Resolute Energy Inc.

Resolute Energy Inc.

March 16, 2005 02:01 ET

Resolute Energy Reports Fourth Quarter Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: RESOLUTE ENERGY INC.

TSX SYMBOL: RSE

MARCH 16, 2005 - 02:01 ET

Resolute Energy Reports Fourth Quarter Results

CALGARY, ALBERTA--(CCNMatthews - March 16, 2005) - Resolute Energy Inc.
(TSX:RSE) is pleased to announce operational and financial results for
the three months and year ended December 31, 2004.

Highlights

- Average production increased 20% to 7,073 boe/day.

- Revenue increased 43% to $27.7 million.

- Cash flow per share increased 44% to $0.23/share.

- Operating expenses decreased 7% to $6.95/boe.

- General and administrative costs decreased 20% to $1.78/boe.

- Year-end net debt was $46.0 million, representing 0.79 times fourth
quarter annualized cash flow.

- Successfully resolved dispute with midstream processor, allowing the
Company to bring shut-in volumes onstream in 2005.



Three Months Ended Year Ended
December 31(1) December 31(1)
% %
2004 2003(2) Change 2004 2003(2) Change
---------------------------------------------------
($000s, except
as noted)
FINANCIAL
Gross oil and
natural gas
revenue 27,742 19,344 43 97,653 81,644 20

Cash flow 14,589 10,060 45 52,655 42,969 23
Per share
basic ($) 0.24 0.17 41 0.87 0.72 21
Per share
diluted ($) 0.23 0.16 44 0.83 0.71 17

Net income from
continuing
operations 3,477 3,546 (2) 15,677 17,197 (9)
Per share
basic ($) 0.06 0.06 - 0.26 0.29 (10)
Per share
diluted ($) 0.05 0.06 (17) 0.25 0.28 (11)

Net income 3,477 2,994 16 15,677 11,284 39
Per share
basic ($) 0.06 0.05 20 0.26 0.19 37
Per share
diluted ($) 0.05 0.05 - 0.25 0.19 32

Capital
expenditures 16,159 10,883 48 79,945 62,733 27
Bank debt and
working capital
deficiency (45,983) (19,958) 130 (45,983) (19,958) 130

Shares
outstanding
(000s)
At period end 60,770 60,097 1 60,770 60,097 1
Weighted average
during period,
basic 60,751 59,923 1 60,448 59,504 2
Weighted average
during period,
diluted 64,809 61,913 5 63,659 60,870 5

OPERATING

Production
Natural gas
(mmcf/day) 31.6 25.1 26 27.6 23.3 18
Oil and natural
gas liquids
(bbls/day) 1,808 1,715 5 1,759 1,720 2
----------------------------------------------------
Oil equivalent
(boe/day) (6:1) 7,073 5,903 20 6,352 5,606 13

Average wellhead
prices
Natural gas
($/mcf) 6.67 6.01 11 6.73 6.80 (1)
Oil and natural
gas liquids
($/bbl) 49.21 34.56 42 45.99 37.82 22
----------------------------------------------------
Oil equivalent
($/boe)(6:1) 42.38 35.62 19 41.93 39.90 5

Wells drilled
(gross/net)
Natural gas 3/3.0 - 65/61.3 90/84.7
Oil 4/3.6 1/1.0 12/11.6 13/12.0
Dry 3/3.0 1/0.5 8/8.0 6/5.0
----------------------------------------------------
Total 10/9.6 2/1.5 85/80.9 109/101.7

Net success
rate (%) 69 67 90 95

Undeveloped land
holdings (000s)
Gross acres 296 337
Net acres 216 244
Average working
interest (%) 73 72

(1) The financial and operating summary represents results of continuing
operations unless otherwise noted.
(2) Comparative amounts have been adjusted to conform to current year
presentation.


MANAGEMENT'S DISCUSSION and ANALYSIS

March 15, 2005

Management's discussion and analysis (MD&A) of the financial condition
and the results of operations should be read in conjunction with the
audited consolidated financial statements for the years ended December
31, 2004 and 2003, together with the accompanying notes. The MD&A is
effective March 15, 2005. Additional information relating to the
Company, including the Annual Information Form, can be viewed or
downloaded at www.resoluteenergy.com or www.sedar.com.

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

The financial information presented has been prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The reporting
and measurement currency is the Canadian dollar.

Forward-Looking Statements

The information contained herein contains forward-looking statements and
assumptions, such as those relating to results of operations and
financial condition, capital spending, financing sources, commodity
prices, costs of production and the magnitude of oil and natural gas
reserves. By their nature, forward-looking statements are subject to
numerous risks and uncertainties that could significantly affect
anticipated future results and, accordingly, actual results may differ
materially from those predicted. The forward-looking statements
contained herein are as of March 15, 2005 and are subject to change
after this date. Readers are cautioned that the assumptions used in the
preparation of such information, although considered reasonable at the
time of preparation, may prove to be imprecise and, as such, undue
reliance should not be placed on forward-looking statements. Resolute
disclaims any intention or obligation to update or revise these forward
looking statements, whether as a result of new information, future
events or otherwise.

All forward looking statements have been prepared on the basis that
Resolute is a stand-alone Company and do not contemplate the effects of
the sale to Esprit Energy Trust and the creation of a new exploration
and coalbed methane company as disclosed in a press release dated March
14, 2005.

Non-GAAP Measures

Cash flow, which is expressed before changes in non-cash working capital
and asset retirement obligation expenditures, is used by the Company to
analyze operating performance, leverage and liquidity. Income from
operations, which represents net income excluding gains or losses on
foreign currency translation and on disposal of assets, is used by the
Company to evaluate operating performance. Operating netback, which is
calculated as the average unit sales price, less royalties,
transportation and operating expenses, and corporate netback, which
deducts administrative and interest expense and current income tax,
represents the cash margin for every barrel of oil equivalent sold. Cash
flow, income from operations and netback do not have any standardized
meanings prescribed by GAAP and therefore may not be comparable with the
calculation of similar measure for other companies.

Critical Accounting Estimates

Management makes certain judgements and estimates in preparing financial
statements in accordance with GAAP. Changes to these judgements and
estimates could have a material effect on Resolute's financial
statements and financial position.

Proved Oil and Gas Reserves

Proved reserves, the estimated quantities of natural gas, crude oil and
natural gas liquids that can be recovered in future years under future
economic and operating conditions, are critical to many aspects of the
Company's financial statements. These estimates are made with reasonable
certainty, using all available geological and reservoir data as well as
historical production data and are subject to revisions based on changes
in the pricing environment and reservoir performance.

Depletion Expense

In accordance with the full cost method of accounting for exploration
and development activities, all costs associated with exploration and
development are capitalized whether successful or not. The aggregate of
capitalized costs, net of costs related to unproved properties, and
estimated future development costs is amortized using the
unit-of-production method based on estimated proved reserves. Changes in
estimated proved reserves or future development costs have a direct
impact on depletion expense.

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 to determine
if proved reserves should be assigned or if impairment exists.

Full Cost Accounting Ceiling Test

The Company reviews the carrying value of all petroleum and natural gas
assets for potential impairment on a quarterly basis. Impairment is
indicated if the carrying value of the assets is not recoverable by the
future undiscounted cash flows. This impairment test is based on
estimates of proved reserves, production rates, petroleum and natural
gas prices, future costs and other relevant assumptions. If impairment
exists, the amount by which the carrying value exceeds the estimated
fair value of the assets is charged to earnings.

Asset Retirement Obligations

The provision for asset retirement obligations is estimated based on
costs to abandon and reclaim wells and facilities, timing of abandonment
and reclamation of wells and facilities, and inflation and discount
rates over the life of the reserves. Changes to any assumptions used in
the calculation will have an impact on the provision and the accretion
expense included in earnings.

Income Taxes

The determination of the Company's income tax liabilities requires
interpretation of complex laws and regulations and all tax filings are
subject to audit and potential reassessment. Future income tax expense
is calculated using tax rates based on the estimated timing of reversal
of temporary differences between accounting and tax values of certain
assets and liabilities. The actual current and future tax expenses
recorded may differ from those actually incurred.

2004 Overview

In 2004, Resolute benefited from another year of strong commodity
pricing, which resulted in record revenue and cash flows. Competitive
industry factors and a significant investment in facilities and extreme
wet conditions at Ante Creek contributed to higher depletion,
depreciation and amortization costs during the year. Additionally,
higher royalty rates and future income taxes also resulted in lower net
income from continuing operations.

During the year, the Company continued to add key individuals with
specialized skills to its exploration and operations team. The overall
staff count increased replacing the reliance on consultants and
efficiency was improved resulting in reduced operating and general and
administrative costs on a per unit basis. Efforts were focused on
evaluating and exploiting opportunities on Resolute's land holdings and
to also gain a thorough understanding of the Company's undeveloped land
base. The endeavor resulted in production and reserves growth in several
areas and the identification of properties for rationalization or swaps.

Resolute was very active in 2004, drilling over 80 net wells and
spending $80 million on its capital program. Capital expenditures were
internally financed with cash flow and bank debt. The Company maintained
a strong balance sheet throughout the year. Net debt at the end of 2004
was $46 million, representing 0.8 times debt to fourth quarter
annualized cash flow.



Three Year Financial Summary
Year ended December 31 2004(1) 2003(1)(2) 2002(1)(2)(3)
------------------------------------------------------------------------
($000s, except per share information)

Gross oil and natural gas revenue 97,653 81,644 29,768

Cash flow from operations 52,655 42,969 10,497

Net income (loss) from continuing
operations 15,677 17,197 (18,535)
Per share - basic 0.26 0.29 (0.32)
Per share - diluted 0.25 0.28 (0.31)

Net income (loss) 15,677 11,284 (16,406)
Per share - basic 0.26 0.19 (0.28)
Per share - diluted 0.25 0.19 (0.28)

Long-term debt 37,000 16,000 20,775

(1) Amounts represent results of continuing operations unless otherwise
noted.
(2) Comparative amounts have been adjusted to conform to current year
presentation.
(3) Amounts include results of operations from June 14, 2002 when the
Company acquired Equatorial Energy Inc.


