractual
obligations. Increasing commodity prices and growing production mean
that the 1:1 debt to cash flow target will continue to be honored. As at
December 31, 2004, we had a $25.0 million revolving operating demand
loan facility, on which we had drawn a total of $14.7 million.

Equity

During 2004 the Company issued 1,035,000 common shares pursuant to the
exercise of stock options for gross proceeds of $194,000.

Capital requirements

The Company will continue to finance its activities through future
equity offerings, internally generated cash flow and bank credit lines.
The Company intends to use these sources of funding to pursue expansion
in existing project areas. Beyond April 30, 2005, the date of the next
bank review of Crispin and the bank credit facilities extended to us,
the possibility exists that the various sources of financing currently
available to the Company may not be available when required, or may not
be attainable in the amounts, or on terms acceptable to the Company when
required to finance Crispin's ongoing activities.

Off-Balance Sheet Arrangements and Transactions with Related Parties

Crispin has no off-balance sheet arrangements or transactions with
related parties.

Business Environment and Risk

The business risks Crispin is exposed to are those inherent in the oil
and gas industry, as well as those in respect of our own operations.
Geological and engineering risks, uncertainties of discovering
commercial quantities of additional reserves, commodity prices, interest
rates, fluctuating foreign exchange rates and government regulations all
govern Crispin's business and influence Crispin's controls and
Management.

We manage the business risks by: attracting and retaining a team of
qualified, experienced and motivated individuals who have a vested
interest in Crispin's success; operating our properties whenever
possible; employing risk management tools to minimize the risks
associated with changing commodity prices, interest rates and foreign
exchange rates; maintaining a strong financial position (i.e. use of
debt); and maintaining strict environmental, health and safety practices.

Critical Accounting Policies

Depletion and depreciation expense

We employ the full cost method of accounting for exploration and
development activities, whereby all costs associated with these
activities are capitalized, whether successful or not. The aggregate of
the capitalized exploration and development costs, net of certain costs
related to unproved properties is charged against income over time as
depletion and depreciation expense. Depletion and depreciation expense
is calculated on a unit-of production method based upon estimated proved
reserves. By their nature the estimate of proved reserves are subject to
measurement uncertainty and the impact on the financial statements as a
result of changes in the estimate of proved could be significant.

The costs of acquiring and evaluating unproven properties are initially
excluded from the depletion and depreciation calculation. These
properties are assessed annually to ascertain whether impairment has
occurred. When the property is developed and proved reserves are added
or the property is considered to be impaired, at which time the cost of
the property is added to the costs subject to depletion and
depreciation. Assessment of impairment is subject to the same
measurement uncertainty associated with the estimate of proved reserves
discussed above, as such the impact on the financial statements for
changes in the proved reserve estimates could be significant.

Ceiling test

Crispin reviews the carrying value of it petroleum and natural gas
properties and equipment at least annually for impairment. Any
impairment is included as additional depletion and depreciation expense
in the period in which it occurs. The carrying value is compared against
the estimated value of reserves. The calculation of estimated reserve
value includes forecasts of future production, commodity prices, royalty
rates, operating costs, capital costs, and other assumptions. By their
nature, these estimates are subject to measurement uncertainty and the
impact on the financial statements as a result of changes in the
estimates could be significant.

Asset retirement obligation ("ARO") liability and accretion expense

We estimate the fair value of ARO in the period in which it is incurred
and record an ARO liability and corresponding increase in the carrying
amount of the related asset. The capitalized amount is depleted, as
discussed above, on the unit-of-production method based on proved
reserves. The liability amount is increased each reporting period due to
the passage of time based on an estimated risk-free interest rate, and
the amount accretion is expensed against income in the period. The
estimates of future cost of the asset retirement obligation, proved
reserves and the risk-free interest rate are each subject to
uncertainty; changes in the estimates may significantly impact the
financial statements.

Income taxes

Crispin follows the liability method of accounting for income taxes. The
determination of Crispin's income tax liability requires interpretation
of complex laws and regulations. Furthermore such laws and regulations
are periodically revised by elected governments. All of Crispin's tax
filings are subject to audit and could be reassessed after a
considerable period of time. Crispin's future income tax liability is
calculated using substantively enacted future income tax rates that
include changes over time. Accordingly the actual income tax liability
may differ significantly from the amounts reflected in the financial
statements and affect the income tax expense and liability in future
periods.

Financial reporting and Regulatory update

Several changes have taken place in the financial reporting and
securities regulatory environments in 2003 and 2004 that will impact all
public companies, including Crispin. The Canadian securities regulators
and the Canadian Institute of Chartered Accountants ("CICA") have
undertaking these measures to increase investor confidence through
increased transparency, consistency and comparability of financial
statements and financial information. These changes have also been
brought about by the goal of harmonizing Canadian standards more closely
with those in the United States.

