Endev Energy Inc.

Endev Energy Inc.

March 02, 2005 20:11 ET

Endev Energy Inc. Announces 2004 Year-End and Fourth Quarter Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: ENDEV ENERGY INC.

TSX SYMBOL: ENE

MARCH 2, 2005 - 20:11 ET

Endev Energy Inc. Announces 2004 Year-End and Fourth
Quarter Results

CALGARY, ALBERTA--(CCNMatthews - March 2, 2005) - Endev Energy Inc.
(TSX:ENE):

(All amounts are in Canadian dollars unless stated otherwise)

Endev Energy Inc. (TSX:ENE) is pleased to announce 2004 year-end and
fourth quarter financial and operating results.

Key accomplishments for 2004 include:

- 23 % increase in annual average production volume to 3,500 boe/d and
fourth quarter production of 4,518 boe/d

- 31% increase in gross revenue to $52.3 million

- 41% increase in cash flow from operations to $27.7 million

2004 was a year which transformed Endev into a successful
growth-oriented shallow gas producer. The Company strengthened its
technical understanding of its core shallow gas play at Majorville,
Alberta, in addition to streamlining its capital expenditure program and
honing its execution of large shallow gas drilling programs. Part of the
Company's commitment to this new performance-oriented approach was
reflected in the appointment of a new management team. Cameron
MacGillivray assumed the role of President and CEO, and Vincent Fera was
named Vice President, Exploration. In February 2005, Scott Bonli was
named Vice President Finance and Chief Financial Officer. They are
joined by Robert Bell, Vice President, Engineering who has been with
Endev for almost three years and brings a solid understanding of the
Company's assets. Together this team has developed a new vision and
strategy for Endev.

"We are truly excited about the opportunities that are before us. After
a thorough evaluation we have identified strategies to exploit Endev's
existing assets in ways that can provide growth in the near term," said
Cameron MacGillivray, Endev's President and Chief Executive Officer. "We
realized significant production gains in the fourth quarter of 2004 and
will continue to exploit these reservoirs when our drilling program
resumes in 2005."

The near term strategy is to focus on exploiting the tight shallow gas
formations at Endev's Majorville core area - geology in which the
Company's operations team has extensive expertise. Endev operates over
90 percent of the production from the 93,000 net acres the Company owns
at this property. At Drumheller, the Company's strategy is to follow up
on a well drilled in 2003 to confirm Drumheller's suitability as a core
area for Endev. The Company owns 14,000 net acres at Drumheller.
Together, these two properties provided 65 percent of Endev's total
production in 2004. The Company's strategy to focus on the Majorville
program resulted in tangible momentum in fourth quarter performance.
Production was up by 50 percent over the third quarter, totalling 4,518
boe/d in the fourth quarter - results that exceeded the Company's 4,000
boe/d target.

Endev spent $34 million in 2004 to drill 146 wells, of which 138 were
operated. All of the 146 wells were drilled at Majorville. The capital
budget for 2005 is $35 million of which 75 percent is allocated to
drilling 115 wells at Majorville and Drumheller, and the remaining 25
percent will be used to explore for new natural gas opportunities in
southern and central Alberta.

During the first quarter of 2005, the Company's operational activities
will include acquiring land and production, recompletions of existing
well bores, and testing prospective new zones in Majorville and
Drumheller, together with land acquisition and exploratory drilling in
new areas. In addition, the Company will be preparing for its shallow
gas drilling program due to commence near the end of the second quarter.

The management team has set as an objective to grow the Company on a
year-over-year basis through production increases from Endev's existing
properties, supplemented by exploration on existing and new acreage as
well as through potential acquisitions. "We need to build upon
production from our existing assets," said Cameron MacGillivray, "which
will provide the cash flow for our next stage of growth into new core
areas. We believe we now have the team in place to do that."



HIGHLIGHTS Three months ended Year ended
Dec 31 Dec 31 Dec 31 Dec 31
2004 2003 2004 2003
------------------------------------------------------------------------
Financial
($millions, except per share amounts)
Gross revenue (1) 17.6 8.9 52.3 39.8
Cash Flow from operations (2) 10.2 4.0 27.7 19.6
Basic per share 0.12 0.05 0.32 0.26
Diluted per share 0.12 0.05 0.31 0.25
Net income (loss) (3) 0.3 (0.2) 0.9 6.1
Basic per share - - 0.01 0.08
Diluted per share - - 0.01 0.08
Capital expenditures, net 7.7 9.3 34.0 86.9
Net debt 32.2 26.7 32.2 26.7

Operations
Daily production
Crude oil (bbl) 648 826 800 1,077
Natural gas liquids (bbl) 80 114 99 206
Natural gas (mcf) 22,744 11,341 15,606 9,447
Total production (boe @ 6:1) 4,518 2,830 3,500 2,857
Average sales price
Crude oil ($/bbl) 56.19 34.20 45.81 37.30
Natural gas liquids ($/bbl) 46.06 29.40 40.55 35.79
Natural gas ($/mcf) 6.61 5.68 6.55 6.52
Netback per boe (6:1) ($)
Petroleum and natural gas revenues 42.16 34.07 40.87 38.20
Royalties, net of ARTC 8.49 6.25 7.87 7.30
Operating expenses 5.90 6.90 7.03 7.93
Transportation 1.12 1.23 0.98 0.72
Operating netback 26.65 19.69 24.99 22.25


(1) Gross of transportation costs previously included in revenue.

(2) The financial data presented has been prepared in accordance with
Canadian generally accepted accounting principles (GAAP) except for the
term cash flow from operations. Cash flow from operations has been
presented for information purposes only and should not be considered an
alternative to, or more meaningful than cash flow from operating
activities as determined in accordance with GAAP. The determination of
Endev's cash flow from operations may not be comparable to the same
reported by other companies. Cash flow from operations is referred to as
funds from operations in the Statements of Cash Flow in the financial
statements. The reconciliation of net income and cash flow from
operations can be found in the statements of cash flow in the financial
statements. Cash flow from operations per share was calculated using the
same weighted average shares outstanding used in calculating net income
per share.

(3) Net income for the three months and year ended December 31, 2004 has
been restated reflecting the retroactive adoption of stock-based
compensation and asset retirement obligation pronouncements.

OPERATIONS REVIEW

Majorville

Majorville is Endev's core producing property, located 125 kilometres
southeast of Calgary. It is a large, low risk shallow gas area where we
own 128,000 gross (93,000 net) acres of land. Of this total land
position, 35,000 gross acres are currently undeveloped. We own a
significant amount of infrastructure at Majorville, including four gross
(3.75 net) compression/dehydration facilities, capable of processing up
to 20 million cubic feet per day (mmcf/d) of natural gas, as well as
approximately 420 kilometres of gas pipeline.

In 2004, Endev's strategy at Majorville was to target sweet natural gas
in the Belly River, Milk River and Medicine Hat shallow gas zones, while
one well targeted the slightly deeper Bow Island formation, found at
1,100 metres. A total of 138 Endev operated gas wells were drilled with
a success rate of 100 percent. In 2004, total production from Majorville
averaged 1,920 barrels of oil equivalent per day (boe/d).

Drumheller

Located 100 kilometres northeast of Calgary, Drumheller is characterized
as a low risk development and exploitation area with similar geological
features as Majorville, which provides the opportunity to leverage our
core expertise of developing tight, sweet, shallow natural gas. We own
32,000 gross (14,000 net) acres of land, of which 19,000 acres are
developed and 13,000 are undeveloped. Endev has working interests
ranging from 28 to 50 percent in seven compressors, and a 50 percent
working interest in an oil battery. In 2004, production from Drumheller
totalled 350 boe/d, from wells drilled prior to this year. Endev did not
drill any wells at this property in 2004 while assessments of the area
were being completed.

RESERVES SUMMARY

Endev has received the results of an independent engineering evaluation
of its oil and gas reserves conducted by AJM Petroleum Consultants (AJM)
effective December 31, 2004. This evaluation was prepared in accordance
with National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities (NI 51-101). This new instrument adopted by the Canadian
Securities Administrators sets out standards of disclosure for oil and
gas activities and mandates the application of evaluation standards
defined in the Society of Petroleum Evaluation Engineers (SPEE) Canadian
Oil and Gas Evaluation Handbook (COGEH). The information that follows
has been derived from the AJM evaluation.

In 2002 and earlier years, the reserve category most often referenced by
the oil and gas industry was "Proved plus Risked Probable", also known
as "Established". The new NI 51-101 standard does not include this
definition, however, the new "Proved plus Probable" category is
reasonably comparable to the old "Established" criteria. Year-over-year
comparisons will therefore be done using Established reserves from
December 31, 2002 and Proved plus Probable reserves from December 31,
2003 and December 31, 2004.

Highlights include:

- Total Proved reserves are 6.2 mmboe and Total Proved plus Probable
reserves are 11.3 mmboe.


- Development activity added 2.3 mmboe of company interest Total Proved
reserves, replacing actual 2004 production by 1.9 times.

- Reserve life indices based on company interest Total Proved and Proved
plus Probable reserves over actual 2004 production are 4.9 and 8.9
years, respectively.




------------------------------------------------------------------------
SUMMARY OF OIL AND GAS RESERVES Light and Natural
CONSTANT PRICES AND COSTS Medium Gas Natural
As at December 31, 2004 Crude Oil Liquids Gas 2004
------------------------------------------------------------------------
Reserves Category (mbbl) (mbbl) (mmcf) (mboe)
------------------------------------------------------------------------
Proved
- Developed producing 1,032 124 27,132 5,678
- Developed non-producing 0 11 444 85
- Undeveloped 0 35 2,264 412
------------------------------------------------------------------------
Total Proved 1,032 170 29,841 6,175
Probable 576 50 26,961 5,119
------------------------------------------------------------------------
Total Proved plus Probable 1,609 219 56,802 11,295
------------------------------------------------------------------------
Note: Columns may not add due to rounding.

------------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
CONSTANT PRICES AND COSTS
As at December 31, 2004
------------------------------------------------------------------------
Before Income Taxes
Reserves Category Discounted at (% per year)
------------------------------------------------------------------------
($ millions) 0 5 10 15 20
------------------------------------------------------------------------
Proved
- Developed producing 126.7 107.9 94.7 84.8 77.1
- Developed non-producing 1.9 1.2 0.9 0.7 0.6
- Undeveloped 8.1 6.2 4.9 4.0 3.3
------------------------------------------------------------------------
Total Proved 136.7 115.3 100.5 89.5 81.0
Probable 94.4 66.8 49.4 37.7 29.3
------------------------------------------------------------------------
Total Proved plus Probable 231.1 182.1 149.9 127.2 110.3
------------------------------------------------------------------------

------------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
CONSTANT PRICES AND COSTS
As at December 31, 2004
------------------------------------------------------------------------
After Income Taxes
Reserves Category Discounted at (% per year)
------------------------------------------------------------------------
($ millions) 0 5 10 15 20
------------------------------------------------------------------------
Proved
- Developed producing 85.6 72.6 63.5 56.7 51.4
- Developed non-producing 1.3 0.8 0.6 0.5 0.4
- Undeveloped 5.6 4.2 3.2 2.6 2.1
------------------------------------------------------------------------
Total Proved 92.4 77.6 67.3 59.7 53.9
Probable 65.7 45.5 32.7 24.0 17.9
------------------------------------------------------------------------
Total Proved plus Probable 158.2 123.0 100.0 83.8 71.8
------------------------------------------------------------------------
Note: Columns may not add due to rounding.

