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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K

|      |  |                                                                                         
|----- |  | ----------------------------------------------------------------------------------------
|[ X ] |  | Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934    
|      |  |                                                                                         
|      |  | For the Fiscal Year ended December 31, 2003.                                            
|      |  |                                                                                         
|[  ]  |  | Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
|      |  |                                                                                         
|      |  | For the transition period from ______________ to ______________ .                       

Commission File Number: 0-29370

ULTRA PETROLEUM CORP.

(Exact Name of Registrant as Specified in Its Charter)


|                                                |  |                                     
|----------------------------------------------- |  | ------------------------------------
|Yukon Territory, Canada                         |  | N/A                                 
|(Jurisdiction of Incorporation or Organization) |  | (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:

|                                 |  |                        
|-------------------------------- |  | -----------------------
|                                 |  | Name of each exchange  
|Title of each class              |  | on which registered    
|                                 |  |                        
|Common Shares, without par value |  | American Stock Exchange
|                                 |  | Toronto 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 [ X ]
  NO [  ]

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. [ X ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
YES [ X ]   NO [  ]

The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant was approximately $959,970,404 as of June 30,
2003 (based on the last reported sales price of $12.91 of such stock on the
American Stock Exchange on such date).

Documents incorporated by reference: The definitive Proxy Statement for the
2004 Annual Meeting of Stockholders, which will be filed with the Securities
and Exchange Commission within 120 days after December 31, 2003, is
incorporated by reference in Part III of this Form 10-K.

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|                                                  |                                                                                                         |  |  |  |  |  |  | 
|------------------------------------------------- | ------------------------------------------------------------------------------------------------------- |  |  |  |  |  |  | 
|PART I                                           
|                                                  | Item 1. Description of Business                                                                        
|                                                  | Item 2. Description of Property                                                                        
|                                                  | Item 3. Legal Proceedings                                                                              
|                                                  | Item 4. Submission of Matters to a Vote of Security Holders                                            
|PART II                                          
|                                                  | Item 5. Market for Registrants Common Stock and Related Stockholder Matters                           
|                                                  | Item 6. Selected Financial Data                                                                        
|                                                  | Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations          
|                                                  | Item 7A. Quantitative and Qualitative Disclosures About Market Risk                                    
|                                                  | Item 8. Financial Statements and Supplementary Data                                                    
|                                                  | Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosures           
|                                                  | Item 9A. Controls and Procedures                                                                       
|Part III                                         
|                                                  | Item 10. Directors and Executive Officers of the Registrant                                            
|                                                  | Item 11. Executive Compensation                                                                        
|                                                  | Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|                                                  | Item 13. Certain Relationships and Related Transactions                                                
|                                                  | Item 14. Principal Accountants Fees and Services                                                       
|Part IV                                          
|                                                  | Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K                              
|SIGNATURES                                       
|EXHIBIT INDEX                                    
|Code of Ethics to CEO & Senior Financial Officers
|3rd Amend.to 1st Amended Credit Agreement        
|Consent of Netherland, Sewell & Associates, Inc. 
|Certification of CEO Pursuant to Section 302     
|Certification of CFO Pursuant to Section 302     
|Certification of CEO Pursuant to Section 906     
|Certification of CFO Pursuant to Section 906     



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TABLE OF CONTENTS

|         |  |                                                                                                |  |     
|-------- |  | ---------------------------------------------------------------------------------------------- |  | ----
|         |  |                                                                                                |  | Page
|         |  |                                                                                                |  |     
|         |  | PART I                                                                                         |  |     
|ITEM 1.  |  | DESCRIPTION OF BUSINESS                                                                        |  | 3   
|ITEM 2.  |  | DESCRIPTION OF PROPERTY                                                                        |  | 8   
|ITEM 3.  |  | LEGAL PROCEEDINGS                                                                              |  | 12  
|ITEM 4.  |  | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                            |  | 12  
|         |  | PART II                                                                                        |  |     
|ITEM 5.  |  | MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS                          |  | 13  
|ITEM 6.  |  | SELECTED FINANCIAL DATA                                                                        |  | 13  
|ITEM 7.  |  | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS          |  | 17  
|ITEM 7A  |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                     |  | 21  
|ITEM 8.  |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                                    |  | 29  
|ITEM 9.  |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES          |  | 45  
|ITEM 9A. |  | CONTROLS AND PROCEDURES                                                                        |  | 45  
|         |  | PART III                                                                                       |  |     
|ITEM 10. |  | DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT                                                 |  | 45  
|ITEM 11. |  | EXECUTIVE COMPENSATION                                                                         |  | 45  
|ITEM 12. |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS |  | 46  
|ITEM 13. |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                                                 |  | 46  
|ITEM 14. |  | PRINCIPAL ACCOUNTANTS FEES AND SERVICES                                                        |  | 46  
|         |  | PART IV                                                                                        |  |     
|ITEM 15. |  | EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K                   |  | 46  
|         |  | SIGNATURES                                                                                     |  | 48  