We implemented the new accounting standard for Stock-based Compensation
in 2003 which is described as follows:

Stock-based Compensation and Other Stock-based Payments - During
September 2003, CICA issued an amendment to section 3870 "Stock-based
compensation and other stock-based payments. The amended section is
effective for fiscal years beginning on or after January 1, 2004;
however, earlier adoption was recommended. The amendment requires
companies to measure all stock-based payments using the fair value
method of accounting and to recognize the compensation expense in their
financial statements. We implemented this amended standard in 2003 in
accordance with the early adoption recommendation. According to the
transitional provisions, early adoption requires that the compensation
expense be calculated and recorded in the income statement for stock
options issued on or after January 1, 2003.

As a result of implementing this amended standard, our net income for
2004 decreased by $303,381 ($105,913) due to the estimated stock-based
compensation expense on employee stock options issued on or after
January 1, 2003.

Additionally in 2004, we implemented the new standards set out below,
which have had the following impact on our 2004 consolidated financial
statements:

Full Cost Accounting Guideline - In September 2003, CICA issued
Accounting Guideline 16 entitled "Oil and Gas Accounting - Full Cost" to
replace CICA Accounting Guideline 5. CICA Accounting Guideline 16
proposes amendments to the ceiling test calculation we apply, and is
effective for fiscal years beginning on or after January 1, 2004.
Implementation of CICA Accounting Guideline 16 did not have an impact on
our financial results for 2004.

Asset Retirement Obligations - CICA issued Section 3110 that harmonizes
Canadian GAAP with Financial Accounting Standards Board statement No.143
entitled "Accounting for Asset Retirement Obligations". The new standard
requires that companies recognize the liability associated with future
site reclamation costs in their financial statements at the time the
liability is incurred. The new Canadian standard is effective for fiscal
years beginning on or after January 1, 2004. Implementation of this
standard retroactive changes to prior periods. Note 5 to the
consolidated financial statements provides additional detail in respect
of the retroactive change.

2005 Outlook

On April 28, 2005 our shareholders will meet to vote approval of the
Plan of Arrangement whereby Pengrowth will acquire Crispin and the
transaction expected to be completed on April 29, 2005. As such the
outlook provided below is only in respect of the period of January 1,
2005 to the anticipated completion date of the Pengrowth acquisition
transaction.

Dependent upon availability of field services, weather conditions, the
timing and length of spring break-up, access to third party gas
processing facilities, strength of oil and gas commodity prices and
Canadian:US dollar exchange rate the table below are Management
expectations:



Expectation Range
---------------------
Low High
--- ----
Average daily production (boepd) 1,825 1,925

Capital expenditures ($ millions) $8.5 $9.5

Wells drilled
- gross 7 10
- net 5.8 8.2

Cash Flow ($ millions) $5.0 $6.5

Net Exit Debt ($ millions) $18.0 $21.0



Quarterly Results Summary

Quarterly Information
(unaudited) 2003 2004
---------------------------------------------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Production
Oil and NGL
(bbls/d) 635 842 789 833 808 815 766 837
Heavy oil
(bbls/d) 225 268 302 254 - - - -
---------------------------------------------------------------------
Total oil
and NGL 860 1,110 1,091 1,087 808 815 766 837
Natural gas
(mcf/d) 420 344 835 1,675 3,937 5,756 5,616 6,155
---------------------------------------------------------------------
Boepd 931 1,168 1,230 1,366 1,464 1,775 1,702 1,863
---------------------------------------------------------------------

($ 000's
except
per share
amounts)
Revenue
Petroleum &
natural
gas sales 3,309 3,705 3,809 4,035 5,392 6,988 7,126 7,660
Royalties (783) (839) (772) (812) (1,193) (1,545) (1,731) (1,719)
Other 5 3 12 13 5 6 5 5
---------------------------------------------------------------------
Net revenues 2,531 2,869 3,049 3,236 4,204 5,449 5,400 5,946
---------------------------------------------------------------------

---------------------------------------------------------------------
Net earnings 489 615 674 468 1,103 1,282 1,384 738
---------------------------------------------------------------------

Earnings per
share
Basic 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.01
Diluted 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.01



Consolidated Balance Sheets as at December 31,
---------------------------------------------------------------------

2004 2003
(Restated note 2)
ASSETS

Current assets:
Cash $ - $ 36,087
Accounts receivable 3,526,867 2,345,822
Prepaid expenses and deposits 130,901 63,496
------------------------------
3,657,768 2,445,405

Property and equipment (note 3) 50,335,326 34,675,906
------------------------------

