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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K þ
    
    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 For the Fiscal Year ended December 31, 2004. o
    
    Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 For the transition period fromto. Commission File Number: 0-29370 ULTRA PETROLEUM CORP.  Yukon Territory, Canada
(Jurisdiction of Incorporation or Organization)
    
    N/A
(I.R.S. Employer Identification No.)
 363 North Sam Houston Parkway East, Suite 1200
Houston, Texas 77060
(Address of Principal Executive Offices) (Zip Code)281-876-0120
(Registrants Telephone Number, Including Area Code) Securities registered pursuant to Section 12(b) of the Act: Title of each class
    
    Name of each exchange
on which registeredCommon Shares, without par value
    
    American Stock Exchange
 Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirement for the past 90 days. YES þ NO o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act
Rule 12b-2).
YES þ NO o The aggregate market value of the voting and non-voting common equity held by non-affiliates of the
registrant was approximately $2,800,510,337 as of June 30, 2004 (based on the last reported sales
price of $37.33 of such stock on the American Stock Exchange on such date). As of February 28, 2005, there were 75,527,468 common shares of the registrant outstanding. Documents incorporated by reference: The definitive Proxy Statement for the 2005 Annual Meeting of
Stockholders, which will be filed with the Securities and Exchange Commission within 120
days after December 31, 2004, is incorporated by reference in Part III of this Form 10-K.   1




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TABLE OF CONTENTS PagePART IItem 1. Business
    
    
    5Item 2.
Properties
    
    
    16Item 3. Legal Proceedings
    
    
    22Item 4. Submission of Matters to a Vote of Security Holders
    
    
    22PART IIItem 5.
Market forRegistrants
Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
    
    
    22Item 6. Selected Financial Data.
    
    
    23Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    24Item 7A Quantitative and Qualitative Disclosures About Market Risk
    
    
    30Item 8. Financial Statements and Supplementary Data
    
    
    32Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
    
    
    52Item 9A Controls and Procedures
    
    
    52Item 9B
Other InformationPART IIIItem 10. Directors and Executive Officers of Registrant
    
    
    52Item 11. Executive Compensation
    
    
    52Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    
    
    52Item 13. Certain Relationships and Related Transactions
    
    
    52Item 14. Principal Accountants Fees and Services
    
    
    52PART IVItem 15.
Exhibits and Financial Statement Schedules
    
    
    53Signatures
    
    
    53Second Amendment to Amended Credit AgreementFirst Amendment to Second Amended Credit AgreementConsent of Netherland, Sewell & Associates, Inc.Consent of Ryder Scott CompanyConsent of KPMG, LLPCertification of CEO & CFO Pursuant to Rule 13a-14(a)Certification of CEO & CFO Pursuant to Section 1350
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Certain Definitions Terms used to describe quantities of oil and natural gas and marketing  
    Bbl One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
    Bcf One billion cubic feet of natural gas.
    Bcfe One billion cubic feet of natural gas equivalent.
    BOE One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil.
    BTU British Thermal Unit.
    CFD Caofaedian  the Chinese designation for the area in Bohai Bay area in the vicinity
of the 04/36 and 05/36 Blocks, offshore China.
    Condensate An oil-like liquid produced in association with natural gas production that
condenses from natural gas as it is produced and delivered into a separator or similar equipment and
collected in tanks at each well prior to the delivery of such gas to the gas gathering
pipeline system.
    ICP Indonesian Crude Price.
    MBbl One thousand barrels.
    Mcf One thousand cubic feet of natural gas.
    Mcfe One thousand cubic feet of natural gas equivalent.
    MMBbl One million barrels of oil or other liquid hydrocarbons.
    MMcf One million cubic feet of natural gas.
    MBOE One thousand BOE.
    MMBOE One million BOE.
    MMBTU One million British Thermal Unit. Terms used to describe the Companys interests in wells and acreage  
    Gross oil and gas wells or acres The Companys gross wells or gross acres represent the
total number of wells or acres in which the Company owns a working interest.
    Net oil and gas wells or acres Determined by multiplying gross oil and natural gas
wells or acres by the working interest that the Company owns in such wells or acres
represented by the underlying properties. Terms used to assign a present value to the Companys reserves  
    Standardized measure of discounted future net cash flows, after income taxes The
present value, discounted at 10%, of the pre-tax future net cash flows attributable to
estimated net proved reserves. The Company calculates this amount by assuming that it will
sell the oil and gas production attributable to the proved reserves estimated in its
independent engineers reserve report for the prices it received for the production on the
date of the report, unless it had a contract to sell the production for a different price.
The Company also assumes that the cost to produce the reserves will remain constant at the
costs prevailing on the date of the report. The assumed costs are subtracted from the
assumed revenues resulting in a stream of future net cash flows. Estimated future income
taxes using rates in effect on the date of the report are deducted from the net cash flow
stream. The after-tax cash flows are discounted at 10% to result in the standardized measure
of the Companys proved reserves.  
    Standardized measure of discounted future net cash flows The discounted present value
of proved reserves is identical to the standardized measure, except that estimated future
income taxes are not deducted in calculating future net cash flows. The Company discloses
the discounted present value without deducting estimated income taxes to provide what it
believes is a better basis for comparison of its reserves to the producers who may have
different tax rates. Terms used to classify the Companys reserve quantities The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X,
is as follows: Proved oil and gas reserves.Proved oil and gas reserves are the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions. (a) Reservoirs are considered proved if economic producibility is supported by either actual
production or conclusive formation test. The area of a reservoir considered proved includes (1)
that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering data. In the absence
of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir. 3




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(b) Reserves which can be produced economically through application of improved recovery
techniques (such as fluid injection) are included in the proved classification when successful
testing by a pilot project, or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was based. (c) Estimates of proved reserves do not include the following: (1) oil that may become
available from known reservoirs but is classified separately as indicated additional reserves;
(2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4)
crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal,
gilsonite and other such sources.  
    Proved developed reserves Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
    Proved undeveloped reserves Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required. Terms used to describe the legal ownership of the Companys oil and gas properties  
    Working interest A real property interest entitling the owner to receive
a specified percentage of the proceeds of the sale of oil and natural gas production
or a percentage of the production, but requiring the owner of the working interest to
bear the cost to explore for, develop and produce such oil and natural gas. A working
interest owner who owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or disapprove the
appointment of an operator and drilling and other major activities in connection with
the development and operation of a property. Terms used to describe seismic operations  
    Seismic data Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in exploration for
new deposits and to manage or enhance production from known reservoirs. To gather
seismic data, an energy source is used to send sound waves into the subsurface
strata. These waves are reflected back to the surface by underground formations,
where they are detected by geophones which digitize and record the reflected waves.
Computers are then used to process the raw data to develop an image of underground
formations.
    2-D seismic data 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad area. 2-D
seismic data is collected by a single line of energy sources which reflect seismic
waves to a single line of geophones. When processed, 2-D seismic data produces an
image of a single vertical plane of sub-surface data.
    3-D seismic data 3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey produces a three
dimensional image of the subsurface geology by collecting seismic data along parallel
lines and creating a cube of information that can be divided into various planes,
thus improving visualization. Consequently, 3-D seismic data is a more reliable
indicator of potential oil and natural gas reservoirs in the area evaluated. 4




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PART I 
 Item 1.Business. Ultra Petroleum Corp. (Ultra or the Company) is an independent oil and gas company engaged
in the development, production, operation, exploration and acquisition of oil and gas properties.
The Company was incorporated on November 14, 1979, under the laws of the Province of British
Columbia, Canada. The Company continued into the Yukon Territory, Canada under Section 190 of the
Business Corporations Act(Yukon Territory) on March 1, 2000. The Companys operations are focused
primarily in the Green River Basin of southwest Wyoming and Bohai Bay, offshore China. From time
to time, the Company evaluates other opportunities for the acquisition, exploration and development
of oil and gas properties. As of December 31, 2004 Ultra owns interests in approximately 166,974 gross (92,997 net) acres
in Wyoming covering approximately 260 square miles. The Company owns working interests in
approximately 241 gross productive wells in this area and is operator of 41.5% of the 241 gross
wells. The Companys current domestic operations are focused on developing and expanding a tight
gas sand project located in the Green River Basin in Southwest Wyoming. In 2004, the Companys
Wyoming production was approximately 92.8% of the Companys total oil and natural gas production on
a BOE basis and 97% of the Companys estimated net proved reserves were in Wyoming. In 2004,
capital expenditures in Wyoming comprised approximately 92% of the Companys total capital
expenditures. Following the acquisition of Pendaries Petroleum Ltd. on January 16, 2001, the Company became
active in oil and gas exploration and development in Bohai Bay, China. The Company holds an
18.182% exploration interest in the 04/36 Block and a 15.00% exploration interest in the 05/36
Block (jointly the Blocks) which interests are reduced upon initiation of development to an 8.91%
working interest and a 7.35% working interest, respectively, for the development areas. On July
19, 2004 oil production began from the CFD 11-1 & 11-2 fields on Block 04/36. In 2004, the Company
spent approximately 8% of its total 2004 capital budget on developing these China fields, as well
as on engineering work focused on development of additional fields and continuing exploration. A
wholly owned subsidiary of Kerr-McGee Corporation is the operator of the Blocks. At the time of the
Pendaries acquisition, there were three oil discoveries on the Blocks. Since then, six new
discoveries have been made on the Blocks. The Company also owns interests in 15,518 gross (14,652 net) acres in Pennsylvania. A test
well is planned to be drilled on this acreage in 2005. The Company owns interest in approximately
720 gross (320 net) acres and interests in three productive wells in Texas. The Companys annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports
on Form 8-K, as well as any amendments to such reports and all other filings we make pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge to the
public on the Companys website at www.ultrapetroleum.com. To access the Companys SEC
filings, select Financials under the Investor Relations tab on the Companys website. The
Companys SEC filings are available on its website as soon as they are posted to the EDGAR database
on the SECs website. Business Strategy Green River Basin, Wyoming The Company will continue the ongoing program to identify, develop and explore the acreage
position now held in the tight gas sand trend in the Green River Basin. The majority of the wells
in the 2005 drilling program will be targeting the sands of the upper Cretaceous Lance Pool in the
Pinedale and Jonah fields. The Lance Pool, as administered by the Wyoming Oil and Gas Conservation
Commission (WOGCC), includes sands of both the Lance at a range of approximately 8,000 to 12,000
feet and Mesaverde at a range of approximately 12,000 to 14,000 feet as found in the Pinedale and
Jonah fields area. The Company will continue to drill step-out and exploration wells on its Green
River Basin acreage position in an ongoing attempt to further define and expand the current known
producing area. In addition to the ongoing efforts in the Lance Pool section, the Company is
continuing to evaluate the deeper potentially productive zones found on its acreage block below the
Lance Pool. All of the Companys drilling activity is conducted utilizing its extensive integrated
geological and geophysical data set which includes what the Company believes is the most
comprehensive 3D seismic data coverage on the Pinedale Field. This data set is being utilized to
map the potentially productive intervals, to identify areas for future extension of the Lance
fairway and to identify deeper objectives which may warrant drilling. 5




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Bohai Bay, China In 2005, the Company plans to continue producing oil at the CFD 11-1 & 11-2 fields, begin
development and appraisal work on existing discoveries and drill additional exploration wells. The
Company has nine discovered oil fields in the Bohai Blocks. The first two oil fields, CFD 11-1 &
11-2, began producing in July 2004. Two additional fields are currently scheduled to go on
production in late 2005 and engineering plans are being completed to bring three more fields into
production in 2006 bringing the total to seven producing fields by year-end 2006. The two
remaining fields are still in the appraisal stage. Marketing and Pricing The Company derives its revenues principally from the sale of its natural gas production, and
associated condensate, from wells operated by the Company and others in the Green River Basin in
Southwest Wyoming. To a lesser extent, the Company derives its revenues from the sale of its share
of oil production from its producing fields in the Bohai Bay area, offshore China. The Companys
revenues are determined, to a large degree, by prevailing natural gas prices for production
situated in the Rocky Mountain Region of the United States; specifically, Southwest Wyoming, as
well as prevailing prices for crude oil produced in the Bohai Bay region of China of comparable
quality. Energy commodity prices in general, and the Companys regional prices in particular, have
experienced a high degree of volatility in the past, and such high levels of volatility are
expected to continue in the future. The Company cannot accurately predict or control the market
prices that it receives for the sale of its natural gas, condensate, or oil production. However,
the Company does, in the regular course of its business, from time to time, hedge a portion of its
natural gas production through the use of fixed price, forward sales of physical gas, or through
the limited use of financial swaps with creditworthy financial counterparties. The Company has
not, to date, hedged any of its Chinese oil production; although it may do so in the future. For a
more detailed description of the Companys hedging activities, see Item 7A Quantitative and
Qualitative Discussion about Market Risk. The Companys hedging policy limits amounts hedged to
not more than 50% of its forecast production without board approval. As a result of its hedging
activities, the Company may realize prices that are less than the spot prices that it would have
received. However, the Company has determined that the certainty and predictability of a portion
of its revenues that result from its hedging activities are both desirable and prudent. Natural Gas Marketing During 2004, the Company realized natural gas prices that were higher than those historically
seen in the Southwest Wyoming region. The market price for natural gas in the Rockies generally,
and in Southwest Wyoming specifically, is influenced by a number of regional and national factors;
all of which are beyond the ability of the Company to control or to predict. These factors include
weather, gas supplies, gas demand, and pipeline export capacity. The Rocky Mountain Region is a
net-exporter of natural gas, since production there exceeds local demand for gas. Historically,
natural gas production in Southwest Wyoming has sold at a discount relative to other U. S. natural
gas production sources or market areas. These regional pricing differentials or discounts are
typically referred to as basis or basis differentials. As recently as the first quarter of
2003, the Company saw significant basis differentials for its Wyoming production, versus the Henry
Hub pricing reference point in south Louisiana. As a result, during that time period, the Company
realized prices that were significantly lower than those received by companies with production in
other regions of the U.S. Since the second quarter of 2003, generally speaking, the Company has
enjoyed, and expects to enjoy, improved basis differentials for its Wyoming natural gas production,
due to significant increases in pipeline capacity to transport production from the Rockies
production areas to markets in the West (Kern River Pipeline  in service May 2003) and the
Midwestern U.S. (Cheyenne Plains Pipeline  in service February 2005). These expansions of
pipeline export capacity have reduced but not eliminated the basis
differential for gas prices in
Southwest Wyoming gas production when compared to prices at the Henry Hub pricing reference point. The Kern River Pipeline system was expanded by over 900 MMcfd, in May 2003, bringing its
capacity to deliver natural gas produced in Southwest Wyoming to markets in Utah, Nevada and
California to over 1.7 Bcf/d. Since that time, Colorado Interstate Gas Pipeline (a subsidiary of
El Paso Corporation) has completed Phase I of the Cheyenne Plains Pipeline, which moves gas from
Wyoming to Greensburg, Kansas, where it is interconnected with several large, interstate gas
pipelines that supply gas to markets in the Midwestern U.S. The completion of Phase I of the
Cheyenne Plains Pipeline adds 560 MMcfd of export capacity for Rocky Mountain gas to markets in the
Midwest. There are numerous other proposed pipeline projects in various stages of planning or
development that have been announced to transport Rockies and Wyoming gas production to markets.
While the Company is optimistic that the pipeline infrastructure will continue to be expanded to
provide 6




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sufficient capacity to transport its gas production and to provide for reasonable basis
differentials for its gas in the future, there can be no assurance that any such expansions, if
built, will prevent large basis differentials from occurring in the future. The Company currently sells all of its natural gas production to a diverse group of
third-party, non-affiliated entities in a portfolio of transactions of various durations (daily,
monthly and longer term). The sale of the Companys natural gas is as produced, and the Company
does not maintain any significant inventories or imbalances of natural gas. The Company maintains
credit policies intended to mitigate the risk of uncollectible accounts receivable. Oil Marketing With the commencement of production from the first two of its fields in Block 04/36 Bohai Bay
offshore China in July 2004, the Company, through its wholly owned Sino-American Energy Corporation
subsidiary, has begun marketing its share of oil production from the CFD 11-1/11-2 fields. The sale of the Companys Chinese oil production (CFD crude) is done on a tanker/cargo lifting
basis. As the Companys share of inventories on the CFD 11-1/11-2 fields Floating Production
Storage and Offloading Vessel (FPSO) become sufficient to schedule a lifting (typically 200,000 
300,000 barrels per cargo), the Company coordinates with the operator and its markets to lift a
cargo. By necessity, the Company will, from time to time, carry inventories of crude oil to
accommodate the lifting schedules for its share of oil from the FPSO. Each of the partners in the
CFD 11-1/11-2 fields are responsible for the disposition of their respective share of the CFD crude
production. Kerr-McGee, as operator of these fields, manages the lifting schedule for production
from these fields. During 2004, the Company lifted and sold 3 cargos of CFD crude for its account. Currently, the CFD crude is a heavy, sweet crude oil, with an API gravity of approximately 19
degrees. The production from these fields is from multiple productive reservoirs, which have
variability in the quality of oil. The Company believes that the quality of the oil produced from
these fields will tend to improve as additional wells and reservoirs are completed and placed into
production. Due to its quality, refiners and other markets for the CFD crude oil typically expect
to be able to purchase CFD crude at prices that are lower than light sweet crude oils like West
Texas Intermediate or Brent. Oil produced and sold from these fields is typically priced based upon
the monthly official Indonesian Crude Price (ICP) for Duri field crude. The Duri crude, produced
in Indonesia, is of similar quality to the CFD crude produced in the Bohai Bay area. The official
ICP Duri price is a monthly weighted average of three (3) independent daily assessments of the
price of Duri crude, reported by Platts, APPI (Asian Petroleum Price Index published by Seapac
Services Limited), and RIM Intelligence Co. To the monthly official ICP Duri marker price, a
premium or discount is added to reflect transportation and quality differentials for the CFD crude
relative to the Duri marker crude. The premium or discount for the CFD crude (relative to the
Duri price) is negotiated monthly between buyers and sellers. To date, the Company has sold its share of the CFD production to an affiliate of its Chinese
partner, Chinese National Offshore Oil Corporation (CNOOC) China, Ltd., at prices that reflect a
slight discount to the ICP Duri monthly average price. The Company continues to assess its
opportunities to market its share of the CFD oil production to other markets such as Korea, Japan
and Singapore. Environmental Matters In 1998, the U.S. Bureau of Land Management (BLM) initiated a requirement for an
Environmental Impact Statement (EIS) for the Pinedale Anticline area in the Green River Basin. An
EIS evaluates the effects that an industrys activities will have on the environment in which the
activity is proposed. This EIS encompasses the area north of the Jonah Field, including the
Pinedale Anticline, which is where most of the Companys exploration and development is taking
place. This environmental study included an analysis of the geological and reservoir
characteristics of the area plus the necessary environmental studies related to wildlife, surface
use, socio-economic and air quality issues. On July 27, 2000, the BLM issued its Record of
Decision (ROD) with respect to the final EIS. The ROD/EIS allows for the drilling of 700
producing surface locations within the area covered by the EIS, but does not authorize the drilling
of particular wells. Ultra must submit applications to the BLMs Pinedale field manager for permits
to drill and for other required authorizations, such as rights-of-way for pipelines, for each
specific well or pipeline location. Development activities in the Pinedale Anticline area, as on
all federal leaseholds, remain subject to regulatory agency approval. In making its determination
on whether to approve specific drilling or development activities, the BLM applies the requirements
outlined in the ROD/EIS. 7




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The ROD/EIS imposes limitations and restrictions on activities in the Pinedale Anticline area,
including limits on winter drilling and completion activity, and proposes mitigation guidelines,
standard practices for industry activities and best management practices for sensitive areas. The
ROD/EIS also provides for annual reviews to compare actual environmental impacts to the
environmental impacts projected in the EIS and provides for adjustments to mitigate such impacts,
if necessary. The review team is comprised of operators, local residents and other affected
persons. The process of reviews is currently undergoing changes to satisfy the Federal Advisory
Committee Act. The Company cannot predict if or how these changes may affect permitting,
development and compliance under the EIS. The BLMs field manager may also impose additional
limitations and mitigation measures as are deemed reasonably necessary to mitigate the impact of
drilling and production operations in the area. As of year end, the Company had approximately 55 approved permits to drill wells on Company
operated federal leases in the Pinedale Anticline area. To date, the Company has expended significant resources in order to satisfy applicable
environmental laws and regulations in the Pinedale Anticline area and other areas of operation
under the jurisdiction of the BLM. The Companys future costs of complying with these regulations
may continue to be substantial. Further, any additional limitations and mitigation measures could
further increase production costs, delay exploration, development and production activities and
curtail exploration, development and production activities altogether. The Company also co-owns leases on state and privately owned lands in the vicinity of the
Pinedale Anticline that do not fall under the jurisdiction of the BLM and are not subject to the
EIS requirement. In August 1999, the BLM required an Environmental Assessment (EA) for the potential
increased density drilling in the Jonah Field area. An EA is a more limited environmental study
than is conducted under an EIS. The EA was required to address the potential environmental impacts
of developing the field on a well density of two (2) wells per 80 acre drilling and spacing unit as
opposed to the one (1) well per 80 acre drilling and spacing unit as was approved in the initial
Jonah Field EIS approved in 1998. The new EA was completed in June 2000. With the approval of this
EA and the earlier approval by the Wyoming Oil and Gas Conservation Commission (WOGCC) for drilling
of two (2) wells per 80 acre drilling and spacing unit, the Company was permitted to drill infill
wells at this well density on the 2,160 gross (1,322 net) acres then owned by the Company in the
Jonah Field. Prior to these approvals, the Company had drilled 21 gross (7.7 net) wells in the
field. Since the increased density approvals, the Company has drilled an additional 22 gross (14.0
net) wells in the field. All 43 wells drilled by the Company in the Jonah Field have been
productive. Since this time various other operators have received approval for the drilling of
increased density wells in pilot areas at well densities ranging from four (4) wells per 80 acre
drilling and spacing unit to sixteen (16) wells per drilling and spacing unit. Results of all of
these pilot projects were utilized in acquiring approval from the WOGCC in November 2004 to
increase the overall density of development for the Jonah Field to eight (8) wells per 80 acre
drilling and spacing unit. The BLM is currently conducting a new EIS covering the Jonah Field to
assess the impacts of this increased density development and define the parameters under which this
increased density development will be allowed to proceed. The draft EIS was made available
mid-February 2005. The Company is currently reviewing the document. During 2003 and 2004 Ultra and other operators in the Pinedale Field received approval from
the WOGCC to drill increased density pilot project wells in several areas of the Pinedale Field.
These pilot projects are designed to test the feasibility of developing this field in well
densities greater than the currently approved one well per 40 acres. The results of some of this
work led to the WOGCC in July 2004 approving the development of the northern portion of the
anticline on a two (2) wells per 40 acre density. The acreage is operated by Questar Exploration
and Production Company (Questar), a working interest partner of the Company, and the Company owns
a working interest in the majority of this acreage. This approval covers approximately 14,432
gross acres. Drilling of additional increased density pilot wells continues and the results of
these are being evaluated to determine the appropriate course of action as to the overall
development strategy for the Pinedale Field. In April 2004 Questar asked the BLM to modify winter-access restrictions to specifically allow
them to operate on three active pads with two drilling rigs per pad. This request required an EA to
weigh the negative impacts of winter activity relative to the extensive mitigation measures
proposed by Questar. On November 9, 2004 they received approval in the form of a Finding of No
Significant Impact from the BLM to phase in over the next year their proposed year-round drilling
program which allows two drilling rigs on one pad during the winter of 2004/2005. After Questar
completes the proposed mitigation measures including construction of a water and 8