2004 Performance Compared to Guidance

The following table illustrates the Company's performance for the year
ended December 31, 2004 compared to the Guidance from November 2003 and
May 2004:



Guidance
May 2004 November 2003
Actual Low High Low High
------ ------------- -------------
Natural gas (mmcf/day) 27.6 26.5 27.0 27.0 29.0
Oil and NGLs (bbls/day) 1,759 1,800 1,900 1,900 2,000
------ ------------- -------------
Barrels of oil equivalent (boe/day) 6,352 6,200 6,400 6,400 6,850

Royalties (% of revenue) 21.0% 19.0% 20.5% 19.0% 20.5%
Operating expenses ($/boe) 6.97 7.00 7.25 7.00 7.25
General and administrative
expenses ($/boe/day) 2.00 2.00 2.20 2.00 2.20

Capital expenditures ($ million) 79.9 65.0 70.0 46.0 50.0


Resolute met its average production and expense targets as outlined in
its Guidance issued November 2003 and updated May 2004. However, capital
expenditures exceeded both the November and May ranges primarily as a
result of the expansion of the coalbed methane drilling recompletion
project at Malmo; higher completion costs associated with testing
multiple zones and cost overruns from operating in extreme wet weather
conditions at Ante Creek; expansion of the drilling and recompletion
program at Gordondale; and the acceleration of wells and pre-purchasing
of supplies related to the 2005 drilling program. The increased capital
did not result in higher average production levels since most of the
incremental production was either temporarily constrained by facilities
or the activities were conducted late in the year.

2005 Guidance

Based on the 2005 budget, approved by the Board of Directors, the
Company expects to average 7,600-8,250 boe/day next year and also
expects to lower both operating and general and administrative expenses
on a per boe basis. The Company has budgeted for an $85 million capital
spending program that will be funded from cash flow and existing credit
facilities. The Company plans to drill 110-120 wells this year at Ante
Creek, Malmo, Winnifred, Gordondale and other areas. Approximately 40%
of the capital program is expected to be executed during the first
quarter. Capital expenditures for 2005 are tracking below budget as $1.9
million of drilling materials and equipment were pre-purchased in 2004
in anticipation of supply shortages during the winter drilling season.
Based on the results to date, the Company confirms that current
expectations for 2005 operating results continue to be within the
November 4, 2004 Guidance summarized below.



The following table outlines Guidance for 2005:

2005 Guidance
----------------
November 2004
Range
Low High
----------------
Natural gas (mmcf/day) 36.0 39.0
Oil and NGLs (bbls/day) 1,600 1,750
----- -----
Barrels of oil equivalent (boe/day) 7,600 8,250

Royalties (% of revenue) 20.0 22.0
Operating expenses ($/boe) 6.75 7.00
General and administrative expenses ($/boe) 1.75 2.00
Available tax deduction ($ million) 50.0 55.0

Capital expenditures ($ million) 90.0 95.0
Capital accelerated into 2004 (8.0) (6.0)
----------------
Net capital ($ million) 82.0 89.0


Sensitivities
Cash Flow Earnings
Per Share Per Share
($000s) Diluted ($) ($000s) Diluted ($)
--------------------------------------------
Oil US$1.00 580 0.009 365 0.006
Gas US$0.25 3,291 0.051 2,073 0.032
Cdn$/US$ exchange rate 1,200 0.018 756 0.012
1% change in interest rate 682 0.011 430 0.007
Oil - 100 bbls/day 842 0.013 531 0.008
Natural gas - 1 mmcf/day 1,342 0.021 846 0.013


Production

Three Months Ended Year Ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Natural gas
(mcf/day) 31,592 25,129 26 27,563 23,319 18
Oil (bbls/day) 1,464 1,505 (3) 1,486 1,500 (1)
NGLs (bbls/day) 344 210 64 273 220 24
---------------------------------------------------
Total (boe/day)
(6:1) 7,073 5,903 20 6,352 5,606 13
---------------------------------------------------
---------------------------------------------------


Daily production averaged 7,073 boe/day in the fourth quarter of 2004,
an increase of 20% over 5,903 boe/day for the same period in 2003.
Year-to-date 2004 daily production increased 13% to 6,352 boe/day
compared to 5,606 boe/day in 2003.

Natural gas production volumes averaged 31,592 mcf/day in the fourth
quarter of 2004, an increase of 26% over the same period in 2003. For
the year ended December 31, 2004, natural gas production of 27,563
mcf/day was 18% higher than in 2003. These increases are the result of
the Company's 2004 drilling program, with the most significant additions
to natural gas production coming from Ante Creek in northwest Alberta
and Winnifred in southeast Alberta. At Ante Creek, the Company completed
construction of its gas processing and gathering facilities during the
third quarter and placed 11 new wells on production throughout the year.
At Winnifred, 42 wells were brought on production during the third and
fourth quarter.

Oil production was slightly lower than 2003 with no significant
production additions and natural declines contributing to a 3% and 1%
decrease for the quarter and year ended December 31, 2004, respectively.
NGL production increased by 64% for the three months and 24% for the
year ended December 31, 2004, primarily due to optimization of
production at a third party plant, as well as production from Ante Creek
wells brought onstream in the previous quarter.

Natural gas production represents approximately 72% of the Company's
total production for 2004. The production base is geographically
balanced with properties located in the southern, central and northwest
regions. The diversification reduces the Company's exposure to
significant production or reserves declines at any property. Production
results for 2005 will depend on drilling success and the time required
to bring new or recompleted wells onstream.



Petroleum and Natural Gas (P&NG) Revenue

Three Months Ended Year Ended
December 31 December 31
% %
($000s) 2004 2003 Change 2004 2003 Change
---------------------------------------------------
Natural gas sales 19,393 13,891 40 67,892 57,900 17
Oil sales 6,765 4,787 41 25,589 20,913 22
NGL sales 1,420 666 113 4,008 2,831 42
---------------------------------------------------
27,578 19,344 43 97,489 81,644 19

Hedging gain 164 - - 164 - -
Total P&NG sales 27,742 19,344 43 97,653 81,644 20
---------------------------------------------------
---------------------------------------------------


Three Months Ended Year Ended
December 31 December 31
Prices and % %
Marketing 2004 2003 Change 2004 2003 Change
---------------------------------------------------
Benchmark prices
AECO natural gas
($/mmbtu) 6.57 5.59 18 6.55 6.67 (2)
WTI oil (US$/bbl) 48.28 31.18 55 41.40 31.04 33
Cdn$/US$ foreign
exchange rate 0.82 0.76 8 0.77 0.72 7
WTI oil
(Cdn equivalent
$/bbl) 58.91 41.03 44 53.78 43.35 24
Edmonton Light
($/bbl) 57.70 39.56 46 52.54 43.14 22
---------------------------------------------------


Three Months Ended Year Ended
December 31 December 31
Average Sales Price % %
- Cdn$ 2004 2003 Change 2004 2003 Change
---------------------------------------------------
Natural gas ($/mcf) 6.67 6.01 11 6.73 6.80 (1)
Oil ($/bbl) 50.23 34.57 45 47.06 38.20 23
NGLs ($/bbl) 44.88 34.49 30 40.14 35.25 14
---------------------------------------------------
Total ($/boe) 42.38 35.62 19 41.93 39.90 5
---------------------------------------------------
---------------------------------------------------


P&NG revenue before royalties for the three months ended December 31,
2004 increased 43% to $27.7 million compared to $19.3 million reported
in the same period in 2003 as a result of higher commodity prices
received and increased production volumes. The realized natural gas
price for the quarter, before hedging, was $6.67/mcf, compared to
$6.01/mcf for the same period in 2003, an increase of 11%. Realized oil
prices were 45% higher for the current quarter at $50.23 compared to
$34.57/bbl in the fourth quarter of 2003.

For the year ended December 31, 2004, P&NG revenue before royalties
increased 20% to $97.7 million, largely due to increased production
volumes, further enhanced by high realized oil prices. The prices
received for crude oil sold by Resolute are related to the price of
crude oil in world markets, as well as the exchange rate of the Canadian
dollar to the U.S. dollar and quality differentials. Benchmark crude oil
prices in 2004 reached all-time highs with an average West Texas
Intermediate (WTI) price of US$41.40/bbl in 2004 compared to
US$31.04/bbl in 2003, an increase of 33%. The higher U.S. denominated
price was partially offset by the strength of the Canadian dollar in
2004 compared to the U.S. dollar. The realized oil price for the Company
in 2004 was $47.06/bbl, 23% higher than the average price of $38.20/bbl
in 2003.

The Company's realized natural gas price is primarily determined by the
AECO Hub in Alberta. Resolute's realized natural gas price, before
hedging, was $6.73/mcf for 2004 compared to $6.80/mcf in 2003, a
decrease of 1%, which is consistent with the change in the annual
average AECO price from 2003 to 2004.

The Company participates in risk management activities in order to
manage its exposure to fluctuations in oil and natural gas prices. In
2004, the Company entered into three natural gas collars for the purpose
of limiting the Company's exposure to downturns in commodity prices,
while allowing it to benefit from rising commodity prices. See note 15
in the "Notes to Consolidated Financial Statements" for a summary of
these contracts.

The Company's contracts are accounted for as hedges and are not
recognized on the balance sheet. Realized gains and losses on these
contracts are recognized in P&NG revenue and cash flows in the same
period in which the revenues associated with the hedged transactions are
recognized.



Royalties

Three Months Ended Year Ended
December 31 December 31
% %
($000s) 2004 2003 Change 2004 2003 Change
---------------------------------------------------
Crown 5,083 2,303 121 15,164 11,250 35
Freehold, GORR 1,405 1,012 39 5,731 4,456 29
ARTC (125) (139) (10) (500) (408) 23
---------------------------------------------------
Total royalties 6,363 3,176 100 20,395 15,298 33
---------------------------------------------------
---------------------------------------------------


Three Months Ended Year Ended
Average Royalty Rate December 31 December 31
(average % of sales) 2004 2003 2004 2003
---------------------------------------------------
Crown 18 12 16 14
Freehold, GORR 5 5 6 6
ARTC - (1) - (1)
---------------------------------------------------
Total royalties 23 17 21 19
---------------------------------------------------
---------------------------------------------------


Royalties increased 100% to $6.4 million for the three months ended
December 31, 2004, from $3.2 million for the same period in 2003. The
Company's average royalty rate for the three months ended December 31,
2004 was 23% which, due to Crown royalty adjustments for periods
preceding the quarter, is higher than the 2004 annual average and higher
than the expected future rate. The factors contributing to the
abnormally low 2003 fourth quarter royalty rate included joint-venture
adjustments, low production royalty rates, royalty holidays on new wells
and a lower Alberta reference price compared to realized wellhead prices
for natural gas.

For the year ended December 31, 2004, royalties increased 33% from $15.3
million to $20.4 million. The Company's annual average royalty rate was
21% in 2004 compared to 19% in 2003. In the current pricing environment,
the Company's overall royalty rate is adversely affected by the
provincial sliding-scale royalty structure which charges higher royalty
rates for higher commodity prices. As well, the Company first exceeded
the $2.0 million Crown royalty threshold for Alberta Royalty Tax Credit
(ARTC) in 2003; therefore, subsequent production additions have
proportionally decreased this benefit. Resolute also had wells with
royalty holidays that expired early in 2004.