$ 53,993,094 $ 37,121,311
------------------------------
------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Bank overdraft $ 566,148 $ -
Accounts payable and
accrued liabilities 4,218,945 4,475,313
Bank debt (note 4) 14,737,696 6,100,000
------------------------------
19,522,789 10,575,313

Asset retirement obligation (note 5) 2,775,147 2,328,626

Future income taxes (note 7) 3,609,989 1,112,211

Shareholders' equity
Share capital (note 6) 17,851,849 17,682,644
Contributed surplus (note 6) 409,294 105,913
Retained earnings 9,824,026 5,316,604
------------------------------
28,085,169 23,105,161
------------------------------

$ 53,993,094 $ 37,121,311
------------------------------
------------------------------

Commitments (note 10)

See accompanying notes to consolidated financial statements



Consolidated Statements of Earnings and Retained Earnings
---------------------------------------------------------------------

Three months Year
ended December 31, ended December 31,
2004 2003 2004 2003
---------------------------------------------------
(Restated (Restated
note 2) note 2)
Revenue
Petroleum and
natural gas
sales $ 7,659,825 $ 4,034,926 $ 27,165,451 $ 14,858,035
Royalties, net
of Alberta
Royalty Tax
Credit (1,719,166) (811,951) (6,188,133) (3,206,160)
Other 4,539 13,188 21,383 33,382
---------------------------------------------------
5,945,198 3,236,163 20,998,701 11,685,257
---------------------------------------------------

Expenses
Operating 1,126,923 871,233 4,062,066 2,909,473
General and
administrative 489,965 314,467 1,627,587 1,125,414
Interest 145,581 93,220 508,843 345,597
Stock-based
compensation
(note 6) 173,276 35,478 303,381 105,913
Accretion expense 70,629 49,478 202,744 155,699
Depletion, and
depreciation 2,018,674 1,309,773 7,273,279 4,061,640
---------------------------------------------------
4,025,048 2,673,649 13,977,900 8,703,736
---------------------------------------------------

Earnings before
taxes 1,920,150 562,514 7,020,801 2,981,521

Taxes (note 7)
Capital tax - 40,930 - 48,430
Future income
taxes 1,182,170 53,208 2,513,379 686,782
---------------------------------------------------

Net earnings 737,980 468,376 4,507,422 2,246,309
---------------------------------------------------

Retained earnings,
beginning of
period 9,086,046 4,848,228 5,835,799 3,070,295

Effect of change
in accounting for
asset retirement
obligation (note 2) - - (519,195) -
---------------------------------------------------

Retained earnings,
end of period $ 9,824,026 $ 5,316,604 $ 9,824,026 $ 5,316,604
---------------------------------------------------
---------------------------------------------------


Net earnings
per share
Basic $ 0.01 $ 0.01 $ 0.08 $ 0.05
Diluted $ 0.01 $ 0.01 $ 0.07 $ 0.05
---------------------------------------------------

See accompanying notes to consolidated financial statements



Consolidated Statements of Cash Flows
---------------------------------------------------------------------

Three months Year
ended December 31, ended December 31,
2004 2003 2004 2003
---------------------------------------------------
(Restated (Restated
note 2) note 2)
Cash provided by
(used for):

Operating
activities:
Net earnings $ 737,980 $ 468,376 $ 4,507,422 $ 2,246,309
Items not
involving cash:
Stock-based
compensation 173,276 35,478 303,381 105,913
Accretion expense 70,629 49,478 202,744 155,699
Depletion,
depreciation and
amortization 2,018,674 1,309,773 7,273,279 4,061,640
Future income
taxes 1,182,170 53,208 2,513,379 686,782
---------------------------------------------------
Funds from
operations 4,182,729 1,916,313 14,800,205 7,256,343

Site restoration
expenditures (25,183) (1,545) (147,275) (128,753)
Change in
non-cash working
capital (note 8) 1,252,149 (268,916) 1,064,289 (731,653)
---------------------------------------------------
Cash flow from
operating
activities 5,409,695 1,645,852 15,717,219 6,395,937
---------------------------------------------------

Financing
activities:
Advances
(repayment) of
bank debt 2,291,686 (2,450,000) 8,637,696 2,450,000
Issuance of
shares 99,000 13,002,000 194,000 13,102,000
Share issue costs - (794,019) (40,396) (794,019)
---------------------------------------------------
Cash flow from
financing
activities 2,390,686 9,757,981 8,791,300 14,757,981
---------------------------------------------------

Investing
activities:
Additions to
property and
equipment (6,156,102) (18,461,221) (22,541,647) (28,770,233)
Disposition of
property and
equipment - 5,233,673 - 5,384,676
Change in
non-cash
working capital
(note 8) (882,706) 2,088,903 (2,569,107) 2,673,393
---------------------------------------------------
Cash flow from
investing
activities (7,038,808) (11,138,645) (25,110,754) (20,712,164)
---------------------------------------------------