------------------------------------------------------------------------
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
CONSTANT PRICES AND COSTS
As at December 31, 2004
($ millions)
------------------------------------------------------------------------
Reserves Royalties, Operating Development
Category Revenue net of ARTC Costs Costs
------------------------------------------------------------------------
Proved 230.7 32.7 54.1 1.8
------------------------------------------------------------------------
Proved plus Probable 419.1 57.7 90.9 32.3
------------------------------------------------------------------------

------------------------------------------------------------------------
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
CONSTANT PRICES AND COSTS
As at December 31, 2004
($ millions)
------------------------------------------------------------------------
Future Net
Revenue
Well Before Future Net
Reserves Abandonment Income Income Revenue
Category Costs Taxes Taxes After Taxes
------------------------------------------------------------------------
Proved 5.4 136.7 44.2 92.4
------------------------------------------------------------------------
Proved plus Probable 7.1 231.1 72.9 158.2
------------------------------------------------------------------------


------------------------------------------------------------------------
FUTURE NET REVENUE BY PRODUCTION GROUP
CONSTANT PRICES AND COSTS
As at December 31, 2004
($millions)
------------------------------------------------------------------------
Future Net Revenue Before Income
Reserves Category Production Group Taxes (Discounted at 10% per year)
------------------------------------------------------------------------
Proved Light and Medium
Crude Oil(1) 17.1
Natural Gas(2) 82.0
------------------------------------------------------------------------
Proved plus Light and Medium
Probable Crude Oil(1) 22.9
Natural Gas(2) 124.9
------------------------------------------------------------------------
(1) Including solution gas and other by-products.
(2) Including by-products but excluding solution gas from oil wells.


------------------------------------------------------------------------
SUMMARY OF OIL AND GAS RESERVES Light and Natural
CONSTANT PRICES AND COSTS Medium Gas Natural
As at December 31, 2004 Crude Oil Liquids Gas 2004
------------------------------------------------------------------------
Reserves Category (mbbl) (mbbl) (mmcf) (mboe)
------------------------------------------------------------------------
Proved
- Developed producing 1,031 124 27,135 5,677
- Developed non-producing 0 11 444 85
- Undeveloped 0 35 2,258 411
------------------------------------------------------------------------
Total Proved 1,031 169 29,837 6,173
Probable 573 49 26,934 5,112
------------------------------------------------------------------------
Total Proved plus Probable 1,604 219 56,772 11,285
------------------------------------------------------------------------
Note: Columns may not add due to rounding.


------------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
CONSTANT PRICES AND COSTS
As at December 31, 2004
------------------------------------------------------------------------
Before Income Taxes
Reserves Category Discounted at (% per year)
------------------------------------------------------------------------
($ millions) 0 5 10 15 20
------------------------------------------------------------------------
Proved
- Developed producing 134.1 115.2 101.9 91.9 84.1
- Developed non-producing 2.1 1.3 0.9 0.7 0.6
- Undeveloped 8.5 6.5 5.2 4.3 3.6
------------------------------------------------------------------------
Total Proved 144.7 122.9 108.0 96.9 88.3
Probable 99.2 70.5 52.6 40.6 32.0
------------------------------------------------------------------------
Total Proved Plus probable 243.8 193.4 160.6 137.5 120.3
------------------------------------------------------------------------

------------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
CONSTANT PRICES AND COSTS
As at December 31, 2004
------------------------------------------------------------------------
After Income Taxes
Reserves Category Discounted at (% per year)
------------------------------------------------------------------------
($ millions) 0 5 10 15 20
------------------------------------------------------------------------
Proved
- Developed producing 90.3 77.2 68.1 61.3 55.9
- Developed non-producing 1.5 0.9 0.6 0.5 0.4
- Undeveloped 5.8 4.4 3.4 2.7 2.2
------------------------------------------------------------------------
Total Proved 97.6 82.5 72.1 64.5 58.6
Probable 68.9 47.8 34.7 25.9 19.7
------------------------------------------------------------------------
Total Proved Plus probable 166.5 130.3 106.9 90.4 78.2
------------------------------------------------------------------------
Note: Columns may not add due to rounding.


------------------------------------------------------------------------
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
CONSTANT PRICES AND COSTS
As at December 31, 2004
($ millions)
------------------------------------------------------------------------
Reserves Royalties, Operating Development
Category Revenue net of ARTC Costs Costs
------------------------------------------------------------------------
Proved 249.9 36.0 60.5 1.9
Proved plus Probable 454.0 63.1 105.1 32.7


------------------------------------------------------------------------
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
CONSTANT PRICES AND COSTS
As at December 31, 2004
($ millions)
------------------------------------------------------------------------
Future Net
Revenue
Well Before Future Net
Reserves Abandonment Income Income Revenue
Category Costs Taxes Taxes After Taxes
------------------------------------------------------------------------
Proved 6.9 144.7 47.1 97.6
Proved plus Probable 9.2 243.8 77.3 166.9
------------------------------------------------------------------------



------------------------------------------------------------------------
FUTURE NET REVENUE BY PRODUCTION GROUP
FORECAST PRICES AND COSTS
As at December 31, 2004
($millions)
------------------------------------------------------------------------
Future Net Revenue Before Income
Reserves Category Production Group Taxes (Discounted at 10% per year)
------------------------------------------------------------------------
Proved Light and Medium
Crude Oil(1) 18.5
Natural Gas(2) 88.5
------------------------------------------------------------------------
Proved plus Light and Medium
Probable Crude Oil(1) 24.1
Natural Gas(2) 134.8
------------------------------------------------------------------------
(1) Including solution gas and other by-products.
(2) Including by-products but excluding solution gas from oil wells.


SUMMARY PRICING ASSUMPTIONS

The December 31, 2004 pricing assumptions utilized by AJM Petroleum
Consultants in determining the reserves and future net revenues are as
follows.

CONSTANT PRICES AND COSTS

------------------------------------------------------------------------
Natural
Natural Gas Exchange
Crude Oil Gas Liquids Rate
------------------------------------------------------------------------
Year WTI Med Oil 25 Alberta
Cushing Edmonton degree API AECO Pentanes +
Oklahoma City Gate Hardisty Average Condensate
$/bbl US $/bbl Cdn $/bbl Cdn $/mcf $/bbl ($US/$Cdn)
------------------------------------------------------------------------
2004
Year
End $42.45 $45.61 $27.61 $6.29 $47.89 0.8264
------------------------------------------------------------------------


FORECAST PRICES AND COSTS
Natural
Natural Gas Inflation Exchange
Crude Oil Gas Liquids Rates Rate
------------------------------------------------------------------------
Med Oil
WTI Edmonton 25 degree Alberta
Cushing City Gate API AECO Pentanes +
Oklahoma Real Hardisty Average Condensate
Real $/bbl Current Current Current
Year $/bbl US Cdn $/bbl Cdn $/mcf $/bbl %/year $US/$Cdn
------------------------------------------------------------------------
2005 $42.00 $51.40 $33.40 $7.00 $53.95 2.0% 0.800
2006 $40.00 $48.85 $35.85 $6.90 $52.35 2.0% 0.800
2007 $38.00 $46.45 $34.30 $6.90 $50.70 2.0% 0.800
2008 $36.00 $43.95 $34.65 $6.50 $49.00 2.0% 0.800
2009 $34.00 $41.50 $32.90 $6.25 $47.15 2.0% 0.800
2010 $32.00 $39.00 $31.05 $5.90 $45.20 2.0% 0.800
2011 $32.00 $39.00 $31.95 $6.05 $46.15 2.0% 0.800
2012 $32.00 $39.00 $32.85 $6.20 $47.10 2.0% 0.800
2013 $32.00 $39.00 $31.75 $6.30 $48.05 2.0% 0.800
2014 $32.00 $39.00 $32.70 $6.50 $49.05 2.0% 0.800
2015 $32.00 $39.00 $33.65 $6.65 $50.05 2.0% 0.800
2016 $32.00 $39.00 $34.60 $6.75 $51.05 2.0% 0.800
2017 $32.00 $39.00 $35.60 $6.95 $52.10 2.0% 0.800
2018 $32.00 $39.00 $32.60 $7.05 $53.15 2.0% 0.800
2019 $32.00 $39.00 $33.65 $7.25 $54.25 2.0% 0.800
2020 $32.00 $39.00 $34.70 $7.45 $55.35 2.0% 0.800
2021 $32.00 $39.00 $35.80 $7.55 $56.50 2.0% 0.800
2022 $32.00 $39.00 $36.90 $7.75 $57.65 2.0% 0.800
2023 $32.00 $39.00 $36.00 $7.95 $58.80 2.0% 0.800
2024 $32.00 $39.00 $37.15 $8.15 $60.00 2.0% 0.800
2024+ 0.0% 0.0% 2.0% 2.0% 2.0% 2.0% 0.800
------------------------------------------------------------------------


Reconciliation of Company Interest Reserves by Product Type Forecast
Prices and Costs

Light and
Medium Natural Gas
Crude Oil Liquids Natural Gas Total
------------------------------------------------------------------------
Company Interest Proved (mbbl) (mbbl) (mmcf) (mboe)

Opening balances
- December 31, 2003 1,342 233 21,777 5,205
Drilling extensions
and discoveries - - 14,104 2,351
Technical revisions (30) (28) (338) (114)
Acquisitions - - - -
Dispositions - - - -
Production (281) (36) (5,706) (1,268)
------------------------------------------------------------------------
Closing balances
- December 31, 2004 1,031 169 29,837 6,173
------------------------------------------------------------------------

Company Interest Probable

Opening balances
- December 31, 2003 792 77 44,075 8,215
Drilling extensions
and discoveries - - 1,224 204
Technical revisions (219) (27) (18,364) (3,307)
Acquisitions - - - -
Dispositions - - - -
Production - - - -
------------------------------------------------------------------------
Closing balances
- December 31, 2004 573 50 26,935 5,112
------------------------------------------------------------------------

Company Interest Proved
plus Probable

Opening balances
- December 31, 2003 2,134 310 65,852 13,419
Drilling extensions and
discoveries - - 15,328 2,555
Technical revisions (249) (55) (18,702) (3,421)
Acquisitions - - - -
Dispositions - - - -
Production (281) (36) (5,706) (1,268)
------------------------------------------------------------------------
Closing balances
- December 31, 2004 1,604 219 56,772 11,285
------------------------------------------------------------------------


FINDING,
DEVELOPMENT
AND
ACQUISITION 3-Year
COSTS 2004 2003 2002 Total/Average
------------------------------------------------------------------------
($000s) Proved Proved Proved Proved Proved Proved Proved Proved
except plus plus plus plus
as noted Probable Probable Probable Probable
(1) (1) (1) (1)
------------------------------------------------------------------------
Total
exploration
and
development
costs
incurred 34,012 34,012 46,633 46,633 2,843 2,843 83,488 83,488
------------------------------------------------------------------------
Change in
future
development
costs 283 (7,303) 1,618 39,976 1,440 3,368 3,341 36,041
------------------------------------------------------------------------
Total
exploration
and
development
costs
for F&D 34,295 26,709 48,251 86,609 4,283 6,211 86,829 119,529
------------------------------------------------------------------------
Reserve
additions,
excluding
revisions
and
acquisitions/
dispositions
(mboe) 2,351 2,555 1,257 6,156 141 189 3,749 8,900
------------------------------------------------------------------------
Average
finding and
development
costs
per boe $14.59 $10.45 $38.39 $14.07 $30.38 $32.86 $23.16 $13.43
------------------------------------------------------------------------
Acquisition
expenditures - - 45,872 45,872 40,458 40,458 86,330 86,330
------------------------------------------------------------------------
Reserve
additions,
from
acquisitions
(mboe) - - 1,362 3,210 5,349 6,526 6,711 9,736
------------------------------------------------------------------------
Average
acquisition
costs
per boe N/A N/A $33.68 $14.29 $7.56 $ 6.20 $12.86 $8.87
------------------------------------------------------------------------
Total
finding,
development
and
acquisition
costs
(FD&A) 34,295 26,709 94,123 132,481 44,741 46,669 173,159 205,859
------------------------------------------------------------------------
Reserve
additions
for
finding,
development
and
acquisition
costs
(mboe) 2,351 2,555 2,619 9,366 5,490 6,715 10,460 18,636
------------------------------------------------------------------------
Average
finding,
development
and
acquisition
costs
per boe $14.59 $10.45 $35.94 $14.14 $8.15 $6.95 $16.55 $11.05
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) 2002 Proved plus Probable Reserves represent "Established" or
"Proved plus Risked Probable" Reserves.