The average annual royalty rate for the Company is expected to be
approximately 21% of revenue, but actual results may be different based
on several factors including: type of royalty (Crown vs. freehold);
future reference prices relative to average wellhead prices; timing of
expiry of royalty holidays on existing wells and the proportion of new
production additions qualifying for royalty holidays; and the level of
gross overriding royalties relating to farm-in arrangements.



Operating Expenses

Three Months Ended Year Ended
December 31 December 31
($000s, % %
except per boe) 2004 2003 Change 2004 2003 Change
---------------------------------------------------
Operating expense
(gross) 4,797 4,265 12 16,906 15,880 6
Processing income (274) (191) 43 (694) (494) 40
---------------------------------------------------
Operating expense
(net, as reported) 4,523 4,074 11 16,212 15,386 5
---------------------------------------------------
---------------------------------------------------

Operating expense
per boe (net) 6.95 7.50 (7) 6.97 7.52 (7)
---------------------------------------------------
---------------------------------------------------


Operating expenses for the three months ended December 31, 2004 were
reduced by 7% to $6.95/boe from $7.50/boe for the same period in 2003.
For the year ended December 31, 2004, operating expenses fell from
$7.52/boe to $6.97/boe. The improved operating expenses reflect more
efficient field operations, the addition of new low-cost production in
2004 and increased third party recoveries.

Future operating costs will depend on several factors, including the
cost profile of new production additions, the level of ownership in
gathering and processing facilities and the cost escalation for supplies
and services.



Transportation and Selling Expenses

Three Months Ended Year Ended
December 31 December 31
($000s, % %
except per boe) 2004 2003 Change 2004 2003 Change
---------------------------------------------------
Transportation and
selling expenses 599 482 24 2,076 1,755 18
---------------------------------------------------

Transportation and
selling per boe 0.92 0.89 3 0.89 0.86 3
---------------------------------------------------


Transportation and selling expenses increased by 3% for the three months
and year ended December 31, 2004 to $0.92/boe and $0.89/boe,
respectively. Future transportation expenses on a per boe basis will
ultimately depend on the type of production additions (oil versus
natural gas), distance from wellhead to sales point, ownership of
gathering and pipeline facilities and the method of transporting oil
(pipeline versus trucking).



General and Administrative Expense (G&A)

Three Months Ended Year Ended
December 31 December 31
($000s, % %
except per boe) 2004 2003 Change 2004 2003 Change
---------------------------------------------------
G&A expense (gross) 2,249 2,048 10 9,099 8,345 9
Overhead recoveries (303) (312) (3) (1,323) (1,244) 6
---------------------------------------------------
1,946 1,736 12 7,776 7,101 10
Allocated to
operating expense - (34) (100) - (132) (100)
Allocated to capital
projects (785) (498) 58 (3,132) (2,049) 53
---------------------------------------------------
G&A expense 1,161 1,204 (4) 4,644 4,920 (6)
---------------------------------------------------
---------------------------------------------------

G&A expense per boe 1.78 2.22 (20) 2.00 2.40 (17)
---------------------------------------------------
---------------------------------------------------


G&A expenses for the three months ended December 31, 2004 decreased by
4% to $1.2 million compared to the three months ended December 31, 2003
and total G&A for 2004 decreased 6% to $4.6 million from $4.9 million
for 2003. Total G&A expenses have improved, reflecting efficiencies
realized with new staff additions and less reliance on consultants as
well as higher recoveries in the current year.

On a boe basis, G&A expenses for the three months ended December 31,
2004 decreased 20% to $1.78/boe from $2.22/boe for the same period in
2003. Year-to-date, G&A expenses declined by 17% to $2.00/boe from
$2.40/boe in the same period in 2003. Increased production volumes
contributed to the majority of the cost reduction on a boe basis.

Stock-Based Compensation

Stock-based compensation expense for the quarters ended December 31,
2004 and 2003 was $0.2 million. For the year ended December 31, 2004,
the expense was $0.9 million compared to $0.4 million for the prior
year. The current year stock-based compensation expense is comparatively
higher because the fair value of each option, calculated using the
Black-Scholes option-pricing model, has increased over the year and
there were more options outstanding at December 31, 2004 than at
December 31, 2003.

Interest Expense

Interest expense for the fourth quarter of 2004 increased to $0.4
million from $0.3 million in the fourth quarter of 2003. Similarly, 2004
interest expense was $1.2 million versus $0.9 million in 2003 due to an
increase in long-term debt from $16.0 million at December 31, 2003 to
$37.0 million at December 31, 2004.



Depletion, Depreciation and Amortization (DD&A)

Three Months Ended Year Ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
DD&A ($000s) 8,967 5,630 59 27,111 19,256 41
---------------------------------------------------
---------------------------------------------------

DD&A ($/boe) 13.78 10.37 33 11.66 9.41 24
---------------------------------------------------
---------------------------------------------------


DD&A expense for the three months ended December 31, 2004 was $13.78/boe
in 2004 compared to $10.37/boe for the same period in 2003, an increase
of 33%. DD&A expense in 2004 increased 24% to $11.66/boe from the prior
year's $9.41/boe. Resolute had a higher depletable base in 2004 due to
the rising cost of proved reserve additions resulting from the
industry-wide trend of increasing costs and a high capital investment on
facilities, particularly at Ante Creek.

Resolute's future DD&A expense will depend on the Company's ability to
add proved reserves at a reasonable cost.

Petroleum and natural gas interests, which is the basis for depletion,
has been adjusted in the current and prior period for amounts relating
to asset retirement obligations.



Accretion

Three Months Ended Year Ended
December 31 December 31
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Accretion ($000s) 149 122 22 533 444 20
---------------------------------------------------
---------------------------------------------------

Accretion ($/boe) 0.23 0.22 5 0.23 0.22 5
---------------------------------------------------
---------------------------------------------------


Accretion on Resolute's asset retirement obligations is calculated at
credit-adjusted, risk-free rates ranging from 7.0-7.5%. The expense has
increased with the liability and will continue to do so as additional
wells are drilled.

Income Taxes

Current income taxes were flat at $0.1 million for the three-month
period and $0.5 million for the year. Current income tax for 2004
represents Large Corporations Tax (LCT) and the Saskatchewan Resource
Surcharge (SRC). The modest increase over the prior year is due to the
Company's increasing taxable capital. The federal government has
approved phasing out the LCT in a series of annual rate reductions until
it is eliminated in 2008.

For 2005, the current tax horizon will ultimately depend on a number of
factors in the future including commodity prices, production, corporate
expenses and both the type and amount of capital expenditures incurred.

Future income tax expense for the quarter ended December 31, 2004 was
$1.8 million compared to $0.6 million for the fourth quarter of 2003.
Future income tax expense was $8.4 million in 2004 and $5.7 million in
2003. Future income tax for the year ended December 31, 2004 includes a
benefit of $0.3 million for lower corporate tax rates legislated for
resource companies compared to $3.1 million for the year ended December
31, 2003. The benefits in both 2003 and 2004 included a change in the
Alberta corporate income tax rate. For 2003, Resolute recognized an
additional non-recurring benefit due to changes in federal taxation
including the corporate tax rate as well as the deductibility of Crown
royalties and the elimination of the resource allowance, both of which
are to be phased-in over a five-year period.



Estimated income tax pools available at January 1, 2005 are as follows:

Annual Deduction
Available (%) ($000s)
------------------------------------------------------------------------

Canadian oil and gas property expenses 10 51,922
Canadian development expenses 30 32,996
Canadian exploration expenses 100 2,820
Undepreciated capital costs 25 35,787
Financing costs 20 353
Other 10 159
---------
124,037
---------
---------


Net Income

Net income from continuing operations for the three months ended
December 31, 2004 decreased 2% to $3.5 million, and for the year ended
December 31, 2004, decreased 9% to $15.7 million. These decreases, which
are attributable to the increased royalties, DD&A expense and future
income tax expense, were offset by an increase in P&NG revenue and a
decrease in operating expenses.

For the three months ended December 31, 2004, net income of $3.5 million
was 16% higher than for the same period in 2003. Net income of $15.7
million for the year ended December 31, 2004 was 39% higher than net
income in 2003. Included in net income for the three months and year
ended December 31, 2003 are losses from discontinued operations of $0.6
million and $5.9 million, respectively.



Cash Netbacks

The components of the Company's operating and corporate netbacks are
summarized below:

Three Months Ended Year Ended
($/boe) December 31 December 31
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Sales price 42.38 35.62 19 41.93 39.90 5
Royalties (9.78) (5.85) 67 (8.78) (7.48) 17
Transportation costs (0.92) (0.89) 3 (0.89) (0.86) 3
Operating expenses (6.95) (7.50) (7) (6.97) (7.52) (7)
---------------------------------------------------
Operating netback 24.73 21.38 16 25.29 24.04 5
G&A (1.78) (2.22) (20) (2.00) (2.40) (17)
Interest (net) (0.60) (0.47) 28 (0.51) (0.42) 21
Current income taxes (0.18) (0.17) 6 (0.20) (0.22) (9)
---------------------------------------------------
Corporate netback 22.17 18.52 20 22.58 21.00 8
---------------------------------------------------
---------------------------------------------------


Recycle Ratio
$/boe Recycle Ratio
------------------------------------------------------------------------
2004 Operating netback 24.73
2004 FD&A
Proved 20.94 1.18
Proved + probable 13.12 1.88
Three-year average FD&A
Proved 13.22 1.86
Proved + probable 10.58 2.34


A key indicator of efficiency and profitability in the oil and gas
industry is the recycle ratio, which is defined as the operating netback
divided by the current year average finding, development and acquisition
costs (FD&A). Management places significant emphasis on maintaining a
high recycle ratio.



Capital Expenditures
Three Months Ended Year Ended
($000s) December 31 December 31
% %
2004 2003 Change 2004 2003 Change
---------------------------------------------------
Land and lease
retention 2,722 678 301 7,126 10,562 (33)
Geological and
geophysical 184 423 (57) 2,394 2,322 3
Drilling and
completions 8,760 5,877 49 41,193 31,552 31
Facilities and
equipment 2,952 2,849 4 23,737 7,318 224
Other 1,736 942 84 5,983 2,748 118
Property acquisitions 324 136 138 731 8,324 (91)
---------------------------------------------------
Total capital
expenditures 16,678 10,905 53 81,164 62,826 29
Dispositions (519) (22) 2,259 (1,219) (93) 1,211
---------------------------------------------------
Net capital
expenditures 16,159 10,883 48 79,945 62,733 27
---------------------------------------------------
---------------------------------------------------


Capital expenditures for the three months ended December 31, 2004 were
$16.2 million, net of one property disposition for $0.5 million. Capital
expenditures in 2004 were $79.9 million, net of three property
dispositions for $1.2 million. The majority of land expenditures in the
year related to land and lease retention of coalbed methane interests in
the Company's Malmo area in central Alberta. Drilling and completions
for the three months ended December 31, 2004 included 4.0 wells at Berry
in southern Alberta and 3.0 wells at Ante Creek in northwest Alberta, as
well as several recompletions at Malmo, Ante Creek and Berry. Drilling
expenditures for 2004 resulted in 85 (80.9 net) wells drilled at a 90%
success rate. The majority of facilities and equipment expenditures for
the year ended December 31, 2004 related to the construction of
processing and gathering facilities and the tie-in of wells at Ante
Creek, Berry and Winnifred in southern Alberta.