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condensate gathering system during the summer of 2005, they will be allowed to operate six
rigs from three active pads beginning in the winter of 2005/2006 through the winter of 2013/2014. The BLM approved the Questar proposal after considering extensive input from the participating
agencies received during the public comment process. Key components of the approval are: 1) One pad
with two drilling rigs during the winter of 2004/2005; 2) three pads with two drilling rigs per pad
in the winter of 2005/2006 and thereafter through the winter of 2013/2014; 3) activities during the
May-November period will continue to be governed by the original Pinedale Anticline EIS; 4)
directional drilling with up to 16 wells per pad resulting in only one-third of the drilling phase
surface disturbance contemplated under the original EIS; 5) construction of a produced water and
condensate gathering system in 2005; 6) funding for continued monitoring of mule deer and other
critical wildlife for the duration of development activity; 7) use of flareless-completion
technology to reduce noise, air and visual pollution during well-completion operations; 8) funding
for air-quality monitoring; and 9) wildlife habitat enhancement as well as other monitoring and
mitigation measures described in the BLM decision record. In September 2002, the Company received the Oil & Gas Wildlife Stewardship award from the
Wyoming Game and Fish Department in recognition of its contribution to wildlife management in the
Pinedale area. During 2001, the Company received the Agency/Corporation of the Year award from
the Wyoming Wildlife Federation and the Regional Administrators Award for Environmental
Achievement from the U.S. Environmental Protection Agency. Regulation Oil and Gas Regulation The availability of a ready market for oil and gas production depends upon numerous factors
beyond the Companys control. These factors include state and federal regulation of oil and gas
production and transportation, as well as regulations governing environmental quality and pollution
control, state limits on allowable rates of production by a well or proration unit, the amount of
oil and gas available for sale, the availability of adequate pipeline and other transportation and
processing facilities and the marketing of competitive fuels. For example, a productive gas well
may be shut-in because of a lack of an available gas pipeline in the areas in which the Company
may conduct operations. State and federal regulations are generally intended to prevent waste of
oil and gas, protect rights to produce oil and gas between owners in a common reservoir, control
the amount of oil and gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines and gas plants are also subject to the jurisdiction of
various federal, state and local agencies. The Companys sales of natural gas are affected by the availability, terms and costs of
transportation both in the gathering systems that transport from the wellhead to the interstate
pipelines and in the interstate pipelines themselves. The rates, terms and conditions applicable
to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory
Commission (FERC) under the Natural Gas Act, as well as under Section 311 of the Natural Gas
Policy Act. Since 1985, the FERC has implemented regulations intended to increase competition
within the gas industry by making gas transportation more accessible to gas buyers and sellers on
an open-access, non-discriminatory basis. On February 25, 2000, FERC issued a statement of policy
and final rule concerning alternatives to its traditional cost-of-service rate-making methodology
to establish the rates interstate pipelines may charge for their services. The final rule revises
the FERCs pricing policy and current regulatory framework to improve the efficiency of the market
and further enhance competition in natural gas markets. FERC is also considering a number of
regulatory initiatives that could affect the terms and costs of interstate transportation of gas by
interstate pipelines on behalf of natural gas shippers, including policy inquiries about gas
quality and interchangeability, selective discounting of transportation services by pipelines to
shippers, and proposed rules governing pipeline creditworthiness and collateral standards. Because
these regulatory initiatives have not been made final, the approach the FERC will take and the
potential impact on gas suppliers are not clear. The Companys sales of oil are also affected by the availability, terms and costs of
transportation. The rates, terms, and conditions applicable to the interstate transportation of
oil by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has
implemented a simplified and generally applicable ratemaking methodology for interstate oil
pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of
an indexing system to establish ceilings on interstate oil pipeline rates. 9




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In the event the Company conducts operations on federal, tribal or state lands, such
operations must comply with numerous regulatory restrictions, including various operational
requirements and restrictions, nondiscrimination statutes and royalty and related valuation
requirements. In addition, certain of such operations must be conducted pursuant to certain
on-site security regulations, bonding requirements and applicable permits issued by the BLM or
Minerals Management Service (MMS), Bureau of Indian Affairs (BIA), tribal or other applicable
federal, state and/or Indian Tribal agencies. The Mineral Leasing Act of 1920 (Mineral Act) prohibits direct or indirect ownership of any
interest in federal onshore oil and gas leases by a foreign citizen of a country that denies
similar or like privileges to citizens of the United States. Such restrictions on citizens of a
non-reciprocal country include ownership or holding or controlling stock in a corporation that
holds a federal onshore oil and gas lease. If this restriction is violated, the corporations
lease can be canceled in a proceeding instituted by the United States Attorney General. Although
the regulations of the BLM (which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect. The Company owns
interests in numerous federal onshore oil and gas leases. It is possible that holders of the
Companys equity interests may be citizens of foreign countries, which at some time in the future
might be determined to be non-reciprocal under the Mineral Act. See Risk Factors for a discussion of the risks to our international operations. Environmental Regulations General. The Companys activities in the United States are subject to existing federal, state
and local laws and regulations governing environmental quality, oil spills and pollution control
and its activities in China are subject to the laws and regulations of China. It is anticipated
that, absent the occurrence of an extraordinary event, compliance with existing federal, state and
local laws, rules and regulations governing the release of materials in the environment or
otherwise relating to the protection of the environment will not have a material effect upon the
Companys operations, capital expenditures, earnings or competitive position. The Companys activities with respect to exploration, drilling and production from wells and
natural gas facilities, including the operation and construction of pipelines, plants and other
facilities for transporting, processing, treating or storing oil, natural gas and other products,
are subject to stringent environmental regulation by state and federal authorities, including the
Environmental Protection Agency (EPA). Such regulation can increase the cost of planning,
designing, installing and operating such facilities. In most instances, the regulatory
requirements relate to water and air pollution control measures. Solid and Hazardous Waste. The Company currently owns or leases, and has in the past owned or
leased, numerous properties that have been used for the exploration and production of oil and gas
for many years. Although the Company utilized operating and disposal practices that were standard
in the industry at the time, hydrocarbons or other solid wastes may have been disposed of or
released on or under the properties that the Company currently owns or leases or properties that
the Company has owned or leased or on or under locations where such wastes have been taken for
disposal. In addition, many of these properties have been operated by third parties over whom the
Company had no control as to such entities treatment of hydrocarbons or other wastes or the manner
in which such substances may have been disposed of or released. State and federal laws applicable
to oil and gas wastes and properties have gradually become stricter over time. Under new laws, the
Company could be required to remediate property, including ground water, containing or impacted by
previously disposed wastes (including wastes disposed of or released by prior owners or operators)
or to perform remedial plugging operations to prevent future, or mitigate existing, contamination. The Company may generate wastes, including hazardous wastes that are subject to the federal
Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The EPA and various
state agencies have limited the disposal options for certain wastes, including wastes designated as
hazardous under the RCRA and state analogs (Hazardous Wastes) and is considering the adoption of
stricter disposal standards for nonhazardous wastes. Furthermore, certain wastes generated by the
Companys oil and gas operations that are currently exempt from treatment as Hazardous Wastes may
in the future be designated as Hazardous Wastes under the RCRA or other applicable statutes, and
therefore be subject to more rigorous and costly operating and disposal requirements. Superfund. The federal Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA), also known as the Superfund law, generally imposes joint and several liability for
costs of investigation and remediation and for natural resource damages, without regard to fault or
the legality of the 10




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original conduct, on certain classes of persons with respect to the release into the environment of
substances designated under CERCLA as hazardous substances (Hazardous Substances). These classes
of persons, or so-called potentially responsible parties (PRPs), include current and certain past
owners and operators of a facility where there has been a release or threat of release of a
Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous
Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third
parties to take actions in response to threats to the public health or the environment and to seek
to recover from the PRP the costs of such action. Although CERCLA generally exempts petroleum
from the definition of Hazardous Substance, in the course of its operations, the Company has
generated and will generate wastes that fall within CERCLAs definition of Hazardous Substances.
The Company may also be an owner or operator of facilities on which Hazardous Substances have been
released. The Company may be responsible under CERCLA for all or part of the costs to clean up
facilities at which such substances have been released and for natural resource damages. To its
knowledge, the Company has not been named a PRP under CERCLA nor have any prior owners or operators
of its properties been named as PRPs related to their ownership or operation of such property. National Environmental Policy ActThe federal National Environmental Policy Act provides
that, for those federal actions that are major federal actions significantly affecting the quality
of the human environment, the federal agency taking such action must follow certain steps in
evaluating the environmental impacts of the federal action. This evaluation generally takes the
form of an Environmental Impact Statement (EIS). In the EIS, the agency is required to evaluate
alternatives to the proposed action and the environmental impacts of the alternatives. Actions
such as drilling on federal lands, to the extent the drilling requires federal approval, likely
trigger the requirements of the National Environmental Policy Act, with few exceptions. Certain of
the Companys activities may trigger these requirements. The requirements of the National
Environmental Policy Act may result in increased costs, significant delays and the imposition of
restrictions or obligations, including the restriction or prohibition of drilling, upon the
Companys activities. Oil Pollution ActThe Oil Pollution Act of 1990 (OPA), which amends and augments oil spill
provisions of the CWA, imposes certain duties and liabilities on certain responsible parties
related to the prevention of oil spills and damages resulting from such spills in or threatening
United States waters or adjoining shorelines. A liable responsible party includes the owner or
operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the
substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of
the area in which a discharging facility is located. The OPA assigns joint and several liability,
without regard to fault, to each liable party for oil removal costs and a variety of public and
private damages. Although defenses and limitations exist to the liability imposed by OPA, they are
limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for
costs and damages. Air Emissions.The Companys operations are subject to local, state and federal regulations
for the control of emissions from sources of air pollution. Federal and state laws require new and
modified sources of air pollutants to obtain permits prior to commencing construction. Major
sources of air pollutants are subject to more stringent, federally imposed requirements including
additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants,
might require installation of additional controls. Administrative enforcement actions for failure
to comply strictly with air pollution regulations or permits are generally resolved by payment of
monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies
could bring lawsuits for civil penalties or require the Company to forego construction,
modification or operation of certain air emission sources. Clean Water Act. The Clean Water Act (CWA) imposes restrictions and strict controls
regarding the discharge of wastes, including produced waters and other oil and natural gas wastes,
into waters of the United States, a term broadly defined. These controls have become more
stringent over the years, and it is probable that additional restrictions will be imposed in the
future. Permits must be obtained to discharge pollutants into federal waters. The CWA provides
for civil, criminal and administrative penalties for unauthorized discharges of pollutants and of
oil and hazardous substances. It imposes substantial potential liability for the costs of removal
or remediation associated with discharges of oil or hazardous substances. State laws governing
discharges to water also provide varying civil, criminal and administrative penalties and impose
liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous
substances, into state waters. In addition, the EPA has promulgated regulations that may require
the Company to obtain permits to discharge storm water runoff, including discharges associated with
construction activities. In the event of an unauthorized discharge of wastes, the Company may be
liable for penalties and costs. Endangered Species Act.The Endangered Species Act (ESA) was established to provide a means
to conserve the ecosystems upon which endangered and threatened species depend, to provide a
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conservation of these endangered and threatened species, and to take the appropriate steps
that are necessary to bring any endangered or threatened species to the point where measures
provided for in the ESA are no longer necessary. The Company conducts operations on federal oil and
gas leases that have species, such as sage grouse or other sensitive species, that potentially
could be listed as threatened or endangered under the ESA. If a species is listed as threatened or
endangered, the U.S. Fish and Wildlife Service must also designate the species critical habitat
and suitable habitat as part of the effort to ensure survival of the species. A critical habitat
or suitable habitat designation could result in further material restrictions to federal land use
and may materially delay or prohibit land access for oil and gas development. If the Company were
to have a portion of its leases designated as critical or suitable habitat, it may adversely impact
the value of the affected leases. OSHA and other RegulationsThe Company is subject to the requirements of the federal
Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title III of CERCLA and
similar state statutes require us to organize and/or disclose information about hazardous materials
used or produced in its operations. The Company believes that it is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing requirements will
not have a material adverse impact on the Company. Employees As of February 28, 2005, the Company had 41 full time employees, including officers. RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995 This report contains or incorporates by reference forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities
Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this document, including without limitation,
statements in Item 7, Managements Discussion and Analysis of Financial Condition and Results of
Operations regarding our financial position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of the Companys management for future
operations, covenant compliance and those statements preceded by, followed by or that otherwise
include the words believe, expects, anticipates, intends, estimates, projects,
target, goal, plans, objective, should, or similar expressions or variations on such
expressions are forward-looking statements. The Company can give no assurances that the assumptions
upon which such forward-looking statements are based will prove to be correct. Important factors
that could cause actual results to differ materially from the Companys expectations are included
throughout this document. The Cautionary Statements expressly qualify all subsequent written and
oral forward-looking statements attributable to the Company or persons acting on the Companys
behalf. Internal Control Systems.There are inherent limitations in all control systems, and
misstatements due to error or fraud that could seriously harm our business may occur and not be
detected. Our management, including our Chief Executive Officer and Chief Financial Officer, does
not expect that our internal controls and disclosure controls will prevent all possible error and
all fraud. A control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system are met. In
addition, the design of a control system must reflect the fact that there are resource constraints
and the benefit of controls must be relative to their costs. Because of the inherent limitations
in all control systems, no evaluation of controls can provide absolute assurance that all control
issues and instances of fraud, if any, in our company have been detected. These inherent
limitations include the realities that judgments in decision-making can be faulty and that
breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by
the individual acts of some persons or by collusion of two or more persons. The design of any
system of controls is based in part upon certain assumptions about the likelihood of future events,
and there can be no assurance that any design will succeed in achieving its stated goals under all
potential future conditions. Over time, a control may be inadequate because of changes in
conditions or the degree of compliance with the policies or procedures may deteriorate. Because of
inherent limitations in a cost-effective control system, misstatements due to error or fraud may
occur and not be detected. A failure of our controls and procedures to detect error or fraud could
seriously harm our business and results of operations. Competition. The Company competes with numerous other companies in virtually all facets of
its business. The competitors in development, exploration, acquisitions and production include
major integrated oil 12




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and gas companies as well as numerous independents, including many that have significantly greater
resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid
for and purchase a greater number of properties or prospects than the financial or personnel
resources of the Company permit. The ability of the Company to increase reserves in the future will
be dependent on its ability to select and acquire suitable prospects for future exploration and
development. Historically, the Companys projects have been financed through debt and internally generated
cash flow. There is competition for capital to finance oil and gas drilling. The ability of the
Company to obtain such financing is uncertain and can be affected by numerous factors beyond its
control. The inability of the Company to raise capital in the future could have an adverse effect
its financial condition and results of operations. Marketing of Oil and Natural Gas. The ability to market oil and natural gas depends
on numerous factors beyond the Companys control. These factors include:  
    the extent of domestic production and imports of oil and natural gas;
    the availability of pipeline capacity;
    the effects of inclement weather;
    the demand for oil and natural gas by utilities and other end users;
    the availability of alternative fuel sources;
    the proximity of natural gas production to natural gas pipelines;
    state and federal regulations of oil and natural gas marketing; and
    federal regulation of natural gas sold or transported in interstate commerce. Because of these factors, the Company may be unable to market all of the oil and natural gas
that it produces, including oil and natural gas that may be produced from the Bohai Bay properties.
In addition, the Company may be unable to obtain favorable prices for the oil and natural gas it
produces. Volatility of Oil and Gas Prices.Prices for oil and gas are subject to large fluctuations in
response to relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond the Companys control. These factors
include but are not limited to weather conditions in the United States, the condition of the United
States economy, the actions of the Organization of Petroleum Exporting Countries (OPEC),
governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
of oil and gas, the price of foreign oil and gas imports and the availability of alternate fuel
sources and transportation interruption. Any substantial and extended decline in the price of oil
or gas could have an adverse effect on the carrying value of the Companys proved reserves,
borrowing capacity, the Companys ability to obtain additional capital, and the Companys revenues,
profitability and cash flows from operations. Volatile oil and gas prices make it difficult to estimate the value of producing properties
for acquisition and divestiture and often cause disruption in the market for oil and gas producing
properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also
makes it difficult to budget for and project the return on acquisitions and development and
exploitation projects. Price of Wyoming Production. The Company produces natural gas in Wyoming. The market price
for this natural gas differs from the market indices for natural gas in the Gulf Coast region of
the United States due potentially to insufficient pipeline capacity and/or low demand in the summer
months for natural gas in the Rocky Mountain region of the United States. Therefore, the effect of
a price decrease may more adversely affect the price received for the Companys Wyoming production
than production in the other U.S. regions. Government Regulations. The Companys operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating to environmental
protection. These laws and regulations may:  
    require that the Company acquire permits before commencing drilling;
    restrict the substances that can be released into the environment in connection with
drilling and production activities;
    limit or prohibit drilling activities on protected areas such as wetlands or
wilderness areas;
    require remedial measures to mitigate pollution from former operations, such as
plugging abandoned wells; and
    require governmental approval of the overall development plan prior to the start of
development of fields in China. 13




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Under these laws and regulations, the Company could be liable for personal injury and clean-up
costs and other environmental and property damages, as well as administrative, civil and criminal
penalties. The Company maintains limited insurance coverage for sudden and accidental environmental
damages, but does not maintain insurance coverage for the full potential liability that could be
caused by sudden and accidental environmental damages. Accordingly, the Company may be subject to
liability or may be required to cease production from properties in the event of environmental
damages. A significant percentage of the Companys United States operations are conducted on federal
lands. These operations are subject to a variety of on-site security regulations as well as other
permits and authorizations issued by the BLM, the Wyoming Department of Environmental Quality and
other agencies. A portion of the Companys acreage is affected by winter lease stipulations that
prohibit exploration, drilling and completing activities generally from November 15 to April 30,
but allow production activities all year round. To drill wells in Wyoming, the Company is required
to file an Application for Permit to Drill with the Wyoming Oil and Gas Conservation Commission.
Drilling on acreage controlled by the federal government requires the filing of a similar
application with the BLM. These permitting requirements may adversely affect the Companys ability
to complete its drilling program at the cost and in the time period currently anticipated. On
large-scale projects, lessees may be required to perform environmental impact statements to assess
the environmental impact of potential development, which can delay project implementation and/or
result in the imposition of the environmental restrictions that could have a material impact on
cost or scope. Limited Financial Resources. The Companys ability to continue exploration and development of
its properties and to replace reserves may be dependent upon its ability to continue to raise
significant additional financing, including debt financing that may be significant, or obtain some
other arrangements with industry partners in lieu of raising financing. Any arrangements that may
be entered into could be expensive to the Company. There can be no assurance that the Company will
be able to raise additional capital in light of factors such as the market demand for its
securities, the state of financial markets for independent oil companies (including the markets for
debt), oil and gas prices and general market conditions. See Managements Discussion and Analysis
of Financial Condition and Results of OperationsLiquidity and Capital Resources for a discussion
of the Companys capital budget. The Company expects to continue using its bank credit facility to borrow funds to supplement
its available cash flow. The amount the Company may borrow under the credit facility may not exceed
a borrowing base determined by the lenders based on their projections of the Companys future
production, future production costs and taxes, commodity prices and other factors. The Company
cannot control the assumptions the lenders use to calculate the borrowing base. The lenders may,
without the Companys consent, adjust the borrowing base at any time. If the Companys borrowings
under the credit facility exceed the borrowing base, the lenders may require that the Company repay
the excess. If this were to occur, the Company may have to sell assets or seek financing from other
sources. The Company can make no assurances that it would be successful in selling assets or
arranging substitute financing. For a description of the bank credit facility and its principal
terms and conditions, see Managements Discussion and Analysis of Financial Condition and Results
of OperationsLiquidity and Capital Resources. Interruptions from Severe Weather. The Companys operations are conducted principally in the
Rocky Mountain region. The weather in this area can be extreme and can cause interruption in the
Companys exploration and production operations. Moreover, especially severe weather can result in
damage to facilities entailing longer operational interruptions and significant capital investment.
Likewise, the Companys Rocky Mountain operations are subject to disruption from winter storms and
severe cold, which can limit operations involving fluids and impair access to the Companys
facilities. A portion of the Companys acreage is affected by winter lease stipulations that
restrict the period of time during which operations may be conducted on the leases. The Companys
leases that are affected by the winter stipulations prohibit drilling and completing activities
from mid-November to mid-May, but allow production activities all year round. The Company Invests Heavily in Exploration. The Company has historically invested a
significant portion of its capital budget in drilling exploratory wells in search of unproved oil
and gas reserves. The Company cannot be certain that the exploratory wells it drills will be
productive or that it will recover all or any portion of its investments. In order to increase the
chances for exploratory success, the Company often invests in seismic or other geoscience data to
assist it in identifying potential drilling objectives. Additionally, the cost of drilling,
completing and testing exploratory wells is often uncertain at the time of the Companys initial
investment. Depending on complications encountered while drilling, the final cost of the well may
significantly exceed that which the Company originally estimated. The Company uses the full cost
method of accounting for exploration 14