Conference Call

Endev will hold a conference call at 7:00 am MST (9:00 am EST), on
Thursday, March 3, 2005 to discuss its financial and operating results.
Callers from the Toronto area may dial 416-695-6120 and all other
participants may dial the toll free number 1-888-789-0150 to join the
call. A taped recording will be available until Thursday March 10, 2005
by dialing 416-695-5275 from the Toronto area and 1-866-518-1010 from
all other areas. This call will also be broadcast live on the Internet
and may be accessed on Endev's website www.endevenergy.com.

Endev Energy Inc. is a Canadian oil and gas exploration and production
company based in Calgary, Alberta. The Company's common shares are
listed on the Toronto Stock Exchange under the trading symbol ENE. Endev
focuses on creating shareholder value by executing low to medium-risk
drilling programs in its focus areas in Alberta.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") for Endev Energy Inc.
("Endev" or the "Company") should be read in conjunction with the
unaudited consolidated financial statements for the year and three
months ended December 31, 2004 and the MD&A and the audited consolidated
financial statements and accompanying notes for the year ended December
31, 2003. Our audited consolidated financial statements, current annual
information form and other documents are filed on SEDAR at www.sedar.com.

PRESENTATION OF CASH FLOW FROM OPERATIONS

The financial data presented has been prepared in accordance with
Canadian generally accepted accounting principles (GAAP) except for the
term cash flow from operations. Cash flow from operations has been
presented for information purposes only and should not be considered an
alternative to, or more meaningful than cash flow from operating
activities as determined in accordance with GAAP. The determination of
Endev's cash flow from operations may not be comparable to the same
reported by other companies. The reconciliation of net income and cash
flow from operations can be found in the statements of cash flows in the
financial statements. The Company calculates cash flow from operations
as funds from operations prior to the change in non-cash working capital
related to operating activities. Cash flow from operations per share was
calculated using the same weighted average shares outstanding used in
calculating net income per share.

BASIS OF BARREL OF EQUIVALENT

For the purposes of calculating unit costs, natural gas has been
converted to a barrel of oil equivalent (boe) using 6,000 cubic feet
equal to one barrel (6:1), unless otherwise stated. The boe conversion
ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion
method and does not represent a value equivalency, therefore boe may be
misleading if used in isolation. This conversion conforms to the
Canadian Securities Regulators' National Instrument 51-101 - Standards
of Disclosure for Oil and Gas Activities.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by Endev Energy Inc. are
disclosed in note 2 to the Consolidated Financial Statements. Certain
accounting policies require that management make appropriate decisions
with respect to the formulation of estimates and assumptions that affect
the reported amounts of assets, liabilities, revenues and expenses.
Changes in these judgments and estimates may have a material impact on
the Company's financial results and condition. The following discusses
such accounting policies and is included in Management's Discussion and
Analysis to aid the reader in assessing the critical accounting policies
and practices of the Company and the likelihood of materially different
results being reported. Endev's management reviews its estimates
regularly. The emergence of new information and changed circumstances
may result in actual results or changes to estimated amounts that differ
materially from current estimates.

The following assessment of significant accounting policies is not meant
to be exhaustive. The Company might realize different results from the
application of new accounting standards promulgated, from time to time,
by various rule-making bodies.

Oil and Gas Reserves

Under NI 51-101, "Proved" reserves are those reserves that can be
estimated with a high degree of certainty to be recoverable (it is
likely that the actual remaining quantities recovered will exceed the
estimated Proved reserves). In accordance with this definition, the
level of certainty targeted by the reporting company should result in at
least a 90 percent probability that the quantities actually recovered
will equal or exceed the estimated reserves. In the case of "Probable"
reserves, which are obviously less certain to be recovered than Proved
reserves, NI 51-101 states that it must be equally likely that the
actual remaining quantities recovered will be greater or less than the
sum of the estimated Proved plus Probable reserves. With respect to the
consideration of certainty, in order to report reserves as Proved plus
Probable, the reporting company must believe that there is at least a 50
percent probability that the quantities actually recovered will equal or
exceed the sum of the estimated Proved plus Probable reserves. Proved
plus Probable reserves as defined in NI 51-101 are viewed by many
industry participants as being comparable to the "Established" reserves
definition that was used historically. Under the previous rules, the
Established reserves category was generally calculated on the basis that
Proved plus half of Probable reserves (as those terms were defined in NP
2B) represented the best estimate at the time.

The oil and gas reserves estimates are made using all available
geological and reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions occur as a
result of changes in prices, costs, fiscal regimes, reservoir
performance or a change in the Company's plans. The reserve estimates
are also used in determining the Company's borrowing base for its credit
facilities and may impact the same upon revisions or changes to the
reserves estimates. The effect of changes in Proved oil and gas reserves
on the financial results and position of the Company is described under
the heading "Full Cost Accounting for Oil and Gas Activities".

FULL COST ACCOUNTING FOR OIL AND GAS ACTIVITIES

Depletion Expense

The Company uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting,
all costs associated with exploration and development is capitalized
whether successful or not. The aggregate of net capitalized costs and
estimated future development costs less estimated salvage values is
amortized using the unit-of-production method based on estimated proved
oil and gas reserves.

An increase in estimated proved oil and gas reserves would result in a
corresponding reduction in depletion expense. A decrease in estimated
future development costs would result in a corresponding reduction in
depletion expense.

Withheld Costs

Certain costs related to unproved properties may be excluded from costs
subject to depletion until proved reserves have been determined or their
value is impaired. These properties are reviewed quarterly and any
impairment is transferred to the costs being depleted or, if the
properties are located in a cost centre where there is no reserve base,
the impairment is charged directly to income.

Full Cost Accounting Ceiling Test

The Company is required to review the carrying value of all property,
plant and equipment, including the carrying value of oil and gas assets,
for potential impairment. Impairment is indicated if the carrying value
of the long-lived asset or oil and gas cost centre is not recoverable by
the future undiscounted cash flows. If impairment is indicated, the
amount by which the carrying value exceeds the estimated fair value of
the long-lived asset is charged to earnings.

The ceiling test is based on estimates of reserves, production rate,
petroleum and natural gas prices, future costs and other relevant
assumptions. By their nature, these estimates are subject to measurement
uncertainty and the impact on the financial statements could be material.

Asset Retirement Obligations

Effective January 1, 2004, the Company changed its accounting policy
with respect to accounting for asset retirement obligations. The
Company, under the current policy, is required to provide for future
removal and site restoration costs. The Company must estimate these
costs in accordance with existing laws, contracts or other policies.
These estimated costs are charged to earnings and the appropriate
liability account over the expected service life of the asset. When the
future removal and site restoration costs cannot be reasonably
determined, a contingent liability may exist. Contingent liabilities are
charged to earnings when management is able to determine the amount and
the likelihood of the future obligation.

Income Tax Accounting

The determination of the Company's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and
potential reassessment after the lapse of considerable time.
Accordingly, the actual income tax liability may differ significantly
from that estimated and recorded by management.

Goodwill

The process of accounting for the purchase of a company, results in
recognizing the fair value of the acquired company's assets on the
balance sheet of the acquiring company. Any excess of the purchase price
over fair value is recorded as goodwill. Since goodwill results from the
culmination of a process that is inherently imprecise the determination
of goodwill is also imprecise. In accordance with the recent issuance of
CICA section 3062, "Goodwill and Other Intangible Assets", goodwill is
no longer amortized but assessed periodically for impairment. The
process of assessing goodwill for impairment necessarily requires Endev
to determine the fair value of its assets and liabilities. Such a
process involves considerable judgment.

Legal, Environmental Remediation and Other Contingent Matters

The Company is required to both determine whether a loss is probable
based on judgment and interpretation of laws and regulations and
determine that the loss can reasonably be estimated. When the loss is
determined it is charged to earnings. The Company's management must
continually monitor known and potential contingent matters and make
appropriate provisions by charges to earnings when warranted by
circumstance.

RESULTS OF OPERATIONS



Production

For the periods ended December 31, Endev achieved the following daily
production rates:

------------------------------------------------------------------------
Three months ended Year Ended
December 31 December 31
------------------------------------------------------------------------
Daily production 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Crude oil (bbl/d) 648 826 800 1,077 1,334
Natural gas liquids (bbl/d) 80 114 99 206 314
Natural gas (mcf/d) 22,744 11,341 15,606 9,447 8,991
------------------------------------------------------------------------
Total production (boe/d) 4,518 2,830 3,500 2,857 3,147
------------------------------------------------------------------------


Production increased 60 percent to 4,518 boe/d for the three months
ended December 31, 2004 compared to 2,830 boe/d for the same period in
2003. Crude oil and natural gas liquids (NGLs) production for the fourth
quarter decreased 23 percent or 212 bbl/d to 728 bbl/d, compared to 940
bbl/d for the same period in 2003. In the fourth quarter, natural gas
production increased 100 percent to 22,744 mcf/d compared to 11,341
mcf/d for the same period in 2003. The increase in natural gas
production was the result of a very successful drilling program in the
Majorville area in the latter part of 2004.

Endev's production increased 23 percent to 3,500 boe/d for the year
ended December 31, 2004 when compared to 2,857 boe/d for the same period
a year ago. Our 2004 production consisted of 74 percent natural gas and
26 percent oil and natural gas liquids.

Natural gas volumes increased 65% to 15,606 mcf/d for the year ended
December 31, 2004 compared to 9,447 mcf/d in 2003. The Company
participated in 146 gas wells with a 100 percent success rate in the
Majorville area. This program resulted in average production from the
Majorville area of approximately 11 mmcf/d for the year ended December
31, 2004.

Crude oil and natural gas liquids production for the year ended December
31, 2004 decreased 30% or 384 bbl/d to 899 bbl/d compared to 1,283 bbl/d
for the same period in 2003. The decrease was due to the rationalization
of non-core assets, natural production declines, and decline of liquids
production at Chambers and oil production at Ogston.

Commodity Markets

Natural Gas

Natural gas prices rose in the US over the year by US$0.65 /mcf on the
Nymex Exchange to average US$6.09/mcf in 2004. The AECO spot daily gas
index was down $0.11/mcf year-over-year (1.7 percent) to $6.52/mcf. The
failure of Alberta spot prices to rise in tandem with US prices was in
part due to the currency effect of a rising Canadian dollar. In the
fourth quarter, US prices on the NYMEX rose by US$1.02 /mcf over the
prior quarter while AECO increased only CDN$0.32/mcf.

Endev believes the supply/demand balance for natural gas in North
America will remain tight over the medium term despite increased
drilling in both Canada and the United States.

Crude Oil

Endev benefited from rising energy prices in 2004, though the impact of
increasing commodity prices in the US was partially offset by the
continued appreciation in the Canadian dollar. Oil prices rose steadily
over the year with West Texas Intermediate (WTI) averaging US$41.42
/bbl, up US$10.38 /bbl (34.5 percent) over the prior year. WTI rose
US$4.40 /bbl in the fourth quarter over the prior quarter and US$17.10
/bbl over the fourth quarter of 2003. The Canadian dollar rose from an
average of US$0.716 in 2003 to an average of US$0.77 in 2004. Edmonton
par prices increased to CDN$52.20/bbl in 2004, up $9.06/bbl (21 percent)
over 2003. Lower quality Canadian crude experienced much less of the
increase in the value of WTI as a worldwide surplus of heavier crude
widened differentials to historic levels. The Company's average
differential to Edmonton par was virtually unchanged over the prior year
at $6.53/bbl.