The Company previously set its 2004 capital budget at $65-70 million;
however, $10.0 million of 2005 projects were accelerated into the last
quarter of 2004 increasing the budget to $79.9 million. The Company's
2005 budget of $85 million includes major development programs at Malmo,
Ante Creek and Winnifred. The Company plans to drill 110-120 wells in
2005.

Liquidity and Capital Resources

The Company's $79.9 million capital program in 2004 was funded through
cash flow ($52.7 million), bank debt ($21.0 million), working capital
($4.8 million) and proceeds from conversion of stock options and
warrants ($1.4 million).

At December 31, 2004, the Company had $37.0 million drawn on its $80.0
million credit facility held with two major Canadian chartered banks.
The debt is secured by the Company's oil and natural gas properties. Net
bank debt and working capital deficiency increased to $46.0 million at
December 31, 2004. The deficiency is the result of normal operating
conditions in periods when the Company incurs significant capital
expenditures relative to revenue.

Resolute expects to fund its 2005 capital program and all other
commitments primarily from internally generated cash flow and existing
credit facilities. The Company may use other sources of funding
including proceeds from disposing of non-strategic properties and equity
issues if available on favourable terms. Oil and natural gas prices have
a significant impact on internally-generated cash flow. Should commodity
prices decline significantly, the Company may reduce its capital
expenditure program accordingly. Resolute expects to be able to fulfill
all of its contractual obligations at December 31, 2004 as summarized
below:



Contractual obligations Less
($000s) than 1 1 - 3 4 - 5 After 5
Total Year Years Years Years
-------------------------------------------
Long-term debt 37,000 - 37,000 - -
Operating lease obligations 1,458 354 1,074 30 -
-------------------------------------------
Total contractual
obligations 38,458 354 38,074 30 -
-------------------------------------------
-------------------------------------------


Changes in Accounting Standards

Accounting Policies Adopted in 2004

Asset Retirement Obligations

Effective January 1, 2004, the Company adopted CICA Handbook Section
3110, "Asset Retirement Obligations". Under the new standard, the fair
value of a liability for asset retirement obligations is recorded in the
period when a reasonable estimate of the fair value can be determined,
with a corresponding increase to the carrying amount of the related
asset. The asset recorded is depleted on a unit-of-production basis over
the life of the reserves. Changes in fair value of the asset retirement
obligations, due to the passage of time, are recorded as accretion
expense. Actual expenditures incurred are charged against the
obligations. Previously, the Company recognized a provision for future
site reclamation and abandonment costs based on the unit-of-production
method applied to the estimated future liability.

This change in accounting policy has been applied retroactively with
restatement of prior periods presented for comparative purposes as
follows:



Consolidated Balance Sheet - as at December 31, 2003

As Reported Change As Restated
---------------------------------
Assets
Petroleum and natural gas interests 156,622 5,091 161,713
Liabilities and shareholders' equity
Site restoration and abandonment 4,015 (4,015) -
Asset retirement obligations - 7,057 7,057
Future income taxes 16,279 674 16,953
Deficit (4,089) 1,375 (2,714)
---------------------------------
---------------------------------

Consolidated Statement of Operations and Deficit
- Year ended December 31, 2003

As Reported Change As Restated
---------------------------------

Depletion, depreciation and
amortization 19,418 (162) 19,256
Accretion - 444 444
Future income taxes 5,765 (57) 5,708
Net income 11,509 (225) 11,284
---------------------------------
---------------------------------


As a result of this change in accounting policy, diluted net income from
continuing operations per share decreased by $0.01 for the year ended
December 31, 2003.

Petroleum and Natural Gas Interests (P&NG)

Effective January 1, 2004, the Company adopted Accounting Guideline 16
(AcG-16), "Oil and Gas Accounting - Full Cost", which replaces
Accounting Guideline 5, "Full Cost Accounting in the Oil and Gas
Industry". AcG-16 modifies how impairment is tested and is consistent
with CICA Section 3063, "Impairment of Long-lived Assets". Under AcG-16,
impairment is recognized if the carrying amount of the P&NG assets
exceeds the sum of the undiscounted cash flows expected to result from
the Company's proved reserves.

If the carrying value is not fully recoverable, the amount of impairment
is measured by comparing the carrying amounts of the P&NG assets to an
amount equal to the estimated net present value of future cash flows
from proved plus probable reserves. This calculation incorporates risks
and uncertainties in the expected future cash flows which are discounted
using a risk-free rate. Any excess carrying value above the net present
value of the future cash flows would be recorded as a permanent
impairment.

Previously, impairment was tested based on undiscounted future net
revenues using proved reserves and providing for future general and
administrative expenses, carrying costs and taxes. The adoption of
AcG-16 had no effect on the Company's financial results.

Hedging Relationships

During the fourth quarter of 2004, the Company adopted Accounting
Guideline 13, (AcG-13) "Hedging Relationships" which provides standards
for the documentation and effectiveness testing of hedging activities.
The adoption of AcG-13 had no effect on the Company's financial results.

Accounting Reclassification

Effective January 1, 2004, and consistent with the adoption of CICA
Handbook Section 1100, "Generally Accepted Accounting Principles",
transportation costs are presented as an expense in the Statement of
Operations and Retained Earnings (Deficit). Previously, these costs were
netted against revenue.

Certain information provided for the prior periods has been reclassified
to conform to the presentation adopted in 2004.

New Standards in 2005 and 2006

Variable Interest Entities

In June 2003, the CICA issued AcG-15, "Consolidation of Variable
Interest Entities", which provides guidance for a company consolidating
variable interest entities for which it is considered to be the primary
beneficiary. The primary beneficiary is defined as an enterprise with a
variable interest that will absorb a majority of an entity's expected
losses, or receive a majority of an entity's expected residual returns,
or both. Variable interests are interests in an entity that change with
changes in the fair value of the entity's net assets exclusive of
variable interests. This guideline applies to annual and interim periods
beginning on or after November 1, 2004 and earlier adoption is
encouraged. This standard does not result in the consolidation of any
additional entities with the Company at December 31, 2004.

Earnings per Share

In July 2004, the CICA proposed to amend Handbook Section 3500 "Earnings
per Share". The majority of the amendments relates to the treatment of
mandatory convertible instruments and reflects proposals made by the
U.S. Financial Accounting Standards Board. These amendments are expected
to be effective for interim and annual periods relating to fiscal years
beginning on or after January 1, 2005. These amendments are not expected
to have an impact on Resolute as the Company does not currently have any
mandatory convertible instruments.

Financial Instruments

The Accounting Standards Board currently plans to issue the following
new Handbook Sections: Section 1530, "Comprehensive Income"; Section
3855, "Financial Instruments - Recognition and Measurement"; and Section
3865, "Hedges". The effective date for these sections is for interim and
annual financial statements relating to fiscal years beginning on or
after October 1, 2006 with earlier adoption permitted only as of the
beginning of a fiscal year ending on or after December 31, 2004. The new
sections will harmonize Canadian GAAP with U.S. GAAP regarding the
recognition and measurement of financial instruments as follows:

- the fair value of all trading financial instruments will be recognized
on the balance sheet with changes in fair value included in earnings,
except for derivatives designated as hedges;

- gains and losses on derivatives designated as hedges will be recorded
in other comprehensive income; and

- all remaining financial assets and liabilities will be recorded at
cost and amortized over the remaining life.

The Company has not assessed the future impact these sections will have
on the financial statements.

Changes in Accounting Policies and Estimates, and Errors

The Accounting Standards Board has proposed to issue a new Handbook
Section "Changes in Accounting Policies and Estimates, and Errors" to
replace Section 1506, "Accounting Changes". This section will provide
guidance on when an entity is permitted to change an accounting policy,
how to account for a change in accounting policy, a change in an
estimate or correction of an error and appropriate disclosures.

Subsequent Events

The Accounting Standards Board has proposed to extend the period during
which subsequent events are required to be considered, to when the
financial statements are authorized for issue. As well, disclosure will
be required as to the date the financial statements were authorized for
issue and who provided that authorization.

Risks and Uncertainties

All companies in the oil and natural gas industry are exposed to a
number of business risks, some of which are beyond their control. These
risks can be categorized as operational, financial and regulatory.

Operational Risks - The Company may have unsuccessful operations or
delays as a result of a number of factors including lack of availability
of services, supplies and equipment; mechanical and technical
difficulties; ability to attract and retain employees on a
cost-effective basis; and commodity and marketing risk. Resolute is also
subject to significant drilling risks and uncertainties including the
ability to find oil and natural gas reserves on an economic basis and
the potential for technical problems that could lead to well blowouts
and environmental damage. There are numerous uncertainties in estimating
the Company's reserve base due to the complexities in estimating future
production, costs and timing of expenses and future capital.

The operational risks can be mitigated by employing a team of highly
qualified staff; providing a compensation system that rewards
above-average performance; developing and maintaining strong, long-term
relationships with contract service providers and operating a
significant portion of its production and drilling activities. The
Company maintains an insurance program consistent with industry practice
to protect against destruction of assets, well blowouts, pollution and
other business interruptions. Resolute maintains a geologically-diverse
prospect inventory, drills a significant number of wells relative to its
size and capital budget and maintains a diverse production base to
reduce its single well or property exposure to delays, malfunction or
failure.

Financial Risks - The Company is exposed to financial risks which
include fluctuations in interest rates, changes in the Canadian/U.S.
dollar exchange rate, commodity prices and access to debt or equity
markets. The Company cannot control these factors, but mitigates the
potential adverse effects of these factors by maintaining a conservative
approach to its finances and a flexible capital expenditure program. The
Company has the option to sell properties, secure farm-out arrangements
with industry partners or reduce its capital program should liquidity
sources such as cash flow, debt or equity tighten unexpectedly.

Regulatory Risks - Resolute is subject to regulatory risks, which are
common to the industry. The Company takes a proactive approach with
respect to the environment and safety. An operations emergency response
plan is in place and the Company is in compliance with current
environmental regulations.