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and development activities as defined by the Securities and Exchange Commission (SEC). Under this
method of accounting, the costs of unsuccessful, as well as successful, exploration and development
activities are capitalized as properties and equipment and are then depleted using the unit of
production method based on the Companys proved reserves. Replacement of Reserves.The Companys future success may depend on its ability to find,
develop and acquire additional oil and gas reserves that are economically recoverable. Without
successful exploration, development or acquisition activities, the Companys reserves and
production will decline. The Company can give no assurance that it will be able to find, develop
or acquire additional reserves at acceptable costs. Operating Hazards and Uninsured Risks. The oil and gas business involves a variety of
operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured
formations, and environmental hazards such as oil spills, gas leaks, and discharges of toxic gases.
The occurrence of any of these events with respect to any property operated or owned (in whole or
in part) by the Company could have a material adverse impact on the Company. The Company and the
operators of its properties maintain insurance in accordance with customary industry practices and
in amounts that management believes to be reasonable. However, insurance coverage is not always
economically feasible and is not obtained to cover all types of operational risks. The occurrence
of a significant event that is not fully insured could have a material adverse effect on the
Companys financial condition. Drilling and Operating Risks. The Companys oil and gas operations are subject to all of the
risks and hazards typically associated with drilling for, and production and transportation of, oil
and gas. These risks include the necessity of spending large amounts of money for identification
and acquisition of properties and for drilling and completion of wells. In the drilling of
exploratory or development wells, failures and losses may occur before any deposits of oil or gas
are found. The presence of unanticipated pressure or irregularities in formations, blow-outs or
accidents may cause such activity to be unsuccessful, resulting in a loss of the Companys
investment in such activity. If oil or gas is encountered, there can be no assurance that it can
be produced in quantities sufficient to justify the cost of continuing such operations or that it
can be marketed satisfactorily. Drilling Plans Subject to Change. This report includes certain descriptions of the Companys
future drilling plans with respect to its prospects. A prospect is an area which the Companys
geoscientists have identified what they believe, based on available seismic and geological
information, to be indications of hydrocarbons. The Companys prospects are in various stages of
review. Whether or not the Company ultimately drills a prospect may depend on the following
factors: receipt of additional seismic data or reprocessing of existing data; material changes in
oil or gas prices; the costs and availability of drilling equipment; success or failure of wells
drilled in similar formations or which would use the same production facilities; availability and
cost of capital; changes in the estimates of costs to drill or complete wells; the approval of
partners to participate in the drilling or, in the case of CNOOC, approval of expenditures for
budget purposes; the Companys ability to attract other industry partners to acquire a portion of
the working interest to reduce exposure to costs and drilling risks; decisions of the Companys
joint working interest owners; and the BLMs interpretation of the EIS and the results of the
permitting process. The Company will continue to gather data about its prospects, and it is
possible that additional information may cause the Company to alter its drilling schedule or
determine that a prospect should not be pursued at all. Financial Reporting Impact of Full Cost Method of Accounting. The Company follows the full
cost method of accounting for its oil and gas properties. A separate cost center is maintained for
expenditures applicable to each country in which the Company conducts exploration and/or production
activities. Under such method, the net book value of properties on a country-by-country basis,
less related deferred income taxes, may not exceed a calculated ceiling. The ceiling is the
estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per
year. In calculating discounted future net revenues, oil and gas prices in effect at the time of
the calculation are held constant, except for changes which are fixed and determinable by existing
contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if
any, of the net book value above the ceiling is required to be written off as an expense. Under
SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and
gas prices increase the ceiling applicable to future periods. Future price decreases could result
in reductions in the carrying value of such assets and an equivalent charge to earnings. Risks Arising From Being Non-Operator in Bohai Bay. Because the Company is not the operator
and holds a minority interest it cannot control the pace of exploration or development in the Bohai
Bay properties or major decisions affecting drilling of wells or the plan for development and
production, although contract 15




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provisions give the Company certain consent rights in some matters. Kerr-McGees influence over
these matters can affect the pace at which the Company spends money on this project. If Kerr-McGee
were to shift its focus from this project, the pace of development of the Blocks could slow down or
stop altogether. The Company currently does not believe it has sufficient funds to purchase
Kerr-McGees interests in these Blocks if they were offered. On the other hand, if Kerr-McGee were
to decide to accelerate development of this project, the Company could be required to fund its
share of costs at a faster pace than anticipated, which might exceed its ability to raise funds.
If, because of this, the Company were unable to pay its share of costs, it could lose or be forced
to sell its interest in the Bohai Bay properties or be forced to not participate in the exploration
or development of specific prospects or fields on the Blocks, potentially diminishing the value of
its Bohai Bay assets. Political, Economic or International Factors Affecting China. Ownership of property interests
and production operations in areas outside the United States are subject to various risks inherent
in foreign operations. These risks may include:  
    loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrections;
    increases in taxes and governmental royalties;
    renegotiation of contracts with governmental entities and quasi-governmental agencies;
    change in laws and policies governing operations of foreign based companies;
    labor problems;
    other uncertainties arising out of foreign government sovereignty over its international operations; and
    currency restrictions and exchange rate fluctuations. Tensions between China and its neighbors or various Western countries, regional political or
military disruption, changes in internal Chinese leadership, social or political disruptions within
China, a downturn in the Chinese economy, or a change in Chinese laws or attitudes toward foreign
investment could make China an unfavorable environment in which to invest. Although all the foreign
interest owners in the Bohai Bay properties have the right to sell production in the world market,
the regulation of the concession by China, and the likely participation by CNOOC as a large working
interest owner, make Chinese internal and external affairs important to the investment in the Bohai
Bay. If any of these negative events were to occur, it could lead to a decision that there is an
intolerable level of risk in continuing with the investment, or the Company may be unable to
attract equity investors or lenders, or satisfy any then-existing lenders. In the event of a dispute arising from foreign operations, the Company may be subject to the
exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to
the jurisdiction of courts in the United States or a potentially more favorable country. In addition, the Companys China PSCs terminate after 15 years of production, unless extended
as provided for, which may be prior to the end of the productive life of the fields. Operating Risks in China. Offshore operations, such as the Companys Bohai Bay properties,
are subject to a variety of operating risks specific to the marine environment, such as capsizing,
collisions and/or loss from storms or other adverse weather conditions. These conditions can cause
substantial damage to facilities and interrupt production. As a result, the Company could incur
substantial liabilities that could result in financial losses or failures. China has many
regulations similar to those addressed in Item I, Environmental Regulation, that may expose the
Company to liability. Offshore projects, like the China field developments, are typically large,
complex construction projects that are potentially subject to delays which may cause delays in
achieving production and profitability. 
 Item 2.Properties. Location and Characteristics The Company is dependent on oil and gas leases in Wyoming and two petroleum contracts in China
in order to explore for and produce oil and gas. The leases in Wyoming are primarily federal leases
with 10-year lease terms until establishment of production. Production on the lease extends the
lease terms until cessation of that production. There are approximately 93,865 gross (42,298 net)
acres currently held by production. The China petroleum contracts are for a maximum of 30 years
and are divided into 3 periods; exploration, development and production. The exploration period is
for approximately 7 years and work is to be performed and expenditures are to be incurred to
delineate the extent and amount of hydrocarbons, if any, for each block. 16




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##### Table of Contents



The development period occurs when a field is discovered and commences on the date of approval of
the Ministry of Energy. There is no limit on the time allowed to develop a field. The production
period of any oil and gas field in a block is a period of 15 consecutive years commencing on the
date of commencement of commercial production from the field, unless extended. Green River Basin, Wyoming As of December 31, 2004, the Company owned developed oil and gas leases totaling 9,686 gross
(4,022 net) acres in the Green River Basin of Sublette County, Wyoming which represents 93% of the
Companys total domestic developed gross acreage. The Company owned undeveloped oil and gas leases
totaling 157,288 gross (88,975 net) acres in the Green River Basin of Sublette County, Wyoming
which represents 91% of the Companys total domestic undeveloped gross acreage. The Companys
acreage in the Green River Basin is primarily covering the Pinedale Anticline with several other
undeveloped acreage blocks north and west of the Pinedale Anticline as well as acreage in the Jonah
Field. Holding costs of leases in Wyoming not held by production were approximately $109,250 for
the fiscal year ended December 31, 2004. The primary target on the Companys Wyoming acreage is
the tight gas sands of the upper Cretaceous Lance formation. Exploratory Wells. During the year-ended December 31, 2004, the Company participated in the
drilling and completion of a total of 32 gross (14.00 net) successful exploratory wells on the
Green River Basin properties. At year end there were 14 gross (7.43 net) additional exploratory
wells that commenced during the year that were either still drilling or had drilling operations
suspended for winter. Development Wells.During the year-ended December 31, 2004, the Company participated in the
drilling and completion of 34 gross (14.48 net) successful development wells in the Pinedale Field
area. At year end there were 4 gross (1.08 net) additional development wells that commenced during
2004 that were either still drilling or had drilling operations suspended for winter. For purposes
of this report, development wells are wells identified as proven undeveloped locations by the
Companys independent petroleum engineering firm Netherland, Sewell & Associates, Inc. at the
previous year-end reserve evaluation. When drilled, these locations will be counted as development
wells. Bohai Bay, China Block 04/36: The Petroleum Sharing Contract (PSC) covering this block became effective
October 1, 1994. Negotiations with the Chinese government in 2004 resulted in an extension of the
third exploration term to September 2005. As the contract now stands, the exploration period will
end at the end of September 2005. Barring an extension, at that time all acreage not under
appraisal, development or production must be relinquished. The Company holds an 18.182%
exploration interest in the exploration portion of the block and an 8.92% development interest in
the CFD 11-1 & 11-2 field development portion. The Company holds 431,513 gross (78,536 net) acres
under the exploration phase and 22,486 gross (2,006 net) acres under development, or 66% of the
Companys total gross international acreage. Block 05/36: The PSC covering this block became effective March 1, 1996. Negotiations with
the CNOOC at the end of 2004 resulted in an extension of the third exploration term to February 28,
2006 when, barring an extension, all acreage not under appraisal, development or production must be
relinquished. The extension granted by CNOOC must be ratified by the Chinese Government which the
foreign parties anticipate will happen. The Company holds a 15.00% exploration interest in this
block which is 233,300 gross (34,995 net) acres, or 34% of the Companys total gross international
acreage. Exploration/Appraisal Activity: In 2004 the Company participated in drilling one exploration
well (0.182 net) which failed to find commercial quantities of oil. The primary target formations
on the blocks are the Upper and Lower Minghuazhen, Guantao and Dongying formations. Development Activity: In July of 2004, the Company started production at the CFD 11-1 & 11-2
fields on the 04/36 Block. The field currently consists of two production platforms and an anchored
FPSO vessel. During start up of the initial (Phase 1) development in 2004, the Company
participated in drilling 33 gross (2.94 net) oil producers and 3 gross (0. 27 net) water injection
wells into the primary producing horizons of the Upper and Lower Minghuazhen, Guantao and Dongying
formations. At completion of Phase 2 of the development in early 2006, as many as 65 wells may have
been drilled in the two fields. Under the PSC, the Company is responsible for 18.182% of all expenses incurred on any portion
of the blocks not declared as development areas (Exploration Interest). Upon declaration of
commerciality of a field 17




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##### Table of Contents



or area by CNOOC, the Companys share of all expenses within that area is decreased by 51%,
with the participation by CNOOC, to 8.92% (Development Interest). Upon initiation of production,
the sharing of production is determined by the language of the PSC which (in general terms) states
that for each individual field: 1) a Chinese National Industrial Tax (VAT) and Royalty are applied
to 100% of the gross volumes of oil, 2) Lease Operating Expenses (LOE) are then taken out of the
remainder oil and 3) after these deductions, 62.5% of the remaining production stream is dedicated
to Exploration and Development Cost Recovery for the participants. The Exploration Cost Recovery
shall be recovered without interest, while the Development Cost Recovery shall be calculated with a
fixed annual interest rate of nine (9%) percent uplift, and 4) the remaining 37.5% of production
goes to the remainder oil category which is divided into a share oil for CNOOC and an
allocable remainder oil for the contractors determined by a sliding scale (determined by yearly
production) X factor. Project profit is subject to Chinese Corporate tax. On October 16, 2003, a 15 year contract which provides for extensions for up to an additional
10 years was signed by the operator to lease the FPSO. The Company ratified the contract for its
net share which is 8.92%. The FPSO is a 110,000-150,000 dead weight tons (DWT), double-hull FPSO
with a 900,000-1,100,000 barrels storage capacity, with Single Point Mooring (SPM) and a
processing plant capable of processing 60,000 barrels oil/day (expandable to 80,000 barrels
oil/day). The FPSO service agreement calls for a day rate lease payment and a sliding scale per
barrel payment that decreases based on cumulative barrels processed. Pennsylvania The Company owns 15,518 gross (14,652 net) acres in Pennsylvania, which represents 9% of the
Companys total domestic undeveloped gross acreage. A location has been selected and permitted for
the drilling of an initial test well on this acreage in 2005. The
drilling objectives in this area are
the carbonates of the Ordovician age Trenton and Black River formations. These objectives have been
the target of ongoing successful exploration efforts by other operators in portions of New York
state, just north of the Companys prospect area in Pennsylvania. Texas The Company operates one gross (0.66 net) well and owns working interests in an additional two
gross (0.22 net) wells in Texas and owns 720 gross (382 net) developed acres which represents 7% of
the Companys total developed gross acreage. In 2003 the Company leased 15,121 gross (11,002 net)
acres in Edwards County, Texas. The Company drilled one gross (0.73 net) well on this Edwards
County acreage in 2004 that was unsuccessful and the Company subsequently dropped the acreage. Oil and Gas Reserves The following table sets forth the Companys quantities of domestic proved reserves, for the
years-ended December 31, 2004, 2003 and 2002 as estimated by independent petroleum engineers
Netherland, Sewell & Associates, Inc. The table summarizes the Companys domestic proved reserves,
the estimated future net revenues from these reserves and the standardized measure of discounted
future net cash flows attributable thereto at December 31, 2004, 2003 and 2002. In accordance with
Ultras three-year planning and budgeting cycle, proved undeveloped reserves included in this table
include only economic locations that are forecast to be on production before January 1, 2008.
Proved undeveloped reserves represent 63.6% of total proved reserves. December 31,(in thousands)2004
    
    
    
    2003
    
    
    
    2002Proved
Undeveloped ReservesNatural gas (MMcf)
    
    
    899,315
    
    
    
    664,295
    
    
    
    444,513Oil (MBbl)
    
    
    7,195
    
    
    
    5,314
    
    
    
    3,556Proved
Developed ReservesNatural gas (MMcf)
    
    
    514,686
    
    
    
    359,072
    
    
    
    222,608Oil (MBbl)
    
    
    4,195
    
    
    
    3,028
    
    
    
    2,003Total Proved Reserves (MMcfe)
    
    
    1,482,341
    
    
    
    1,073,419
    
    
    
    700,474Estimated future net cash flows, before income tax
    
    $
    5,889,630
    
    
    $
    4,456,478
    
    
    $
    1,308,595Standardized measure of discounted future net cash flows
    
    $
    2,438,837
    
    
    $
    1,784,314
    
    
    $
    473,528Standardized measure of discounted future net cash flows,
after income tax
    
    $
    1,615,465
    
    
    $
    1,135,513
    
    
    $
    316,965
 18




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##### Table of Contents



The following table sets forth the Companys quantities of proved reserves in China, for the
year-ending December 31, 2004, as estimated by independent petroleum engineers Ryder Scott Company.
In accordance with the Companys new field reserve booking policy, proved reserves were booked
after production commenced. The table summarizes the Companys proved reserves in China, the
estimated future net revenues from these reserves and the standardized measure of discounted future
net cash flows attributable thereto at December 31, 2004. In accordance with Ultras three-year
planning and budgeting cycle, proved undeveloped reserves included in this table include only
economic locations that are forecast to be on production before January 1, 2008. Proved
undeveloped reserves represent 42.6% of total proved reserves. December 31,(in thousands)2004
    
    
    2003
    
    
    2002Proved
Undeveloped ReservesNatural gas (MMcf)
    
    
    
    
    
    
    
    
    
    
    Oil (MBbl)
    
    
    3,231
    
    
    
    
    
    
    
    Proved
Developed ReservesNatural gas (MMcf)
    
    
    
    
    
    
    
    
    
    
    Oil (MBbl)
    
    
    4,356
    
    
    
    
    
    
    
    Total Proved Reserves (MMcfe)
    
    
    45,526
    
    
    
    
    
    
    
    Estimated future net cash flows, before income tax
    
    $
    137,762
    
    
    $
    
    
    
    $
    Standardized measure of discounted future net cash flows
    
    $
    103,518
    
    
    $
    
    
    
    $
    Standardized measure of discounted future net cash flows,
after income tax
    
    $
    53,871
    
    
    $
    
    
    
    $
    
 The following table sets forth the Companys quantities of total proved reserves both
domestically and in China, for the years-ended December 31, 2004, 2003 and 2002 as estimated by
independent petroleum engineers Netherland, Sewell & Associates, Inc. and Ryder Scott Company. The
table summarizes the Companys total proved reserves, the estimated future net revenues from these
reserves and the standardized measure of discounted future net cash flows attributable thereto at
December 31, 2004, 2003 and 2002. In accordance with Ultras three-year planning and budgeting
cycle, proved undeveloped reserves included in this table include only economic locations that are
forecast to be on production before January 1, 2008. Proved undeveloped reserves represent 63.0%
of total proved reserves. December 31,(in thousands)2004
    
    
    2003
    
    
    2002Proved
Undeveloped ReservesNatural gas (MMcf)
    
    
    899,315
    
    
    
    664,295
    
    
    
    444,513Oil (MBbl)
    
    
    10,426
    
    
    
    5,314
    
    
    
    3,556Proved
Developed ReservesNatural gas (MMcf)
    
    
    514,686
    
    
    
    359,072
    
    
    
    222,608Oil (MBbl)
    
    
    8,551
    
    
    
    3,028
    
    
    
    2,003Total Proved Reserves (MMcfe)

    
    
    1,527,867
    
    
    
    1,073,419
    
    
    
    700,474Estimated future net cash flows, before income tax
    
    $
    6,027,392
    
    
    $
    4,456,478
    
    
    $
    1,308,595Standardized measure of discounted future net cash flows
    
    $
    2,542,355
    
    
    $
    1,784,314
    
    
    $
    473,528Standardized measure of discounted future net cash flows,
after income tax
    
    $
    1,669,336
    
    
    $
    1,135,513
    
    
    $
    316,965
 19




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##### Table of Contents



Production Volumes, Average Sales Prices and Average Production Costs The following table sets forth certain information regarding the production volumes and
average sales prices received for and average production costs associated with Ultras sale of oil
and natural gas for the periods indicated. Year Ended December 31,2004
    
    
    2003
    
    
    2002ProductionNatural gas (Mcf)
    
    
    43,667,384
    
    
    
    27,621,759
    
    
    
    16,495,751Oil (Bbl)  US
    
    
    349,673
    
    
    
    211,591
    
    
    
    151,215Oil (Bbl)  China
    
    
    593,332
    
    
    
    
    
    
    
    Total (Mcfe)
    
    
    49,325,414
    
    
    
    28,891,305
    
    
    
    17,403,041RevenuesGas sales
    
    $
    224,207,694
    
    
    $
    114,840,558
    
    
    $
    38,502,971Oil sales  US
    
    
    14,659,219
    
    
    
    6,740,539
    
    
    
    3,839,421Oil sales  China
    
    
    19,170,436
    
    
    
    
    
    
    
    Total Revenues
    
    
    258,037,349
    
    
    
    121,581,097
    
    
    
    42,342,392Lease Operating ExpensesProduction costs  US*
    
    
    6,286,715
    
    
    
    3,627,639
    
    
    
    2,356,986Production costs  China*
    
    
    2,286,000
    
    
    
    
    
    
    
    Severance/production taxes
    
    
    28,151,661
    
    
    
    13,767,668
    
    
    
    4,116,012Gathering
    
    
    13,135,809
    
    
    
    7,828,372
    
    
    
    4,937,870Total Lease Operating Expenses
    
    $
    49,860,185
    
    
    $
    25,223,679
    
    
    $
    11,410,868Realized PricesNatural gas (Mcf)
    
    $
    5.13
    
    
    $
    4.16
    
    
    $
    2.33Oil (Bbl)  US
    
    $
    41.92
    
    
    $
    31.86
    
    
    $
    25.39Oil (Bbl)  China
    
    $
    32.31
    
    
    $
    
    
    
    $
    Operating Costs per McfeProduction costs  Total
    
    $
    0.17
    
    
    $
    0.13
    
    
    $
    0.14Severance/production taxes
    
    $
    0.57
    
    
    $
    0.48
    
    
    $
    0.24Gathering
    
    $
    0.27
    
    
    $
    0.27
    
    
    $
    0.28DD&A
    
    $
    0.61
    
    
    $
    0.56
    
    
    $
    0.56Interest
    
    $
    0.08
    
    
    $
    0.10
    
    
    $
    0.10Total Operating Costs per Mcfe
    
    $
    1.70
    
    
    $
    1.54
    
    
    $
    1.32
   *
    
    Average production costs include lifting costs and remedial workover expenses. Productive Wells As of December 31, 2004, the Companys total gross and net wells were as follows: Productive Wells*
    

Gross Wells
    
    
    Net WellsDomesticNatural Gas and Condensate
    
    
    244.00
    
    
    
    103.89ChinaChina Oil
    
    
    36.00
    
    
    
    3,21TOTAL
    
    
    280.00
    
    
    
    107.10
   *
    
    Productive wells are producing wells plus shut-in wells the Company deems capable of production.
A gross well is a well in which a working interest is owned. The number of net wells represents
the sum of fractional working interests the Company owns in gross wells. 20




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##### Table of Contents



Oil and Gas Acreage As of December 31, 2004, the Company had total gross and net developed and undeveloped oil and
gas leasehold acres in the United States as set forth below. The developed acreage is stated on
the basis of spacing units designated by state regulatory authorities. The acreage and other
additional information concerning the Companys oil and gas operations are presented in the
following tables. United States Acreage: Developed Acres
    