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PART I




Item 1. Description of 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 exploration and development of oil and gas properties.

As of December 31, 2003 Ultra owns interests in approximately 175,345
gross (97,990 net) acres in Wyoming covering approximately 300 square miles.
The Company owns working interest in approximately 156 gross productive wells
in this area and is operator of 51% of those wells. The Companys current
domestic operations are principally focused on developing and expanding a tight
gas sand project located in the Green River Basin in Southwest Wyoming. In
2003, the Companys Wyoming production was approximately 99% of the Companys
total oil and natural gas production and all of the Companys proved reserves
were in Wyoming. In 2003, capital expenditures in Wyoming comprised
approximately 85% of the Companys total capital expenditures.

The Company acquired Pendaries Petroleum Ltd. on January 16, 2001. As a
result of this acquisition, the Company became active in oil and gas
exploration and development in Bohai Bay, China. The Company now holds an
18.182% working interest in Block 04/36 and a 15% working interest in Block
05/36 (jointly the Blocks). In 2003, the Company reported no production or
reserves attributable to its China property. The Company spent approximately
15% of its 2003 capital budget in China. A wholly-owned subsidiary of
Kerr-McGee Corporation is the operator of the Blocks. At the time of the
acquisition, three oil discoveries had been made on the Blocks. Since the
acquisition of Pendaries, six additional discoveries have been made on the
Blocks, two of which were discoveries added in 2003.

The Company owns interests in approximately 15,841 gross (11,384 net)
acres and interest in three productive wells in Texas. The Company also owns
interest in 14,741 gross (14,087 net) acres in Pennsylvania.

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 plans to continue to identify, develop and explore the
gas-rich acreage in the Green River Basin. The Green River Basin 2004 drilling
program targets the upper Cretaceous Lance and Mesaverde sands in the area of
the Pinedale Anticline and Jonah Fields. The Company plans to attempt to
continue expanding the identified productive area through the drilling of
step-out and exploration wells on its Green River Basin acreage as well as
continue drilling deeper wells to test other potentially productive horizons.
The Company is utilizing its 3-D seismic to map these deeper potentially
productive intervals and to identify further extensions of the productive Lance
fairway.

Bohai Bay, China

The Company plans to drill additional exploration and appraisal wells in
2004 on the Blocks and to continue development planning on the appraised
discovery areas. The Company has discovered 9 oil fields on its two Bohai Bay
Blocks. Of these 9 fields, 2 fields are under development with first
production expected in the fourth quarter of 2004. Five of the fields are in
various stages of development planning with tentative plans calling for all 5
fields to have an Overall Development Plan (ODP) submitted to the Chinese by
year end 2004. If

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current development schedules are followed for these 5 fields, the Company
should have a total of 7 fields on production by the end of 2006. Two of the 9
fields are still under appraisal.

Marketing and Pricing

The Company currently derives its revenue principally from the sale of
natural gas. As a result, the Companys revenues are determined, to a large
degree, by prevailing natural gas prices. The Company currently sells the
majority of its natural gas on the open market at prevailing market prices, or
pursuant to market price contracts in the Rocky Mountain region, more
specifically in southwestern Wyoming. The market price for natural gas is
dictated by supply and demand at these sales points, and the Company cannot
accurately predict or control the price it receives for its natural gas.
Moreover, market prices for natural gas vary significantly by region. For
example, natural gas in the Rocky Mountain region, where the Company produces
most of its natural gas, historically sells for less than natural gas in the
Gulf Coast (Henry Hub), Mid Continent, Midwest and Northeast. Accordingly, the
Companys income and cash flows will be affected by changes in natural gas
prices and by regional pricing differentials. The Company will experience
reduced cash flows and may experience operating losses when natural gas prices
are low in the Rocky Mountain region. Under extreme circumstances, the
Companys natural gas sales may not generate sufficient revenue to meet the
Companys financial obligations and fund planned capital expenditures.
Moreover, significant price decreases could negatively affect the Companys
reserves by reducing the quantities of reserves that are recoverable on an
economic basis, necessitating write-downs to reflect the realizable value of
the reserves in the low price environment.