Outstanding Share Data

Outstanding at period-end (000s) March 15 December 31 December 31
2005 2004 2003
-----------------------------------

Common shares 60,793 60,770 60,097
Common shares issuable on conversion
Share purchase warrants 3,642 3,648 3,715
Performance warrants 2,505 2,505 2,505
Stock options 4,333 4,363 3,828
-----------------------------------
Total 71,273 71,286 70,145
-----------------------------------
-----------------------------------

Resolute Share Trading Statistics

December 31
2004 2003
-----------------------------------
Trading volume (000s) 35,927 42,526
Daily average (000s) 142 169
Trading value ($000s) 144,280 110,612
Share price ($/share)
High 5.15 3.30
Low 3.05 2.02
Average 4.02 2.64
Market capitalization
Shares outstanding (000s) 60,770 60,097
Year-end share price ($/share) 4.51 3.23
Total ($000s) 274,073 194,114


Selected Quarterly Information

2004
Q4 Q3(1) Q2(1) Q1(1)
------------------------------------------------------------------------
Production
Natural gas (mmcf/day) 31.6 29.3 25.5 23.8
Oil and natural gas liquids
(bbls/day) 1,808 1,767 1,647 1,811
Barrels of oil equivalent
(boe/day) 7,073 6,651 5,894 5,780

Financial
($000s, except as noted)
Petroleum and natural gas
revenue 27,742 25,137 23,623 21,151
Revenue net of royalties 21,379 19,964 18,567 17,348

Cash flow from operations 14,589 13,598 12,718 11,750
Per share basic 0.24 0.22 0.21 0.20
Per share diluted 0.23 0.21 0.20 0.19

Net income from continuing
operations 3,477 4,108 4,100 3,992
Per share basic 0.06 0.07 0.07 0.07
Per share diluted 0.05 0.06 0.06 0.06

Net income (loss) 3,477 4,108 4,100 3,992
Per share basic 0.06 0.07 0.07 0.07
Per share diluted 0.05 0.06 0.06 0.06

Capital expenditures 16,159 16,186 17,221 30,379
Bank debt and working
capital deficit (45,983) (44,453) (42,550) (38,282)

Shares outstanding (000s) 60,770 60,721 60,382 60,259

Per unit information
Natural gas ($/mcf) 6.67 6.37 7.29 6.65
Oil and natural gas liquids
($/bbl) 49.21 49.01 44.81 40.85
Oil equivalent ($/boe) 42.38 41.08 44.06 40.21

Operating netback ($/boe) 22.17 22.22 23.72 22.37

Net wells drilled
Natural gas 3.0 22.8 19.0 16.0
Oil 3.6 - - 8.0
Dry 3.0 1.0 - 2.0
Total 9.6 23.8 19.0 26.0

Net success rate (%) 69 96 100 92


2003(1)
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Production
Natural gas (mmcf/day) 25.1 23.6 22.6 21.9
Oil and natural gas liquids
(bbls/day) 1,715 1,814 1,689 1,658
Barrels of oil equivalent
(boe/day) 5,903 5,749 5,448 5,316

Financial
($000s, except as noted)
Petroleum and natural gas
revenue 19,344 19,286 19,814 23,198
Revenue net of royalties 16,168 16,050 15,684 18,442

Cash flow from operations 10,060 10,798 9,799 12,598
Per share basic 0.17 0.18 0.17 0.21
Per share diluted 0.16 0.18 0.16 0.21

Net income from continuing
operations 3,546 4,030 4,804 4,750
Per share basic 0.06 0.07 0.08 0.08
Per share diluted 0.06 0.07 0.08 0.08

Net income (loss) 2,994 4,731 (1,543) 5,102
Per share basic 0.05 0.08 (0.03) 0.09
Per share diluted 0.05 0.08 (0.03) 0.09

Capital expenditures 10,883 22,723 22,485 6,641
Bank debt and working
capital deficit (19,958) (19,127) (9,213) (20,122)

Shares outstanding (000s) 60,097 59,833 59,233 59,233

Per unit information
Natural gas ($/mcf) 6.01 6.06 7.03 8.39
Oil and natural gas liquids
($/bbl) 34.56 36.76 35.03 45.43
Oil equivalent ($/boe) 35.62 36.47 39.97 48.50

Operating netback ($/boe) 18.52 20.42 19.77 25.59

Net wells drilled
Natural gas - 54.9 24.8 5.0
Oil 1.0 6.0 5.0 -
Dry 0.5 1.5 1.0 2.0
Total 1.5 62.4 30.8 7.0

Net success rate (%) 67 98 97 71

(1) Certain amounts have been adjusted to conform to current period
presentation.

See accompanying notes


Quarterly Summary

2003

Q1 - Revenue, cash flow and earnings were positively impacted by
exceptionally high commodity prices. Oil and NGLs averaged $45.43/bbl
while natural gas averaged $8.39/mcf. Successful first-quarter drilling
increased average production for the year by 365 boe/day from the 2002
fourth quarter. The Company accrued a $0.75 million current tax
provision based on prevailing prices and available tax pools at the time.

Q2 - The Company acquired 250 boe/day in the Berry area of southern
Alberta for $8.3 million. Resolute had a very active period, spending
$22.5 million and drilling 30.8 net wells. The Company reclassified its
Indonesian assets as Discontinued Operations as a result of a pending
sale and recognized a loss of $6.1 million relating to the transaction.
The Company recorded a $1.9 million future tax benefit during the
quarter, reflecting lower tax rates substantially enacted for resource
companies.

Q3 - Indonesian operations were sold for cash proceeds of $23.2 million,
which were used to repay Canadian debt. Canadian production increased to
5,749 boe/day as a result of drilling. The Company spent $22.7 million,
which included the drilling of 62.4 wells. The $0.75 million current tax
provision recorded in the first quarter was reversed due to revised cash
flow and capital forecasts.

Q4 - Production averaged 5,903 boe/day for the quarter. The majority of
the $10.9 million capital program was allocated to land, seismic and
facilities. The future income tax calculation was recalculated using tax
pools available at year end. This step determined that an additional
$1.2 million future tax benefit should be recognized in addition to the
$1.9 million recorded in the second quarter for new tax legislation
introduced earlier in the year. Future income taxes were $0.6 million,
net of the $1.2 million adjustment.

2004

Q1 - The Company had an active drilling quarter with $18.0 million spent
on drilling and completions, resulting in 27 (26.0 net) new wells at a
92% success rate, focused on the Ante Creek and Berry areas. Production
averaged 5,780 boe/day for the quarter, down slightly from the fourth
quarter of 2003, due to cold weather and well tie-in delays. Early
spring break-up left the Company with 23 wells awaiting completions,
tie-in and facilities. Despite lower production, both revenue and cash
flows increased over the prior quarter as a result of higher commodity
prices. Net income was higher than the previous quarter as it was the
first reporting period without the impact of discontinued operations.

Q2 - Increased production of 5,894 boe/day for the quarter and favorable
commodity prices resulted in higher revenue, cash flow and earnings
compared to the first quarter of the year. The Company's syndicated
credit facility was expanded by 40% to $70 million to allow the Company
to expand its development activities when appropriate.

Q3 - The facilities at Ante Creek and Winnifred were completed and
volumes brought onstream during the quarter, contributing to quarterly
production of 6,651 boe/day, an increase of 13%. The Company reported
increased cash flow due to higher production and also improved cash
costs. Increased DD&A expense resulting from the high cost of proved
reserve additions had a slight adverse effect on earnings for the
quarter. A dispute with a midstream processor was successfully resolved,
allowing the Company to bring shut-in volumes on production in early
2005.

Q4 - Production for the quarter exceeded 7,000 boe/day which, combined
with high commodity prices and further-improved cash costs, resulted in
exceptional earnings and cash flows ($0.23/share). Earnings in the
quarter were again impacted by the increased cost of proved reserve
additions and the resultant higher DD&A expense. The Company's
syndicated credit facility was further increased by $10 million to $80
million.

Notice of Conference Call

Resolute will host a conference call to discuss these results on March
17, 2005 at 11 a.m. ET or 9 a.m. MT. Participants may access the call
toll-free at 1-888-334-7880 or direct at 416-695-9714. This call will
also be available by webcast and can be accessed from Resolute's
website: www.resoluteenergy.com. A telephone replay of the call will be
available through March 24, 2005 by dialing toll-free at 1-888-509-0081
or 416-695-5275.



Resolute Energy Inc.
Consolidated Balance Sheets

($000s) December 31 December 31
2004 2003(1)
--------------------------

Assets

Current
Cash 150 1,443
Accounts receivable 12,976 10,788
13,126 12,231

Petroleum and natural gas interests (note 6) 219,307 161,853
--------------------------

232,433 174,084
--------------------------
--------------------------

Liabilities

Current
Accounts payable and accrued liabilities 19,683 16,189
Bank indebtedness 2,426 -
--------------------------
22,109 16,189

Long-term debt (note 7) 37,000 16,000

Future income taxes (note 12) 25,366 16,953

Asset retirement obligations (note 8) 12,100 7,057
Commitments (note 15)

Shareholders' equity
Share capital (notes 9 and 10) 121,610 120,235
Contributed surplus 1,285 364
Retained earnings (deficit) 12,963 (2,714)
--------------------------
135,858 117,885
--------------------------

232,433 174,084
--------------------------
--------------------------
(1) Restated (note 3).

See accompanying notes.


Resolute Energy Inc.
Consolidated Statements of Operations and Retained Earnings (Deficit)

Three months ended Year ended
($000s, except per share amounts) December 31 December 31
2004 2003(1) 2004 2003(1)
--------------------------------------
Revenue
Gross oil and natural gas revenue
(note 4) 27,742 19,344 97,653 81,644
Royalties (6,363) (3,176) (20,395) (15,298)
--------------------------------------
21,379 16,168 77,258 66,346
--------------------------------------
Expenses
Operating 4,523 4,074 16,212 15,386
Transportation and selling (note 4) 599 482 2,076 1,755
Administrative 1,161 1,204 4,644 4,920
Interest (note 7) 391 257 1,184 868
Depletion, depreciation and
amortization 8,967 5,630 27,111 19,256
Accretion (note 8) 149 122 533 444
Stock-based compensation (note 10) 207 170 921 364
Other expenses (income) 1 - 11 (6)
--------------------------------------
15,998 11,939 52,692 42,987
--------------------------------------

Income from continuing operations
before income taxes 5,381 4,229 24,566 23,359

Income taxes (note 12)
Current income taxes 115 91 476 454
Future income taxes 1,789 592 8,413 5,708
--------------------------------------
1,904 683 8,889 6,162

Net income from continuing
operations 3,477 3,546 15,677 17,197

Discontinued operations
Net loss from discontinued
operations (note 5) - (552) - (5,913)
--------------------------------------
Net income 3,477 2,994 15,677 11,284

Retained earnings (deficit),
beginning of period (note 3) 9,486 (7,110) (2,714) (15,598)
Retroactive application of changes
in accounting policies (note 3) - 1,402 - 1,600
--------------------------------------
Retained earnings (deficit),
beginning of period as restated 9,486 (5,708) (2,714) (13,998)
Retained earnings (deficit),
end of period 12,963 (2,714) 12,963 (2,714)
--------------------------------------
--------------------------------------

Net income per share from
continuing operations (note 11)
Basic 0.06 0.06 0.26 0.29
Diluted 0.05 0.06 0.25 0.28
--------------------------------------
--------------------------------------
Net income per share (note 11)
Basic 0.06 0.05 0.26 0.19
Diluted 0.05 0.05 0.25 0.19
--------------------------------------
--------------------------------------
(1) Restated (notes 3 and 4).