    
    Undeveloped AcresGross
    
    
    Net
    
    
    Gross
    
    
    NetWyoming
    
    
    9,686
    
    
    
    4,022
    
    
    
    157,288
    
    
    
    88,975Pennsylvania
    
    
    
    
    
    
    
    
    
    
    15,518
    
    
    
    14,652Texas
    
    
    720
    
    
    
    382
    
    
    
    
    
    
    
    All States
    
    
    10,406
    
    
    
    4,404
    
    
    
    172,806
    
    
    
    103,627
 As of December 31, 2004, the Company had total gross and net developed and undeveloped oil and
gas leasehold acres in the Bohai Bay, China as set forth below. Bohai Bay Acreage: Developed Acres
    
    
    Undeveloped AcresGross
    
    
    Net
    
    
    Gross
    
    
    NetBlock 04/36
    
    
    22,486
    
    
    
    2,006
    
    
    
    431,514
    
    
    
    78,536Block 05/36
    
    
    
    
    
    
    
    
    
    
    233,300
    
    
    
    34,995Total Bohai Acreage
    
    
    22,486
    
    
    
    2,006
    
    
    
    664,814
    
    
    
    113,531
 Drilling Activities For each of the three fiscal years ended December 31, 2004, 2003 and 2002, the number of gross
and net wells drilled by the Company was as follows: Wyoming  Green River Basin 2004
    
    
    2003
    
    
    2002Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetDevelopment
WellsProductive
    
    
    34.00
    
    
    
    14.48
    
    
    
    24.00
    
    
    
    6.88
    
    
    
    16.00
    
    
    
    5.50Dry
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00Total
    
    
    34.00
    
    
    
    14.48
    
    
    
    24.00
    
    
    
    6.88
    
    
    
    16.00
    
    
    
    5.50
 At year end there were 4 gross (1.08 net) additional development wells that were either
drilling or had drilling operations suspended over winter. Exploratory
WellsProductive
    
    
    32.00
    
    
    
    14.00
    
    
    
    24.00
    
    
    
    9.86
    
    
    
    10.00
    
    
    
    5.22Dry
    
    
    0.00
    
    
    
    0.00
    
    
    
    1.00
    
    
    
    0.32
    
    
    
    0.00
    
    
    
    0.00Total
    
    
    32.00
    
    
    
    14.00
    
    
    
    25.00
    
    
    
    10.18
    
    
    
    10.00
    
    
    
    5.22
 At year end there were 14 gross (7.43 net) additional exploratory wells that were either
drilling or had drilling operations suspended over winter. 21




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##### Table of Contents



Texas 2004
    
    
    2003
    
    
    2002Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetExploratory WellsProductive
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00Dry
    
    
    1.00
    
    
    
    0.73
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    1.00
    
    
    
    0.15Total
    
    
    1.00
    
    
    
    0.73
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    1.00
    
    
    
    0.15
 China  Bohai Bay 2004
    
    
    2003
    
    
    2002Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetDevelopment WellsProductive
    
    
    36.0
    
    
    
    3.21
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00Dry
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00Total
    
    
    36.0
    
    
    
    3.21
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00
    
    
    
    0.00Exploratory WellsProductive and
Successful Appraisal*
    
    
    0.00
    
    
    
    0.00
    
    
    
    6.00
    
    
    
    1.03
    
    
    
    4.00
    
    
    
    0.70Dry
    
    
    1.00
    
    
    
    0.18
    
    
    
    4.00
    
    
    
    0.66
    
    
    
    1.00
    
    
    
    0.18Total
    
    
    1.00
    
    
    
    0.18
    
    
    
    10.00
    
    
    
    1.69
    
    
    
    5.00
    
    
    
    0.88
   *
    
    A successful appraisal well is a well that is drilled into a formation shown to be productive of
oil or gas by an earlier well for the purpose of obtaining more information about the reservoir. 
 Item 3.Legal Proceedings. The Company is currently involved in various routine disputes and allegations incidental to
its business operations. While it is not possible to determine the ultimate disposition of these
matters, the Company believes that the resolution of all such pending or threatened litigation is
not likely to have a material adverse effect on the Companys financial position, or results of
operations. 
 Item 4.Submission of Matters to a Vote of Security Holders. No matters were submitted to a vote of the Companys security holders during the fourth
quarter of the fiscal year ended December 31, 2004. 
 PART II 
 Item 5.Market for Registrants Common Equity Related
Stockholder Matters and Issuer Purchases of Equity Securities. The common shares of the Company have been listed and posted for trading on the American Stock
Exchange (AMEX) since January 17, 2001 under the symbol UPL and were traded on the Toronto
Stock Exchange (TSE) from September 30, 1998 to March 31, 2004 under the symbol UP. The
following table sets forth the high and low closing sales prices on the AMEX and TSE for 2004 and
2003 as reported by each exchange, respectively. AMERICAN STOCK EXCHANGE (US$) 2004
    
    High
    
    
    LowFirst Quarter
    
    $
    30.08
    
    
    $
    22.20Second Quarter
    
    $
    37.77
    
    
    $
    29.46Third Quarter
    
    $
    50.09
    
    
    $
    36.95Fourth Quarter
    
    $
    54.86
    
    
    $
    46.51
 TORONTO STOCK EXCHANGE (CDN$) 2004
    
    High
    
    
    LowFirst Quarter
    
    $
    40.25
    
    
    $
    29.66Second Quarter
    
    $
    
    
    
    $
    Third Quarter
    
    $
    
    
    
    $
    Fourth Quarter
    
    $
    
    
    
    $
    
 22




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##### Table of Contents



AMERICAN STOCK EXCHANGE (US$) 2003
    
    High
    
    
    LowFirst Quarter
    
    $
    10.24
    
    
    $
    8.60Second Quarter
    
    $
    12.91
    
    
    $
    8.45Third Quarter
    
    $
    14.80
    
    
    $
    11.50Fourth Quarter
    
    $
    25.45
    
    
    $
    14.05
 TORONTO STOCK EXCHANGE (CDN$) 2003
    
    High
    
    
    LowFirst Quarter
    
    $
    15.66
    
    
    $
    12.61Second Quarter
    
    $
    17.41
    
    
    $
    12.42Third Quarter
    
    $
    20.18
    
    
    $
    15.90Fourth Quarter
    
    $
    33.36
    
    
    $
    18.94
 On February 28, 2005, the last reported sale price of the common stock on the AMEX was $56.35
per share. As of February 28, 2005 there were approximately 415 holders of record of the common
stock. The Company has not declared or paid and does not anticipate declaring or paying any dividends
on its common stock in the near future. The Company intends to retain its cash flow from operations
for the future operation and development of its business. In addition, the Companys current credit
facility prohibits payment of dividends on its common stock. 
 Item 6.Selected Financial Data. The selected consolidated financial information presented below for the years ended December
31, 2004, 2003, 2002, 2001 and 2000 is derived from the Consolidated Financial Statements of the
Company. Year Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in thousands, except per share data)Statement of Operations DataRevenues:Natural gas sales
    
    $
    224,208
    
    
    $
    114,841
    
    
    $
    38,503
    
    
    $
    38,204
    
    
    $
    19,399Oil sales
    
    
    33,829
    
    
    
    6,740
    
    
    
    3,839
    
    
    
    2,997
    
    
    
    1,604Interest and other
    
    
    91
    
    
    
    37
    
    
    
    23
    
    
    
    393
    
    
    
    171Total revenues
    
    
    258,128
    
    
    
    121,618
    
    
    
    42,365
    
    
    
    41,594
    
    
    
    21,174Expenses:Production expenses and taxes
    
    
    49,860
    
    
    
    25,224
    
    
    
    11,411
    
    
    
    9,023
    
    
    
    4,241Depreciation, depletion and
amortization
    
    
    30,249
    
    
    
    16,216
    
    
    
    9,712
    
    
    
    6,687
    
    
    
    3,163General and administrative
    
    
    6,152
    
    
    
    5,733
    
    
    
    4,199
    
    
    
    3,894
    
    
    
    2,828Stock compensation
    
    
    924
    
    
    
    1,018
    
    
    
    1,211
    
    
    
    337
    
    
    
    250Interest
    
    
    3,783
    
    
    
    2,851
    
    
    
    2,691
    
    
    
    1,687
    
    
    
    802Total expenses
    
    
    90,968
    
    
    
    51,042
    
    
    
    29,224
    
    
    
    21,628
    
    
    
    11,284Income from continuing
operations before
income taxes
    
    
    167,160
    
    
    
    70,576
    
    
    
    13,141
    
    
    
    19,966
    
    
    
    9,890Income tax provision  deferred
    
    
    58,010
    
    
    
    25,254
    
    
    
    5,059
    
    
    
    2,087
    
    
    
    Net income
    
    $
    109,150
    
    
    $
    45,323
    
    
    $
    8,082
    
    
    $
    17,879
    
    
    $
    9,890Basic income per common share
    
    $
    1.46
    
    
    $
    0.61
    
    
    $
    0.11
    
    
    $
    0.25
    
    
    $
    0.17Diluted income per common share
    
    $
    1.35
    
    
    $
    0.58
    
    
    $
    0.10
    
    
    $
    0.24
    
    
    $
    0.17Statement of Cash Flows DataNet cash provided by (used in):Operating activities
    
    $
    175,343
    
    
    $
    90,051
    
    
    $
    21,490
    
    
    $
    34,136
    
    
    $
    9,046Investing activities
    
    
    (165,014
   )
    
    
    (103,622
    )
    
    
    (64,360
    )
    
    
    (59,862
    )
    
    
    (24,541
    )Financing activities
    
    
    4,770
    
    
    
    13,988
    
    
    
    42,908
    
    
    
    25,961
    
    
    
    16,236Balance Sheet DataCash and cash equivalents
    
    $
    16,933
    
    
    $
    1,834
    
    
    $
    1,418
    
    
    $
    1,379
    
    
    $
    1,144Working capital (deficit)
    
    
    (9,969
    )
    
    
    (22,057
    )
    
    
    (4,415
    )
    
    
    (6,635
    )
    
    
    241Oil and gas properties
    
    
    474,634
    
    
    
    307,864
    
    
    
    207,362
    
    
    
    155,221
    
    
    
    59,729Total assets
    
    
    537,186
    
    
    
    345,770
    
    
    
    221,874
    
    
    
    167,583
    
    
    
    73,177Total long-term debt
    
    
    198,098
    
    
    
    104,120
    
    
    
    89,859
    
    
    
    48,885
    
    
    
    24,731Deferred income taxes
    
    
    85,035
    
    
    
    33,446
    
    
    
    10,033
    
    
    
    4,974
    
    
    
    Total shareholders equity
    
    
    267,992
    
    
    
    149,453
    
    
    
    104,067
    
    
    
    95,320
    
    
    
    35,694
 23




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Item 7.Managements Discussion and Analysis of Financial Condition and Results of Operations. The following discussion of the financial condition and operating results of the Company
should be read in conjunction with the consolidated financial statements and related notes of the
Company. Except as otherwise indicated all amounts are expressed in U.S. dollars. We operate in
one segment, natural gas and oil exploration and development with two geographical segments, the
United States and China. The Company currently generates the majority of its revenue, earnings and cash flow from the
production and sales of natural gas and oil from its property in southwestern Wyoming. The price
of natural gas in the southwest Wyoming region is a critical factor to the Companys business. The
price of gas in southwest Wyoming historically has been volatile. The average annual realizations
for the period 2001-2004 have ranged from $2.33 to $5.13 per Mcf. This volatility could be very
detrimental to the Companys financial performance. The Company seeks to limit the impact of this
volatility on its results by entering into forward sales and derivative contracts for gas in
southwest Wyoming. The average realization for the Companys gas during calendar 2004 was $5.13
per Mcf, basis Opal, Wyoming, including the effect of hedges. For the quarter ended December 31,
2004, the average realization for the Companys gas was $5.70 per Mcf, basis Opal, Wyoming,
including the effect of hedges. On July 18, 2004 the Company initiated production at the first two fields of the nine fields
discovered on its oil properties offshore Bohai Bay, China. Production from these fields is
characterized as a Heavy, Sweet Crude. The Company sold its first cargos of oil in September 2004.
At that time, the price of oil in east Asia became much more relevant to the Company. During the
twelve-month period ended December 31, 2004, the Company sold 593,332 barrels of its Chinese oil
production at a price based on the official ICP posting for Duri field crude, less a discount for
location and quality differences. These sales were made to an affiliate of CNOOC, Ltd., the
Companys Chinese partner, at an average price of $32.31 USD per barrel. For the quarter ended
December 31, 2004, the Company sold 288,818 barrels of its Chinese crude for an average price of
$27.66. There can and will be differences in timing between the sale of the Companys crude oil
cargos and the Companys pro-rata share of production. As of February 28, 2005, the Duri price was
approximately $39.04 USD (before discount) per barrel. The Company expects to sell at least one cargo of its Chinese crude oil production
approximately every two months during 2005. The Company has the right to export and sell its crude
at market prices into the international markets, and is evaluating options to do so in the future.
Other markets for the Companys Chinese oil may be potentially developed in South Korea, Japan,
Singapore or other countries. The Company has grown its natural gas and oil production significantly over the past four
years and management believes it has the ability to continue growing production by drilling already
identified locations on its leases in Wyoming and by bringing into production the already
discovered oil fields in China. The Company delivered 74.5% production growth on an Mcfe basis
during the quarter ended December 31, 2004 as compared to the same quarter in 2003 and 70.7% for
the year-ended December 31, 2004 compared to the same period in 2003. Management expects to
deliver additional production growth during 2005 by drilling and bringing into production
additional wells in Wyoming and bringing into production the next two fields in China. 2001
    
    
    2002
    
    
    2003
    
    
    2004Production  Bcfe
    
    
    12.2
    
    
    
    17.4
    
    
    
    28.9
    
    
    
    49.3
 The Company conducts operations in both the United States and China. Separate cost centers
are maintained for each country in which the Company has operations. Substantially all of the oil
and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the
Companys proportionate interest in such activities. Inflation has not had a material impact on
the Companys results of operations and is not expected to have a material impact on the Companys
results of operations in the future. Critical Accounting Policies The discussion and analysis of the Companys financial condition and results of operations is
based upon consolidated financial statements, which have been prepared in accordance with U.S.
GAAP. In addition, application of generally accepted accounting principles requires the use of
estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as
of the date of the financial statements as well as the revenues and expenses reported during the
period. Changes in these estimates, judgments and assumptions will occur as a result of future
events, and, accordingly, actual results could differ from amounts estimated. 24




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Use of Estimates.The more significant areas requiring the use of assumptions, judgments and
estimates relate to volumes of oil and gas reserves used in calculating depletion, the amount of
future net revenues used in computing the ceiling test limitations and the amount of abandonment
obligations used in such calculations. Assumptions, judgments and estimates are also required in
determining impairments of undeveloped properties and the valuation of deferred tax assets. Oil and Gas Reserves.The Company emphasizes that the volumes of reserves are estimates
which, by their nature, are subject to revision. The estimates are made using all available
geological and reservoir data as well as production performance data. These estimates are currently
made annually by independent petroleum engineers and reviewed by the Companys engineers. The
reserves are periodically reviewed and revised, either upward or downward, if warranted by
additional data. Revisions are necessary due to changes in assumptions based on, among other
things, reservoir performance, prices, economic conditions and governmental restrictions. Estimates
of proved crude oil and natural gas reserves significantly affect the Companys depreciation,
depletion and amortization (DD&A) expense. For example, if estimates of proved
reserves decline, the Companys DD&A rate will increase, resulting in a decrease in net income. A
decline in estimates of proved reserves could also result in a full cost ceiling writedown (see
discussion below). The present value of oil and gas properties represents the estimated future net cash flows
from proved oil and gas reserves, discounted using a prescribed 10% discount rate (PV 10). Proved
oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs
that geological and engineering data demonstrate with reasonable certainty can be recovered in
future years from known reservoirs under existing economic and operating conditions. Reserves are
considered proved if they can be produced economically as demonstrated by either actual
production or conclusive formation tests. Proved developed oil and gas reserves can be expected
to be recovered through existing wells with existing equipment and operating methods. Due to the volatility of commodity prices, the oil and gas prices on the last day of the
period significantly impact the calculation of the PV 10. The present value of future net cash
flows does not purport to be an estimate of the fair market value of the Companys proved reserves.
An estimate of fair value would also take into account, among other things, anticipated changes in
future prices and costs, the expected recovery of reserves in excess of proved reserves and a
discount factor more representative of the time value of money and the risks inherent in producing
oil and gas. Full Cost Method of Accounting. The Company uses the full cost method of accounting for its
oil and gas operations. Separate cost centers are maintained for each country in which the Company
incurs costs. All costs incurred in the acquisition, exploration and development of properties
(including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and
overhead related to exploration and development activities) are capitalized. Effective with the
adoption of SFAS No. 143, Accounting for Asset Retirement
Obligations, the carrying amount of oil and gas properties includes estimated asset
retirement costs recorded based on the fair value of the asset retirement obligation when incurred.
The sum of net capitalized costs and estimated future development costs of oil and gas properties
for each full cost center are depleted using the units-of-production method. Changes in estimates
of reserves, future development costs or asset retirement obligations are accounted for
prospectively in our depletion calculation. Investments in unproved properties are not depleted pending the determination of the existence
of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment
has occurred. Unproved properties whose costs are individually significant are assessed
individually by considering the primary lease terms of the properties, the holding period of the
properties, and geographic and geologic data obtained relating to the properties. Where it is not
practicable to individually assess the amount of impairment of properties for which costs are not
individually significant, such properties are grouped for purposes of assessing impairment. The
amount of impairment assessed is added to the costs to be amortized in the appropriate full cost
pool. Companies that use the full cost method of accounting for oil and gas exploration and
development activities are required to perform a ceiling test each quarter. The full cost ceiling
test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is
performed on a country-by-country basis. The test determines a limit, or ceiling, on the book value
of oil and gas properties. That limit is basically the after tax present value of the future net
cash flows from proved crude oil and natural gas reserves. For purposes of the full cost ceiling
calculation, future cash outflows associated with settling asset retirement obligations that have
been accrued on the Companys balance sheet are excluded from the computation of the present value
of estimated future net revenues. This ceiling is compared to the net book value of the oil and
gas properties 25




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reduced by any related deferred income tax liability. If the net book value reduced
by the related deferred income taxes exceeds the ceiling, an impairment or non-cash writedown is
required. A ceiling test impairment can give the Company a significant loss for a particular
period; however, future depletion, depreciation and amoritization expense would be reduced. The Company did not have any writedowns related to the full cost ceiling limitation in 2004,
2003 or 2002. As of December 31, 2004, the ceiling limitation exceeded the carrying value of the
Companys oil and gas properties by approximately $1.3 billion in the U.S. and $110 million in
China. Estimates of discounted future net cash flows at December 31, 2004 were based on average
natural gas prices of approximately $5.54 per MCF in the U.S. and on average liquids prices of
approximately $42.80 per barrel in the U.S. In China, estimates of discounted future net cash
flows on crude oil were based on a net realized price of $29.46 per barrel. A reduction in oil and
gas prices and/or estimated quantities of oil and gas reserves would reduce the ceiling limitation
in the U.S. and could result in a ceiling test writedown. Asset Retirement Obligation.The Companys asset retirement obligations (ARO) consist
primarily of estimated costs of dismantlement, removal, site reclamation and similar activities
associated with its oil and gas properties. SFAS No. 143 requires that the discounted fair value of a liability for an ARO be recognized in
the period in which it is incurred with the associated asset retirement cost capitalized as part of
the carrying cost of the oil and gas asset. The recognition of an ARO requires that management
make numerous estimates, assumptions and judgments regarding such factors as the existence of a
legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; inflation rates, and future advances in technology. In
periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period
changes in the liability resulting from the passage of time and revisions to either the timing or
the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due
to passage of time impact net income as accretion expense. The related capitalized cost, including
revisions thereto, is charged to expense through DD&A. Entitlements Method of Accounting for Oil and Gas Sales. The
Company generally sells natural gas, condensate and crude oil under
both long-term and short-term agreements at prevailing market prices.
The Company recognizes revenues when the products are delivered,
which occurs when the customer has taken title and has assumed the risks and
rewards of ownership, prices are fixed or determinable and
collectibility is reasonably assured. The Company accounts for oil and gas
sales using the entitlements method. Under the entitlements method, revenue is recorded based
upon the Companys ownership share of volumes sold, regardless of whether it has taken its
ownership share of such volumes. The Company records a receivable or a liability to the extent it
receives less or more than its share of the volumes and related revenue. Under the alternative
sales method of accounting for oil and gas sales, revenue would be recorded based on volumes
taken by the Company or allocated to it by third parties, regardless of whether such volumes are
more or less than its ownership share of volumes produced. Reserve estimates would be adjusted to
reflect any over-produced or under-produced positions. Receivables or payables would be recognized
on a companys balance sheet only to the extent that remaining reserves are not sufficient to
satisfy volumes over- or under-produced. Make-up provisions and ultimate settlements of volume imbalances are generally governed by
agreements between the Company and its partners with respect to specific properties or, in the
absence of such agreements, through negotiation. The value of volumes over- or under-produced can
change based on changes in commodity prices. The Company prefers the entitlements method of
accounting for oil and gas sales because it allows for recognition of revenue based on its actual
share of jointly owned production, results in better matching of revenue with related operating
expenses, and provides balance sheet recognition of the estimated value of product imbalances. Valuation of Deferred Tax Assets. The Company uses the asset and liability method of
accounting for income taxes. Under this method, future income tax assets and liabilities are
determined based on differences between the financial statement carrying values and their
respective income tax bases (temporary differences). To assess the realization of deferred tax assets, management considers whether it is more
likely than not that some portion or all of the deferred tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and
tax planning strategies in making this assessment. In order to fully realize its U.S. net deferred
tax asset at December 31, 2004, the Company will need to generate future taxable income prior to
the expiration of the net operating loss carryforwards in 2005 to 2024. Based upon the level of
historical taxable income and projections for future taxable income over the periods which the
deferred tax assets are deductible, management believes it is more likely than not the Company will
realize the benefits of these 26