During the first half of 2003, the Company experienced significant pricing
differentials in southwestern Wyoming relative to the Henry Hub (Louisiana)
pricing reference point primarily due to production in the region exceeding
interstate pipeline capacity to deliver gas to the consuming west and east.
Without sufficient pipeline capacity to move the gas to markets, gas prices
were bid down at the inlet of the interstate pipelines. Because of this
large differential, the Company received prices significantly lower than those
received by companies with production in other regions of the U.S.

In May of 2003, Kern River Pipeline which serves markets in California,
Nevada and Utah expanded its system by over 900 MMcf/d or 100% to 1.73 Bcf/d.
Additionally, Northwest Pipeline, which serves the Pacific Northwest, expanded
its system by 175 MMcf/d in late 2003. These expansions moderated the price
differentials between southwestern Wyoming and the Henry Hub (Louisiana)
pricing reference point. However, there can be no assurance that the
expansions will eliminate large differentials in the future or that future
expansions will be made to accommodate the projected growth in production from
the region.

The Company expects to begin production from the first two fields (CFD
11-1/11-2) on Block 04/36 Bohai Bay, China in the fourth quarter of 2004. At
that time, the price of crude oil, in particular oil prices in East Asia, will
become important to the Companys revenues. As of February 27, 2004, the
Company was still negotiating a Memorandum of Understanding (MOU) relating to
the valuation of marketing of crude oil from the CFD 11-1/11-2 fields. It is
anticipated that the oil from the CFD 11-1/11-2 fields will be priced based on
(Indonesian) Duri crude postings with adjustments for quality and location.
The quality of crude blend from CFD 11-1/11-2 is currently not known with any
degree of certainty because of variations in crude quality from the multiple
productive reservoirs. The Company believes it will be successful in reaching
agreement on the MOU. The Company will review opportunities to utilize forward
sales and financial derivations, if any, to reduce the volatility of the prices
it will receive for its CFD 11-1/11-2 crude oil.

The Company uses forward sales and financial derivations to reduce the
volatility of the prices it receives for the sale of its natural gas
production. See Item 7A for more details.

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 and gas companies as well as numerous
independents, including many that have significantly greater resources.

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

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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.

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 85 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 drilling density 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 environmental impacts of developing the field on
40-acre well density rather than the 80-acre density that was approved in the
initial EIS in 1998. The EA was completed in June 2000. With the approval of
this subsequent EA, the Company was permitted to infill drill on 40-acre well
density the 2,160 gross (1,322 net) acres owned in the field. Prior to this
approval, the Company had drilled 21 gross (7.7 net) wells in the field. Since
the approval of 40-acre spacing, the Company drilled an additional 22 gross
(14.0 net) wells during 2000 and 2001. All 43 of the wells drilled by the
Company in Jonah Field have been productive. Other operators in the Jonah
Field have obtained approval for down-spacing portions of the Jonah Field to
20-acre and 10-acre spacing to test the feasibility of developing the field at
tighter spacing than the currently approved 40-acre spacing. The BLM is
currently conducting a new EIS covering the Jonah Field in anticipation of
down-spacing the entire field at some point in the near future. The Company
cannot predict when this EIS will be finalized.

During 2003 Ultra and other operators on the Pinedale Anticline received
approval from the Wyoming Oil & Gas Conservation Commission to drill increased
density pilots in several areas of the Pinedale Anticline Field to test the
feasibility of developing the field at higher well density than the currently
allowed 16 wells per section (40-acre spacing).

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.

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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 Acts, 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.

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 VIII of the Energy Policy Act of 1992
comprised of an indexing system to establish ceilings on interstate oil
pipeline rates. The FERC has announced several important
transportation-related policy statements and rule changes, including a
statement of policy and final rule issued February 25, 2000 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.