See accompanying notes.


Resolute Energy Inc.
Consolidated Statements of Cash Flow

($000s) Three months ended Year ended
December 31 December 31
2004 2003(1) 2004 2003(1)
--------------------------------------
Cash flows from the following:
Operating activities
Net income 3,477 2,994 15,677 11,284
Items not affecting cash
Depletion, depreciation and
amortization 8,967 5,630 27,111 19,256
Accretion (note 8) 149 122 533 444
Future income taxes 1,789 592 8,413 5,708
Stock-based compensation 207 170 921 364
Net loss from discontinued
operations - 552 - 5,913
--------------------------------------
Cash flow from operations 14,589 10,060 52,655 42,969
Asset retirement obligation
expenditures (note 8) (74) (1) (107) (98)
Changes in non-cash working
capital (note 13) 2,275 (1,082) 165 198
--------------------------------------
16,790 8,977 52,713 43,069
--------------------------------------

Financing activities
Issue of common shares net of
issue expenses (note 9) 115 545 1,375 2,026
Debt - drawdown (repayment) of
loan facility 3,000 10,000 21,000 (4,775)
Increase (decrease) in bank
indebtedness (6,140) (1,924) 2,426 -
Repayments from (advances to)
discontinued operations - (234) - 831
--------------------------------------
(3,025) 8,387 24,801 (1,918)
--------------------------------------

Investing activities
Petroleum and natural gas
expenditures (16,159) (10,883) (79,945) (62,733)
Changes in non-cash working
capital (note 13) 2,391 (4,962) 1,138 (1,695)
Disposition of Equatorial
Indonesia (note 5) - (318) - 23,181
--------------------------------------
(13,768) (16,163) (78,807) (41,247)
--------------------------------------

Net (decrease) increase in cash (3) 1,201 (1,293) (96)

Cash, beginning of period 153 242 1,443 1,539
--------------------------------------

Cash, end of period 150 1,443 150 1,443
--------------------------------------
--------------------------------------
(1) Restated (note 3).

See accompanying notes.


RESOLUTE ENERGY INC.

Notes to Consolidated Financial Statements

(unaudited)

For the three months and year ended December 31, 2004 (tabular amounts
in thousands of dollars, except as otherwise stated).

1. Description of Business

Resolute Investments Inc. was incorporated on June 6, 2001 and commenced
operations on October 1, 2001. The Company is in the business of
exploration, development and production of petroleum and natural gas
reserves.

On June 14, 2002, Resolute Investments Inc. acquired Equatorial Energy
Inc. ("Equatorial"). The transaction was accounted for as a reverse
takeover whereby Resolute Investments Inc. became a wholly-owned
subsidiary of Equatorial.

On November 14, 2002, Equatorial changed its name to Resolute Energy
Inc. ("Resolute" or the "Company").

On July 23, 2003, the Company completed the sale of its Indonesian
subsidiary. The consolidated financial statements for the year ended
December 31, 2003 included the wholly-owned subsidiaries Equatorial
Energy (International) Inc. and Equatorial Energy Trading Corp., which
were amalgamated December 30, 2003 and dissolved November 11, 2004. For
the year ended December 31, 2003, the financial position and results of
operations of the Indonesian subsidiaries have been reclassified as
discontinued operations. For the year ended December 31, 2004, the
consolidated financial statements include the accounts of the Company
and its remaining wholly owned subsidiary, Resolute Investments Inc.

2. Significant Accounting Policies

The consolidated financial statements are presented in accordance with
Canadian Generally Accepted Accounting Principles and are expressed in
Canadian dollars. The preparation of financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the consolidated financial statements,
and revenues and expenses during the reporting period. Actual results
could differ from those estimated.

(a) Joint-Venture Activities

A portion of the Company's exploration, development and production
activities are conducted jointly with others. These financial statements
reflect the Company's proportionate interest in such activities.

(b) Cash

Cash includes cash and short-term investments with a maturity of 90 days
or less at the time of issue.

(c) Petroleum and Natural Gas Interests

Capitalized Costs

The Company follows the full cost method of accounting for petroleum and
natural gas interests whereby all costs relating to exploration for and
development of petroleum and natural gas reserves are capitalized in one
Canadian cost centre. Such costs include land acquisition costs,
geological and geophysical expenses, costs of drilling both productive
and non-productive wells, tangible equipment and administrative costs
directly related to acquisition, exploration and development activities.
Gains or losses are not recognized upon disposition of oil and natural
gas properties unless crediting the proceeds against accumulated costs
would result in a change in the rate of depletion of 20% or more.

Depletion and Depreciation

The costs associated with proved reserves are depleted or depreciated
using the unit-of-production method based on an independent engineering
estimate of the Company's share of proved reserves, before royalties,
with natural gas converted to its energy equivalent at a ratio of six
thousand cubic feet of natural gas to one barrel of oil. Office
equipment is amortized on a straight-line basis over five years.

Impairment

Petroleum and natural gas assets are evaluated at least annually to
determine that the costs are recoverable. The costs are assessed to be
recoverable if the sum of the undiscounted cash flows expected from the
production of proved reserves and the lower of cost and market of
unproved properties exceed the carrying value of the assets. If the
carrying value is assessed as unrecoverable, an impairment loss is
recognized to the extent that the carrying value of assets exceeds the
sum of the discounted cash flows expected from the production of proved
and probable reserves and the lower of cost and market of unproved
properties. The cash flows are estimated using expected future product
prices and costs and are discounted using a risk-free rate.

Asset Retirement Obligations

The fair value of a liability for asset retirement obligations is
recorded in the period when a reasonable estimate of the fair value can
be determined, with a corresponding increase to the carrying amount of
the related asset. The asset recorded is depleted on a
unit-of-production basis over the life of the resources. Increases in
the fair value of the asset retirement obligations due to the passage of
time are recorded as accretion expense. Actual expenditures incurred are
charged against the obligations.

(d) Revenue Recognition

Revenue is recognized when title passes to the customer.

(e) Foreign Currency Translation

Transactions of the Company that are denominated in foreign currencies
are recorded in Canadian dollars at exchange rates in effect at the
related transaction dates. Monetary assets and liabilities denominated
in foreign currencies are adjusted to reflect exchange rates at the
consolidated balance sheet date. Non-monetary assets and liabilities
denominated in foreign currencies are translated at the exchange rate in
effect when the assets are acquired or the liabilities assumed. Exchange
gains and losses arising on the translation of monetary assets and
liabilities are included in the determination of income for the period.

(f) Stock-Based Compensation Plans

The Company has a stock option plan that allows employees, independent
directors and consultants to be granted options to purchase common
shares at a fixed price not less than the fair market value of the stock
on the day preceding the grant date. The Company has also issued
performance warrants in conjunction with a private placement to
executives as disclosed in note 9. The fair value of the options and
warrants is estimated using the Black-Scholes option-pricing model that
takes into account, as of the grant date: exercise price; expected life;
current price; expected volatility; expected dividends; and risk-free
interest rates. Compensation expense relating to stock options includes
amounts for options granted on or after January 1, 2003. The expense
related to options issued during 2002 is disclosed as pro forma
information in note 10.

Consideration paid upon the exercise of the stock options or performance
warrants, together with corresponding amounts previously recognized in
contributed surplus, is recorded as an increase to share capital.

In the event that vested options or warrants expire without being
exercised, previously recognized compensation costs associated with such
stock options are not reversed.

(g) 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
basis, using enacted income tax rates. The effect of a change in income
tax rates on future income tax liabilities and assets is recognized in
income in the period that the change occurs.

(h) Earnings per Share

Per share information is calculated on the basis of the weighted average
number of common shares outstanding during the fiscal year. Diluted per
share information is calculated using the treasury stock method which
assumes that any proceeds received by the Company upon the exercise of
in-the-money stock options, plus unamortized stock compensation costs,
would be used to buy back common shares at the average market price for
the period.

(i) Derivative Financial Instruments

Derivative financial instruments are used by the Company to manage its
exposure to fluctuations in oil and natural gas prices. The Company does
not enter into derivative financial instruments for trading or
speculative purposes.

The Company formally documents all relationships between hedged items
and hedging items, the risk management objectives and the strategy for
undertaking various hedge transactions. This process includes linking
all derivatives to specific assets and liabilities on the balance sheet
or to specific firm commitments or forecasted transactions. The Company
also formally assesses, both at the inception of the hedge and on an
ongoing basis, whether the derivatives are highly effective in
offsetting changes in cash flows of hedged items.

The commodity price contracts the Company enters into are accounted for
as hedges and are not recognized on the balance sheet. Realized gains
and losses on these contracts are recognized in petroleum and natural
gas revenue and cash flows in the same period in which the revenues
associated with the hedged transactions are recognized.

3. Changes in Accounting Policies

(a) Asset Retirement Obligations

Effective January 1, 2004, the Company adopted CICA Handbook Section
3110, "Asset Retirement Obligations". Under the new standard, the fair
value of a liability for asset retirement obligations is recorded in the
period when a reasonable estimate of the fair value can be determined
with a corresponding increase to the carrying amount of the related
asset. The asset recorded is depleted on a unit-of-production basis over
the life of the reserves. Increases in the fair value of the asset
retirement obligations due to the passage of time are recorded as
accretion expense. Actual expenditures incurred are charged against the
obligations. Previously, the Company recognized a provision for future
site reclamation and abandonment costs based on the unit-of-production
method applied to the estimated future liability.

This change in accounting policy has been applied retroactively with
restatement of prior periods presented for comparative purposes as
follows:



Consolidated Balance Sheet - as at December 31, 2003

As Reported Change As Restated
----------------------------------
Assets
Petroleum and natural gas interests 156,622 5,091 161,713
Liabilities and shareholders' equity
Site restoration and abandonment 4,015 (4,015) -
Asset retirement obligations - 7,057 7,057
Future income taxes 16,279 674 16,953
Deficit (4,089) 1,375 (2,714)
----------------------------------
----------------------------------


Consolidated Statement of Operations and Deficit - Three months ended
December 31, 2003

As Reported Change As Restated
----------------------------------

Depletion, depreciation and amortization 5,710 (80) 5,630
Accretion - 122 122
Future income taxes 607 (15) 592
Net income 3,021 (27) 2,994
----------------------------------
----------------------------------


Consolidated Statement of Operations and Deficit - Year ended December
31, 2003

As Reported Change As Restated
----------------------------------

Depletion, depreciation and amortization 19,418 (162) 19,256
Accretion - 444 444
Future income taxes 5,765 (57) 5,708
Net income 11,509 (225) 11,284
----------------------------------
----------------------------------


As a result of this change in accounting policy, diluted net income per
share decreased by $0.01 for the year ended December 31, 2003.