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deductible differences at December 31, 2004. The amount of the
deferred tax asset considered realizable, however, could be reduced in the near term if estimates
of future taxable income during the carryforward periods are reduced. Commodity Derivative Instruments and Hedging Activities. The Company periodically enters into
commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and
natural gas price volatility. The Company primarily utilizes price swaps, which are generally
placed with major financial institutions or with counter-parties of high credit quality that it
believes are minimal credit risks. The oil and natural gas reference prices of these commodity
derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of
historical correlation with actual prices the Company receives. Under SFAS No. 133 all derivative
instruments are recorded on the balance sheet at fair value. Changes in the derivatives fair
value are recognized currently in earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other
comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value
hedges, the gain or loss on the derivative is
offset by related results of the hedged item in the income statement. Gains and losses on
hedging instruments included in accumulated other comprehensive income (loss) are reclassified to
oil and natural gas sales revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative
assets and liabilities at market value in the consolidated balance sheet, and the associated
unrealized gains and losses are recorded as current expense or income in the consolidated statement
of operations. The Company currently does not have any derivative contracts in place that do not
qualify as cash flow hedges. Legal, Environmental and Other Contingencies.A provision for legal, environmental and other
contingencies is charged to expense when the loss is probable and the cost can be reasonably
estimated. Determining when expenses should be recorded for these contingencies and the
appropriate amounts for accrual is a complex estimation process that includes the subjective
judgment of management. In many cases, managements judgment is based on interpretation of laws
and regulations, which can be interpreted differently by regulators and/or courts of law. The
Companys management closely monitors known and potential legal, environmental and other
contingencies and periodically determines when the Company should record losses for these items
based on information available to the Company. Results of Operations  Year Ended December 31, 2004 Compared to Year Ended December 31, 2003 Oil and gas revenues increased to $258.0 million for the year ended December 31, 2004 from
$121.6 million for the same period in 2003. This increase was attributable to an increase in both
the Companys production and prices received for that production. During this period the Companys
production increased to 43.7 Bcf of gas and 349.7 thousand barrels of condensate in Wyoming and
593.3 thousand barrels of crude oil in China, up from 27.6 Bcf of gas and 211.6 thousand barrels of
condensate in Wyoming. This 71% increase on a Mcfe basis was attributable to the Companys
successful drilling activities during 2004 and 2003 in Wyoming and initiation of production in
China. During the year ended December 31, 2004 the average product prices were $5.13 per Mcf and
$41.92 per barrel of condensate in Wyoming and $32.31 per barrel for crude oil in China, compared
to $4.16 per Mcf and $31.86 per barrel in Wyoming for the same period in 2003. In Wyoming, direct lease operating (LOE) costs increased to $6.3 million in 2004 from $3.6
million in 2003 due to sharply higher production. On a unit of production basis, LOE costs were
$0.14 per Mcfe in 2004, as compared to $0.13 per Mcfe in 2003. Production taxes in 2004 were $28.2
million, compared to $13.8 million in 2003, or $0.57 per Mcfe in 2004, compared to $0.48 per Mcfe
in 2003. Production taxes are calculated based on a percentage of revenue from production.
Therefore, higher prices received increased the cost on a per unit basis. Gathering fees for the
period increased to $13.1 million in 2004 from $7.8 million in 2003, attributable to higher
production volumes. In Wyoming, depletion, depreciation and amortization (DD&A) expenses increased to $27.4
million during the year ended December 31, 2004 from $16.2 million for the same period in 2003,
attributable to increased production volumes and higher depletion rate, attributable to forecasted
increased future development costs. On a unit basis, DD&A increased to $0.60 per Mcfe in 2004 from
$0.56 per Mcfe in 2003. In China, production costs were $2.3 million in 2004, or $0.64 per Mcfe or $3.85 per BOE.
DD&A was $2.9 million or $0.82 per Mcfe or $4.89 per BOE in 2004. Production in China started
during July 2004. 27




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Interest expense for the period increased to $3.8 million in 2004 from $2.8 million in 2003.
This increase was attributable to the increase in borrowings under the senior credit facility
combined with increasing interest rates. Deferred income tax expense for the period increased to $58.0 million in 2004 from $25.3
million in 2003. This increase was attributable to an increase in net income from continuing
operations. Deferred income taxes were booked at the rate of 34.7% as compared to a rate of 35.8%
in 2003. The Company was not liable for current payment of any material amount of income taxes for
the period ending December 31, 2004. Results of Operations  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002 Oil and gas revenues increased to $121.6 million for the year ended December 31, 2003 from
$42.3 million for the same period in 2002. This increase was attributable to an increase in both
the Companys production and prices received for that production. During this period the Companys
production increased to 27.6 Bcf of gas and 211.6 thousand barrels of condensate, up from 16.5 Bcf
of gas and 151.2 thousand barrels
of condensate for the same period in 2002. This 66% increase on a Mcfe basis was attributable
to the Companys successful drilling activities during 2003 and 2002. During the year ended
December 31, 2003 the average product prices were $4.16 per Mcf and $31.86 per barrel, compared to
$2.33 per Mcf and $25.39 per barrel for the same period in 2002. Production costs increased to $3.6 million in 2003 from $2.4 million in 2002 primarily due to
increased production. On a unit of production basis, costs were $0.13 per Mcfe in 2003, as
compared to $0.14 per Mcfe in 2002. Production taxes in 2003 were $13.8 million, compared to $4.1
million in 2002, or $0.48 per Mcfe in 2003, compared to $0.24 per Mcfe in 2002. Production taxes
are calculated based on a percentage of revenue from production. Therefore, higher prices
received increased the cost on a per unit basis. Gathering fees for the period increased to $7.8
million in 2003 from $4.9 million in 2002, attributable to higher production volumes. Depletion, depreciation and amortization (DD&A) expenses increased to $16.2 million during
the year ended December 31, 2003 from $9.7 million for the same period in 2002, also attributable
to increased production volumes. On a unit basis, DD&A remained flat at $0.56 per Mcfe in 2003. Interest expense for the period increased to $2.8 million in 2003 from $2.7 million in 2002.
This increase was attributable to the increase in borrowings under the senior credit facility which
was partially offset by lower interest rates. Deferred income tax expense for the period increased to $25.3 million in 2003 from $5.1
million in 2002. This increase was attributable to an increase in net income from continuing
operations. Deferred income taxes were booked at the rate of 35.8% as compared to a rate of 38.5%
in 2002. The Company was not liable for current payment of any material amount of income taxes for
the period ending December 31, 2003. At year-end 2003, the Company had an inventory account of $13.6 million as compared to $0.0 at
year-end 2002. This inventory is tubular materials related to the purchase of pipe for the
Companys operated drilling program in Wyoming. In previous years the Company did not purchase
tubular materials prior to when they would be used. Liquidity and Capital Resources In the year-ended December 31, 2004, the Company relied on cash provided by operations and
borrowings under its senior credit facility to finance its capital expenditures. The Company
participated in the drilling of 84 wells in Wyoming and continued to participate in the development
process in the China blocks, including the ongoing drilling of development wells. Due to this
continued development in China, the Company saw first production from these properties in July
2004. For the year-ended December 31, 2004 net capital
expenditures were $174.1 million. At
December 31, 2004, the Company reported a cash position of $16.9 million compared to $1.8 million
at December 31, 2003. Working capital deficit at
December 31, 2004 was $(10.0) million as compared
to $(22.1) million at December 31, 2003. As of December 31, 2004, the Company had incurred bank
indebtedness of $102.0 million and other long-term obligations of $9.3 million comprised of items
payable in more than one year, primarily related to production taxes. The Companys positive cash provided by operating activities, along with the availability
under the senior credit facility, are projected to be sufficient to fund the Companys budgeted
capital expenditures for 2005, which are currently projected to be $290.0 million. Of the $290.0
million budget, the Company plans to spend 28




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approximately $263.0 million of its 2005 budget in
Wyoming and approximately $20.0 million in China with the balance allocated to evaluating other
areas. With the $263.0 million for Wyoming, the Company plans to drill or participate in an
estimated 100 gross wells in 2005, of which approximately 30% will be for exploration wells and the
remaining will be for development wells. Of the $20.0 million budgeted for China, approximately 14%
will be for exploratory/appraisal activity and the balance will be for development activity. The
Company currently has no budget for acquisitions in 2005. The Company (through its subsidiary) participates in a long-term credit facility with a group
of banks led by Bank One N.A. The agreement specifies a maximum loan amount of $500 million and an
aggregate borrowing base of $400 million and a commitment amount of $200 million at November 1,
2004. The commitment amount may be increased up to the lesser of the borrowing base amount or $500
million at any time at the request of the Company. Each bank shall have the right, but not the
obligation, to increase the amount of their commitment as requested by the Company. In the event
that the existing banks increase their commitment to an amount less
than the requested commitment amount, then it would be necessary to bring additional banks
into the facility. At December 31, 2004, the Company had $102 million outstanding and $98 million
unused and available under the current committed amount. The credit facility matures on May 1, 2008. The note bears interest at either the banks
prime rate plus a margin of one-quarter of one percent (0.25%) to seven-eighths of one percent
(0.875%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and
one-quarter percent (1.25%) to one and seven-eighths of one percent (1.875%) based on the
percentage of available credit drawn. For the purposes of calculating interest, the available
credit is equal to the borrowing base. An average annual commitment fee of 0.30% to 0.50%,
depending on the percentage of available credit drawn, is charged quarterly for any unused portion
of the commitment amount. The borrowing base is subject to periodic (at least semi-annual) review and re-determination
by the banks and may be decreased or increased depending on a number of factors, including the
Companys proved reserves and the banks forecast of future oil and gas prices. If the borrowing
base is reduced to an amount less than the balance outstanding, the Company has sixty days from the
date of written notice of the reduction in the borrowing base to pay the difference. Additionally,
the Company is subject to quarterly reviews of compliance with the covenants under the bank
facility including minimum coverage ratios relating to interest, working capital and advances to
Sino-American Energy Corporation. In the event of a default under the covenants, the Company may
not be able to access funds otherwise available under the facility. As of December 31, 2004, the
Company was in compliance with required ratios of the bank facility. The debt outstanding under the credit facility is secured by a majority of the Companys
proved domestic oil and gas properties. During
the year ended December 31, 2004, net cash provided by operating
activities was $175.3 million as compared to $90.1 million for the year ended December 31, 2003. The increase in cash
provided by operating activities was primarily attributable to the increase in earnings, DD&A and
deferred taxes, all attributable to higher production levels. During
the year ended December 31, 2004, cash used in investing
activities was $165.0 million as compared to $103.6 million for the year ended December 31, 2003. The change is primarily
attributable to increased activity for drilling and completion
operations in Wyoming. The $173.1 million used in oil and gas
property expenditures consists of $195.6 million incurred for
drilling and completion activities in 2004, offset by $(22.5) million attributable to capital expenditures
incurred but not yet paid. During the year ended December 31, 2004, cash provided by financing activities was $4.8
million as compared to $14.0 million for the year ended December 31, 2003. The change is primarily
attributable to drawing down additional debt under the senior credit facility and proceeds of
employee stock option exercises. 29




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##### Table of Contents



Contractual Obligations The following table summarizes our contractual obligations as of December 31, 2004: Less Than
    
    
    
    
    
    
    
    
    
    
    More ThanTotal
    
    
    One Year
    
    
    1-3 Years
    
    
    3-5 Years
    
    
    5 YearsLong-term debt
    
    $
    102,000,000
    
    
    $
    
    
    
    $
    
    
    
    $
    102,000,000
    
    
    $
    Operating leases
    
    
    330,040
    
    
    
    198,020
    
    
    
    132,020
    
    
    
    
    
    
    
    Office space lease
    
    
    824,083
    
    
    
    245,493
    
    
    
    578,590
    
    
    
    
    
    
    
    Total contractual
obligations
    
    $
    103,154,123
    
    
    $
    443,513
    
    
    $
    710,610
    
    
    $
    102,000,000
    
    
    $
    
 As of December 31, 2004 the Company had committed to drilling obligations in progress that
will continue into 2005. The Companys senior credit facility with its group of banks matures on May 1, 2008. Unless
the facility is extended or a new facility put into place, the full amount drawn under the facility
would become due and payable at that time. The Company believes that it will be able to extend or
renew the facility or one substantially similar to the existing facility prior to May 1, 2008. On October 16, 2003 the operator of the Companys properties in China, Kerr-McGee
(Operator), signed a 15 year contract, which provides for up to an additional 10 years, to lease
the FPSO. The Company ratified the contract for its net share which is 8.92%. The FPSO service
agreement calls for a day rate lease payment and a sliding scale per barrel processing fee that
decreases based on cumulative barrels processed. The lease contains a cancellation fee for the
Company based on a sliding time-scale (cancellation fee decreases with time) which as of December
31, 2004 was $3.87 million net to the Companys 8.92% interest. The Company considers it very
unlikely that a lease cancellation situation will occur. Due to the terms of the lease, the
Company cannot estimate with any degree of accuracy the costs it may incur during the life of the
lease. The Companys net share for the costs of the FPSO in 2004 was approximately $1.3 million. In May 2003 the Company amended its prior office lease in Englewood, Colorado, which it has
committed to through June 2008. The Companys total remaining commitment of this lease is
$702,441. In December 2003, the Company signed a lease for office space in Houston, Texas, which
it has committed to through April 2007 for a total remaining
commitment of $121,643. The total
remaining commitment for both offices is $824,083. Additionally, in maintaining its acreage base that is not held by production, the Company
incurs certain expenses including delay rental costs. From year to year, the Companys acreage
base varies, sometimes dramatically, rendering it impossible to forecast with any accuracy what the
amount of these holding expenses will be. In 2004, total holding costs for all of the Companys
leases not held by production were $109,250. 
 Item 7A.Quantitative and Qualitative Disclosures About Market Risk The Companys major market risk exposure is in the pricing applicable to its gas and oil
production. Realized pricing is currently driven primarily by the prevailing price for the
Companys Wyoming natural gas production. Historically, prices received for gas production have
been volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations
ranged from a monthly low of $4.64 per Mcf to a monthly high of $6.15 per Mcf during 2004.
Realized natural gas prices are derived from the financial statements which include the effects of
hedging and gas balancing. The Company uses derivative instruments as one way to manage its exposure to commodity prices.
The Company has periodically entered into fixed price to index price swap agreements in order to
hedge a portion of its production. The purpose of the swaps is to provide a measure of stability
to the Companys cash flows in an environment of volatile oil and gas prices. The derivatives
reduce the Companys exposure on the hedged volumes to decreases in commodity prices and limit the
benefit the Company might otherwise have received from any increases in commodity prices on the
hedged volumes. The Company recognizes all derivative instruments as assets or liabilities in the
balance sheet at fair value. The accounting treatment of the changes in fair value as specified in
SFAS No. 133 is dependent upon whether or not a derivative instrument is 30




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##### Table of Contents



designated as a hedge. For
derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is
effective, are recognized in other comprehensive income until the hedged item is recognized in
earnings as oil and gas revenue. For all other derivatives, changes in fair value are recognized in
earnings as income or expense. At December 31, 2004 the Company had a current derivative liability
of $3,739,406, which is included in current liabilities in our balance sheet. The Company
designates these derivatives as cash flow hedges. During 2004, the Company made payments on financially settled swaps to counterparties totaling
$8,493,300 as its net cost from hedging activities. This total includes $1,383,300 for the first
quarter of 2004, $1,870,725 for the second quarter of 2004, $1,988,700 for the third quarter of
2004, and $3,250,575 for the fourth quarter of 2004. At December 31, 2004, the Company had the following open derivative contracts to manage price
risk on a portion of its natural gas production (all prices southwest Wyoming basis). (The
Companys gas contains approximately 1.06 MMBtu per Mcf upon delivery at the sales point.) Contract
    
    Volume-
    
    
    Average
    
    
    Unrealized gainType
    
    Period
    
    MMBTU / day
    
    
    Price / MMbtu
    
    
    (loss) at 12/31/04*Swap
    
    Jan 2005-Jan 2006
    
    
    10,000
    
    
    $
    4.42
    
    
    $
    4,057,004
   *
    
    Unrealized losses are not adjusted for income tax effect. The Company also utilizes fixed price forward gas sales at southwest Wyoming delivery points
to hedge its commodity exposure. In addition to the derivative contracts discussed above, the
Company had the following physical delivery contracts in place at December 31, 2004. (The
Companys average net interest in physical gas sales is approximately 80%.) Contract
    
    Volume-
    
    
    AveragePeriod
    
    MMBTU / day
    
    
    Price / MMbtuCalendar 2005
    
    
    70,000
    
    
    $
    5.03Apr-Oct 2005
    
    
    10,000
    
    
    $
    6.03Calendar 2006
    
    
    25,000
    
    
    $
    4.58
 Subsequent to December 31, 2004 and through March 2, 2005, the Company has entered into
additional contracts for fixed price physical delivery of gas during Calendar 2006 for an
additional 25,000 MMBTU/day at an average price of $6.015 per MMBTU. As
of March 2, 2005, the Companys fixed price forward gas sales contracts represented net
volumes equal to approximately 45% of the Companys currently forecasted production for Calendar
2005 and 19% for Calendar 2006. 31




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##### Table of Contents



Item 8.Financial Statements and Supplementary Data. MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The management of the Company is responsible for the preparation and integrity of all information
contained in this Annual Report. The accompanying financial statements have been prepared in
conformity with accounting principles generally accepted in the United States of America. The
financial statements include amounts that are managements best estimates and judgments. Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
supervision and with the participation of our management, including our principal executive officer
and principal financial officer, we conducted an evaluation of the effectiveness of our internal
control over financial reporting based on the framework (in Internal Control  Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission). Based on our
evaluation under the framework in Internal Control  Integrated Framework, our management concluded
that our internal control over financial reporting was effective as of December 31, 2004. -s- Michael D. Walford 
 March 15, 2005 32




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Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders
Ultra Petroleum Corp. We have audited managements assessment, included in the accompanying Managements Report On
Internal Control Over Financial Reporting, that Ultra Petroleum Corp. and subsidiaries maintained
effective internal control over financial reporting as of December 31, 2004, based on criteria
established in Internal Control  Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Ultra Petroleum Corp.s management is responsible
for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility is to express an
opinion on managements assessment and an opinion on the effectiveness of the Companys internal
control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion. A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate. In our opinion, managements assessment that Ultra Petroleum Corp. and subsidiaries maintained
effective internal control over financial reporting as of December 31, 2004, is fairly stated, in
all material respects, based on criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our
opinion, Ultra Petroleum Corp. and subsidiaries maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2004, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Ultra Petroleum Corp. and subsidiaries as
of December 31, 2004 and 2003, and the related consolidated statements of operations and retained
earnings, shareholders equity, and cash flows for each of the years in the three-year period ended
December 31, 2004, and our report dated March 15, 2005 expressed an unqualified opinion on those
consolidated financial statements. KPMG LLP Denver, Colorado
March 15, 2005 33




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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders
Ultra Petroleum Corp. We have audited the consolidated balance sheets of Ultra Petroleum Corp. and subsidiaries as of
December 31, 2004 and 2003, and the consolidated statements of
operations and retained earnings,
shareholders equity and cash flows for each of the years in the three-year period ended December
31, 2004. These consolidated financial statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these financial statements based on our
audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Ultra Petroleum Corp. and subsidiaries as of
December 31, 2004 and 2003, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2004, in accordance with U.S. generally
accepted accounting principles. As explained in Note 1 to the Financial Statements, effective January 1, 2003, the Company changed
its method of accounting for asset retirement obligations. We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Ultra Petroleum Corp. and subsidiaries
internal control over financial reporting as of December 31, 2004, based on criteria established in
Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated March 15, 2005 expressed an unqualified opinion on
managements assessment of, and the effective operation of, internal control over financial
reporting. (KPMG LLP) KPMG, LLP
Denver, Colorado
March 15, 2005 34




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##### Table of Contents



ULTRA PETROLEUM CORP. CONSOLIDATED BALANCE SHEETS (Expressed in U.S. Dollars)December 31,2004
    
    
    2003ASSETSCurrent assetsCash and cash equivalents
    
    $
    16,932,661
    
    
    $
    1,834,112Restricted cash
    
    
    211,961
    
    
    
    210,669Accounts receivable
    
    
    35,749,287
    
    
    
    19,348,861Deferred tax asset
    
    
    1,327,489
    
    
    
    Inventory
    
    
    5,180,024
    
    
    
    13,589,270Prepaid drilling costs and other current assets
    
    
    1,725,843
    
    
    
    1,711,737Total current assets
    
    
    61,127,265
    
    
    
    36,694,649Oil and gas properties, using the full
cost method of accountingProved
    
    
    385,794,926
    
    
    
    211,288,957Unproved
    
    
    88,839,460
    
    
    
    96,574,765Capital assets
    
    
    1,424,367
    
    
    
    1,212,006TOTAL ASSETS
    
    $
    537,186,018
    
    
    $
    345,770,377LIABILITIES AND SHAREHOLDERS EQUITYCurrent liabilitiesAccounts payable and accrued liabilities
    
    $
    14,238,836
    
    
    $
    23,353,323Fair value of derivative instruments
    
    
    3,739,406
    
    
    
    4,781,068Capital cost accrual
    
    
    53,118,385
    
    
    
    30,616,912Total current liabilities
    
    
    71,096,627
    
    
    
    58,751,303Long-term debt
    
    
    102,000,000
    
    
    
    99,000,000Deferred income tax liability
    
    
    86,362,741
    
    
    
    33,446,131Other long-term obligations
    
    
    9,734,904
    
    
    
    5,120,213Shareholders equity:Common stock
 no par value: authorized  unlimited; issued and
outstanding  75,527,468
    
    
    106,513,852
    
    
    
    97,448,221Treasury stock
    
    
    (1,193,650
    )
    
    
    (1,193,650
    )Other comprehensive loss
    
    
    (2,616,767
    )
    
    
    (2,940,357
    )Retained earnings
    
    
    165,288,311
    
    
    
    56,138,516Total shareholders equity
    
    
    267,991,746
    
    
    
    149,452,730Commitments
and contingencies (Note 12)TOTAL LIABILITIES AND SHAREHOLDERS EQUITY
    
    $
    537,186,018
    
    
    $
    345,770,377
 See accompanying notes to consolidated financial statements. Approved on behalf of the Board: -s- Michael D. Walfrod
    
    , Director
    
    -s-
    
    , Director
 35




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ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (Expressed in U.S. Dollars)
    