In the event the Company conducts operations on federal or state oil and
gas leases, such operations must comply with numerous regulatory restrictions,
including various nondiscrimination statutes and royalty and related valuation
requirements. In addition, certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the BLM or Minerals Management Service (MMS) or other appropriate
federal or state 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 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

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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 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 Substance. 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.

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.

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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 program for 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 Act 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.

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 27, 2004, the Company had 31 full time employees, including
officers.




Item 2. Description of Property.

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 65,528 gross
(36,494 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. 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, 2003, the Company owned developed oil and gas leases
totaling 7,290 gross (3,157 net) acres in the Green River Basin of Sublette
County, Wyoming which represents 91% of the Companys total domestic developed
gross acreage. The Company owned undeveloped oil and gas leases totaling
168,055 gross (94,833 net) acres in the Green River Basin of Sublette County,
Wyoming which represents 85% 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 $130,000
for the fiscal year ended December 31, 2003. The primary target on the
Companys Wyoming acreage is the tight gas sands of the upper Cretaceous Lance
formation.

8



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##### Table of Contents



Exploratory Wells. During the year-ended December 31, 2003, the Company
participated in the drilling of a total of 25 gross (10.18 net) exploratory
wells on the Green River Basin properties. Of these, only 1 gross (.32 net)
was a dry hole. This one well had to be junked and abandoned due to mechanical
problems. At year end there were 9 gross (4.66 net) additional exploratory
wells that were either still drilling or had drilling operations suspended for
winter.

Development Wells.The Company participated in the drilling of 24 gross
(6.88 net) successful development wells in the Pinedale Field area. At year
end there were 5 gross (1.95 net) additional development wells that were either
still drilling or had drilling operations suspended for winter. For purposes
of classification of development wells, the Company is using the definition of
wells identified as proven undeveloped locations by the 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 Production Sharing Contract (PSC) covering this block
became effective October 1, 1994. Negotiations with the Chinese government in
2003 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% working interest in this block which is 454,000 gross (82,546 net)
acres, 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 Chinese government in 2003 resulted in an extension of
the third exploration term to the end of February 2005. The third (and final)
exploration term will now continue through the end of February 2005 when,
barring an extension, all acreage not under appraisal, development or
production must be relinquished. The Company holds a 15% working 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 2003, utilizing 3-D seismic data,
the Company participated in drilling 4.0 gross (0.66 net) exploratory wells and
6.0 gross (1.03 net) appraisal wells on the Blocks. The exploratory drilling
resulted in 2 new discoveries on the Blocks. Four appraisal wells were
successful. The primary target formations on the Blocks are the Tertiary
Minghuazhen, Guantuao and Dongying formations.

Development Activity.An ODP for two of the fields on Block 04/36 (CFD
11-1/11-2) was approved by CNOOC in September 2002 and CNOOC has elected to
participate for its 51% working interest in the development of these fields.
The Chinese government gave its approval in June 2003. A MOU for marketing and
valuation of the CFD 11-1/11-2 crude oil, a Lifting Agreement for the CFD
11-1/11-2 oil fields and a Field Terminal Information and Regulation Agreement
are expected to be signed in March 2004 thus clearing the way for full
commerciality of the two fields. Construction started on the offshore
production platforms and a Floating Production Storage and Offloading (FPSO) vessel, which will be leased from CNOOC under
an operating lease for these fields. The platform jackets were installed
offshore in June 2003 and development well drilling started in the fourth
quarter 2003. The FPSO contract calls for the vessel to be on location ready to
receive oil in the third quarter of 2004 with oil production starting soon
thereafter.

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 an FPSO. The
Company ratified the contract for its net share which is 8.92%. The FPSO
contract specifies 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 14,741 gross (14,087 net) acres in Pennsylvania, which
represents 7% of the Companys total domestic undeveloped gross acreage.

9



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##### Table of Contents



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 9% of the Companys total developed gross
acreage. In 2003, the Company leased 15,121 gross (11,002 net) acres in Texas
which represents 8% of the Companys total domestic undeveloped gross acreage.