Endev expects strong world crude prices to continue in the medium term
as strong global demand growth keeps crude supply/demand fundamentals
tight. The Company believes that world crude prices are influenced by
geopolitical risks, tight supply/demand fundamentals and a lack of
infrastructure to process, store, refine and transport sufficient crude
volumes.



Average Prices Received

For the periods ended December 31, Endev realized the following
commodity prices:

Three months ended Year Ended
December 31 December 31
Average sales prices realized 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Crude oil (before hedging)
($/bbl) 56.19 34.20 45.97 37.35 36.45
Hedging settlements ($/bbl) - - (0.16) (0.05) -
Crude oil (after hedging)
($/bbl) 56.19 34.20 45.81 37.30 36.45
Natural gas liquids ($/bbl) 46.06 29.40 40.55 35.79 33.75
Natural gas ($/mcf) 6.61 5.68 6.55 6.52 4.06
Weighted Average ($/boe) (6:1) 42.16 34.07 40.87 38.20 30.96


Operating Netbacks

For the periods ended December 31, Endev realized the following
operating netbacks from oil and gas operations:

Three months ended Year Ended
December 31 December 31
Netback per boe (6:1) ($) 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Petroleum and natural gas
revenues 42.16 34.07 40.87 38.20 30.96
Royalties, net of ARTC 8.49 6.25 7.87 7.30 5.46
Operating expenses 5.90 6.90 7.03 7.93 7.98
Transportation 1.12 1.23 0.98 0.72 0.52
------------------------------------------------------------------------
Operating netback 26.65 19.69 24.99 22.25 17.00
------------------------------------------------------------------------


Production Revenue

For the fourth quarter, gross revenues increased 98 percent to $17.6
million from $8.9 million for the same period in 2003 mainly due to the
increase in natural gas production volume. Natural gas production
increased 100 percent to 22,744 mcf/d in the fourth quarter of 2004
compared to 11,341 mcf/d for the same period in 2003. The average price
received for natural gas increased 16% to $6.61 per mcf in the fourth
quarter of 2004 compared to $5.68 per mcf in 2003.

Crude oil and natural gas liquids (NGLs) production for the fourth
quarter decreased 23 percent or 212 bbl/d to 728 bbl/d, compared to 940
bbl/d for the same period in 2003. This decrease resulted from natural
declines and the rationalization of non-core assets. The average price
received for crude oil increased 64 percent to $56.19 per bbl in the
fourth quarter of 2004 compared to $34.20 in 2003.



For the years ended December 31, Endev realized the following gross
revenues:
Three months ended Year Ended
December 31 December 31
($millions) 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Crude oil 3.5 2.6 13.4 14.7 8.9
Natural gas liquids 0.3 0.4 1.5 2.6 2.0
Natural gas 13.8 5.9 37.4 22.5 6.7
------------------------------------------------------------------------
Total 17.6 8.9 52.3 39.8 17.6
------------------------------------------------------------------------


Revenue for the year ended December 31, 2004 increased by 31 percent to
$52.3 million when compared to $39.8 million for the same period in
2003. This increase in revenue was achieved due to significantly higher
natural gas volumes resulting from a very successful drilling program in
the Majorville area. In 2004, natural gas prices averaged $6.55 per mcf,
up from $6.52 in 2003. Average oil prices increased 23 percent to $45.81
per bbl in 2004 from $37.30 per bbl in 2003. The increase in the oil
price received was offset by a decrease in the volume.



Royalties

Three months ended Year Ended
December 31 December 31
2004 2003 2004 2003 2002
------------------------------------------------------------------------
Royalties ($millions) 3.5 1.6 10.1 7.6 3.2
Average royalty rate (%) 20 18 19 19 18
$/boe 8.49 6.25 7.87 7.30 5.46


Royalties, net of the Alberta Royalty Tax Credit (ARTC), were $3.5
million in the fourth quarter of 2004 and $1.6 million in the fourth
quarter of 2003, and averaged $8.49 per boe or 20 percent of revenue
compared to $6.25 per boe or 18 percent of revenue for the same period
in 2003. This increase is a direct result of the higher natural gas
revenue realized in the period compared to the same period in 2003.

Royalties, net of the Alberta Royalty Tax Credit, increased 33 percent
from $7.6 million for the year ended December 31, 2003 to $10.1 million
for the same period in 2004 mainly due to the increase in natural gas
revenue. Royalties as a percentage of revenue was 19 percent for 2004
and 2003.



Expenses
Three months ended Year Ended
December 31 December 31
($millions) 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Operating 2.5 1.8 9.0 8.3 4.6
Transportation 0.5 0.3 1.3 0.8 0.3
General and administrative 0.8 0.8 3.5 2.8 2.0
Interest 0.4 0.2 1.1 0.4 0.1


Three months ended Year Ended
December 31 December 31
Expenses per boe $ 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Operating 5.90 6.90 7.03 7.93 7.98
Transportation 1.12 1.23 0.98 0.72 0.52
General and administrative 1.85 2.98 2.73 2.71 3.37
Interest 0.87 0.53 0.83 0.40 0.09


Operating

During the fourth quarter of 2004 operating expenses increased 39
percent to $2.5 million compared to $1.8 million in the same period for
2003. On a per unit basis, operating costs decreased 14 percent to $5.90
per producing boe during the quarter compared to $6.90 per producing boe
in the same period for 2003. This decrease was the result of the
increase in natural gas production volumes in the Majorville area where
the majority of the gas is processed through company owned facilities.

Industry activity, driven by strong commodity prices, increased in 2004
when compared to 2003. Despite the increased pressure on operating
costs, the Company added lower per unit operating cost production in the
Majorville area, resulting in decreased average per unit operating costs
in 2004. Average operating costs decreased to $7.03 per boe for the year
ended December 31, 2004 from $7.93 per boe in 2003. Total operating
costs increased to $9.0 million for 2004 compared to $8.3 million for
the same period in 2003. This increase resulted from the higher
production volume.

Transportation

Transportation costs averaged $1.12 per boe in the fourth quarter of
2004 compared to $1.23 per boe in the fourth quarter of 2003.

Transportation costs averaged $0.98 per boe for the year ended December
31, 2004 compared to $0.72 per boe in 2003. This increase was due to
increased gas production and inflation on service costs.

General and Administrative

General and administrative costs remained unchanged at $0.8 million in
the fourth quarter of 2004 and 2003. The fourth quarter of 2004 included
executive recruiting fees of $0.2 million incurred in the period related
to the recruitment of the new management team. General administrative
costs during the fourth quarter were $1.85 per producing boe compared to
$2.98 per producing boe for the same period in 2003. The decrease is due
to the higher volumes in 2004.

General and administrative expenses, after overhead recoveries of $0.9
million, increased to $3.5 million for the year ended December 31, 2004
from $2.8 million after overhead recoveries of $0.6 million in 2003. On
a per boe basis, general and administrative expenses remained relatively
flat at $2.73 per boe for the year ended December 31, 2004 compared to
$2.71 per boe for the same period in 2003. General and administrative
expenses for the year ended December 31, 2004 included $1.1 million or
$0.87 per boe consisting of severance obligations paid to the former
President and COO and to the Chairman of the Board for termination of
his position as Chief Executive Officer and executive search firm fees
related to the recruitment of the new management team.

Interest and Financing Charges

Interest and financing charges for the fourth quarter of 2004 were $0.4
million or $0.87 per producing boe compared to $0.2 million or $0.53 per
producing boe for the comparable period in 2003.

Interest and financing charges increased 155 percent to $1.1 million for
the year ended December 31, 2004 from $0.4 million in 2003. Interest and
financing charges on a per boe basis also increased 108 percent to $0.83
per boe for the year ended December 31, 2004 from $0.40 in 2003. The
increase in interest and financing charges is a direct result of
increased average debt from drilling activities accumulated during the
year.

Stock-based Compensation

The Company adopted the new standards on accounting for stock-based
compensation effective January 1, 2003. Stock-based compensation costs
were $0.4 million in the fourth quarter of 2004 compared to $0.04
million for the same period of 2003.

Stock-based compensation costs of $0.5 million or $0.42 per boe were
recognized in 2004 compared to $0.1 million or $0.13 per boe in 2003.

Income and Capital Taxes

Current taxes consists of Federal Large Corporations Tax (LCT) which is
calculated based on the debt and equity balances of each legal entity
comprising Endev Energy Inc. as the consolidated entity. The 2003
Federal budget proposed that the LCT rate is to be reduced over a period
of five years, so that by 2008, the tax will be eliminated.

Current taxes, which include LCT, were a recovery of $0.2 million for
the fourth quarter of 2004 compared to $0.1 million in 2003.

Current taxes, which include LCT, were $0.05 million for the year ended
December 31, 2004 and $0.2 million in 2003.

Capital taxes are primarily the Saskatchewan Capital Tax and Resource
Surcharge, which is based on Saskatchewan oil and gas revenues and
Manitoba Capital Tax. Capital taxes were $0.1 million for each of the
years ended December 31, 2004 and 2003.

Future income tax liabilities arise due to the difference between the
tax basis of assets and their respective accounting carrying cost. For
the year ended December 31, 2004, the provision for future taxes was
$0.3 million. Included in the year ended December 31, 2004 provision for
future income taxes is a benefit of $0.05 million, resulting from the
benefit of substantially enacted changes to Federal and Alberta tax
rates and deductions for resource income. The changes reduce the rate of
tax on resource income, provide for the deduction of Crown charges and
eliminate the resource allowance to be phased in over a five-year period.

Depletion and Depreciation

Depletion and depreciation expense for the fourth quarter was $8.0
million or $19.09 per boe, compared to $5.2 million or $20.06 per boe
for the same period in 2003. The increase in depletion during the fourth
quarter was due to higher production volume.

Depletion and depreciation is calculated using the unit-of-production
method based on total estimated proved reserves. Depletion and
depreciation expense increased 95 percent to $25.0 million for the year
ended December 31, 2004 from $12.9 million in 2003 due to our increased
production levels and larger asset base. The average per unit cost
increased 58 percent to $19.51 per boe for the year ended December 31,
2004 from $12.32 per boe in 2003. The increase in the depletion rate was
due to adjustments to proved reserves at January 1, 2004 with adoption
of new reserve definitions under NI 51-101.

Asset Retirement Obligation Accretion

The provision for accretion of asset retirement costs for the fourth
quarter was $0.15 million or $0.36 per boe, compared to $0.15 million or
$0.49 per boe for the same period in 2003.

Effective January 1, 2004, the Company adopted the new accounting policy
with respect to accounting for asset retirement obligation. The Company,
under the current policy, is required to provide for future removal and
site restoration costs. The Company must estimate these costs in
accordance with existing laws, contracts or other policies. These
estimated costs are charged to income and the appropriate liability
account over the expected service life of the asset.

The provision for accretion of these costs for the year ended December
31, 2004 was $0.6 million or $0.44 per boe compared to $0.5 million or
$0.47 per boe in 2003.



Net Income and Cash Flow from Operations

Three months ended Year Ended
December 31 December 31
($millions, except per
share amounts) 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Net income (loss) 0.3 (0.2) 0.9 6.1 1.5
Basic per share - - 0.01 0.08 0.04
Diluted per share - - 0.01 0.08 0.04
Cash flow from operations 10.2 4.0 27.7 19.6 7.7
Basic per share 0.12 0.05 0.32 0.26 0.20
Diluted per share 0.12 0.05 0.31 0.25 0.19


The Company realized net income of $0.3 million for the fourth quarter,
with earnings of $nil per share on a basic and diluted basis compared to
a net loss of $0.2 million for the same period in 2003, with a loss of
$nil per share on a basic and diluted basis. The increase in net income
was due mainly to the increase in natural gas production volumes and
revenues. Cash flow from operations, a non-GAAP measurement, before
adjusting for the change in non-cash working capital, for the fourth
quarter increased 155 percent to $10.2 million in 2004 compared to $4.0
million for the same period in 2003. On a per unit basis cash flow from
operations increased 140 percent to $0.12 per share on a basic and
diluted basis compared to $0.05 per share on a basic and diluted basis
for the same period in 2003.