    Year Ended December 31,2004
    
    
    2003
    
    
    2002REVENUES:Natural gas sales
    
    $
    224,207,694
    
    
    $
    114,840,558
    
    
    $
    38,502,971Oil sales
    
    
    33,829,655
    
    
    
    6,740,539
    
    
    
    3,839,421258,037,349
    
    
    
    121,581,097
    
    
    
    42,342,392EXPENSES:Production expenses and taxes
    
    
    49,860,185
    
    
    
    25,223,679
    
    
    
    11,410,868Depletion and depreciation
    
    
    30,249,061
    
    
    
    16,215,714
    
    
    
    9,712,111General and administrative
    
    
    6,152,097
    
    
    
    5,733,147
    
    
    
    4,199,104General and administrative, stock compensation
    
    
    923,623
    
    
    
    1,018,220
    
    
    
    1,211,16587,184,966
    
    
    
    48,190,760
    
    
    
    26,533,248OPERATING INCOME
    
    
    170,852,383
    
    
    
    73,390,337
    
    
    
    15,809,144OTHER INCOME (EXPENSE):Interest income
    
    
    90,760
    
    
    
    36,889
    
    
    
    23,151Interest expense
    
    
    (3,783,070
    )
    
    
    (2,850,916
    )
    
    
    (2,691,608
    )(3,692,310
    )
    
    
    (2,814,027
    )
    
    
    (2,668,457
    )INCOME BEFORE INCOME TAXES
    
    
    167,160,073
    
    
    
    70,576,310
    
    
    
    13,140,687Income tax provision
    
    
    58,010,278
    
    
    
    25,253,671
    
    
    
    5,059,166NET INCOME
    
    
    109,149,795
    
    
    
    45,322,639
    
    
    
    8,081,521RETAINED EARNINGS, beginning of year
    
    
    56,138,516
    
    
    
    10,815,877
    
    
    
    2,734,356RETAINED EARNINGS, end of year
    
    $
    165,288,311
    
    
    $
    56,138,516
    
    
    $
    10,815,877NET INCOME PER COMMON SHARE  BASIC
    
    $
    1.46
    
    
    $
    0.61
    
    
    $
    0.11NET INCOME PER COMMON SHARE  DILUTED
    
    $
    1.35
    
    
    $
    0.58
    
    
    $
    0.10Weighted average common sharesoutstanding  basic
    
    
    75,000,333
    
    
    
    74,231,553
    
    
    
    73,770,841Weighted average common sharesoutstanding  diluted
    
    
    80,735,267
    
    
    
    78,651,439
    
    
    
    77,605,018
 See accompanying notes to consolidated financial statements. 36




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##### Table of Contents



ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY AccumulatedOther
    
    
    
    
    
    
    TotalShares
    
    
    Common
    
    
    Retained
    
    
    Comprehensive
    
    
    Treasury
    
    
    Shareholders'Issued
    
    
    Stock
    
    
    Earnings
    
    
    Income (Loss)
    
    
    Stock
    
    
    EquityBalances at December 31, 2001
    
    
    73,318,418
    
    
    $
    92,585,148
    
    
    $
    2,734,356
    
    
    $
    
    
    
    $
    
    
    
    $
    95,319,504Stock options exercised
    
    
    617,750
    
    
    
    1,101,674
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,101,674Employee stock plan grants
    
    
    183,000
    
    
    
    1,299,765
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,299,765Fair value of non-employee stock option grants
    
    
    
    
    
    
    112,103
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    112,103Purchase of 132,500 shares of treasury stock
    
    
    (132,500
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,193,650
    )
    
    
    (1,193,650
    )Comprehensive earnings:Net earnings
    
    
    
    
    
    
    
    
    
    
    8,081,521
    
    
    
    
    
    
    
    
    
    
    
    8,081,521Change in derivative instrument fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (653,875
    )
    
    
    
    
    
    
    (653,875
    )Total comprehensive earnings
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7,427,646Balances at December 31, 2002
    
    
    73,986,668
    
    
    
    95,098,690
    
    
    
    10,815,877
    
    
    
    (653,875
    )
    
    
    (1,193,650
    )
    
    
    104,067,042Stock options exercised
    
    
    443,000
    
    
    
    988,247
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    988,247Employee stock plan grants
    
    
    118,000
    
    
    
    1,148,630
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,148,630Fair value of non-employee stock option grants
    
    
    
    
    
    
    212,654
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    212,654Comprehensive earnings:Net earnings
    
    
    
    
    
    
    
    
    
    
    45,322,639
    
    
    
    
    
    
    
    
    
    
    
    45,322,639Change in derivative instrument fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,286,482
    )
    
    
    
    
    
    
    (2,286,482
    )Total comprehensive earnings
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    43,036,157Balances at December 31, 2003
    
    
    74,547,668
    
    
    
    97,448,221
    
    
    
    56,138,516
    
    
    
    (2,940,357
    )
    
    
    (1,193,650
    )
    
    
    149,452,730Stock options exercised
    
    
    553,300
    
    
    
    1,770,099
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,770,099Employee stock plan grants
    
    
    16,500
    
    
    
    560,175
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    560,175Fair value of non-employee stock option grants
    
    
    
    
    
    
    100,550
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    100,550Tax benefit of stock options exercised
    
    
    
    
    
    
    6,634,807
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,634,807Comprehensive earnings:Net earnings
    
    
    
    
    
    
    
    
    
    
    109,149,795
    
    
    
    
    
    
    
    
    
    
    
    109,149,795Change in derivative instrument fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    323,590
    
    
    
    
    
    
    
    323,590Total comprehensive earnings
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    109,473,385Balances at December 31, 2004
    
    
    75,117,468
    
    
    $
    106,513,852
    
    
    $
    165,288,311
    
    
    $
    (2,616,767
    )
    
    $
    (1,193,650
    )
    
    $
    267,991,746
 See accompanying notes to consolidated financial statements. 37




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ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOW Year Ended December 31,2004
    
    
    2003
    
    
    2002Cash flows from operating activities:Net income for the year
    
    $
    109,149,795
    
    
    $
    45,322,639
    
    
    $
    8,081,521Adjustments to reconcile net income to net cash
provided by operating activities:Depletion and depreciation
    
    
    30,249,061
    
    
    
    16,215,714
    
    
    
    9,712,111Deferred income taxes
    
    
    57,748,452
    
    
    
    25,253,671
    
    
    
    5,059,166Stock compensation
    
    
    923,623
    
    
    
    1,018,220
    
    
    
    1,211,165Net changes in working capital:Restricted cash
    
    
    (1,292
    )
    
    
    (1,363
    )
    
    
    (2,127
    )Accounts receivable
    
    
    (16,400,426
    )
    
    
    (7,950,378
    )
    
    
    (4,039,741
    )Inventory
    
    
    (275,424
    )
    
    
    
    
    
    
    Prepaid expenses and other current assets
    
    
    (14,106
    )
    
    
    (1,237,458
    )
    
    
    1,695,459Accounts payable and accrued liabilities
    
    
    (10,169,082
    )
    
    
    10,168,164
    
    
    
    1,799,538Other long-term obligations
    
    
    3,870,179
    
    
    
    1,261,403
    
    
    
    (2,026,604
    )Taxation
payable
    
    
    261,826
    
    
    
    
    
    
    
    Net cash provided by operating activities
    
    
    175,342,606
    
    
    
    90,050,612
    
    
    
    21,490,488Cash flows from investing activities:Oil and gas property expenditures
    
    
    (195,598,484
    )
    
    
    (115,837,250
    )
    
    
    (61,257,518
    )Change in
capital costs accrual
    
    
    22,501,473
    
    
    
    26,541,083
    
    
    
    (2,288,540
    )Inventory
    
    
    9,037,557
    
    
    
    (13,589,270
    )
    
    
    Purchase of capital assets
    
    
    (954,702
    )
    
    
    (737,021
    )
    
    
    (814,205
    )Net cash used in investing activities
    
    
    (165,014,156
    )
    
    
    (103,622,458
    )
    
    
    (64,360,263
    )Cash flows from financing activities:Borrowings of long-term debt, gross
    
    
    44,000,000
    
    
    
    43,000,000
    
    
    
    43,000,000Payments on long-term debt, gross
    
    
    (41,000,000
    )
    
    
    (30,000,000
    )
    
    
    Proceeds from issuance of common stock
    
    
    1,770,099
    
    
    
    988,247
    
    
    
    1,101,674Repurchase of common stock
    
    
    
    
    
    
    
    
    
    
    (1,193,650
    )Net cash provided by financing activities
    
    
    4,770,099
    
    
    
    13,988,247
    
    
    
    42,908,024Net increase in cash and cash equivalents
    
    
    15,098,549
    
    
    
    416,401
    
    
    
    38,249Cash and cash equivalents, beginning of year
    
    
    1,834,112
    
    
    
    1,417,711
    
    
    
    1,379,462Cash and cash equivalents, end of year
    
    $
    16,932,661
    
    
    $
    1,834,112
    
    
    $
    1,417,711SUPPLEMENTAL INFORMATIONCash paid for:Interest
    
    $
    3,783,070
    
    
    $
    2,850,916
    
    
    $
    2,691,608Income taxes
    
    $
    153,905
    
    
    $
    
    
    
    $
    
 See accompanying notes to consolidated financial statements. 38




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ULTRA PETROLEUM CORP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Expressed in U.S. dollars unless otherwise noted)
Years ended December 31, 2004, 2003 and 2002 DESCRIPTION OF THE BUSINESS Ultra Petroleum Corp. (the Company) is an independent oil and gas company engaged in the
acquisition, exploration, development, and production of oil and gas properties. The Company is
incorporated under the laws of the Yukon Territory, Canada. The Companys principal business
activities are in the Green River Basin of southwest Wyoming and Bohai Bay, China. 1. SIGNIFICANT ACCOUNTING POLICIES: (a) Basis of presentation and principles of consolidation: The consolidated financial statements
include the accounts of the Company and its wholly owned subsidiaries UP Energy Corporation, Ultra
Resources, Inc. and Sino-American Energy Corporation. The Company presents its financial
statements in accordance with U.S. GAAP. All material inter-company transactions and balances have
been eliminated upon consolidation. (b) Accounting principles: The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States. (c) Cash and cash equivalents: We consider all highly liquid investments with an original maturity
of three months or less to be cash equivalents. (d) Restricted cash: Restricted cash represents cash received by the Company from production sold
where the final division of ownership of the production is unknown or in dispute. Wyoming law
requires that these funds be held in a federally insured bank in Wyoming. (e) Capital assets: Capital assets are recorded at cost and depreciated using the
declining-balance method based on a seven-year useful life. (f) Oil and gas properties: The Company uses the full cost method of accounting for exploration
and development activities as defined by the Securities and Exchange Commission (SEC). Under this
method of accounting, the costs of unsuccessful, as well as successful, exploration and development
activities are capitalized as properties and equipment. This includes any internal costs that are
directly related to exploration and development activities but does not include any costs related
to production, general corporate overhead or similar activities. Effective with the adoption of
SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset
retirement costs recorded based on the fair value of the asset retirement obligation when incurred.
Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless
the gain or loss would significantly alter the relationship between capitalized costs and proved
reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil
and gas properties are amortized using the unit-of-production method based on the proven reserves
as determined by independent petroleum engineers. Oil and gas reserves and production are
converted into equivalent units based on relative energy content. Operating fees
received related to the properties in which the Company owns an interest are netted against
expenses. Fees received in excess of costs incurred are recorded as a reduction to the full cost
pool. Effective with the adoption of SFAS 143 asset retirement obligations are included in the
base costs for calculating depletion. Oil and gas properties include costs that are excluded from capitalized costs
being amortized. These amounts represent investments in unproved properties and major development
projects. The Company excludes these costs on a country-by-country basis until proved reserves are
found or until it is determined that the costs are impaired. All costs excluded are reviewed at
least quarterly to determine if impairment has occurred. The 39




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amount of any impairment is transferred to the capitalized costs being amortized (the
depreciation, depletion and amortization (DD&A) pool) or a charge is made against earnings for
those international operations where a reserve base has not yet been established. For international
operations where a reserve base has not yet been established, an impairment requiring a charge to
earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or
other information. Under the full cost method of accounting, a ceiling test is performed each quarter. The full
cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling
test determines a limit, on a country-by-country basis, on the book value of oil and gas
properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A
and the related deferred income taxes, may not exceed the estimated future
net cash flows from proved oil and gas reserves, generally using prices in effect at the end of the
period held flat for the life of production excluding the estimated
abandonment cost for properties with asset retirement obligations
recorded on the balance sheet and including the effect of derivative contracts that
qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of
unevaluated properties and major development. The effect of implementing SFAS 143 has no effect on
the ceiling test calculation as the future cash outflows associated with settling asset retirement
obligations are excluded from this calculation. (g) Inventories:Crude oil products and merchandise inventories are carried at the lower of
current market value or cost. Inventory costs include expenditures and other charges directly and
indirectly incurred in bringing the inventory to its existing condition and location. Selling
expenses and general and administrative expenses are reported as period costs and excluded from
inventory cost. Inventories of materials and supplies are valued at
cost or less. Inventory at December 31, 2004 includes depletion
and lease operating expenses of $628,311, associated with the
Companys crude oil production in China. (h) Derivative transactions: The Company has entered into commodity price risk management
transactions to manage its exposure to gas price volatility. These transactions are in the form of
price swaps with financial institutions and other credit worthy counterparties. These transactions
have been designated by the Company as cash flow hedges. As such, unrealized gains and losses
related to the change in fair market value of the derivative contracts are recorded in other
comprehensive income in the balance sheet to the extent the hedges are effective. (i) Income taxes:
Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and
their respective tax bases and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years
in which those temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a change
in tax rates is recognized in income in the period that includes the
enactment date. (j) Earnings per share: Basic earnings per share is computed by dividing net earnings attributable
to common stock by the weighted average number of common shares outstanding during each period.
Diluted earnings per share is computed by adjusting the average number of common shares outstanding
for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock
method to determine the dilutive effect. The following table provides a reconciliation of the components of basic and diluted net
income per common share for the years ended December 31, 2004, 2003 and 2002: Year Ended December 31,2004
    
    
    2003
    
    
    2002Net income
    
    $
    109,149,795
    
    
    $
    45,322,639
    
    
    $
    8,081,521Weighted average common
shares outstanding during the
period
    
    
    74,867,833
    
    
    
    74,231,553
    
    
    
    73,770,841Effect of dilutive instruments
    
    
    5,734,934
    
    
    
    4,419,886
    
    
    
    3,834,177Weighted average common
shares outstanding during the
period including the effects
of dilutive instruments
    
    
    80,602,767
    
    
    
    78,651,439
    
    
    
    77,605,018Basic earnings per share
    
    $
    1.46
    
    
    $
    0.61
    
    
    $
    0.11Diluted earnings per share
    
    $
    1.35
    
    
    $
    0.58
    
    
    $
    0.10Number of shares not included
in dilutive earnings per
share that would have been
antidilutive because the
exercise price was greater
than the average market price
of the common shares
    
    
    
    
    
    
    13,630
    
    
    
    130,570
 40




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(k) Use of estimates: Preparation of consolidated financial statements in accordance
with accounting principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ
from those estimates. (l) Reclassifications: Certain amounts in the financial statements of the prior years have been
reclassified to conform to the current year financial statement presentation. (m) Accounting for stock-based compensation:SFAS No. 123 defines a fair value method of
accounting for employee stock options and similar equity instruments. SFAS No. 123 allows for the
continued measurement of compensation cost for such plans using the intrinsic value based method
prescribed by APB Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), provided
that pro forma results of operations are disclosed for those options granted. The Company accounts
for stock options granted to employees and directors of the Company under the intrinsic value
method. Had the Company reported compensation costs as determined by the fair value method of
accounting for option grants to employees and directors, net income and net income per common share
would approximate the following pro forma amounts: For the Year Ended December 31,2004
    
    
    2003
    
    
    2002Net income:As reported
    
    $
    109,149,795
    
    
    $
    45,322,639
    
    
    $
    8,081,521Employee
stock grants
    
    
    923,623
    
    
    
    1,018,220
    
    
    
    1,211,165Deduct
stock-based compensation under SFAS 123
    
    
    (17,714,486
    )
    
    
    (1,522,968
    )
    
    
    (2,913,531
    )Pro forma
    
    $
    92,358,932
    
    
    $
    44,817,891
    
    
    $
    6,379,155Net income per common share:Basic:As reported
    
    $
    1.46
    
    
    $
    0.61
    
    
    $
    0.11Pro forma
    
    $
    1.23
    
    
    $
    0.59
    
    
    $
    0.07Diluted:As reported
    
    $
    1.35
    
    
    $
    0.58
    
    
    $
    0.10Pro forma
    
    $
    1.15
    
    
    $
    0.56
    
    
    $
    0.07
 For purposes of pro forma disclosures, the estimated fair value of options is amortized to
expense over the options vesting period. The weighted-average fair value of each option granted
is estimated on the date of grant using the Black Scholes option pricing model with the following
assumptions: at December 31, 2004, expected volatility of 38.4%
and a risk free rate of 3.713% at December 31, 2003, expected
volatility of 25.0% and a risk free rate of 4.35% and at
December 31, 2002, expected volatility of 30.0% and a risk free
rate of 4.85%. At December 31, 2004
options have expected lives of 6.5 years, and at December 31, 2003 and 2002 options had expected
lives of ten years. (n) Revenue Recognition.Natural gas revenues are recorded on the entitlement method. Under the
entitlement method, revenue is recorded when title passes based on the Companys net interest. The
Company records its entitled share of revenues based on estimated production volumes.
Subsequently, these estimated volumes are adjusted to reflect actual volumes that are supported by
third party pipeline statements or cash receipts. Since there is a ready market for natural gas,
the Company sells the majority of its products soon after production at various locations at which
time title and risk of loss pass to the buyer. Gas imbalances occur when the Company sells more or
less than its entitled ownership percentage of total gas production. Any amount received in excess
of the Companys share is treated as a liability. If the Company receives less than its entitled
share, the underproduction is recorded as a receivable. At December 31, 2004 and 2003, the Company
had net gas imbalance receivables of $2 million in both years. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable
price, when delivery has occurred and title is transferred. (o) Impact of recently issued accounting pronouncements: In December 2004, the Financial
Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No.
123 (FAS 123R), Share-based Payment. FAS 123R requires compensation costs related to share-based
payments to be recognized in the income statement over the vesting period. The amount of the
compensation cost will be 41




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measured based on the grant-date fair value of the instrument issued. FAS 123R is effective as of
July 1, 2005, for all awards granted or modified after that date and for those awards granted prior
to that date that have not vested. Beginning after July 1, 2005 the Company will begin expensing
share based compensation. All outstanding awards issued prior to this
date will have fully vested. 2. ASSET RETIREMENT OBLIGATIONS: In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations
(SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset
retirement obligation as a liability in the period in which it incurs a legal obligation
associated with the retirement of tangible long-lived assets that result from the
acquisition, construction, development and/or normal use of the assets. The Company has
recorded a liability of $744,512 ($321,506 U.S and $423,006 China) to account for future
obligations associated with its assets in both the United States and China. 3. OIL AND GAS PROPERTIES: December 31,
    
    
    December 31,2004
    
    
    2003Developed Properties:Acquisition, equipment, exploration, drilling and environmental
costs  Domestic
    
    $
    429,597,822
    
    
    $
    249,784,562Acquisition, equipment, exploration, drilling and environmental
costs  China
    
    
    24,552,316
    
    
    
    Less accumulated depletion, depreciation and amortization  Domestic
    
    
    (65,099,325
    )
    
    
    (38,495,605
    )Less accumulated depletion, depreciation and amortization  China
    
    
    (3,255,887
    )
    
    
    385,794,926
    
    
    
    211,288,957Unproven Properties:Acquisition and exploration costs  Domestic
    
    
    16,910,010
    
    
    
    15,604,521Acquisition and exploration costs  China
    
    
    71,929,450
    
    
    
    80,970,244$
    474,634,386
    
    
    $
    307,863,722
 Domestic
    
    
    ChinaExpenditure on Unproven
Properties for years ended December 31:2004
    
    $
    1,305,489
    
    
    $
    7,719,2992003
    
    
    1,285,537
    
    
    
    8,862,0002002
    
    
    2,066,842
    
    
    
    8,920,000Prior
    
    
    12,252,142
    
    
    
    46,428,151Total
    
    $
    16,910,010
    
    
    $
    71,929,450
 4. CAPITAL ASSETS: December 31, 2004December 31, 2004
    
    
    Accumulated
    
    
    December 31, 2004
    
    
    December 31, 2003Cost
    
    
    Depreciation
    
    
    Net Book Value
    
    
    Net Book ValueComputer equipment
    
    $
    808,812
    
    
    $
    587,551
    
    
    $
    221,261
    
    
    $
    188,376Office equipment
    
    
    261,832
    
    
    
    173,493
    
    
    
    88,339
    
    
    
    78,227Field equipment
    
    
    608,103
    
    
    
    278,839
    
    
    
    329,264
    
    
    
    115,641Other
    
    
    2,032,917
    
    
    
    1,247,415
    
    
    
    785,502
    
    
    
    829,762$
    3,711,664
    
    
    $
    2,287,298
    
    
    $
    1,424,367
    
    
    $
    1,212,006
 5. LONG-TERM LIABILITIES: December 31, 2004
    
    
    December 31, 2003Bank indebtedness
    
    $
    102,000,000
    
    
    $
    99,000,000Other long-term obligations
    
    
    9,734,904
    
    
    
    5,120,213$
    111,734,904
    
    
    $
    104,120,213
 Bank indebtedness: The Company (through its subsidiary) participates in a revolving credit
facility with a group of banks led by Bank One N.A. The agreement specifies a maximum loan amount
of $500 million and an aggregate borrowing base of $400 million and a commitment amount of $200
million at November 1, 2004. The commitment amount may be increased up to the lesser of the
borrowing base amount or $500 million at any time at the 42