Increase
(decrease) in
cash position 761,573 265,188 (602,235) 441,754

Cash (bank
overdraft),
beginning of
period (1,327,721) (229,101) 36,087 (405,667)
---------------------------------------------------

Cash (bank
overdraft), end
of period (566,148) 36,087 (566,148) 36,087
---------------------------------------------------
---------------------------------------------------

See accompanying notes to consolidated financial statements



Notes to the Consolidated Financial Statements
Years ended December 31, 2004 and 2003
---------------------------------------------------------------------


Crispin Energy Inc. (the "Company") is engaged in the exploration,
development and production of petroleum and natural gas in Western
Canada.

The consolidated financial statements of Crispin Energy Inc. ("Crispin"
or "the Company") have been prepared by management in accordance with
Canadian generally accepted accounting principles. The preparation of
the financial statements in conformity with Canadian generally accepted
accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities
and disclosure of contingent assets and liabilities at the dates of the
financial statements and the reported amounts of revenues and expenses
during the reporting periods. Actual results could differ from those
estimates.

Certain comparative figures have been reclassified to conform to the
current period financial presentation.

1. Significant accounting policies

(a) Principles of consolidation:

The consolidated financial statements include the accounts of the
Company, its subsidiaries and partnership all of which are wholly owned.

(b) Joint operations:

Substantially all of the Company's exploration, development and
production activities are conducted jointly with others and accordingly,
the Company only reflects its proportionate interest in such activities.

(c) Measurement uncertainty:

The amounts recorded for depletion and depreciation of petroleum and
natural gas properties are based on estimates. The cost recovery ceiling
test is based on estimates of proved reserves, production rates,
commodity 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.

(d) Revenue recognition:

Revenues from properties in which the Company has an interest with other
producers are recognized on the basis of the Company's net working
interest. Revenues from the sale of petroleum and natural gas are
recorded when title passes to an external party.

(e) Depletion and depreciation:

Capitalized costs, together with estimated future capital costs
associated with proved reserves, are depleted and depreciated using the
unit of production method based on estimated gross proved reserves of
petroleum and natural gas as determined by independent petroleum
engineers. For purposes of this calculation, reserves and production are
converted to equivalent units of petroleum based on relative energy
content of six thousand cubic feet of natural gas to one barrel of
petroleum. Costs of significant unproved properties, net of impairments,
are excluded from the depletion calculation. These properties are
assessed periodically to ascertain whether impairment has occurred. When
proved reserves are assigned or the property is considered to be
impaired, the cost of the property or the amount of the impairment is
added to the costs subject to depletion.

Other equipment, which is comprised of office equipment, furniture and
fixtures, are recorded at cost and depreciated over their useful lives
on a declining balance basis at 30%.

(f) Derivative financial instruments:

The Company uses derivative financial instruments from time to time to
hedge its exposure to commodity price risk. The Company does not enter
into derivative financial instruments for trading or speculative
purposes.

The derivative financial instruments are initiated within the guidelines
of the Company's risk management policy. This includes linking all
derivatives contracts to specific firm commitments or forecasted
transactions. The Company believes the derivative financial instruments
are effective as hedges, both at inception and over the term of the
instrument, as the term and notional amount do not exceed the Company's
firm commitment or forecasted transaction and the underlying basis of
the instrument, commodity price, matches the Company's exposure.

The Company enters into hedges of its exposure to petroleum and natural
gas commodity prices by entering into crude oil and natural gas swap
contracts, options or collars, when it is deemed appropriate. These
derivative contracts, accounted for as hedges, are not recognized on the
balance sheet. Realized gains and losses on these contracts are
recognized in petroleum and natural gas revenue and cash flows in the
same period in which the revenues associated with the hedged transaction
are recognized. Premiums paid or received are deferred and amortized to
earnings over the term of the contract.

Gains and losses resulting from changes in the fair value of derivative
contracts that do not qualify for hedge accounting are recognized in
earnings when those changes occur.

(g) Flow-through shares:

Flow-through shares are issued at a fixed price and the proceeds are
used to fund qualifying exploration and development expenditures within
a defined time period. The expenditures funded by flow-through
arrangements are renounced to investors in accordance with tax
legislation. Share capital is reduced, and future tax liability is
increased by the total estimated future income tax cost of the renounced
tax deductions at the time of the issue.

(h) Income taxes:

The Company uses the asset and liability method of accounting for income
taxes. Under the asset and liability method, future income tax assets
and liabilities are recognized for the future income tax consequences
attributable to differences between the financial statement carrying
amounts of existing assets and liabilities and their respective tax
bases. Future income 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 income tax assets and
liabilities of a change in income tax rates is recognized in income in
the period that includes the date of enactment or substantive enactment.