Oil and Gas Reserves

The following table sets forth the Companys quantities of proved
reserves, for the years-ended December 31, 2003, 2002 and 2001 as estimated by
independent petroleum engineers Netherland, Sewell & Associates, Inc. All of
the Companys proved oil and gas reserves are located in the Green River Basin,
Wyoming. The table summarizes the Companys 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, 2003,
2002 and 2001. 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, 2007. Proved
undeveloped reserves represent 64.9% of total proved reserves.

|                                                                           |                    |   |                |         |      |   |           |         |  |   |         |         | 
|-------------------------------------------------------------------------- | ------------------ | - | -------------- | ------- | ---- | - | --------- | ------- |  | - | ------- | ------- | 
|                                                                           |                    |   | December 31,  
|                                                                           |                    |   |               
|                                                                           |                    |   | (in thousands)
|                                                                           |                    |   | 2003           |         | 2002 |   | 2001     
|                                                                           |                    |   |                |         |      |   |          
|Proved Undeveloped Reserves                                                |                    |   |                |         |      |   |           |         |  |   |         |        
|                                                                           | Natural gas (MMcf) |   |                | 664,295 |      |   |           | 444,513 |  |   |         | 273,433 | 
|                                                                           | Oil (MBbl)         |   |                | 5,314   |      |   |           | 3,556   |  |   |         | 2,187   | 
|Proved Developed Reserves                                                  |                    |   |                |         |      |   |           |         |  |   |         |        
|                                                                           | Natural gas (MMcf) |   |                | 359,072 |      |   |           | 222,608 |  |   |         | 150,397 | 
|                                                                           | Oil (MBbl)         |   |                | 3,028   |      |   |           | 2,003   |  |   |         | 1,295   | 
|Total Proved Reserves (MMcfe)                                              |                    |   | 1,073,419      |         |      |   | 700,474   |         |  |   | 444,727 |        
|Estimated future net cash flows, before income tax                         |                    | $ | 4,456,478      |         |      | $ | 1,308,595 |         |  | $ | 531,676 |        
|Standardized measure of discounted future net cash flows                   |                    | $ | 1,784,314      |         |      | $ | 473,528   |         |  | $ | 182,460 |        
|Standardized measure of discounted future net cash flows,
after income tax |                    | $ | 1,135,513      |         |      | $ | 316,965   |         |  | $ | 119,259 |        

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,
|                         |  |                                |  |                        
|                         |  |                                |  | 2003                    |             | 2002 |  | 2001
|                         |  |                                |  |                         |             |      |  |     
|Production               |  |                                |  |                         |             |      |  |      |            |  |  |  
|                         |  | Natural gas (Mcf)              |  |                         | 27,621,759  |      |  |      | 16,495,751 |  |  |   | 11,500,446 | 
|                         |  | Oil (Bbl)                      |  |                         | 211,591     |      |  |      | 151,215    |  |  |   | 116,413    | 
|                         |  |                                |  |                         |             |      |  |      |            |  |  |  
|                         |  | Total (Mcfe)                   |  |                         | 28,891,305  |      |  |      | 17,403,041 |  |  |   | 12,198,924 | 
|Revenues                 |  |                                |  |                         |             |      |  |      |            |  |  |  
|                         |  | Gas sales                      |  | $                       | 114,840,558 |      |  | $    | 38,502,971 |  |  | $ | 38,204,298 | 
|                         |  | Oil sales                      |  |                         | 6,740,539   |      |  |      | 3,839,421  |  |  |   | 2,996,955  | 
|                         |  |                                |  |                         |             |      |  |      |            |  |  |  
|                         |  | Total Revenues                 |  |                         | 121,581,097 |      |  |      | 42,342,392 |  |  |   | 41,201,253 | 
|Lease Operating Expenses |  |                                |  |                         |             |      |  |      |            |  |  |  
|                         |  | Production costs*              |  |                         | 3,627,639   |      |  |      | 2,356,986  |  |  |   | 1,439,026  | 
|                         |  | Severance/production taxes     |  |                         | 13,767,668  |      |  |      | 4,116,012  |  |  |   | 4,425,345  | 
|                         |  | Gathering                      |  |                         | 7,828,372   |      |  |      | 4,937,870  |  |  |   | 3,158,901  | 
|                         |  |                                |  |                         |             |      |  |      |            |  |  |  
|                         |  | Total Lease Operating Expenses |  | $                       | 25,223,679  |      |  | $    | 11,410,868 |  |  | $ | 9,023,271  | 