(b) Petroleum and Natural Gas Interests (P&NG)

Effective January 1, 2004, the Company adopted Accounting Guideline 16
(AcG-16), "Oil and Gas Accounting - Full Cost", which replaces
Accounting Guideline 5, "Full Cost Accounting in the Oil and Gas
Industry". AcG-16 modifies how impairment is tested and is consistent
with CICA Section 3063, "Impairment of Long-lived Assets". Under AcG-16,
impairment is recognized if the carrying amount of the P&NG assets
exceeds the sum of the undiscounted cash flows expected to result from
the Company's proved reserves.

If the carrying value is not fully recoverable, the amount of impairment
is measured by comparing the carrying amounts of the P&NG assets to an
amount equal to the estimated net present value of future cash flows
from proved plus probable reserves. This calculation incorporates risks
and uncertainties in the expected future cash flows which are discounted
using a risk-free rate. Any excess carrying value above the net present
value of the future cash flows would be recorded as a permanent
impairment.

Previously, impairment was tested based on undiscounted future net
revenues using proved reserves and providing for future general and
administrative expenses, carrying costs and taxes. The adoption of
AcG-16 had no effect on the Company's financial results.

(c) Hedging Relationships

During 2004, the Company adopted Accounting Guideline 13 (AcG-13),
"Hedging Relationships", which provides standards for the documentation
and effectiveness testing of hedging activities. The adoption of AcG-13
had no effect on the Company's financial results.

4. Accounting Reclassification

Effective January 1, 2004 and consistent with the adoption of CICA
Handbook Section 1100, "Generally Accepted Accounting Principles",
transportation costs are presented as an expense in the Statement of
Operations and Retained Earnings (Deficit). Previously, these amounts
were recorded as an offset to revenue and have been reclassified to
conform to the presentation adopted in 2004.

Certain information provided for the prior periods has been reclassified
to conform to the presentation adopted in 2004.

5. Discontinued Operations

On July 23, 2003, the Company completed the sale of the shares of its
Indonesian subsidiary, Equatorial Energy (Indonesia) Inc. The sale
resulted in net proceeds of $23.2 million, after deduction of
transaction costs, and was accounted for as follows:





Gross sales proceeds (US$18 million) 24,835
Transaction costs (1,654)
--------
Net proceeds 23,181
Net book value of discontinued operations 29,732
--------
Loss on sale of discontinued operations (6,551)
--------
--------

The loss from discontinued operations in the consolidated statement of
operations and retained earnings (deficit) for the year ended December
31, 2003 includes the following:

Revenue 19,498
Income before income taxes 2,451
Income taxes 1,813
--------
638
Loss on sale of Indonesian operations (6,551)
--------
Loss from discontinued operations (5,913)
--------
--------

6. Petroleum and Natural Gas Interests

Accumulated
Depletion and Net Book
December 31, 2004 Cost Depreciation Value
----------------------------------
Petroleum and natural gas interests 305,935 (87,632) 218,303
Other assets 1,680 (676) 1,004
----------------------------------
307,615 (88,308) 219,307
----------------------------------
----------------------------------

December 31, 2003
Petroleum and natural gas interests
(note 2) 221,757 (60,801) 160,956
Other assets 1,293 (396) 897
----------------------------------
223,050 (61,197) 161,853
----------------------------------
----------------------------------


As at December 31, 2004, unproved Canadian properties with capitalized
costs of $18,211,000 (December 31, 2003 - $17,683,000) and other P&NG
assets of $2,007,000 (December 31, 2003 - $140,000), which consisted of
drilling supplies to be used for future exploration and development,
were not subject to depletion.

The Company capitalized overhead expenses of $785,000 (2003 - $383,000)
and $3,132,000 (2003 - $2,049,000) relating to petroleum and natural gas
exploration and development activities for the three-month period and
year ended December 31, 2004, respectively.

Resolute performed a ceiling test calculation at December 31, 2004 to
assess the recoverability of the carrying value of the petroleum and
natural gas interests. The following table summarizes the benchmark
prices used in the ceiling test calculation. Based on these assumptions,
there was no impairment at December 31, 2004.



Foreign Edmonton
WTI Oil Exchange Light Crude Oil AECO C Gas
Year (US$/bbl) Rate (Cdn$/bbl) (Cdn$/mmbtu)
------------------------------------------------------------------------
2005 42.00 0.84 50.25 6.60
2006 40.00 0.84 47.75 6.35
2007 38.00 0.84 45.50 6.15
2008 36.00 0.83 43.25 6.00
2009 34.00 0.83 40.75 6.00
2010-2012 33.00 0.84 39.50 6.00
Escalate
thereafter 2.0% per year 2.0% per year 2.0% per year


7. Long-term Debt

On June 14, 2004, the Company increased its revolving syndicated loan
facility from $50,000,000 to $70,000,000 and then on December 23, 2004
increased it to $80,000,000. Borrowings are made by way of prime loans
with interest at the banks' prime rate or bankers' acceptances and LIBOR
advances at money market rates plus a stamping fee of 1.10%. The
facility is secured by a first floating charge debenture and general
assignment of book debts and is subject to annual review by the lenders.
If not renewed, the total amount owing is repayable 366 days after the
conversion date. At December 31, 2004, the Company had drawn $37,000,000
(2003 - $16,000,000) against the loan.

Interest expense for the three months and year ended December 31, 2004
was as follows:



Three Months Ended Year Ended
December 31 December 31
($000s) 2004 2003 2004 2003
--------------------------------------
Long-term debt 324 230 835 739
Short-term debt 67 27 349 129
--------------------------------------
Total interest expense 391 257 1,184 868
--------------------------------------
--------------------------------------


8. Asset Retirement Obligations

Resolute's asset retirement obligations are based on the net ownership
in wells and facilities and management's estimate of costs to abandon
and reclaim those wells and facilities as well as an estimate of the
future timing of the costs to be incurred.

The Company has estimated the present value of its total asset
retirement obligations to be $12,100,000 at December 31, 2004 based on a
total future liability of $32,235,000. Payments to settle asset
retirement obligations occur over the operating lives of the underlying
assets, estimated to be from zero to 45 years, with the majority of
costs to be incurred by the end of 2020. Estimated cash flows have been
discounted at credit-adjusted, risk-free rates ranging from 7.0-7.5% and
inflation rates of 1.5-2.0%.



Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------
Asset retirement obligations,
beginning of period 7,880 6,919 7,057 6,129
Liabilities incurred during period 253 17 725 582
Revisions to obligations 3,892 - 3,892 -
Expenditures incurred during period (74) (1) (107) (98)
Accretion 149 122 533 444
--------------------------------------
Asset retirement obligations,
end of period 12,100 7,057 12,100 7,057
--------------------------------------
--------------------------------------

9. Share Capital

(a) Authorized Authorized

Unlimited number of common shares.
Unlimited number of preferred shares.

(b) Issued

Number Consideration
($000s)
----------------------------
Common Shares

Balance, December 31, 2002 59,154,700 115,404
Issued for cash
Private placement 425,000 1,012
Exercise of stock options & share purchase
warrants 517,637 1,068
Share issue costs (net of future tax effect) (54)
----------------------------
Balance, December 31, 2003 60,097,337 117,430
Issued for cash
Exercise of stock options & share purchase
warrants 672,735 1,458
Share issue costs (net of future tax effect) (32)
----------------------------
Balance, December 31, 2004 60,770,072 118,856
----------------------------

Share purchase warrants
Balance, December 31, 2003 and 2002 3,714,901 2,805
Exercise of warrants (66,772) (51)
----------------------------
Balance, December 31, 2004 3,648,129 2,754
----------------------------

Common shares and purchase warrants
Balance, December 31, 2003 120,235
---------------
Balance, December 31, 2004 121,610
---------------


The share purchase warrants have an exercise price of $2.08 per common
share and expire on December 14, 2005. The warrants were valued using
the Black-Scholes option-pricing model with a risk-free interest rate of
4.72%, a 42-month term, an expected volatility factor of 42.17% and a 0%
dividend yield.

(c) Performance warrants

As part of the initial capitalization of the Company, certain founding
shareholders were issued an aggregate of 3,310,005 performance warrants
on December 10, 2001. The performance warrants expire on December 10,
2008. In 2003, 1,223,064 performance warrants expired due to
resignations and 6,465 were exercised. On June 19, 2003, 425,000
performance warrants, expiring on June 19, 2008, were issued to new
officers pursuant to a private placement. The total performance warrants
outstanding at December 31, 2003 and 2004 were as follows:



Number of Exercise
Warrants Price ($)
-------------------------------
260,060 2.16
85,000 2.38
345,060 2.70
475,089 3.24
605,120 3.78
735,147 4.32
-------------------------------
2,505,476 3.47
-------------------------------
-------------------------------


(d) Share Purchase Loan

At December 31, 2004, the loan to an officer has been fully repaid. At
December 31, 2003, the outstanding amount of $188,000 was included in
"accounts receivable" on the balance sheet.

10. Stock-Based Compensation

(a) Stock Option Plan

The Company has established a stock option plan whereby officers,
directors, employees and service providers may be granted options to
purchase common shares at a fixed price not less than the fair market
value of the stock on the day preceding the grant date. Vesting and
expiry provisions are determined at the date of grant. At December 31,
2004, shareholders have authorized 5,359,684 stock options or 8.8% of
outstanding common shares, of which 4,362,561 are outstanding and
997,123 are available for future grants.

The following tables summarize information about the Company's stock
options outstanding at December 31, 2004:



Weighted
Average
Number of Exercise
Options Price ($)
------------------------
Outstanding at December 31, 2002 3,551,878 2.16
Granted 2,042,750 2.50
Cancelled (765,604) 2.29
Expired (489,880) 2.18
Exercised (511,172) 2.06
-----------
Outstanding at December 31, 2003 3,827,972 2.32
Granted 1,565,500 3.59
Cancelled (424,944) 2.76
Expired - -
Exercised (605,967) 2.08
-----------
Outstanding at December 31, 2004 4,362,561 2.77
-----------
-----------

Exercisable at December 31, 2004 1,364,004 2.29
-----------
-----------

The following table summarizes information about options exercised and
outstanding at December 31, 2004:

Remaining Remaining
Exercise Options Contractual Options Contractual
Price $ Outstanding Life (Years) Exercisable Life (Years)
------------------------------------------------------------------------

2.10 - 2.50 2,491,811 2.78 1,240,091 2.57
2.51 - 3.00 407,750 2.90 123,913 1.86
3.01 - 3.50 746,000 3.91 - -
3.51 - 4.56 717,000 3.56 - -
------------- -------------
2.10 - 4.56 4,362,561 3.11 1,364,004 2.50
------------- -------------
------------- -------------


(b) Share Appreciation Rights Plan

Share appreciation rights (SARs) were issued by Equatorial prior to the
Equatorial acquisition. The Company currently has no intention of
granting additional share appreciation rights.