Net income decreased to $0.9 million for the year ended December 31,
2004 from $6.1 million for the same period in 2003. Higher net revenues
were more than offset by an increase in depletion expense due an
increase in the depletion rate, additional general and administrative
costs for severance obligations and higher interest cost for the
additional bank debt.

For the year ended December 31, 2004, Endev achieved a 41 percent
increase in cash flow from operations to $27.7 million ($0.32 per share
basic) from $19.6 million ($0.26 per share basic) in 2003. This increase
is primarily the result of an increase in natural gas production volume
and associated revenue.



QUARTERLY FINANCIAL INFORMATION
Net Income
(loss)
Net Per Income Per Share
($000s) except per share amounts Revenue(1) (Loss) Basic Diluted
------------------------------------------------------------------------
2004
First quarter 9,567 273 - -
Second quarter 9,585 488 0.01 0.01
Third quarter 9,023 (140) - -
Fourth quarter 14,089 305 - -
------------------------------------------------------------------------
42,264 926 0.01 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------
2003
First quarter 9,521 2,126 0.03 0.03
Second quarter 7,785 3,092 0.04 0.04
Third quarter 7,670 1,103 0.01 0.01
Fourth quarter 7,244 (231) - -
------------------------------------------------------------------------
32,220 6,090 0.08 0.08
------------------------------------------------------------------------
------------------------------------------------------------------------

(1)Net after royalties

FOURTH QUARTER HIGHLIGHTS
Three months ended
----------------------------------------------
Dec 31 Sept 30 Dec 31
2004 2004 Variance 2003 Variance
------------------------------------------------------------------------
Financial
($millions, except per
share amounts)
Gross revenue (1) 17.6 11.2 57 % 8.9 98 %
Cash flow from operations 10.2 5.7 79 % 4.0 155 %
Basic per share 0.12 0.07 71 % 0.05 140 %
Diluted per share 0.12 0.06 100 % 0.05 140 %
Net income (loss) (2) 0.3 (0.1) 400 % (0.2) 250 %
Basic per share - - -
Diluted per share - - -
Capital expenditures, net 7.7 15.5 50 % 9.3 17 %
Net debt 32.2 35.4 9 % 26.7 (21)%

Operations
Daily production
Crude oil (bbl) 648 759 (15)% 826 (22)%
Natural gas liquids (bbl) 80 91 (12)% 114 (30)%
Natural gas (mcf) 22,744 13,013 75 % 11,341 100 %
Total production
(boe @ 6:1) 4,518 3,018 50 % 2,830 60 %
Average sales price
Crude oil ($/bbl) 56.19 46.73 20 % 34.20 64 %
Natural gas liquids
($/bbl) 46.06 42.39 9 % 29.40 57 %
Natural gas ($/mcf) 6.61 6.35 4 % 5.68 16 %
Netback per boe (6:1) ($)
Petroleum and natural
gas revenues 42.16 40.42 4 % 34.07 24 %
Royalties, net of ARTC 8.49 7.93 (7)% 6.25 (36)%
Operating expenses 5.90 8.88 31 % 6.90 12 %
Transportation 1.12 0.99 13 % 1.23 9 %
Operating netback 26.65 22.62 18 % 19.69 35 %

(1) Gross of transportation costs previously included in revenue.

(2) Net income for the three months ended December 31, 2003 has been
restated reflecting the retroactive adoption of stock-based
compensation and asset retirement obligation pronouncements.


CAPITAL EXPENDITURES

The following table outlines our capital expenditures in 2004
compared to 2003 and 2002.

Three months ended Year Ended
December 31 December 31
($000s) 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Acquisitions - 6 - 45,872 40,458
Dispositions - (177) - (5,569) (1,411)
------------------------------------------------------------------------
- (171) - 40,303 39,047
------------------------------------------------------------------------
Land and seismic 1,467 82 2,191 2,686 713
Drilling and completions 2,478 4,517 20,739 27,117 1,610
Tie-ins and facilities 3,728 10,251 11,064 16,761 391
Other 4 44 18 69 129
------------------------------------------------------------------------
Net property 7,677 14,894 34,012 46,633 2,843
------------------------------------------------------------------------
Total net capital expenditures 7,677 14,717 34,012 86,936 41,890
------------------------------------------------------------------------


The Company spent $34.0 million to drill, complete and tie-in 146 gas
wells (112.4 net) for the year ended December 31, 2004 for a 100 percent
success rate. Costs of $32.0 million were incurred in the Majorville
area and $2.0 million was spent on minor properties.

DRILLING ACTIVITIES

During 2004, Endev continued to focus on the Majorville area where
activity included drilling 146 wells (112.4 net) as at December 31,
2004, and completion of 36 existing well bores targeting Belly River
formation gas. These completions resulted in commingled gas production
with the Milk River/Medicine Hat zones in 33 wells and 3 Belly River
only producing wells.



2004 Fourth Quarter Drilling Results

Gross Net
---------------------- -----------------------
Gas Oil Dry Total Gas Oil Dry Total
---------------------- -----------------------
Majorville 23 - - 23 11.5 - - 11.5
----------------------------------------------

2004 Drilling Results

Gross Net
---------------------- -----------------------
Gas Oil Dry Total Gas Oil Dry Total
---------------------- -----------------------
Majorville 146 - - 146 112.4 - - 112.4
----------------------------------------------


The year-to-date success rate of wells drilled, net to Endev's
interests, stands at 100 percent. As at December 31, 2004, 133 wells
(106.7 net) have been tied-in and are on production, the remaining wells
will be tied in following additional drilling operations and building of
infrastructure in 2005.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

Endev's one year finding, development and acquisition costs were $10.45
per boe on a proved plus probable basis including future development
capital and $14.59 per boe on a proved basis including future
development capital. Endev's three year average finding, development and
acquisition costs were $11.05 per boe on a proved plus probable basis
including future development capital and $16.55 per boe on a proved
basis including future development capital.



UNDEVELOPED LAND SUMMARY

As at December 31, 2004
(acres) Gross Net
--------------------------------------------------------------
Alberta 129,315 73,179
Saskatchewan 744 241
British Columbia 316 43
--------------------------------------------------------------
Total undeveloped 130,375 73,463
--------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Endev has a revolving credit facility with the National Bank of Canada
for $38 million and an acquisition/development facility of $10 million.
At December 31, 2004, the Company had approximately $29.4 million
outstanding on its revolving credit facility and a working capital
deficiency of $2.8 million for total net debt of approximately $32.2
million.

Total net capital expenditures of $34.0 million for the year ended
December 31, 2004, were funded primarily from cash flow and additional
bank debt.

Future capital expenditures and operations are anticipated to be funded
with cash flow and additional debt.

SHARE INFORMATION

The Company had 87,835,888 shares outstanding as at March 2, 2005.

The Company issued a total of approximately 1.3 million shares net of
share cancellations pursuant to the exercise of stock options and
settlement of severance obligations. On August 12, 2002, 596,472 common
shares of the Company were placed in trust, to be released subject to
satisfaction of certain conditions. As these conditions had not been
met, all such common shares were cancelled on March 3, 2004.


Three months ended Year Ended
December 31 December 31
(000s) 2004 2003 2004 2003 2002
------------------------------------------------------------------------
Shares outstanding
- Basic 87,803 86,482 87,803 86,482 69,421
- Diluted 91,575 89,896 91,575 89,896 72,633
Weighted average shares
outstanding
- Basic 87,337 86,482 86,643 75,482 39,040
- Diluted 89,305 88,829 88,430 78,331 39,921


BUSINESS RISKS

The oil and gas exploration and development sector has inherent risks
that begin with the exploration process, which is capital intensive and
may or may not encounter economic reserves of crude oil or natural gas,
in addition to unforeseen production declines and as a consequence
reduced reserves. Increasingly, readily available technology helps to
mitigate the risk. Endev employs the most appropriate technology in all
areas of its business. The intrinsic business and financial risks within
the industry include volatility of commodity prices, fluctuation in
supplier costs, inflation, changes in exchange rates, the cost of
capital and other macro economic factors. Endev focuses on managing the
costs within its control and pursuing geographic areas and geologic
targets that result in manageable capital risk. By focusing on core
areas, Endev reduces risk by utilizing its experience in the area and
reducing the administrative and logistical costs of its field activity.
In order to minimize the risks to the community and to its field staff
and suppliers, Endev demands the highest standards of safety on its
leases.

Sensitivity Analysis

The following table shows sensitivities to cash flow as a result of
product price and operations changes. The table is based on actual 2004
prices and production volumes.



Change to annual cash flow
Change $000s $/share (2)
Price per barrel of oil (US$ WTI) (1) $ 1.00 305 0.004
Price per mcf of natural gas (C$ AECO) (1) $ 0.25 1,142 0.013
Oil production volumes - 100 bbl/d (1) 12.5% 1,319 0.015
Gas production volumes - 1 mmcf/d (1) 6.4% 1,914 0.022
Exchange rate (US/Canadian) $ 0.01 171 0.002
Interest rate on debt ($30 million) 1% 300 0.003

(1) After adjustment for estimated royalties.
(2) Based on 2004 weighted average basic shares


TRANSACTIONS WITH RELATED PARTIES

During the year ended December 31, 2004, the Company paid $77,000 to
Petrofund Corp. (Petrofund) which has two directors in common with
Endev, for computer related services. In 2003 the Company paid $375,000
to NCE Management Services Inc. (NMSI) for accounting and administrative
services. The Chairman and former CEO of the Company was the sole
shareholder of NMSI. These costs are reflected in the consolidated
statement of operations and retained earnings as general and
administrative expenses. The NMSI contract was terminated effective May
31, 2003.

As a result of being a shareholder of one of the acquired private
companies, a director of Endev Energy Inc. received gross proceeds of
$564,000 including a hold-back adjustment in relation to the purchase of
the five private companies during the period. The director did not
initiate this purchase and abstained from approving of the transaction
by the Board.

The purchase and sale transaction concluded on July 15, 2003 for net
proceeds of $4.6 million before adjustments, was completed with
Petrofund. Neither of the directors of Petrofund initiated this
transaction and both abstained from approving of the transaction by the
Board.

CONTRACTUAL OBLIGATIONS

The Company entered into a lease for office premises commencing January
1, 2004 and terminating on March 29, 2007. The estimated annual
obligation including operating costs at current levels is $251,868 or
$20,989 per month for approximately 13,600 square feet of office space.
The Company has subleased approximately 3,300 square feet of surplus
area on the same commercial terms to recover approximately $58,575 per
annum or $4,900 per month.

OFF BALANCE SHEET ARRANGEMENTS

The Company had entered a hedge transaction via a costless collar for
400 barrels per day of oil with a floor of US$27.50 and a ceiling of
US$31.00 for the period November 1, 2003 to March 31, 2004. The Company
has entered into no other hedging arrangements since March 31, 2004.

IMPACT OF NEW CANADIAN ACCOUNTING PRONOUNCEMENTS

Fair Value of Derivative Instruments

In November 2002, the Canadian Institute of Chartered Accountants (CICA)
amended the effective date of its accounting guideline on hedging
relationships, which was originally issued in November 2001. The
guideline establishes certain conditions where hedge accounting may be
applied. It is effective for fiscal years beginning on or after July 1,
2003. The guideline will not have a significant impact on the Company's
financial position or results of operations.