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request of the Company. Each bank shall have the right, but not the obligation, to increase the
amount of their commitment as requested by the Company. In the event that the existing banks
increase their commitment to an amount less than the requested commitment amount, then it would be
necessary to bring additional banks into the facility. At December 31, 2004, the Company had $102
million outstanding and $98 million unused and available under the current committed amount. The credit facility matures on May 1, 2008. The note bears interest at either the banks
prime rate plus a margin of one-quarter of one percent (0.25%) to seven-eighths of one percent
(0.875%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and
one-quarter percent (1.25%) to one and seven-eighths of one percent (1.875%) based on the
percentage of available credit drawn. For the purposes of calculating interest, the available
credit is equal to the borrowing base. An average annual commitment fee of 0.30% to 0.50%,
depending on the percentage of available credit drawn, is charged quarterly for any unused portion
of the commitment amount. In 2004 the Companys total commitment
fee was $374,096, $249,788 in 2003 and $13,791 in 2002. The borrowing base is subject to periodic (at least semi-annual) review and re-determination
by the banks and may be decreased or increased depending on a number of factors, including the
Companys proved reserves and the banks forecast of future oil and gas prices. If the borrowing
base is reduced to an amount less than the balance outstanding, the Company has sixty days from the
date of written notice of the reduction in the borrowing base to pay the difference. Additionally,
the Company is subject to quarterly reviews of compliance with the covenants under the bank
facility including minimum coverage ratios relating to interest, working capital and advances to
Sino-American Energy Corporation. In the event of a default under the covenants, the Company may
not be able to access funds otherwise available under the facility. As of December 31, 2004, the
Company was in compliance with required ratios of the bank facility. The debt outstanding under the credit facility is secured by a majority of the Companys
proved domestic oil and gas properties. Other long-term obligations:These costs relate to the long-term portion of production taxes
payable, a liability associated with imbalanced production, the long-term portion of the fair value
estimate of our hedging liability and our asset retirement obligations mentioned in Note 2. 6. STOCK BASED COMPENSATION: The Companys Stock Incentive Plans are administered by the board of directors (the Plan
Administrator). The Plan Administrator may make awards of stock options to employees, directors,
officers and consultants of the Company as long as the aggregate number of common shares issuable
to any one person pursuant to incentives does not exceed 5% of the number of common shares
outstanding at the time of the award. In addition, no participant may receive during any fiscal
year of the Companys awards of incentives covering an aggregate of more than 500,000 common
shares. The Plan Administrator determines the vesting requirements and any vesting restrictions or
forfeitures in certain circumstances. Incentives may not have an exercise period longer than 10
years. The exercise price of the stock may not be less than the fair market value of the common
shares at the time of award, where fair market value means the weighted average trading price of
the common shares for the five trading days preceding the date of the award. The following table
summarizes the changes in stock options for the three-year period ended December 31, 2004: Number of
    
    
    Weighted AverageOptions
    
    
    Exercise Price (US$)Balance, December 31, 2001
    
    
    5,431,000
    
    
    $
    0.51 to $  5.23Granted
    
    
    748,500
    
    
    $
    7.82 to $  8.86Exercised
    
    
    (617,750
    )
    

    $
    0.64 to $  5.23Balance, December 31, 2002
    
    
    5,561,750
    
    
    $
    0.51 to $  8.86Granted
    
    
    797,500
    
    
    $
    9.66 to   14.21Exercised
    
    
    (443,000
    )
    
    $
    0.64 to $  8.86Cancelled
    
    
    (13,750
    )
    
    $
    8.86 to $  9.66Balance, December 31, 2003
    
    
    5,902,500
    
    

    $
    0.51 to $14.21Granted
    
    
    1,002,500
    
    
    $
    23.37 to $48.62Exercised
    
    
    (553,300
    )
    

    $
    0.76 to $14.21Balance, December 31, 2004
    
    
    6,351,700
    
    
    $
    0.51 to $48.62
 43




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No compensation resulted from the granting of these options as all were granted at or above
the market value of the common shares at the date of grant. Stock options granted to consultants
have been assessed at fair value and capitalized to the full cost pool based on the nature of the
services provided by the consultants. The Companys stock options vest each quarter over a
one-year period. At December 31, 2004, all stock options granted to date were fully vested. The following table summarizes information about the stock options outstanding at December 31,
2004: OPTIONS OUTSTANDING
    
    
    OPTIONS EXERCISABLEWeighted Average
    
    
    Weighted Average
    
    
    
    
    
    
    Weighted Average
    
    
    Weighted AverageRange of Exercise
    
    
    
    
    
    Remaining
    
    
    Exercise
    
    
    
    
    
    
    Remaining
    
    
    Exercise PricePrice ($US)
    
    Number Outstanding
    
    
    Contractual Life
    
    
    Price ($US)
    
    
    Number Exercisable
    
    
    Contractual Life
    
    
    ($US)$0.64-0.93
    
    
    1,952,000
    
    
    
    4.31
    
    
    $
    0.86
    
    
    
    1,952,000
    
    
    
    4.31
    
    
    $
    0.86$0.51-2.65
    
    
    716,400
    
    
    
    5.35
    
    
    $
    0.90
    
    
    
    716,400
    
    
    
    5.35
    
    
    $
    0.90$2.99-5.23
    
    
    1,240,000
    
    
    
    6.24
    
    
    $
    3.95
    
    
    
    1,240,000
    
    
    
    6.24
    
    
    $
    3.95$7.82-8.86
    
    
    678,500
    
    
    
    7.36
    
    
    $
    8.82
    
    
    
    678,500
    
    
    
    7.36
    
    
    $
    8.82$9.66-14.21
    
    
    762,300
    
    
    
    8.34
    
    
    $
    9.96
    
    
    
    762,300
    
    
    
    8.34
    
    
    $
    9.96$23.37-48.62
    
    
    1,002,500
    
    
    
    9.33
    
    
    $
    33.13
    
    
    
    1,002,500
    
    
    
    9.33
    
    
    $
    33.13
 7. DERIVATIVE FINANCIAL INSTRUMENTS: The Company uses derivative instruments as one way to manage its exposure to commodity prices. The
Company has periodically entered into fixed-price to index-price swap agreements in order to hedge
a portion of its production. The purpose of the swaps is to provide a measure of stability to the
Companys cash flows in an environment of volatile oil and gas prices. The derivatives reduce the
Companys exposure on the hedged volumes to decreases in commodity prices and limit the benefit the
Company might otherwise have received from any increases in commodity prices on the hedged volumes.
The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at
fair value. The accounting treatment of the changes in fair value as specified in SFAS No. 133 is
dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives
designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are
recognized in other comprehensive income until the hedged item is recognized in earnings as oil and
gas revenue. For all other derivatives, changes in fair value are recognized in earnings as income
or expense. At December 31, 2004 the Company had a current derivative liability of $3,739,406,
which is included in current liabilities in its balance sheet. The Company designates these
derivatives as cash flow hedges. During 2004, the Company made payments on financially settled swaps to counter-parties
totaling $8,493,300 as its net cost from hedging activities. This total includes $1,383,300 for
the first quarter of 2004, $1,870,725 for the second quarter of 2004, $1,988,700 for the third
quarter of 2004, and $3,250,575 for the fourth quarter of 2004. At December 31, 2004, the Company had the following open derivative contracts to manage price
risk on a portion of its natural gas production (all prices southwest Wyoming basis). Average
    
    
    Unrealized loss atType
    
    Contract Period
    
    
    Volume-MMBTU / day
    
    
    Price / MMbtu
    
    
    12/31/04*Swap
    
    Jan 2005-Jan 2006
    
    10,000
    
    $4.42
    
    $4,057,004
 * Unrealized losses are not adjusted for income tax effect. 44




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The Company also utilizes fixed price forward gas sales at southwest Wyoming delivery points
to hedge its commodity exposure. In addition to the derivative contracts discussed above, the
Company had the following physical delivery contracts in place at December 31, 2004. Volume
    
    
    AverageContract Period
    
    MMBTU / day
    
    
    Price / MMbtuCalendar 2005
    
    
    70,000
    
    
    $
    5.03Apr-Oct 2005
    
    
    10,000
    
    
    $
    6.03Calendar 2006
    
    
    25,000
    
    
    $
    4.58
 Subsequent to December 31, 2004 and through March 2, 2005, the Company entered into additional
contracts for fixed price physical delivery of gas during Calendar 2006 for an additional 25,000
MMBTU/day at an average price of $6.015 per MMBTU. 8. INCOME TAXES: Income (loss) before income taxes is as follows: Year Ended December 31,2004
    
    
    2003
    
    
    2002United States
    
    $
    153,553,816
    
    
    $
    70,970,170
    
    
    $
    13,846,884Foreign
    
    
    13,606,257
    
    
    
    (393,860
    )
    
    
    (706,197
    )Total
    
    $
    167,160,073
    
    
    $
    70,576,310
    
    
    $
    13,140,687The consolidated income tax
provision (benefit) is comprised of the following:Year Ended December 31,2004
    
    
    2003
    
    
    2002Current:U.S. federal & state
    
    $
    261,826
    
    
    
    
    
    
    
    Foreign
    
    
    
    
    
    
    
    
    
    
    Deferred:U.S. federal & state
    
    
    53,144,257
    
    
    
    25,253,671
    
    
    
    5,059,166Foreign
    
    
    4,604,195
    
    
    
    
    
    
    
    Total income tax provision (benefit)
    
    $
    58,010,278
    
    
    $
    25,253,671
    
    
    $
    5,059,166The income tax provision (benefit) differs from the amount that would be
computed by applying the U.S. federal income tax rate of 35% to pretax income as
a result of the following:Year Ended December 31,2004
    
    
    2003
    
    
    2002Income tax provision (benefit) computed at
the U.S. statutory rate
    
    $
    58,506,026
    
    
    $
    24,701,708
    
    
    $
    4,599,240State income tax provision (benefit), net
of federal benefit
    
    
    159,628
    
    
    
    455,557
    
    
    
    456,497Other, net
    
    
    (655,376
    )
    
    
    96,406
    
    
    
    3,429$
    58,010,278
    
    
    $
    25,253,671
    
    
    $
    5,059,166The tax effects of temporary differences that give rise to significant
components of the Companys deferred tax assets and liabilities
are as follows:Year Ended December 31,2004
    
    
    2003Deferred tax assets:Current:Unrecognized loss on derivative instruments
    
    
    
    
    
    $
    1,327,489
    
    
    
    Noncurrent deferred tax assets:U.S. federal net operating loss carryforwards
    
    
    
    
    
    
    5,845,351
    
    
    
    9,090,091Foreign net operating loss carryforwards
    
    
    
    
    
    
    2,554,106
    
    
    
    2,624,677Unrecognized loss on derivative instruments
    
    
    
    
    
    
    112,747
    
    
    
    1,840,713Other, net
    
    
    
    
    
    
    1,009,305
    
    
    
    843,9299,521,509
    
    
    
    14,399,410Valuation allowance
    
    
    
    
    
    
    (2,554,106
    )
    
    
    (2,624,677
    )Net noncurrent deferred tax assets
    
    
    
    
    
    
    6,967,403
    
    
    
    11,774,733Deferred tax liabilities:Noncurrent :Property and equipment
    
    
    
    
    
    
    (93,330,144
    )
    
    
    (45,220,864
    )Net noncurrent deferred tax asset (liability)
    
    
    
    
    
    
    ($86,362,741
    )
    
    
    ($33,446,131
    )
 In assessing the realizability of the deferred tax assets, Management
considers whether it is more likely than not that some or all of the deferred
tax assets will not be realized. The ultimate realization of the deferred tax
assets is dependent upon the recognition of future taxable income during the
periods in which the temporary differences are available. Among other items,
management considers the reversal of deferred tax liabilities, projections of
future taxable income and available tax planning strategies. As of December 31, 2004, the Company has U.S. federal regular tax net
operating loss carryforwards (NOLs) of approximately $16.7 million which are
available to offset future U.S. taxable income. If not used, these carryforwards
will expire between 2019 and 2021. The Company has not recorded any valuation
allowance attributable to its U.S. NOLs as management estimates that it is
more likely than not that these assets will be fully utilized before they
expire. The Company has Canadian non-capital tax loss carryforwards of approximately
$7.3 million and $7.5 million as of December 31, 2004 and December 31, 2003
respectively. The benefit of the Canadian loss carryforwards can only be
utilized to the extent the Company generates future taxable income in Canada. If
not utilized, the $7.3 million Canadian loss carryforward will expire between
2005 and 2011. Since the Company currently has no income producing operations in Canada,
management estimates that it is more likely than not that the Canadian loss
carryforwards will not be utilized. A valuation allowance has been recorded at
December 31, 2004 and December 31, 2003 attributable to this deferred tax asset. The Company uses derivative instruments designated as cash flow hedges as a
method of managing its exposure to commodity price fluctuations. To the extent
these hedges are effective, changes in the fair value of these derivative
instruments are recorded in Other Comprehensive Income, net of income tax. A tax
benefit attributable to unrecognized loss on derivative instruments of
$1,440,236 and $1,840,713 has been allocated directly to Other Comprehensive
Income as of December 31, 2004 and December 31, 2003 respectively. 45




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9. EMPLOYEE BENEFITS: The Company sponsors a qualified tax-deferred savings plan in accordance with provisions of
Section 401(k) of the Internal Revenue Code for its U.S. employees. Employees may defer up to 15%
of their compensation, subject to certain limitations. The Company matches the employee
contributions up to 5% of employee compensation along with a profit sharing contribution of 8%. The
plan operates on a calendar year basis and began in February 1998. The expense associated with the
Companys contribution was $396,684, $299,832 and $236,765 for the years ended December 31, 2004,
2003 and 2002, respectively. 10. SEGMENT INFORMATION The Company has two reportable operating segments, one domestic and one foreign, which are in
the business of natural gas and crude oil exploration and production. The accounting policies of
the segments are the same as those described in the summary of significant accounting policies.
The Company evaluates performance based on profit or loss from oil and gas operations before
price-risk management and other, general and administrative expenses and interest expense. The
Companys reportable operating segments are managed separately based on their geographic locations.
Financial information by operating segment is presented below: United States
    
    
    China
    
    
    TotalYear-ended December 31, 2004Oil and gas sales
    
    $
    238,866,913
    
    
    $
    19,170,436
    
    
    $
    258,037,349Costs and Expenses:Depletion and depreciation
    
    
    27,346,061
    
    
    
    2,903,000
    
    
    
    30,249,061Lease operating expenses
    
    
    6,286,715
    
    
    
    2,286,000
    
    
    
    8,572,715Production taxes
    
    
    28,151,661
    
    
    
    
    
    
    
    28,151,661Gathering
    
    
    13,135,809
    
    
    
    
    
    
    
    13,135,809Operating income
    
    $
    163,946,667
    
    
    $
    13,981,436
    
    
    $
    177,928,103General and administrative
    
    
    
    
    
    
    
    
    
    
    7,075,720Other expense
    
    
    
    
    
    
    
    
    
    
    3,692,310Income before income taxes and cumulative
effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    $
    167,160,073
 United States
    
    
    China
    
    
    TotalYear-ended December 31, 2003Oil and gas sales
    
    $
    121,581,097
    
    
    
    
    
    
    $
    121,581,097Costs and Expenses:Depletion and depreciation
    
    
    16,215,714
    
    
    
    
    
    
    
    16,215,714Lease operating expenses
    
    
    3,627,639
    
    
    
    
    
    
    
    3,627,639Production taxes
    
    
    13,767,668
    
    
    
    
    
    
    
    13,767,668Gathering
    
    
    7,828,372
    
    
    
    
    
    
    
    7,828,372Operating income
    
    $
    80,141,704
    
    
    $
    
    
    
    $
    80,141,704General and administrative
    
    
    
    
    
    
    
    
    
    
    6,751,367Other expense
    
    
    
    
    
    
    
    
    
    
    2,814,028Income before income taxes and cumulative
effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    $
    70,576,310
 46




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United States
    
    
    China
    
    
    TotalYear-ended December 31, 2002Oil and gas sales
    
    $
    42,342,392
    
    
    $
    
    
    
    $
    42,342,392Costs and Expenses:Depletion and depreciation
    
    
    9,712,111
    
    
    
    
    
    
    
    9,712,111Lease operating expenses
    
    
    2,356,986
    
    
    
    
    
    
    
    2,356,986Production taxes
    
    
    4,116,012
    
    
    
    
    
    
    
    4,116,012Gathering
    
    
    4,937,870
    
    
    
    
    
    
    
    4,937,870Operating income
    
    $
    21,219,413
    
    
    $
    
    
    
    
    21,219,413General and administrative
    
    
    
    
    
    
    
    
    
    
    5,410,269Other expense
    
    
    
    
    
    
    
    
    
    
    2,668,457Income before income taxes and cumulative
effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    $
    13,140,687
  11.
    DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES: In September 2003, the AcSB (Accounting Standards Board) released revised transitional
provisions for Stock-Based Compensation and Other Stock-Based Payments, Section 3870, to provide
the same alternative methods of transition as is provided in the US for voluntary adoption of the
fair value based method of accounting. These provisions permit either retroactive (with or without
restatement) or prospective application of the recognition provisions to awards not previously
accounted for at fair value. Prospective application is only available to enterprises that elect to
apply the fair value based method of accounting to that type of award for fiscal years beginning
before January 1, 2004. The AcSB has also amended Section 3870 to require that all transactions whereby goods and
services are received in exchange for stock-based compensation and other payments result in
expenses that should be recognized in financial statements, and that this requirement would be
applicable for financial periods beginning on or after January 1, 2004. Section 3870 requires that
share-based transactions be measured on a fair value basis. As described in Note 1, had the Company expensed the fair value of options vested during the
period, net income would have been reported as $92,358,232 for the year ended December 31, 2004,
$43,799,671 for the year ended December 31, 2003 and $5,167,990 for the year ended December
31,2002. Recorded in other comprehensive loss in the equity section of the Companys balance sheet is
an offset of $2,616,767 to a liability that measures a future effect of the fixed price to index
price swap agreements that the Company currently has in place. The Company has recorded this in
compliance with FASB No. 133 which addresses accounting impacts of derivative instruments. The AcSB issued a new Accounting Guideline (Guideline), AcG-13, Hedging Relationships, in
December 2001 in connection with amendments to CICA Handbook Section 1650, Foreign Currency
Translation. The Guideline is applicable to hedging relationships in effect in fiscal years
beginning on or after July 1, 2003 (the AcSB changed the original effective date of January 1, 2002
in its December 2001 meeting, and further deferred the effective date in its September 2002
meeting). The Guideline is not applicable to prior periods, but requires the discontinuance of
hedge accounting for hedging relationships established in prior periods that do not meet the
conditions for hedge accounting at the date it is first applied. The Guideline supplements some of the requirements on accounting for hedges of foreign
currency items in Section 1650, but is equally applicable to accounting for hedges of other types
of risk exposure. The Guideline deals with the identification, documentation, designation and
effectiveness of hedges and also the discontinuance of hedge accounting, but does not specify hedge
accounting methods. The Guideline is intended to improve the quality and consistency of hedge accounting under
Canadian GAAP. The Guideline incorporates certain features of the U.S. hedge accounting standards
as requirements. 47




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The AcSB has attempted to avoid creating any additional GAAP differences, i.e., requirements
that prevent an entity from adopting a U.S. requirement. However, Canadian hedge accounting
remains inconsistent with U.S. GAAP in some fundamental ways.  12.
    COMMITMENTS AND CONTINGENCIES: In May 2003 the Company amended its prior office lease in Englewood, Colorado, which it has
committed to through June 2008. The Companys total remaining commitment at December 31, 2004 on
this lease is $702,441. In December 2003, the Company signed a lease for office space in Houston,
Texas, which it has committed to through April 2007 for a total
remaining commitment at December 31, 2004 of $121,643. On October 16, 2003 the operator of the Companys properties in China, Kerr-McGee
(Operator), signed a 15 year contract, which provides for up to an additional 10 years, to lease
a floating production storage offloading unit (FPSO). The Company ratified the contract for its net share which is 8.92%. The FPSO service
agreement calls for a day rate lease payment and a sliding scale per barrel processing fee that
decreases based on cumulative barrels processed. The lease contains a cancellation fee based on a
sliding time-scale (cancellation fee decreases with time), which as of December 31, 2004 was $3.87
million net to the Companys 8.92% interest. The Company considers it very unlikely that a lease
cancellation situation will occur. Due to the terms of the lease, the Company cannot estimate with
any degree of accuracy the costs it may incur during the life of the lease. The Companys net
share for the costs of the FPSO in 2004 was approximately $1.3 million. The Company is currently involved in various routine disputes and allegations incidental to
its business operations. While it is not possible to determine the ultimate disposition of these
matters, management, after consultation with legal counsel, is of the opinion that the final
resolution of all such currently pending or threatened litigation is not likely to have a material
adverse effect on the consolidated financial position, results of operations or cash flows of the
Company.  13.
    FAIR VALUE OF FINANCIAL INSTRUMENTS: For certain of the Companys financial instruments, including accounts receivable, notes
receivable, accounts payable and accrued liabilities, the carrying amounts approximate fair value
due to the immediate or short-term maturity of these financial instruments. The carrying value for
notes payable approximates fair market value because the interest rates are similar to the current
rates presently available to the Company for loans with similar terms and maturity. The Companys revenues are derived principally from uncollateralized sales to customers in the
gas and oil industry. The concentration of credit risk in a single industry affects the Companys
overall exposure to credit risk because customers may be similarly affected by changes in economic
and other conditions. The Company had two significant customers, BP Energy Company and Sempra
Energy Trading, that accounted for 10% or more of the Companys total gas and oil sales during
2004.  14.
    SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): IncomeBeforeIncome
    
    
    Income
    
    
    
    
    