Certain share appreciation rights had been granted to employees and
service providers. Each right entitles the participant to receive from
the Company an amount equal to the positive difference, if any, obtained
by subtracting the assigned amount from the simple average of the
closing trading price of the common shares on the Toronto Stock Exchange
for up to 20 trading days immediately preceding the date of exercise.

The following tables summarize information about the Company's share
appreciation rights outstanding at December 31, 2004:



Number of Weighted Average
SARs Exercise Price ($)
------------------------------

Outstanding at December 31, 2003 191,250 1.93
Exercised (103,750) 1.63
---------- -------------------
Outstanding at December 31, 2004 87,500 2.28
---------- -------------------
---------- -------------------

SARs
Number Remaining Contractual SARs
Base Value ($) Outstanding Life (Years) Exercisable
------------------------------------------------------------------------

1.45 37,500 2.96 37,500
2.90 50,000 1.16 50,000
------------- -------------
87,500 1.93 87,500
------------- -------------
------------- -------------


(c) Stock-Based Compensation Expense

The fair value of each option granted in 2003 and 2004 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:



Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------
Risk free interest rate (%) 3.39 3.35 3.03 3.29
Expected life (years) 3 3 3 3
Expected volatility (%) 44 26 47 34
Dividend yield (%) - - - -
Weighted average fair value ($) 1.52 0.66 1.25 0.68


The fair value of each performance warrant granted in 2003 was estimated
on the date of grant using the Black-Scholes option-pricing model with a
risk-free interest rate of 3.08%, a 60-month term, an expected
volatility factor of 38% and a 0% dividend yield.

The Company continues to disclose the pro forma earnings impact of stock
options granted in 2002. If the fair value method had been used for
options granted in 2002, the Company's net income from continuing
operations and net income for the periods ended December 31, 2004 and
2003 would be as follows:



Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------
Net income from continuing
operations
As reported 3,477 3,546 15,677 17,197
Pro forma 3,477 3,355 15,667 16,761

Per share basic, as reported 0.06 0.06 0.26 0.29
Per share basic, pro forma 0.06 0.06 0.26 0.28

Per share diluted, as reported 0.05 0.06 0.25 0.28
Per share diluted, pro forma 0.05 0.06 0.25 0.28

Net income
As reported 3,477 2,994 15,677 11,284
Pro forma 3,477 2,803 15,667 10,848

Per share basic, as reported 0.06 0.05 0.26 0.19
Per share basic, pro forma 0.06 0.05 0.26 0.18

Per share diluted, as reported 0.05 0.05 0.25 0.19
Per share diluted, pro forma 0.05 0.05 0.25 0.18


(d) Deferred Share Unit Plan for Non-Employee Directors

During the year, the Company established a deferred share unit (DSU)
plan to provide directors with the option to elect to receive DSUs in
lieu of cash payment for all or a portion of their retainer fees. When
elected, the Company will credit to the account of each director a
number of DSUs (each equivalent in value to a common share) equal to the
amount of fees divided by the fair market value of the common shares.
Upon the director ceasing to be a member of the Board of Directors, the
director shall receive a cash amount equal to the number of DSUs in his
or her account multiplied by the fair market value of the common shares
on the fourth business day following the next release of the Company's
quarterly financial results immediately following termination of Board
service. Or, if the Company has ceased to be a reporting issuer, this
will be a date specified by the Board. During the year ended December
31, 2004, there were 38,100 DSUs issued and the Company recorded
$125,000 in director fee compensation related to the DSU plan.

11. Net Income per Share

Net income per share figures have been calculated using the treasury
stock method. The following reconciles the number of shares used in the
basic and diluted net income per share calculations:



Three Months Year
Ended December 31 Ended December 31
Common Shares 2004 2003 2004 2003
------------------------------------------------

Basic 60,750,953 59,923,283 60,447,873 59,503,542
Dilutive securities
Stock options 1,477,454 778,514 1,127,133 527,626
Warrants 1,945,880 1,104,430 1,687,638 788,009
Performance warrants 634,902 106,667 396,614 50,697
------------------------------------------------
Diluted 64,809,189 61,912,894 63,659,258 60,869,874
------------------------------------------------
------------------------------------------------


12. Income Taxes

The future income tax provision reflects an effective tax rate which
differs from the expected statutory tax rate. Differences were accounted
for as follows:



2004 2003
------------------
Income from continuing operations before income taxes 24,566 23,359

Expected income taxes at the Canadian statutory rate
of 38.87% (2003 - 40.72%) 9,549 9,512
Increase (decrease) in income tax expense resulting
from:
Non-deductible Canadian Crown charge 4,396 3,899
Canadian resource allowance (4,723) (4,511)
Canadian large corporation tax and provincial
capital tax 476 454
Non-deductible amounts 394 227
Change in tax rates (1,239) (3,124)
Other 36 (295)
------------------
8,889 6,162
------------------
------------------


The major components of the future income tax liability are as follows:

2004 2003
------------------
Petroleum and natural gas interests 32,133 25,045
Asset retirement obligations (4,068) (2,442)
Non-capital losses - (2,612)
Share issue costs (137) (253)
Attributed Canadian Royalty Income (2,562) (2,785)
------------------
25,366 16,953
------------------
------------------

The Company's tax pools in Canada are approximately $146,319,000,
including $22,282,000 of Attributed Canadian Royalty Income (which is
deductible for Alberta tax purposes only) at December 31, 2004.

13. Statements of Cash Flows

Changes in non-cash working capital

Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------
Accounts receivable (1,509) (914) (2,191) (1,743)
Accounts payable and accrued
liabilities 6,175 (5,130) 3,494 246
--------------------------------------
Change in non-cash working capital 4,666 (6,044) 1,303 (1,497)
relating to:
--------------------------------------
Operating activities 2,275 (1,082) 165 198
Investing activities 2,391 (4,962) 1,138 (1,695)
--------------------------------------
4,666 (6,044) 1,303 (1,497)
--------------------------------------

Interest and taxes paid
Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------
Cash interest paid 355 206 1,324 868
--------------------------------------
Cash taxes paid 115 75 561 298
--------------------------------------


14. Financial Instruments

Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable,
accounts payable, bank indebtedness and long-term debt approximates
their fair value due to the short-term maturity of these instruments or
the indexed rate of interest on the bank debt.

Credit Risk

A substantial portion of the Company's accounts receivable are with
customers in the energy industry and are subject to normal industry
credit risk. The Company routinely assesses the financial strength of
its customers.

Commodity Price Contracts

The Company is party to certain derivative financial instruments,
specifically natural gas collars, for the purpose of managing its
exposure to fluctuations in natural gas prices. The collars reduce the
fluctuations in petroleum and natural gas revenues by locking in a floor
and ceiling on a portion of the Company's natural gas production.



Contracts outstanding as at December 31, 2004 were as follows:

Pricing Cost/
Contract Volume Point Floor Ceiling Premium Fair Value Term
------------------------------------------------------------------------
Collar 10,000 Dec 01/04 -
GJ/day AECO $7.85 $9.32 $0.15/GJ $1,728,000 Mar 31/05
Collar 7,000 Apr 01/05 -
GJ/day AECO $6.00 $7.68 $0.15/GJ $648,000 Oct 31/05
Collar 5,000 Apr 01/05 -
GJ/day AECO $6.00 $7.35 $0.15/GJ $403,000 Oct 31/05
------------------------------------------------------------------------


15. Commitments

The Company has obligations under operating leases for office space,
which expire on January 31, 2009. The total obligation, excluding
operating costs over the next 50 months, is $1,458,000 with an annual
minimum lease rental of $354,421 in 2005.

16. Subsequent Event

On March 14, 2005, the Company entered into an arrangement agreement
whereby Esprit Energy Trust will acquire the majority of the Company's
assets. Certain Resolute assets will be transferred to a separate
exploration and coalbed methane development company, to be named at a
later date. This transaction will require certain approvals to be
obtained subsequent to the date of this document.



Corporate Information

Board of Directors Officers

S. Barry Jackson (2)(3)(4) Brian K. Lemke
Chairman, Corporate Director President and Chief
Calgary, Alberta Executive Officer

Douglas D. Baldwin (1)(2) David V. Elgie
Corporate Director Executive Vice President and
Calgary, Alberta Chief Operating Officer

Donald P. Driscoll (1)(3) C. Dean Setoguchi
President and Chief Vice President and
Executive Officer Chief Financial Officer
NAL Resources
Calgary, Alberta Head Office
2500 Bow Valley Square 3
Brian K. Lemke (4) 255 - 5th Avenue SW
President and Chief Calgary, Alberta T2P 3G6
Executive Officer Tel: (403) 264-9562
Resolute Energy Inc. Fax: (403) 234-0322
Calgary, Alberta Email: info@resoluteenergy.com
Website: www.resoluteenergy.com
Douglas G. Manner (3)
Senior Vice President Solicitors
and Chief Operating Officer
Kosmos Energy LLC Bennett Jones LLP
Dallas, Texas Calgary, Alberta

Paul McDermott (1) Bankers
Managing Partner
Cadent Energy Partners LLC Canadian Imperial
Purchase, New York Bank of Commerce
Royal Bank of Canada
Robert R. Rooney (2)
Partner, Bennett Jones LLP Auditors
Barristers and Solicitors
Calgary, Alberta Deloitte & Touche LLP
Calgary, Alberta
Jeffrey T. Smith (3)(4)
Corporate Director Independent Reservoir
Calgary, Alberta Consultants

Philip C. Swift(1)(2) Gilbert Laustsen Jung
Co-Chairman Associates Ltd.
ARC Financial Corporation Calgary, Alberta
Calgary, Alberta
Transfer Agent
Members of the following Committees:
(1) Audit and Finance Valiant Trust Company
(2) Human Resources and Governance Calgary, Alberta
(3) Technical
(4) Corporate Advisory Stock Exchange Listing
Toronto Stock Exchange
Trading symbol: RSE


-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Resolute Energy Inc.
    Brian K. Lemke
    President and Chief Executive Officer
    (403) 264-9562 or Toll Free: 1-888-608-1866
    or
    Resolute Energy Inc.
    C. Dean Setoguchi
    Vice President and Chief Financial Officer
    (403) 264-9562 or Toll Free: 1-888-608-1866
    Email: info@resoluteenergy.com
    Website: www.resoluteenergy.com