(i) Per share amounts:

Basic per share amounts are computed by dividing net earnings by the
weighted average shares outstanding during the reporting period. Diluted
per share amounts are computed similar to basic per share amounts except
that the weighted average shares outstanding are increased to include
additional shares from the assumed exercise of stock options, if
dilutive. The number of additional shares is calculated by assuming that
outstanding stock options were exercised and that the proceeds from such
exercises were used to acquire shares of common stock at the average
market price during the reporting period.

(j) Stock-based compensation:

On January 1, 2003 the Company prospectively adopted the new accounting
standard for stock-based compensation. Under this method, the
compensations cost attributable to share options granted is measured at
the grant date and expensed over the vesting period with a corresponding
increase to contributed surplus. Upon exercise of the stock options,
consideration received together with the amount previously recognized in
contributed surplus is recorded as an increase to share capital.

Stock options granted prior to January 1, 2003 are accounted for by
crediting the proceeds to share capital upon exercise.

(k) Cash:

Cash consists of cash in the Company's bank accounts, less cheques
issued but not yet cashed.

2. Change in accounting policy

(a) Asset retirement obligations

Effective January 1, 2004, the Company adopted the new Canadian
accounting standard for asset retirement obligations. The new standard
requires the Company to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a legal
obligation associated with the retirement of tangible long-lived assets
that result from the 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
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. The effect of
adoption of the new standard on the financial statements is disclosed in
note 4.

(b) Full cost ceiling test

Effective January 1, 2004, the Company adopted the new Canadian
accounting guideline for the full cost method of accounting for oil and
gas activities. The new guideline requires a detail impairment
calculation when events or circumstances indicate a potential impairment
of the carrying amount of oil and gas assets may have occurred, but at
least annually.

An impairment loss is recognized when the carrying amount of a cost
centre is not recoverable and exceeds its fair value. The carrying
amount is assessed to be recoverable when the sum of the undiscounted
cash flows expected from proved reserves plus the cost of unproved
interests, net of impairments, exceeds the carrying amount of the cost
centre. When the carrying amount is assessed not to be recoverable, an
impairment loss is recognized to the extent that the carrying amount of
the cost centre exceeds the sum of the discounted cash flows from proved
and probable reserves plus the cost of unproved interests, net of
impairments, of the cost centre. The cash flows are estimated using
expected future product prices and costs and are discounted using a
risk-free interest rate. Adoption of the new guideline had no effect on
the Company's financial statements. The future prices used in the
initial adoption ceiling test are disclosed in note 3.

Prior to January 1, 2004, an impairment loss was recognized when the
carrying amount of a cost centre exceeded its recoverable amount. The
recoverable amount was the sum of the undiscounted cash flows expected
from the production of proved reserves plus the lower of cost or market
of unproved interests less estimated future costs for administration,
financing and site restoration. The cash flows were estimated using
period end prices and costs.

(c) Hedging relationships

Effective January 1, 2004, the Company adopted the new Canadian
accounting guideline relating to hedging relationships which requires
the identification, designation and documentation of each hedging
relationship as well as an assessment of the effectiveness of the
hedging relationship. The guideline does not specify how hedge
accounting is applied, and accordingly, the Company's derivative
financial instrument accounting policy in the 2004 annual consolidated
financial statements remains unchanged. Adoption of the new guideline
had no effect on the Company's financial statements.



3. Property and equipment
2004 2003
(Restated
Net book value note 2)
------------------------------------------------------------------------
Petroleum and natural gas properties $67,718,839 $44,786,135
Less: accumulated depletion and depreciation (17,383,508) (10,110,229)
------------------------------------------------------------------------
$50,335,326 $34,675,906
------------------------------------------------------------------------
------------------------------------------------------------------------


During the year ended December 31, 2004, the Company capitalized
$416,507 (2003 - $380,968) of general and administrative costs directly
related to exploration and development activities. As at December 31,
2004, the depletion and depreciation calculation excluded unproved
properties of $4,643,926 (2003 - $3,184,600).