Asset Retirement Obligations

In December 2002, the CICA issued a new standard on the accounting for
asset retirement obligations. This standard, as with the new U.S.
standard (FAS 143) requires recognition of a liability for the future
retirement obligations associated with property, plant and equipment.
These obligations are initially measured at fair value, which is the
discounted future value of the liability. This fair value is capitalized
as part of the cost of the related asset and amortized to expense over
its useful life. The liability accretes until the date of expected
settlement of the retirement obligations. The new standard is effective
for all fiscal years beginning on or after January 1, 2004 but earlier
adoption was encouraged. The impact of the effect of this new standard
on the financial statements is to increase property, plant and
equipment, and asset retirement obligation on the balance sheet, but it
is not expected to have a material impact on earnings.

Full Cost Accounting for Oil and Gas Activities

In September 2003, the application of the impairment test for companies
following the full cost method of accounting for oil and natural gas
properties was revised through Accounting Guideline 16 - Oil and Gas
Accounting - Full Cost (AcG-16). The new guideline, which is effective
for all fiscal years commencing on or after January 1, 2004, limits the
carrying value of oil and natural gas properties to their fair value,
which is ascertained from the estimated future cash flows from proved
and probable reserves using future price forecasts and costs discounted
at a risk free basis. This differs from the prior ceiling test that used
undiscounted cash flows and constant prices and costs less general and
administrative and financing costs. There is no write down of the
Company's oil and natural gas property and royalty interests December
31, 2004. Further, AcG-16 also adopted the reserve evaluation procedures
and disclosure requirements of NI 51-101 which are included with this
report.

Continuous Disclosure Obligations

Effective March 30, 2004, all reporting issuers are subject to the new
disclosure requirements of National Instrument 51-102 - Continuous
Disclosure Obligations, for year-ends commencing on or after January 1,
2004. The Instrument mandates enhanced and shorter reporting periods for
filing annual and interim financial statements, Management's Discussion
and Analysis (MD&A) and the Annual Information Form (AIF). This
instrument enables companies to provide the annual and interim financial
statements, MD&A and AIF on an "as requested" basis to shareholders.

Other accounting standards issued by the CICA during the year ended
December 31, 2004 are not expected to impact the Company at this time.

FORWARD-LOOKING STATEMENTS

Certain information regarding Endev Energy Inc. set forth in this entire
document, including management's assessment of the Company's future
plans and operations contains forward-looking statements that involve
substantial known and unknown risks and uncertainties. These
forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond the Company's and management's
control, including but not limited to, the impact of general economic
conditions, industry conditions, fluctuation of commodity prices,
fluctuation of foreign exchange rates, imperfection of reserve
estimates, environmental risks, industry competition, availability of
qualified personnel and management, stock market volatility, and timely
and cost-effective access to sufficient capital from internal and
external sources. Endev'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 to occur or transpire from the
forward-looking statements will provide what, if any benefits to Endev
Energy Inc.

NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR DISSEMINATION IN THE
UNITED STATES.



ENDEV ENERGY INC.
Consolidated Balance Sheets
($000s)

As at December 31 2004 2003
------------------------------------------------------------------------
Restated
ASSETS (notes 3 and 5)
Current
Cash and short term investments $ - $ 2,421
Accounts receivable 7,385 4,864
Prepaid expenses and deposits 226 243
------------------------------------------------------------------------
7,611 7,528
Property, plant and equipment
(notes 4 and 6) 125,482 116,506
Goodwill (note 4) 7,800 7,800
------------------------------------------------------------------------
$ 140,893 $ 131,834
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Bank indebtedness (note 7) $ 29,419 $ 18,800
Accounts payable and accrued liabilities 10,402 15,398
Current taxes payable 24 10
------------------------------------------------------------------------
39,845 34,208
Asset retirement obligations (note 5) 7,517 6,587
Future income taxes (note 8) 16,923 16,653
------------------------------------------------------------------------
64,285 57,448
------------------------------------------------------------------------

SHAREHOLDERS' EQUITY
Share capital (note 9) 67,425 66,617
Contributed surplus (note 9) 627 139
Retained earnings 8,556 7,630
------------------------------------------------------------------------
76,608 74,386
------------------------------------------------------------------------
$ 140,893 $ 131,834
------------------------------------------------------------------------
------------------------------------------------------------------------
Commitments (note 13)
Signed on behalf of the Board:

John F. Driscoll, Director Richard Zarzeczny, Director

The accompanying notes are integral to these consolidated financial
statements


ENDEV ENERGY INC.
Consolidated Statements of Operations and Retained Earnings
($000s except per share information)

For the period ended Three months ended Year ended
December 31 2004 2003 2004 2003
------------------------------------------------------------------------
(unaudited)(unaudited)

Restated Restated
(notes 3 (notes 3
and 5) and 5)

REVENUES
Petroleum and natural gas $ 17,615 $ 8,871 $ 52,349 $ 39,837
Royalties (net of Alberta
Royalty Tax Credit) (3,527) (1,627) (10,085) (7,617)
Interest and other revenue - 1 - 39
------------------------------------------------------------------------
14,088 7,245 42,264 32,259
------------------------------------------------------------------------

EXPENSES
Operating 2,451 1,797 9,002 8,266
Transportation 465 321 1,260 754
General and administrative 767 775 3,499 2,828
Stock-based compensation 359 40 537 139
Interest 361 137 1,062 417
Capital taxes 22 (16) 91 92
Depletion and depreciation 7,937 5,224 24,999 12,850
Accretion of asset
retirement obligations 150 128 563 493
------------------------------------------------------------------------
12,512 8,406 41,013 25,839
------------------------------------------------------------------------
Income (loss) before taxes 1,576 (1,161) 1,251 6,420
------------------------------------------------------------------------
TAXES (RECOVERY) (note 8)
Current (213) 85 55 185
Future income 1,484 (1,015) 270 145
------------------------------------------------------------------------
1,271 (930) 325 330
------------------------------------------------------------------------
NET INCOME (LOSS) 305 (231) 926 6,090
Retained earnings,
beginning of period,
as previously reported 8,251 8,203 7,954 1,646
Cumulative effect of change
in accounting for asset
retirement obligations
(note 3) - (342) (324) (106)
------------------------------------------------------------------------
Retained earnings,
beginning of period
restated 8,251 7,861 7,630 1,540
------------------------------------------------------------------------
------------------------------------------------------------------------
Retained earnings,
end of period $ 8,556 $ 7,630 $ 8,556 $ 7,630
------------------------------------------------------------------------
------------------------------------------------------------------------

NET INCOME PER SHARE
(note 9)
Basic $ - $ - $ 0.01 $ 0.08
Diluted $ - $ - $ 0.01 $ 0.08
------------------------------------------------------------------------
The accompanying notes are integral to these consolidated financial
statements


ENDEV ENERGY INC.
Consolidated Statements Of Cash Flow
($000s)

For the period ended Three months ended Year ended
December 31 2004 2003 2004 2003
------------------------------------------------------------------------
(unaudited)(unaudited)
Restated Restated
(notes 3 (notes 3
and 5) and 5)

Cash provided by (used in)

OPERATIONS
Net income (loss) $ 305 $ (231) $ 926 $ 6,090
Depletion and depreciation 7,937 5,224 24,999 12,850
Accretion of asset
retirement obligations 150 128 563 493
Future income taxes
(recovery) 1,484 (1,015) 270 145
Actual abandonment costs (25) (99) (55) (115)
Stock-based compensation 359 40 537 139
Shares issued for
severance obligations - - 450 -
------------------------------------------------------------------------
Funds from operations 10,210 4,047 27,690 19,602
Changes in non-cash working
capital (note 12) (3,550) 2,938 (1,961) (2,617)
------------------------------------------------------------------------
6,660 6,985 25,729 16,985
------------------------------------------------------------------------
FINANCING
Issue of common shares, net 451 199 768 18,577
Bank indebtedness 371 12,180 10,619 18,800
------------------------------------------------------------------------
822 12,379 11,387 37,377
------------------------------------------------------------------------
INVESTING
Capital asset additions (7,677) (13,677) (34,012) (46,612)
Acquisitions - (2,274) - (31,565)
Cash acquired on acquisition - 1,364 - 1,364
Proceeds from disposition of
capital assets - 177 - 5,569
Changes in non-cash working
capital (note 12) 195 (3,313) (5,525) 10,684
------------------------------------------------------------------------
(7,482) (17,723) (39,537) (60,560)
------------------------------------------------------------------------
Increase (decrease) in cash - 1,641 (2,421) (6,198)
Cash, beginning of period - 780 2,421 8,619
------------------------------------------------------------------------
Cash, end of period $ - $ 2,421 $ - $ 2,421
------------------------------------------------------------------------
Interest paid $ 361 $ 137 $ 1,062 $ 417
------------------------------------------------------------------------
Taxes paid $ 175 $ (86) $ 370 $ 185
------------------------------------------------------------------------
------------------------------------------------------------------------
The accompanying notes are integral to these consolidated financial
statements


Notes to consolidated financial statements

December 31, 2004 and 2003

(all tabular amounts in $000s, except per share amounts)

1. NATURE OF OPERATIONS AND ORGANIZATION

Endev Energy Inc. is a Calgary-based company involved in the
exploration, development and production of petroleum and natural gas in
Alberta, Saskatchewan and Manitoba. These consolidated financial
statements include the accounts of Endev Energy Inc., it's wholly owned
subsidiary Moxie Exploration Ltd. from July 28, 2003 and Endev Resources
Partnership, a partnership formed effective August 1, 2003 by Endev
Energy Inc. and Moxie Exploration Ltd. collectively referred hereinafter
as "Endev" or the "Company".

Endev Energy Inc. was originally incorporated pursuant to the provisions
of the Business Corporation Act of Alberta on May 31, 1995 as 656525
Alberta Ltd. The name was changed to Internet Filtering System Inc. on
October 18, 1995, to Net Shepherd Inc. on February 28, 1996, to Flock
Resources Ltd. on April 8, 2002 and again on June 10, 2002, to Endev
Energy Inc.

The Company, from its inception until the first quarter of 2002, was an
emerging Internet technology and development stage company and had
discontinued the operations of this business during the first half of
2002. In conjunction with the consolidation of the shares on the basis
of one new common share for each ten common shares formerly issued and
the private placement of 5.5 million shares at $0.25 per share, the
Company changed its focus to an oil and gas exploration and production
operation. In June 2002 it acquired the partnership units of nine
separate limited partnerships, the principal business of which was oil
and gas exploration and production. As the prior business was
discontinued, approval was obtained at the June 10, 2002 meeting of the
shareholders to eliminate the deficit of $140.86 million as at December
31, 2001, by reducing contributed surplus by $51.44 million and stated
capital by $89.42 million.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The consolidated financial statements are stated in Canadian dollars and
have been prepared in accordance with Canadian generally accepted
accounting principles.

The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, and disclosures of contingencies at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.

Principles of Consolidation

The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiary and partnership. All
inter-company transactions and balances have been eliminated.

Joint Ventures

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

Measurement Uncertainty

The amounts recorded for depletion and depreciation of oil and gas
properties and equipment and the provision for accretion of asset
retirement obligations are based on estimates. The ceiling test is based
on estimates of reserves, production rates, oil and 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.

Cash and Cash equivalents

Cash includes cash and short-term money market instruments with a
maturity of less than three months.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of
accounting whereby all costs of acquiring, exploring and developing, and
renewals and enhancements that extend the economic life of oil and gas
properties are capitalized. All costs of exploring for and developing
petroleum and natural gas properties and related reserves are
capitalized into a cost centre. Such costs include those related to
lease acquisition, geological and geophysical activities, lease rentals
on non-producing properties, drilling of productive and non-productive
wells, tangible production equipment, asset retirement costs, and that
portion of general and administrative expenses directly attributable to
exploration and development activities. Proceeds on sale or disposition
of oil and gas properties are credited to the full cost pool unless this
results in a change in the depletion and depreciation rate by 20 percent
or more, in which case a gain or loss is recognized in the statement of
operations.

i) Ceiling Test

The Company follows the full cost method of accounting for oil and gas
activities which requires a detailed impairment calculation at least
annually when events or circumstances indicate a potential impairment of
the carrying amount of oil and gas assets may have occurred.