    
    Basic
    
    
    DilutedTax
    
    
    Tax
    
    
    Net
    
    
    Earnings
    
    
    EarningsRevenues
    
    
    Expenses
    
    
    Provision
    
    
    Provision
    
    
    Income
    
    
    Per Share
    
    
    Per Share(in thousands, except for per share data)2004First Quarter
    
    $
    48,619
    
    
    $
    17,947
    
    
    $
    30,672
    
    
    $
    10,888
    
    
    $
    19,784
    
    
    $
    0.26
    
    
    $
    0.25Second Quarter
    
    $
    46,110
    
    
    $
    17,393
    
    
    $
    28,717
    
    
    $
    10,195
    
    
    $
    18,522
    
    
    $
    0.25
    
    
    $
    0.23Third Quarter
    
    $
    66,441
    
    
    $
    22,853
    
    
    $
    43,588
    
    
    $
    15,713
    
    
    $
    27,875
    
    
    $
    0.37
    
    
    $
    0.35Fourth Quarter
    
    $
    96,867
    
    
    $
    32,684
    
    
    $
    64,183
    
    
    $
    21,214
    
    
    $
    42,969
    
    
    $
    0.57
    
    
    $
    0.53$
    258,037
    
    
    $
    90,877
    
    
    $
    167,160
    
    
    $
    58,010
    
    
    $
    109,1502003First Quarter
    
    $
    24,671
    
    
    $
    11,303
    
    
    $
    13,368
    
    
    $
    5,147
    
    
    $
    8,221
    
    
    $
    0.11
    
    
    $
    0.11Second Quarter
    
    $
    23,466
    
    
    $
    11,075
    
    
    $
    12,391
    
    
    $
    4,771
    
    
    $
    7,620
    
    
    $
    0.10
    
    
    $
    0.10Third Quarter
    
    $
    29,291
    
    
    $
    12,422
    
    
    $
    16,869
    
    
    $
    6,541
    
    
    $
    10,328
    
    
    $
    0.14
    
    
    $
    0.13Fourth Quarter
    
    $
    44,153
    
    
    $
    16,205
    
    
    $
    27,948
    
    
    $
    8,795
    
    
    $
    17,188
    
    
    $
    0.26
    
    
    $
    0.24$
    121,581
    
    
    $
    51,005
    
    
    $
    70,576
    
    
    $
    25,254
    
    
    $
    43,357
 48




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15.
    DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): The following information about the Companys oil and gas producing activities is presented in
accordance with Financial Accounting Standards Board Statement No. 69, Disclosure About Oil and Gas
Producing Activities: A. OIL AND GAS RESERVES: The determination of oil and gas reserves is complex and highly interpretive. Assumptions
used to estimate reserve information may significantly increase or decrease such reserves in future
periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate
determination of reserves may not be possible for many years because of the time needed for
development, drilling, testing, and studies of reservoirs. The following unaudited tables as of
December 31, 2004, 2003 and 2002 are based upon estimates prepared by Netherland, Sewell &
Associates, Inc. dated January 24, 2005, January 23, 2004 and January 21, 2003, respectively. The
estimates for properties in China were prepared by Ryder Scott Company in a report dated February
11, 2005. These are estimated quantities of proved oil and gas reserves for the Company and the
changes in total proved reserves as of December 31, 2004, 2003 and 2002. All such reserves are
located in the Green River Basin, Wyoming and Bohai Bay, China. B. ANALYSES OF CHANGES IN PROVEN RESERVES: United States
    
    
    China
    
    
    TotalOil (Bbls)
    
    
    Gas (Mcf)
    
    
    Oil (Bbls)
    
    
    Gas (Mcf)
    
    
    Oil (Bbls)
    
    
    Gas (Mcf)Reserves, December 31, 2001
    
    
    3,482,800
    
    
    
    423,829,600
    
    
    
    
    
    
    
    
    
    
    
    3,482,800
    
    
    
    423,829,600Extensions, discoveries and additions
    
    
    1,101,500
    
    
    
    139,044,000
    
    
    
    
    
    
    
    
    
    
    
    1,101,500
    
    
    
    139,044,000Production
    
    
    (151,200
    )
    
    
    (16,496,000
    )
    
    
    
    
    
    
    
    
    
    
    (151,200
    )
    
    
    (16,496,000
    )Revisions
    
    
    1,125,900
    
    
    
    120,743,400
    
    
    
    
    
    
    
    
    
    
    
    1,125,900
    
    
    
    120,743,400Reserves, December 31, 2002
    
    
    5,559,000
    
    
    
    667,121,000
    
    
    
    
    
    
    
    
    
    
    
    5,559,000
    
    
    
    667,121,000Extensions, discoveries and additions
    
    
    2,894,700
    
    
    
    361,298,700
    
    
    
    
    
    
    
    
    
    
    
    2,894,700
    
    
    
    361,298,700Production
    
    
    (211,600
    )
    
    
    (27,621,800
    )
    
    
    
    
    
    
    
    
    
    
    (211,600
    )
    
    
    (27,621,800
    )Revisions
    
    
    100,400
    
    
    
    22,569,400
    
    
    
    
    
    
    
    
    
    
    
    100,400
    
    
    
    22,569,400Reserves, December 31, 2003
    
    
    8,342,500
    
    
    
    1,023,367,300
    
    
    
    
    
    
    
    
    
    
    
    8,342,500
    
    
    
    1,023,367,300Extensions, discoveries and additions
    
    
    4,520,000
    
    
    
    562,548,000
    
    
    
    8,180,900
    
    
    
    
    
    
    
    12,700,900
    
    
    
    562,548,000Production
    
    
    (349,700
    )
    
    
    (43,667,400
    )
    
    
    (593,300
    )
    
    
    
    
    
    
    (943,000
    )
    
    
    (43,667,400
    )Revisions
    
    
    (1,123,700
    ) (1)
    
    
    (128,247,300
    ) (2)
    
    
    
    
    
    
    
    
    
    
    (1,123,700
    )
    
    
    (128,247,300
    )Reserves, December 31, 2004
    
    
    11,389,100
    
    
    
    1,414,000,600
    
    
    
    7,587,600
    
    
    
    
    
    
    
    18,976,700
    
    
    
    1,414,000,600Proved developed reserves:December 31, 2001
    
    
    1,295,000
    
    
    
    150,397,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    150,397,000December 31, 2002
    
    
    2,003,000
    
    
    
    222,608,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    222,608,000December 31, 2003
    
    
    3,028,000
    
    
    
    359,072,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    359,072,000December 31, 2004
    
    
    4,195,000
    
    
    
    514,686,000
    
    
    
    4,356,000
    
    
    
    
    
    
    
    8,551,000
    
    
    
    514,686,000
   (1)
    
    Revision amount of 936,500 attributable to 40 wells dropped from PUD category replaced by more attractive wells.(2)
    
    Revision amount of 117,064,000 associated with above 40 mentioned wells. C. STANDARDIZED MEASURE: The following table sets forth a standardized measure of the estimated discounted future net
cash flows attributable to the Companys proved gas reserves. Gas prices have fluctuated widely in
recent years. The calculated weighted average sales prices utilized for the purposes of estimating
the Companys proved reserves and future net revenues were $5.46, $5.59, and $2.94 per Mcf of gas
at December 31, 2004, 2003 and 2002, respectively. The calculated weighted average crude oil price
at December 31, 2004 for China was a Duri price of $29.46. The future production and development
costs represent the estimated future expenditures to be incurred in developing and producing the
proved reserves, assuming continuation of existing economic conditions. Future income tax expense
was computed by applying statutory income tax rates to the difference 49




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##### Table of Contents



between pretax net cash flows relating to the Companys proved reserves and the tax basis of proved
properties and available operating loss carryovers (US $000). United States
    
    
    China
    
    
    TotalAs of December 31, 2002Future cash inflows
    
    $
    2,132,521
    
    
    
    
    
    
    $
    2,132,521Future production costs
    
    
    (569,034
    )
    
    
    
    
    
    
    (569,034
    )Future development costs
    
    
    (254,892
    )
    
    
    
    
    
    
    (254,892
    )Future income taxes
    
    
    (432,663
    )
    
    
    
    
    
    
    (432,663
    )Future net cash flows
    
    
    875,932
    
    
    
    
    
    
    
    875,932Discounted at 10%
    
    
    (558,967
    )
    
    
    
    
    
    
    (558,967
    )Standardized measure of
discounted future net cash flows
    
    $
    316,965
    
    
    
    
    
    
    $
    316,965Pre-tax standardized measure SEC PV-10
    
    $
    473,528
    
    
    
    
    
    
    $
    473,528As of December 31, 2003Future cash inflows
    
    $
    5,986,603
    
    
    
    
    
    
    $
    5,986,603Future production costs
    
    
    (1,171,314
    )
    
    
    
    
    
    
    (1,171,314
    )Future development costs
    
    
    (358,811
    )
    
    
    
    
    
    
    (358,811
    )Future income taxes
    
    
    (1,620,437
    )
    
    
    
    
    
    
    (1,620,437
    )Future net cash flows
    
    
    2,836,041
    
    
    
    
    
    
    
    2,836,041Discounted at 10%
    
    
    (1,700,528
    )
    
    
    
    
    
    
    (1,700,528
    )Standardized measure of
discounted future net cash flows
    
    $
    1,135,513
    
    
    
    
    
    
    $
    1,135,513Pre-tax standardized measure SEC PV-10
    
    $
    1,784,314
    
    
    
    
    
    
    $
    1,784,314As of December 31, 2004Future cash inflows
    
    $
    8,213,061
    
    
    $
    223,531
    
    
    $
    8,436,592Future production costs
    
    
    (1,699,891
    )
    
    
    (67,387
    )
    
    
    (1,767,278
    )Future development costs
    
    
    (623,539
    )
    
    
    (18,382
    )
    
    
    (641,921
    )Future income taxes
    
    
    (1,988,387
    )
    
    
    (21,436
    )
    
    
    (2,009,823
    )Future net cash flows
    
    
    3,901,244
    
    
    
    116,326
    
    
    
    4,017,570Discounted at 10%
    
    
    (2,285,779
    )
    
    
    (62,455
    )
    
    
    (2,348,234
    )Standardized measure of
discounted future net cash flows
    
    $
    1,615,465
    
    
    $
    53,871
    
    
    $
    1,669,336Pre-tax standardized measure SEC PV-10
    
    $
    2,438,837
    
    
    $
    103,518
    
    
    $
    2,542,355
 The estimate of future income taxes is based on the future net cash flows from proved reserves
adjusted for the tax basis of the oil and gas properties but without consideration of general and
administrative and interest expenses.  D.
    SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (US$000) December 31,
    
    
    December 31,
    
    
    December 31,2004
    
    
    2003
    
    
    2002Standardized measure, beginning
    
    $
    1,135,513
    
    
    $
    316,965
    
    
    $
    119,259Net revisions
    
    
    (245,950
    )
    
    
    41,715
    
    
    
    119,995Extensions, discoveries and other changes
    
    
    1,062,236
    
    
    
    680,136
    
    
    
    136,194Changes in future development costs
    
    
    (123,051
    )
    
    
    (10,603
    )
    
    
    (40,825
    )Sales of oil and gas, net of production costs
    
    
    (216,670
    )
    
    
    (96,357
    )
    
    

    (39,985
    )Net change in prices and production costs
    
    
    2,645
    
    
    
    605,892
    
    
    
    91,501Development costs incurred during the
period that reduce future development costs
    
    
    96,220
    
    
    
    8,886
    
    
    
    1,573Accretion of discount
    
    
    178,431
    
    
    
    47,353
    
    
    
    18,246Net change in income taxes
    
    
    (220,038
    )
    
    
    (458,474
    )
    
    
    (88,993
    )Standardized measure, ending
    
    $
    1,669,336
    
    
    $
    1,135,513
    
    
    $
    316,965
 50




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##### Table of Contents



There are numerous uncertainties inherent in estimating quantities of proved reserves and
projected future rates of production and timing of development expenditures, including many factors
beyond the control of the Company. The reserve data and standardized measures set forth herein
represent only estimates. Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way and the accuracy of any
reserve estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different engineers often vary. In addition,
results of drilling, testing and production subsequent to the date of an estimate may justify
revision of such estimates. Accordingly, reserve estimates are often different from the quantities
of oil and gas that are ultimately recovered. Further, the estimated future net revenues from
proved reserves and the present value thereof are based upon certain assumptions, including
geologic success, prices, future production levels and costs that may not prove correct over time.
Predictions of future production levels are subject to great uncertainty, and the meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon which they are based.
Historically, oil and gas prices have fluctuated widely.  E.
    COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES (US$000): UNITED STATES Years ended
    
    December 31,
    
    
    December 31,
    
    
    December 31,2004
    
    
    2003
    
    
    2002Acquisition costs  unproved properties
    
    $
    1,268
    
    
    $
    1,603
    
    
    $
    937Exploration
    
    
    97,068
    
    
    
    55,095
    
    
    
    22,722Development
    
    
    82,324
    
    
    
    43,111
    
    
    
    28,620Asset retirement obligations
    
    
    322
    
    
    
    
    
    
    
    Total
    
    $
    180,982
    
    
    $
    99,809
    
    
    $
    52,279
 CHINA Years ended
    
    December 31,
    
    
    December 31,
    
    
    December 31,2004
    
    
    2003
    
    
    2002Acquisition costs  unproved properties
    
    $
    2,351
    
    
    $
    16,027
    
    
    $
    8,979Exploration
    
    
    
    
    
    
    
    
    
    
    Development
    
    
    12,234
    
    
    
    
    
    
    
    Asset retirement obligations
    
    
    423
    
    
    
    
    
    
    
    Total
    
    $
    15,008
    
    
    $
    16,027
    
    
    $
    8,979
  F.
    RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (US$000): UNITED STATES Years ended
    
    December 31,
    
    
    December 31,
    
    
    December 31,2004
    
    
    2003
    
    
    2002Oil and gas revenue
    
    $
    238,867
    
    
    $
    121,581
    
    
    $
    43,342Production expenses and taxes
    
    
    (47,574
    )
    
    
    (25,224
    )
    
    
    (11,411
    )Depletion and depreciation
    
    
    (27,346
    )
    
    
    (16,216
    )
    
    
    (9,712
    )Deferred income taxes
    
    
    (58,010
    )
    
    
    (25,254
    )
    
    
    (5,059
    )Total
    
    $
    105,937
    
    
    $
    54,887
    
    
    $
    17,160
 CHINA Years ended
    
    December 31,
    
    
    December 31,
    
    
    December 31,2004
    
    
    2003
    
    
    2002Oil and gas revenue
    
    $
    19,170
    
    
    $
    
    
    
    $
    Production expenses and taxes
    
    
    (2,286
    )
    
    
    
    
    
    
    Depletion and depreciation
    
    
    (2,903
    )
    
    
    
    
    
    
    Deferred income taxes
    
    
    Total
    
    $
    13,981
    
    
    $
    
    
    
    $
    
 51




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##### Table of Contents



Item 9.
    Change in and Disagreements with Accountants on Accounting and Financial Disclosures. None 
  Item 9A.
    Controls and Procedures. The Companys management, including the Companys principal executive officer and principal
financial officer, has evaluated the effectiveness of the Companys disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934)
as of the end of the period covered by this Annual Report on Form 10-K. Based upon that
evaluation, the Companys principal executive officer and principal financial officer have
concluded that the disclosure controls and procedures were effective as of the end of the period
covered by this Annual Report on Form 10-K. There were no changes in the Companys internal control over financial reporting that occurred
during the Companys last fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the Companys internal control over financial reporting.  Item 9B.
    Other Information. None. 
 Part III 
  Item 10.
    Directors and Executive Officers of the Registrant. The information required by this item will be included in the Companys definitive proxy
statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated
herein by reference. 
  Item 11.
    Executive Compensation. The information required by this item will be included in the Companys definitive proxy
statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated
herein by reference. 
  Item 12.
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The information required by Item 403 of Regulation S-K will be included in the Companys
definitive proxy statement, which will be filed not later than 120 days after December 31, 2004,
and is incorporated herein by reference. Number of securitiesNumber of
    
    
    
    
    
    
    remaining available forsecurities to be
    
    
    
    
    
    
    future issuance underissued upon
    
    
    
    
    
    
    equity compensationexercise of
    
    
    Weighted-average
    
    
    plans (excludingoutstanding
    
    
    exercise price of
    
    
    securities reflected inPlan Category
    
    options
    
    
    outstanding options
    
    
    the first column)Equity compensation plans
approved by security holders
at 12/31/2004
    
    
    6,363,800
    
    
    $
    8.49
    
    
    
    3,824,000Equity compensation plans
not approved by security
holders
    
    
    n/a
    
    
    
    n/a
    
    
    
    n/aTotal
    
    
    6,363,800
    
    
    $
    8.49
    
    
    
    3,824,000
 
  Item 13.
    Certain Relationships and Related Transactions. The information required by this item will be included in the Companys definitive proxy
statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated
herein by reference. 
  Item 14.
    Principal Accountants Fees and Services The information required by this item will be included in the Companys definitive proxy
statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated
herein by reference. 52




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##### Table of Contents



Part IV 
  Item 15.
    Exhibits, Financial Statement Schedules, and Reports on Form 8-K. The following documents are filed as part of this report:  1.
    Financial Statements: See Index to Consolidated Financial Statements in
Item 8.2.
    Financial Statement Schedules: None3.
    Exhibits. The following Exhibits are filed herewith pursuant to Rule 601
of the Regulation S-K or are incorporated by reference to previous filings. Exhibits
designated with a + constitute a management contract or compensatory plan or
arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. Exhibit Number
    
    Description3.1
    
    Articles of Incorporation of Ultra Petroleum Corp.  (incorporated by reference
to Exhibit 3.1 of the Companys Quarterly Report on Form 10-Q for the period ended June
30, 2001)3.2
    
    By-Laws of Ultra Petroleum Corp.  (incorporated by reference to Exhibit 3.2 of
the Companys Quarterly Report on Form 10-Q for the period ended June 30, 2001)4.1
    
    Specimen Common Share Certificate  (incorporated by reference to Exhibit 4.1 of
the Companys Quarterly Report on Form 10-Q for the period ended June 30, 2001)*10.1
    
    Second Amendment to Second Amended and Restated Credit Agreement dated November 1,
2004 among Ultra Resources, Inc., Bank One, NA, Union Bank of California, N.A., Hibernia
National Bank, Guaranty Bank, FSB, Compass Bank, Bank of Scotland and Fleet National Bank.*10.2
    
    First Amendment to Second Amended and Restated Credit Agreement dated August 10, 2004
among Ultra Resources, Inc., Bank One, NA, Union Bank of California, N.A., Hibernia National
Bank, Guaranty Bank, FSB, Compass Bank, Bank of Scotland and Fleet National Bank.10.3
    
    Second Amended and Restated Credit Agreement dated June 9, 2004 among Ultra Resources,
Inc., Bank One, NA, Union Bank of California, N.A., Hibernia National Bank, Guaranty
Bank, FSB, Compass Bank, Bank of Scotland and Fleet National Bank (incorporated by
reference to Exhibit 10.1 of the Companys Quarterly Report on Form 10-Q for the
period ended June 30, 2004).14.1
    
    Code of Ethics for Chief Executive Officer and Senior Financial Officers of Ultra
Petroleum Corp. (Incorporated by reference to Exhibit 3.3 of the Companys Annual Report
on Form 10-K for the year ended December 31, 2003)21.1
    
    Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 to the
Companys Annual Report on Form 10-K for the period ended December 31, 2001)*23.1
    
    Consent of Netherland, Sewell & Associates, Inc.*23.2
    
    Consent of Ryder Scott Company*23.3
    
    Consent of KPMG, LLP*31.1
    
    Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13(a)-14(a)*32.1
    
    Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13(a)-14(a)
   *
    
    Filed herewith 53




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##### Table of Contents



SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized. ULTRA PETROLEUM CORP.Date: March 16, 2005
    
    By:
    
    
    
    -s- Michael D. WatfordName:
    
    Michael D. WatfordTitle:
    
    Chairman of the Board,Chief Executive Officer, PresidentAnd Chief Financial Officer
 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the capacities and on the
dates indicated. Signature
    
    Title
    
    Date-s- Michael D. WatfordChairman of the Board,Michael D. Watford
    
    Chief Executive Officer, PresidentAnd Chief Financial Officer
    
    March 16, 2005-s- W. Charles HeltonW. Charles Helton
    
    Director
    
    March 16, 2005-s- James E. NielsonJames E. Nielson
    
    Director
    
    March 16, 2005-s- Robert E. RigneyRobert E. Rigney
    
    Director
    
    March 16, 2005-s- James C. RoeJames C. Roe
    
    Director
    
    March 16, 2005-s- Kristen MarronKristen
Marron
    
    Financial Reporting
Manager(Principal Accounting
Officer)
    
    March 16, 2005
 54




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##### Table of Contents



EXHIBIT INDEX Exhibit Number
    
    Description3.1
    
    Articles of Incorporation of Ultra Petroleum Corp.  (incorporated by reference
to Exhibit 3.1 of the Companys Quarterly Report on Form 10-Q for the period ended June
30, 2001)3.2
    
    By-Laws of Ultra Petroleum Corp.  (incorporated by reference to Exhibit 3.2 of
the Companys Quarterly Report on Form 10-Q for the period ended June 30, 2001)4.1
    
    Specimen Common Share Certificate  (incorporated by reference to Exhibit 4.1 of
the Companys Quarterly Report on Form 10-Q for the period ended June 30, 2001)*10.1
    
    Second Amendment to Second Amended and Restated Credit Agreement dated November 1,
2004 among Ultra Resources, Inc., Bank One, NA, Union Bank of California, N.A., Hibernia
National Bank, Guaranty Bank, FSB, Compass Bank, Bank of Scotland and Fleet National Bank.*10.2
    
    First Amendment to Second Amended and Restated Credit Agreement dated August 10, 2004
among Ultra Resources, Inc., Bank One, NA, Union Bank of California, N.A., Hibernia National
Bank, Guaranty Bank, FSB, Compass Bank, Bank of Scotland and Fleet National Bank.10.3
    
    Second Amended and Restated Credit Agreement dated June 9, 2004 among Ultra Resources,
Inc., Bank One, NA, Union Bank of California, N.A., Hibernia National Bank, Guaranty
Bank, FSB, Compass Bank, Bank of Scotland and Fleet National Bank (incorporated by
reference to Exhibit 10.1 of the Companys Quarterly Report on Form 10-Q for the
period ended June 30, 2004).14.1
    
    Code of Ethics for Chief Executive Officer and Senior Financial Officers of Ultra
Petroleum Corp. (Incorporated by reference to Exhibit 3.3 of the Companys Annual Report
on Form 10-K for the year ended December 31, 2003)21.1
    
    Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 to the
Companys Annual Report on Form 10-K for the period ended December 31, 2001)*23.1
    
    Consent of Netherland, Sewell & Associates, Inc.*23.2
    
    Consent of Ryder Scott Company*23.3
    
    Consent of KPMG, LLP*31.1
    
    Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13(a)-14(a)*32.1
    
    Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13(a)-14(a)
   *
    
    Filed herewith