Adoption of the new guideline, as outlined in note 2(b), had no effect
on the Company's financial statements. The future commodity prices used
in the ceiling test prepared on initial adoption were based January 1,
2004 commodity price forecasts of our independent reserve engineers
adjusted for differential specific to the Company reserves. The
following table summarizes the future benchmark and Company prices used
for the years 2005 to 2009 used in the impairment test at December 31,
2004:



------------------------------------------------------------------------
WTI Foreign WTI Company AECO Company
Oil Exchange Oil Price Gas Price
($US/bbl) Rate ($Cdn/bbl) Oil ($Cdn/mcf) Gas
------------------------------------------------------------------------
2005 42.00 0.82 51.22 46.55 6.60 6.65
2006 40.00 0.82 48.78 44.14 6.35 6.40
2007 38.00 0.82 46.34 41.99 6.15 6.24
2008 36.00 0.82 43.90 39.92 6.00 6.10
2009 34.00 0.82 41.46 37.61 6.00 6.10
------------------------------------------------------------------------
------------------------------------------------------------------------


4. Bank debt

In December 2004, the Company and its lender, a Canadian chartered bank,
agreed to amend the revolving operating demand bank loan facility to
increase the maximum borrowing amount to $25 million with a $1 million
sub-limit in respect of Letters of Credit or Letters of Guarantee
(collectively the "Letters"). Borrowings may be in the form of Canadian
or U.S. dollar overdraft drawings, Canadian dollar bankers' acceptances,
or U.S. dollar London Interbank Offered Rate ("LIBOR") borrowings.
Borrowings and interest are payable on demand.

Interest is payable on borrowings under the operating facility at
interest rates that are determined quarterly based on the preceding
quarter's debt on cash flow ratio. Interest rates on the operating line
of credit range from Canadian prime rate or U.S. base rate, when the
debt to cash flow ratio is below 1.0:1.0, to prime plus one and one half
percent when the debt to cash flow ratio is greater than 3.0:1.0.
Interest payable on amounts drawn is at prevailing bankers' acceptance
rates plus stamping fees or lenders' prime lending rates plus the
applicable margin. Stamping fees on banker's acceptances and LIBOR
borrowings range from 1% when the debt to cash flow ratio is below
1.0:1.0, to 2% when the cash flow ratio is greater than 2.5:1.0. The fee
in respect of Letters is 1.5% per annum, payable at the Letters issue
date.

Collateral for the credit facility consists of a general assignment of
book debts, a $5 million debenture with a fixed and floating charge over
certain of the Company's assets, a floating charge supplemental
debenture in the amount of $75 million covering the major producing
petroleum and natural gas assets of the Company and corporate guarantee
supported by a $75 million supplemental demand debenture providing a
first floating charge on all of the assets provided by the Crispin
Energy Partnership.

This credit facility is subject to a periodic borrowing base review, the
next due April 30, 2005, and, other than interest, does not currently
call for any repayments or availability reductions.

5. Asset retirement obligations

The effect of the change in accounting policy as outlined in note 2(a)
has been recorded retroactively with restatement of prior periods. The
effect of the adoption on the balance sheet and statement of earnings is
presented below as increases (decreases):



------------------------------------------------------------------------
------------------------------------------------------------------------
December 31,
Balance sheet 2003
------------------------------------------------------------------------

Asset retirement cost, included in property and equipment $ 1,199,711
Asset retirement obligations 2,328,626
Future income tax liability (263,632)
Accumulated future abandonment and site restoration (346,088)
Retained earnings (519,195)
------------------------------------------------------------------------
------------------------------------------------------------------------
December 31,
Statements of earnings 2003
------------------------------------------------------------------------

Accretion expense, included in depletion,
depreciation and accretion $ 155,699
Depletion and depreciation on asset retirement costs 182,488
Amortization of estimated future abandonment
and site restoration liability (245,573)
Future income tax expense (117,695)
------------------------------------------------------------------------
Net earnings - decrease (increase) $ (25,081)
------------------------------------------------------------------------
------------------------------------------------------------------------

Net earnings per share:
Basic $ 0.00
Diluted $ 0.00
------------------------------------------------------------------------


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 $5,546,775, which will be
incurred between 2007 to 2044. The majority of the costs are expected to
be paid over an average of 11 years and will be funded from general
Company resources at the time of restoration and reclamation. A
credit-adjusted risk-free rate of 8.1 percent was used to calculate the
fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

------------------------------------------------------------------------
Year ended December 31,
2004 2003
------------------------------------------------------------------------
Balance, beginning of period $ 2,328,626 $ 1,493,189
Accretion expense 202,744 155,699
Liabilities incurred 391,052 808,491
Liabilities settled (147,275) (128,753)
------------------------------------------------------------------------
Balance, end of period $ 2,775,147 $ 2,328,626
------------------------------------------------------------------------
------------------------------------------------------------------------

6. Share capital

(a) Authorized Unlimited number of common shares
150,000 preferred shares

(b) Issued

2004 2003
----------------------- -----------------------
Number Amount Number Amount
Common shares of shares of shares
------------------------------------------------------------------------
Balance, January 1 57,085,776 $17,682,644 44,765,776 $ 5,052,138
Shares issued on
exercise of options 1,035,000 194,000 500,000 100,000
Shares issued for cash - - 11,820,000 13,002,000
Share issue costs,
net of income taxes - (24,795) - (471,494)
------------------------------------------------------------------------
Balance, December 31 58,120,776 $17,851,849 57,085,776 $17,682,644
------------------------------------------------------------------------
------------------------------------------------------------------------


(c) Stock options

The Company has established a stock option plan whereby officers,
directors and employees may be granted options to purchase common
shares. A maximum of 10% of the outstanding common shares of the Company
may, from time to time be allocated for issuance to eligible
participants. Under this program, the exercise price of each option
equals the closing market price of the Company's stock date prior to the
date of grant, the options maximum term is five years, with various
vesting periods.