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.

ii) Depletion and Depreciation

The provision for depletion and depreciation is computed using the
unit-of-production method based on the estimated gross proved oil and
gas reserves, before royalties, as determined by an independent
engineer. For purposes of the calculation, natural gas reserves and
production are converted to equivalent volumes of petroleum based upon
relative energy. Costs of significant unproved properties, net of
impairments are excluded from the depletion calculation. When Proved
reserves are assigned to the property or the property is considered to
be impaired, the cost of the property or the amount of impairment is
added to the full cost pool.

Depreciation of office equipment and furniture is provided for at 20
percent per annum.

Asset Retirement Obligations

The Company uses the asset retirement obligation method of recording the
future cost associated with removal, site restoration and asset
retirement costs. The fair value of the liability for the Company's
asset retirement obligation is recorded in the period in which it is
incurred, discounted to its present value using the Company's credit
adjusted risk-free interest rate and the corresponding amount is
recognized by increasing the carrying amount of petroleum and natural
gas properties. The liability amount is increased each reporting period
due to the passage of time and the amount of accretion is charged to
earnings in the period. Revisions to the estimated timing of cash flows
or to the original estimated undiscounted cost could also result in an
increase or decrease to the obligation. Actual costs incurred upon
settlement of the retirement obligation are charged against the
obligation to the extent of the liability recorded.

Goodwill

Goodwill is recorded in a corporate acquisition where the total purchase
price exceeds the net identifiable assets and liabilities of the
acquired company. The goodwill balance is not amortized but is assessed
for impairment annually in the fourth quarter, or when indications of
impairment are present. Where fair value of the consolidated entity is
less than the book value of the consolidated entity, a loss would be
charged to income for the amount that the carrying amount of the
goodwill exceeds its fair value.

Derivative Financial Instruments

The Company uses derivative financial instruments from time to time to
hedge its exposure to commodity price fluctuations within the Company's
risk management policy and does not enter these for trading or
speculative purposes.

The Company may enter into hedges of its exposure to oil and gas prices
by entering into collars. These derivative contracts, accounted for as
hedges, are not recognized on the balance sheet. Realized gains or
losses on these contracts are recognized in oil and gas revenues and
cash flows in the same period in which the revenues associated with the
hedged transaction are recognized.

The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective
and strategy for undertaking various hedge transactions. This process
includes linking all derivatives to specific assets and liabilities on
the balances sheet or to specific firm commitments or anticipated
transactions.

The Company also formally assesses, both at the hedge's inception and on
a ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values
or cash flows of hedged items. For cash flow hedges, effectiveness is
achieved if the changes in the cash flows of the derivative
substantially offset the changes in the cash flows of the hedged
position and the timing of the cash flows is similar. Effectiveness for
fair value hedges is achieved if the fair value of the derivative
substantially offsets changes in the fair value attributable to the
hedged item. In the event that a derivative does not meet the
designation or effectiveness criterion, the gain or loss on the
derivative is recognized in income. If a derivative that qualifies as a
hedge is settled early, the gain or loss at settlement is deferred and
recognized when the gain or loss on the hedged transaction is
recognized. Premiums paid or received with respect to derivatives that
are hedges are deferred and amortized to income over the term of the
hedge.

Realized gains or losses on changes in oil and natural gas commodity
prices are recognized in income in the same period and in the same
financial statement category as the income or expense arising from
corresponding commodity swap contracts.

Income Taxes

The Company follows the liability method of accounting for income taxes.
Under this method, income tax liabilities and assets are recognized for
the estimated tax consequences attributable to differences between the
amounts reported in the financial statements and their respective tax
bases, using enacted income tax rates. The effect of a change in income
tax rates on future tax liabilities and assets is recognized in income
in the period that the change occurs. Temporary differences arising on
acquisitions result in future income tax assets and liabilities.

Per Share Information

Basic net income per share is computed by dividing net income by the
weighted average number of shares outstanding during the period. The
weighted average number of shares is adjusted for the dilutive effect of
options. The dilutive effect of options uses proceeds received on
exercise of options to purchase common shares at the average price
during the period. The weighted average number of shares outstanding is
then adjusted by the net change.

Stock-based Compensation Plan

The Corporation has a stock-based compensation plan as described in note
9. Stock options granted after January 1, 2003 have been accounted for
based on the fair value method. The fair value is measured at the grant
date and charged to income over the vesting period with a corresponding
increase in contributed surplus. Consideration paid on exercise of
options is credited to share capital together with the amount previously
recognized in contributed surplus.

Prior to January 1, 2003, consideration paid by employees, officers or
directors on the exercise of stock options under the option plan were
recorded as share capital. The Company did apply the fair value method
to stock options granted to non-employees resulting in recognition of an
expense with a corresponding amount to contributed surplus. The
pro-forma impact on net income of stock options granted during 2002 has
been shown in note 9.

Revenue Recognition

Petroleum and natural gas revenues are recognized when the title and
risks pass to the purchaser. Revenue has been presented prior to
transportation costs and a separate expense for transportation costs has
been presented in the consolidated statement of operations and retained
earnings.

3. CHANGE OF ACCOUNTING POLICIES

(a) Asset retirement obligations

Effective January 1, 2004, the Company adopted the new Canadian
accounting standard for asset retirement obligations as outlined under
note 2. Prior to January 1, 2004, an estimate of future abandonment and
restoration costs was provided for using the unit-of-production method
over estimated gross Proved reserves.

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 as follows:



Balance Sheet 2003 2002
------------------------------------------------------------------------
Asset retirement cost, included in
property and equipment $ 4,492 $ 5,273
Asset retirement obligations $ 6,587 6,059
Future income tax liability $ (185) (70)
Accumulated site restoration and abandonment $ (1,586) (610)
Retained earnings $ (324) $ (106)
------------------------------------------------------------------------


Statement of Operations Year ended December 31, 2003
------------------------------------------------------------------------
Accretion expense $ 493
Depletion on asset retirement costs 785
Site restoration and abandonment expense (945)
Future income tax expense (115)
------------------------------------------------------------------------
Net earnings $ (218)
------------------------------------------------------------------------

Net earnings per share
Basic -
Diluted -
------------------------------------------------------------------------


(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 as outlined under note 2. Adoption of the new guideline
had no effect on the Company's financial statements.

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 as because there
were no hedge transactions at the year end.

(d) Transportation costs

For the fiscal year beginning January 1, 2004, the Company revised its
presentation of transportation costs in accordance with CICA Handbook
Section 1100 "Generally Accepted Accounting Principles". As a result,
revenue has been presented prior to transportation costs and a separate
expense for transportation costs has been presented in the consolidated
statement of operations and retained earnings. The Company has
reclassified previously reported amounts to be consistent with the
presentation under this new policy. There was no impact on net income or
cash flow in the years ended December 31, 2004 and December 31, 2003.

4. ACQUISITIONS

Effective February 28, 2003, Endev acquired all the issued and
outstanding shares of five private companies, which jointly owned an
interest in nine oil and gas producing properties, for net proceeds of
$11.5 million subject to adjustment. The transaction was accounted for
using the purchase method. The purchase price resulted in an excess
purchase price over the fair value of assets acquired of approximately
$4.5 million, which has been reflected as goodwill due to the intrinsic
value of acquiring the properties in a strategic core area. The purchase
was effective February 1, 2003, and the operating results were included
in the accounts of the Company from February 28, 2003.

On July 28, 2003, Endev acquired all the issued and outstanding shares
of Moxie Exploration Ltd. (Moxie), for total net proceeds of $21.5
million through the issuance of a total of 5,825,001 common shares of
the Company and total cash payment of $11.8 million. The purchase price
resulted in an excess purchase price over the fair value of assets
acquired of approximately $3.3 million, which has been reflected as
goodwill due to the value of acquiring the properties in Endev's key
strategic core area. This acquisition was accounted for using the
purchase method, with the operating results of Moxie being included in
the accounts of the Company from July 28, 2003.



A summary of the net assets acquired in 2003 is as follows:

Private Companies Moxie Total
Working capital deficiency $ (28) $ (520) $ (548)
Oil and gas properties 11,453 26,200 37,653
Abandonment liability - (146) (146)
Future income taxes (4,600) (7,370) (11,970)
Goodwill (note 1) 4,500 3,300 7,800
------------------------------------------------------------------------
Cost of acquisition $ 11,325 $ 21,464 $ 32,789
------------------------------------------------------------------------
------------------------------------------------------------------------


On March 12, 2003, Endev entered into an agreement to purchase an
interest in a shallow gas property in the Majorville area for a total
purchase price of $7.3 million, subject to adjustments, and closed this
transaction on April 9, 2003. The purchase was effective February 1,
2003, and the operating results were included in the accounts of the
Company from April 9, 2003.

On July 15, 2003, the Company purchased additional lands and production
in the Majorville area for a total purchase price of $2.0 million,
subject to adjustments and sold to the same party, for gross proceeds of
$6.6 million, subject to adjustments, certain non-core lands and
production. Thus the Company received a net before adjustments amount of
approximately $4.6 million. The transaction was effective June 1, 2003,
and the operating results from the purchase and sale were included in
the accounts of the Company from and until July 15, 2003.

5. ASSET RETIREMENT OBLIGATION

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. As at December 31, 2004,
the Company estimates the total undiscounted amount of cash flows
required to settle its asset retirement obligations is approximately
$14.3 million which will be incurred from 2005 to 2030. The majority of
the costs will be incurred between 2012 and 2030. A credit-adjusted
risk-free rate of eight percent was used to calculate the fair value of
the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

Asset Retirement Obligations
2004 2003
------------------------------------------------------------------------
Balance, beginning of year $ 6,587 $ 5,273
Accretion Expense 563 493
Costs incurred 422 936
Actual abandonment cost (55) (115)
------------------------------------------------------------------------
Balance, end of year $ 7,517 $ 6,587
------------------------------------------------------------------------

6. PROPERTY, PLANT AND EQUIPMENT

2004 2003
------------------------------------------------------------------------
Oil and gas properties $ 168,414 $ 134,457
Other assets 219 201
------------------------------------------------------------------------
168,633 134,658
Accumulated depletion and depreciation (43,151) (18,152)
------------------------------------------------------------------------
Net book value $ 125,482 $ 116,506
------------------------------------------------------------------------


During the year ended December 31, 2004, the Company capitalized $0.7
million (2003 - $0.9 million), of general and administrative expenses
related to exploration and development activities. As at December 31,
2004, the depletion calculation excluded unproved properties of $8.5
million (2003 - $12.2 million).