The following table summarizes the changes in the stock option plan.

2004 2003
-------------------- --------------------
Weighted Weighted
Number average Number average
of shares price of shares price
------------------------------------------------------------------------
Balance, January 1 4,225,000 $0.31 4,210,000 $0.23
Exercised (1,035,000) 0.19 (500,000) 0.20
Granted 1,515,000 1.17 515,000 0.87
------------------------------------------------------------------------
Balance, December 31 4,705,000 $0.62 4,225,000 $0.31
------------------------------------------------------------------------
Options vested at December 31 2,521,500 $0.30 2,961,000 $0.24
------------------------------------------------------------------------


At December 31, 2004 the options outstanding had exercise prices ranging
from $0.15 to $1.34 with a weighted average contractual life of 3.0
years.

(d) Per share amounts

The following table summarizes the common shares used in calculating
earnings per share for the period ended December 31:



Weighted average Year ended December 31
Common shares 2004 2003
------------------------------------------------------------------------
Basic 57,394,232 45,715,200
Diluted 60,344,225 48,844,039
------------------------------------------------------------------------


The reconciling items between the basic and diluted common shares result
from in the money stock options.

(e) Stock-based compensation

Effective January 1, 2003, the Company began prospectively expensing the
fair value of stock options granted over the vesting period. In
accordance with the prospective method of adoption, the Company will
continue to record no compensation expense for stock options granted
prior to January 1, 2003 and will continue to provide pro forma
disclosure of the net effect on net earnings and earnings per share had
the fair value been expensed.

The fair value of each option granted by the Company was estimated on
the date of grant using the Black-Scholes option-pricing model with
weighted average assumptions for grants assuming no dividends are paid
on common shares. The amounts computed using the Black-Scholes
option-pricing model may not be indicative of the actual values realized
upon the exercise of these options by the holders.



Year ended December 31,
2004 2003
(Restated note 2)
------------------------------------------------------------------------
Net earnings:
Reported $4,507,422 $2,246,309
Pro-forma 4,429,657 1,950,508
Basic earnings per share:
Reported $ 0.08 $ 0.05
Pro-forma $ 0.08 $ 0.04
Diluted earnings per share:
Reported $ 0.07 $ 0.05
Pro-forma $ 0.07 $ 0.04
------------------------------------------------------------------------

The fair value of each option granted is estimated on the date of grant
using the Modified Black-Scholes option-pricing model with the following
assumptions:

2004 2003
------------------------------------------------------------------------
Weighted average grant date fair value $0.74 $0.57
Average risk-free interest rate (%) 5.0% 5.0%
Average volatility (%) 74% 77%
Average expected life Five years Five years

(f) Contributed surplus

Changes to the contributed surplus account are as follows:

Year ended December 31
2004 2003
------------------------------------------------------------------------
Balance, beginning of period $ 105,913 $ -
Stock-based compensation 303,381 105,913
------------------------------------------------------------------------

Balance, December 31 $ 409,294 $ 105,913
------------------------------------------------------------------------

7. Income taxes

Income taxes recorded on the statement of earnings differ from the
income tax calculated by applying the combined Federal and Provincial
income tax rate to income before taxes as follows:

2004 2003
------------- -------------
Corporate income tax rate 38.62% 40.62%

Estimated income tax expense $ 2,711,433 $ 1,211,094
Increase (decrease) in income taxes
Non-deductible crown charges, net of ARTC 737,360 444,181
Non-deductible Stock based compensation 117,166 43,022
Federal resource allowance (1,109,638) (706,103)
Change in income tax rate (93,141) (305,412)
Other 150,199 -
------------- -------------
Future income taxes 2,513,379 686,782
Capital taxes - 48,430
------------- -------------

Provision for taxes $ 2,513,379 $ 735,212
------------- -------------
------------- -------------

The components of future income tax liability consist of the following
temporary differences:

2004 2003
------------- -------------
Property and equipment $(3,987,803) $(1,649,589)
Asset retirement obligations 183,215 170,979
Capital losses 131,877 104,495
Non-capital losses - 3,656
Share issue costs 194,280 326,534
Other 319 36,209
------------- -------------
(3,478,112) (1,007,716)
Less: valuation allowance (131,877) (104,495)
------------- -------------

Net future income tax liability $(3,609,989) $(1,112,211)
------------- -------------
------------- -------------

8. Supplemental cash flow information

Changes in non-cash working capital Year ended December 31
2004 2003
------------------------------------------------------------------------
(Increase) decrease in accounts receivable $(1,181,045) $ (736,965)
(Increase) decrease in prepaid expenses
and deposits (67,405) (139,275)
Increase (decrease) in accounts payable (256,368) 2,817,980
------------------------------------------------------------------------
Change in non-cash working capital $(1,504,818) $1,941,740
------------------------------------------------------------------------

Relating to:
Investing activities $(2,569,107) $2,673,393
Financing activities - -
Operating activities 1,064,289 (731,653)
------------------------------------------------------------------------
Change in non-cash working capital $(1,504,818) $1,941,740
------------------------------------------------------------------------

Cash interest paid $ 507,811 $ 345,597
Cash taxes paid 35,685 9,000


9. Risk Management

Fair value of financial instruments

At December 31, 2004, the fair value of cash, accounts receivable,
deposits, bank overdraft, accounts payable and accrued liabilities
approximate their carrying value due to their current maturities. The
bank debt carrying value approximates fair value due to the cost of
borrowing being at a floating rate.

Commodity price risk

The Company has been party to certain physical purchase price contracts
that have fixed the price of a portion of its production. For the year
ended December 31, 2004, the Company realized a net loss of $772,396
(2003 - $397,345) on its commodity hedging program. These amounts have
been recorded against petroleum and natural gas sales.

There were no physical purchase price or derivative financial instrument
contracts outstanding in respect to price risk management at December
31, 2004.

Credit risk

The Company's accounts receivable are with customers and joint venture
partners in the petroleum and natural gas business and although a
substantial portion of its debtor's ability to pay is dependent the
business environment of the oil and gas industry, credit risks are
minimal. Marketing production to numerous purchasers under normal
industry sale and payment terms mitigates concentration of credit risk.
The Company routinely assesses the financial strength of its customers.
Counterparties to commodity price contracts or derivative financial
instruments may expose the Company to certain losses in the event of
non-performance. The Company mitigates this risk by entering into
transactions with highly rated major financial institutions.

Interest rate risk

The Company's credit facilities are subject to floating interest rates.
As such any debt carried on the books by the Company would be subject to
interest rate cash flow risk, as the required cash flow to service debt
would fluctuate as a result of changes in market rates. The Company had
total borrowings outstanding under its available credit facilities as of
December 31, 2004 of $ 14,737,696 (2003 - $6,100,000).

10. Future Commitments

(a) Office lease

The Company has entered into a sub-lease that expires in 2006 for office
premises. Annual lease payments for these office premises are as follows:

2005 $270,068

2006 $100,330

(b) Operating lease

Additionally, in return for third party construction of additional gas
gathering and processing facilities, the Company has committed to a
minimum annual processing and gathering fees until payout in May 2005 of
the gas gathering and processing facilities. Future payments remaining
until payout in May 2005 total $73,336.

11. Subsequent event:

On February 17, 2005 the Company entered into an agreement for a
business combination pursuant to a Plan of Arrangement with Pengrowth
Energy Trust ("Pengrowth"). The Plan of Arrangement calls for the
acquisition of the common shares of the Company by Pengrowth
Corporation, a subsidiary of Pengrowth, in exchange for Pengrowth Trust
Units. Completion of the Plan of Arrangement is subject to various
conditions, including receipt of all regulatory, Company shareholder and
judicial approval. Assuming the receipt of all approvals the business
combination is anticipated to be completed on April 29, 2005.

Crispin is an exploration, development and production company listed on
the TSX under the trading symbol "CEY".

Corporate information provided herein contains forward-looking
information. The reader is cautioned that assumptions used in the
preparation of such information, which are considered reasonable by
Crispin at the time of preparation, may prove to be incorrect. Actual
results achieved during the forecast period will vary from the
information provided herein and the variations may be material. There is
no representation by Crispin that actual results achieved during the
forecast period will be the same in whole or in part as those forecast.

Not for distribution to US Newswire services or dissemination in the
United States.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Crispin Energy Inc.
    Murray R. Nunns
    President and CEO
    (403) 237-6375
    (403) 265-5993 (FAX)
    or
    Crispin Energy Inc.
    William V. Bradley
    Executive Vice-President
    (403) 237-6375
    (403) 265-5993 (FAX)
    info@crispinenergy.com
    www.crispinenergy.com
    The TSX Venture Exchange has not reviewed and does not accept
    responsibility for the adequacy or accuracy of this release.