The Company has performed the ceiling test under AcG-16 as of December
31, 2004. The impairment test was calculated using forecast prices at
January 1 as outlined in the following table and adjusted for commodity
differentials specific to the Company:



FORECAST PRICES

-----------------------------------------------------------------------
Natural
Natural Gas Inflation Exchange
Crude Oil Gas Liquids Rates Rate
------------------------------------------------------------------------
Med Oil
Edmonton 25 degree
WTI City Gate API Alberta Pentanes +
$/bbl $/bbl Hardisty AECO Condensate $US/
Year US Cdn $/bbl Cdn $/mcf $/bbl %/year $Cdn
------------------------------------------------------------------------
2005 $42.00 $51.40 $33.40 $7.00 $53.95 2.0% 0.800
2006 $40.00 $48.85 $35.85 $6.90 $52.35 2.0% 0.800
2007 $38.00 $46.45 $34.30 $6.90 $50.70 2.0% 0.800
2008 $36.00 $43.95 $34.65 $6.50 $49.00 2.0% 0.800
2009 $34.00 $41.50 $32.90 $6.25 $47.15 2.0% 0.800
2010 $32.00 $39.00 $31.05 $5.90 $45.20 2.0% 0.800
2011+ 0.0% 0.0% 2.0% 2.0% 2.0% 2.0% 0.800
------------------------------------------------------------------------


7. BANK INDEBTEDNESS

As at December 31, 2004, the Company has a revolving demand credit
facility with a maximum availability of $38.0 million and an
acquisition/development facility for $10.0 million. The interest rate at
December 31, 2004, was prime plus 0.375 percent (4.625 percent) and
subject to quarterly adjustment from time to time based on certain debt
to cash flow ratios. The limit of the credit facility is subject to
adjustments from time to time to reflect changes in Endev's asset base.
There are no principal repayments required on the loan. The credit
facility is secured by a $75.0 million fixed and floating charge over
all the assets of the Company.

8. INCOME TAXES

The provision for current and future income taxes differs from the
result which would be obtained by applying the combined federal and
provincial statutory tax rates to income before income taxes. This
difference results from the following:



2004 2003
------------------------------------------------------------------------
Income before income tax provision $ 1,251 $ 6,420
------------------------------------------------------------------------
Statutory rates 38.62% 40.74%

Income tax provision computed at statutory rates $ 483 $ 2,615
Effect on income tax of:
Non-deductible crown charges 1,431 1,822
Resource allowance (1,961) (2,167)
Impact of future income tax rate reductions 56 (2,212)
Capital taxes and other non-deductibles 407 364
------------------------------------------------------------------------

Income tax expense $ 416 $ 422
------------------------------------------------------------------------


The oil and gas properties owned by the Company have a tax basis of
approximately $85.6 million (2003 - $70.8 million) available for future
use as deductions from taxable income. Included in this tax basis are
non-capital loss carry forwards of $11.5 million (2003 - $15.2 million)
which expire over the next five years.

Future income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts for income tax purposes. The
components of the Company's future income tax assets and liabilities are
as follows:



2004 2003
------------------------------------------------------------------------
Net book value of capital assets in excess
of tax pools $ 18,379 $ 19,799
Asset retirement obligations (2,667) (10)
Non-capital losses (4,171) (5,915)
Partnership income 5,382 2,779

------------------------------------------------------------------------

Future income tax liability $ 16,923 $ 16,653
------------------------------------------------------------------------
------------------------------------------------------------------------

9. SHARE CAPITAL

The authorized share capital of the Company consists of an unlimited
number of common shares without nominal or par value.

Issued and outstanding Common shares Amount
------------------------------------------------------------------------
Balance, December 31, 2002 69,420,801 $ 37,995
Options exercised 255,834 128
Issued for cash 10,979,889 19,764
Issued on acquisition of Moxie Exploration Ltd. 5,825,001 9,472
Share issue costs - (1,315)
Tax effect of share issue costs - 573
------------------------------------------------------------------------
Balance, December 31, 2003 86,481,525 $ 66,617
Options exercised 1,417,501 768
Shares issued in satisfaction of severance
obligations 500,000 450
Contributed surplus associated with options
exercised - 49
Cancelled (596,472) (459)
Balance, December 31, 2004 87,802,554 $ 67,425
------------------------------------------------------------------------

The weighted average number of shares outstanding is as follows:

2004 2003
------------------------------------------------------------------------
Basic 86,642,480 75,481,822
Diluted 88,430,150 78,331,399
------------------------------------------------------------------------


On August 12, 2002, 596,472 common shares of the Company were placed in
trust, to be released subject to satisfaction of certain conditions. As
these conditions had not been met, all such common shares were cancelled
on March 3, 2004.

On September 11, 2003, the Company closed a bought deal private
placement financing for gross proceeds of approximately $19.8 million
through the issuance of 10,979,889 common shares at $1.80 per share.

The Company has one fixed option plan where the Company may grant
options to its directors, officers, employees and consultants, for up to
6,942,456 shares of common stock. The following tables summarize
information about the fixed stock options outstanding at December 31,
2004:



2004 2003
------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
------------------------------------------------------------------------
Stock options outstanding,
beginning of year 3,414,000 $0.69 3,211,500 $0.55
Granted 2,610,000 1.06 480,000 1.59
Exercised (1,417,501) 0.54 (255,834) 0.50
Cancelled or expired (834,999) 1.22 (21,666) 0.50
------------------------------------------------------------------------
Stock options outstanding,
end of year 3,771,500 $0.89 3,414,000 $0.69
------------------------------------------------------------------------

------------------------------------------------------------------------
Exercisable at year-end 2,231,505 $0.75 1,212,111 $0.68
------------------------------------------------------------------------


Options Outstanding Options Exercisable
------------------------------------------------------------------------
Weighted Weighted Weighted
Range of Average Remaining Average
Exercise Number Exercise Contractual Number Exercise
Prices Outstanding Price Life (years) Exercisable Price
------------------------------------------------------------------------
$0.50 1,410,000 $0.50 2.3 1,410,000 $0.50
$0.66 - $0.90 556,500 0.81 4.0 316,502 0.75
$1.05 - $1.30 1,710,000 1.12 7.7 441,670 1.13
$1.67 - $2.27 95,000 1.91 3.4 63,333 1.91
----------------------------------------------------------
3,771,500 $0.89 5.0 2,231,505 $0.75
----------------------------------------------------------


All options granted vest as to one third upon grant and one third on
each of the first two anniversaries, and expire five years after the
grant, except for a portion of those granted on April 23, 2002, which
commence vesting in 2004 and 500,000 options granted on December 17,
2004 which vest on the stock reaching certain target prices and expire
ten years after the grant.

The fair value of each option granted is estimated on the date of grant
using the Black-Scholes option pricing model with weighted average
assumptions and resulting values for grants as follows:



Assumptions 2004 2003
------------------------------------------------------------------------
Risk free interest rate (%) 4.00 4.71
Expected life (years) 5.00 5.00
Expected volatility (%) 60 22
Weighted average fair value of each option granted ($) 0.50 0.49
Dividend yield (%) - -


Prior to January 1, 2003, the Company did not record compensation
expense when stock options were issued to employees, officers or
directors. Had the fair-value method been used for stock options issued
prior to January 1, 2003 the Company's net income and net income per
share would approximate the following pro forma amounts:



2004 2003
------------------------------------------------------------------------
Net income
As reported $ 926 $ 6,090
Pro forma $ 859 $ 5,944
Net income per share
Basic
As reported 0.01 0.08
Pro forma 0.01 0.08
Diluted
As reported 0.01 0.08
Pro forma 0.01 0.08
------------------------------------------------------------------------


CONTRIBUTED SURPLUS

2004 2003
------------------------------------------------------------------------
Balance, beginning of year $ 139 $ -
Stock-based compensation expense 656 139
Options exercised (49) -
Options forfeited and cancelled (119) -
------------------------------------------------------------------------
Balance, end of year $ 627 $ 139
------------------------------------------------------------------------


10. RELATED-PARTY TRANSACTIONS

During the year ended December 31, 2004, the Company paid $77,000 to
Petrofund Corp (Petrofund) which has two directors in common with Endev,
for computer related services. In 2003 the Company paid $375,000 to NCE
Management Services Inc. (NMSI) for accounting and administrative
services. The Chairman and former CEO of the Company was the sole
shareholder of NMSI. These costs are reflected in the consolidated
statement of operations and retained earnings as general and
administrative expenses. The NMSI contract was terminated effective May
31, 2003.

As a result of being a shareholder of one of the acquired private
companies (see note 4), a director of Endev Energy Inc. received gross
proceeds of $564,000 including a hold-back adjustment in relation to the
purchase of the five private companies during the period. The director
did not initiate this purchase and abstained from approving of the
transaction by the Board.

The purchase and sale transaction concluded on July 15, 2003 (see note
4) was completed with Petrofund. Neither of the Petrofund directors
initiated this transaction and both abstained from approving of the
transaction by the Board.

11. FINANCIAL INSTRUMENTS

(i) Fair value of financial instruments:

The Company's financial instruments consist of cash, accounts receivable
and accounts payable and accrued liabilities. As at December 31, 2004
and 2003, the carrying value of these financial instruments approximated
their fair value due to their short-term nature. The Company's bank
indebtedness bears interest at a floating market rate and accordingly
the fair market value approximates the carrying value.

(ii) Foreign Currency Exchange risk:

The Company is exposed to foreign currency fluctuations as crude oil and
natural gas prices are referenced in U.S. dollar denominated prices.

(iii) Credit risk:

Virtually all of the Company's accounts receivable are with customers
involved in the oil and gas industry and are subject to normal industry
credit risks. The carrying value of accounts receivable reflects
management's best estimate of the credit risk associated with the
Company's counterparties.

(iv) Interest rate risk:

The Company is exposed to interest rate risk to the extent that bank
debt is at a floating rate of interest.

(v) Commodity Price Contracts

On October 9, 2003, the Company entered into a derivative financial
instrument for the purpose of protecting future earnings and cash flow
from operating activities from the volatility of crude oil prices. The
Company entered into a crude oil collared contract for 400 barrels per
day of production at a base price of US$27.50 and cap price of US$31.00
based on the West Texas Intermediate price index for the period November
1, 2003 to March 31, 2004. The Company made net settlement payments of
$0.2 million during the year ended December 31, 2004 (2003 - $0.04
million) which are included in petroleum and natural gas revenue.



12. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital
2004 2003
------------------------------------------------------------------------
Accounts receivable $ (2,521) $ (1,825)
Prepaid expenses and deposits 17 (89)
Accounts payable and accrued liabilities (4,996) 11,897
Current income taxes 14 (2)
Cash acquired with acquisitions nil (1,364)
------------------------------------------------------------------------
Change in non-cash working capital $ (7,486) $ 8,617
relating to:
Investing activities (5,525) 11,234
Operating activities (1,961) (2,617)
------------------------------------------------------------------------


13. COMMITMENTS

The Company entered into a lease agreement for office premises
commencing January 1, 2004 to March 31, 2007. The minimum rentals
payable including estimated operating costs are summarized in the
following table:



2005 $ 252
2006 258
2007 66
Thereafter -
-------------------
$ 576
-------------------


14. COMPARATIVE FINANCIAL STATEMENTS

Certain prior year's comparative figures have been restated to conform
to the current year's presentation.

Conference Call

Endev will hold a conference call at 7:00 am MST (9:00 am EST), on
Thursday, March 3, 2005 to discuss its financial and operating results.
Callers from the Toronto area may dial 416-695-6120 and all other
participants may dial the toll free number 1-888-789-0150 to join the
call. A taped recording will be available until Thursday March 10, 2005
by dialing 416-695-5275 from the Toronto area and 1-866-518-1010 from
all other areas. This call will also be broadcast live on the internet
and may be accessed on Endev's website www.endevenergy.com.

Endev Energy Inc. is a Canadian oil and gas exploration and production
company based in Calgary, Alberta. The Company's common shares are
listed on the Toronto Stock Exchange under the trading symbol ENE. Endev
focuses on creating shareholder value by making strategic acquisitions
and executing low to medium-risk drilling programs in its focus areas in
Alberta.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Endev Energy Inc.
    Cameron MacGillivray
    President and CEO
    (403) 750-2600 or 1-888-750-2677
    or
    Endev Energy Inc.
    Scott Bonli, C.A.
    Vice President, Finance and CFO
    (403) 750-2600 or 1-888-750-2677
    Website: www.endevenergy.com
    The Toronto Stock Exchange has neither approved nor disapproved of the
    contents of this release.