10



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##### Table of Contents



|                         |  |                                |  |                         |       |      |  |      |       |  |  |   |       | 
|------------------------ |  | ------------------------------ |  | ----------------------- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|                         |  |                                |  | Year Ended December 31,
|                         |  |                                |  |                        
|                         |  |                                |  | 2003                    |       | 2002 |  | 2001
|                         |  |                                |  |                         |       |      |  |     
|Realized Prices          |  |                                |  |                         |       |      |  |      |       |  |  |  
|                         |  | Natural gas (Mcf)              |  | $                       | 4.16  |      |  | $    | 2.33  |  |  | $ | 3.32  | 
|                         |  | Oil (Bbl)                      |  | $                       | 31.86 |      |  | $    | 25.39 |  |  | $ | 25.74 | 
|Operating Costs per Mcfe |  |                                |  |                         |       |      |  |      |       |  |  |  
|                         |  | Production costs               |  | $                       | 0.13  |      |  | $    | 0.14  |  |  | $ | 0.12  | 
|                         |  | Severance/production taxes     |  | $                       | 0.48  |      |  | $    | 0.24  |  |  | $ | 0.36  | 
|                         |  | Gathering                      |  | $                       | 0.27  |      |  | $    | 0.28  |  |  | $ | 0.26  | 
|                         |  |                                |  |                         |       |      |  |      |       |  |  |  
|                         |  | Total Operating Costs per Mcfe |  | $                       | 0.88  |      |  | $    | 0.66  |  |  | $ | 0.74  | 



---

|* |  | Average production costs include lifting costs and remedial workover
expenses.
|- |  | ------------------------------------------------------------------------------

Productive Wells

As of December 31, 2003, the Companys total gross and net wells were as
follows:

|                           |  |             |     |           |  |  |       | 
|-------------------------- |  | ----------- | --- | --------- |  |  | ----- | 
|Productive Wells*          |  | Gross Wells |     | Net Wells
|                           |  |             |     |          
|Natural Gas and Condensate |  |             | 159 |           |  |  | 69.58 | 



---

|* |  | 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.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Oil and Gas Acreage

As of December 31, 2003, 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 Acres
|             |  |                 |       |                  
|             |  | Gross           |       | Net               |  | Gross |       | Net
|             |  |                 |       |                   |  |       |       |    
|Wyoming      |  |                 | 7,290 |                   |  |       | 3,157 |     |  |  | 168,055 |  |  |  | 94,833  | 
|Pennsylvania |  |                 |      |                   |  |       |      |     |  |  | 14,741  |  |  |  | 14,087  | 
|Texas        |  |                 | 720   |                   |  |       | 382   |     |  |  | 15,121  |  |  |  | 11,002  | 
|             |  |                 |       |                   |  |       |       |     |  |  |         |  |  |  |         | 
|All States   |  |                 | 8,010 |                   |  |       | 3,539 |     |  |  | 197,917 |  |  |  | 119,922 | 

As of December 31, 2003, 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 Acres
|                    |  |                 |   |                  
|                    |  | Gross           |   | Net               |  | Gross |   | Net
|                    |  |                 |   |                   |  |       |   |    
|Block 04/36         |  |                 | 0 |                   |  |       | 0 |     |  |  | 454,000 |  |  |  | 82,546  | 
|Block 05/36         |  |                 | 0 |                   |  |       | 0 |     |  |  | 233,300 |  |  |  | 34,995  | 
|                    |  |                 |   |                   |  |       |   |     |  |  |         |  |  |  |         | 
|Total Bohai Acreage |  |                 | 0 |                   |  |       | 0 |     |  |  | 687,300 |  |  |  | 117,541 | 

11



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##### Table of Contents



Drilling Activities

For each of the three fiscal years ended December 31, 2003, 2002 and 2001,
the number of gross and net wells drilled by the Company was as follows:

Wyoming  Green River Basin

|                  |            |  |       |       |      |  |       |      |     |  |       |       |     |  |      |      |  |  |      |      |  |  |      |      | 
|----------------- | ---------- |  | ----- | ----- | ---- |  | ----- | ---- | --- |  | ----- | ----- | --- |  | ---- | ---- |  |  | ---- | ---- |  |  | ---- | ---- | 
|                  |            |  | 2003  |       | 2002 |  | 2001 
|                  |            |  |       |       |      |  |      
|                  |            |  | Gross |       | Net  |  | Gross |      | Net |  | Gross |       | Net
|                  |            |  |       |       |      |  |       |      |     |  |       |       |    
|Development Wells |            |  |       |       |      |  |       |      |     |  |       |       |     |  |      |      |  |  |      |      |  |  |      |     
|                  | Productive |  |       | 24.00 |      |  |       | 6.88 |     |  |       | 16.00 |     |  |      | 5.50 |  |  |      | 9.00 |  |  |      | 5.52 | 
|                  | Dry        |  |       | 0.00  |      |  |       | 0.00 |     |  |       | 0.00  |     |  |      | 0.00 |  |  |      | 0.00 |  |  |      | 0.00 | 
|                  |            |  |       |       |      |  |       |      |     |  |       |       |     |  |      |      |  |  |      |      |  |  |      |     
|Total             |            |  | 24.00 |       |      |  | 6.88  |      |     |  | 16.00 |       |     |  | 5.50 |      |  |  | 9.00 |      |  |  | 5.52 |     

At year end there were 5 gross (1.95 net) additional development wells that were either drilling or had
drilling operations suspended over the winter.

|                  |            |  |       |       |      |  |       |      |     |  |       |       |     |  |      |      |  |  |       |       |  |  |      |      | 
|----------------- | ---------- |  | ----- | ----- | ---- |  | ----- | ---- | --- |  | ----- | ----- | --- |  | ---- | ---- |  |  | ----- | ----- |  |  | ---- | ---- | 
|                  |            |  | 2003  |       | 2002 |  | 2001 
|                  |            |  |       |       |      |  |      
|                  |            |  | Gross |       | Net  |  | Gross |      | Net |  | Gross |       | Net
|                  |            |  |       |       |      |  |       |      |     |  |       |       |    
|Exploratory Wells |            |  |       |       |      |  |       |      |     |  |       |       |     |  |      |      |  |  |       |       |  |  |      |     
|                  | Productive |  |       | 24.00 |      |  |       | 9.86 |     |  |       | 10.00 |     |  |      | 5.22 |  |  |       | 22.00 |  |  |      | 8.67 | 
|                  | Dry        |  |       | 1.00  |      |  |       | 0.32 |     |  |       | 0.00  |     |  |      | 0.00 |  |  |       | 1.00  |  |  |      | 0.42 | 
|                  |            |  |       |       |      |  |       |      |     |  |       |       |     |  |      |      |  |  |       |       |  |  |      |     
|Total             |            |  | 25.00 |       |      |  | 10.18 |      |     |  | 10.00 |       |     |  | 5.22 |      |  |  | 23.00 |       |  |  | 9.09 |     

At year end there were 9 gross (4.66 net) additional exploratory wells
that were either drilling or had drilling operations suspended over the winter.

Texas

|                  |            |  |       |      |      |  |       |      |     |  |       |      |     |  |      |      |  |  |      |      |  |  |      |      | 
|----------------- | ---------- |  | ----- | ---- | ---- |  | ----- | ---- | --- |  | ----- | ---- | --- |  | ---- | ---- |  |  | ---- | ---- |  |  | ---- | ---- | 
|                  |            |  | 2003  |      | 2002 |  | 2001 
|                  |            |  |       |      |      |  |      
|                  |            |  | Gross |      | Net  |  | Gross |      | Net |  | Gross |      | Net
|                  |            |  |       |      |      |  |       |      |     |  |       |      |    
|Exploratory Wells |            |  |       |      |      |  |       |      |     |  |       |      |     |  |      |      |  |  |      |      |  |  |      |     
|                  | Productive |  |       | 0.00 |      |  |       | 0.00 |     |  |       | 0.00 |     |  |      | 0.00 |  |  |      | 0.00 |  |  |      | 0.00 | 
|                  | Dry        |  |       | 0.00 |      |  |       | 0.00 |     |  |       | 1.00 |     |  |      | 0.15 |  |  |      | 0.00 |  |  |      | 0.00 | 
|                  |            |  |       |      |      |  |       |      |     |  |       |      |     |  |      |      |  |  |      |      |  |  |      |     
|Total             |            |  | 0.00  |      |      |  | 0.00  |      |     |  | 1.00  |      |     |  | 0.15 |      |  |  | 0.00 |      |  |  | 0.00 |     

China  Bohai Bay

|                  |                                      |  |       |      |      |  |       |      |     |  |       |      |     |  |      |      |  |  |       |       |  |  |      |      | 
|----------------- | ------------------------------------ |  | ----- | ---- | ---- |  | ----- | ---- | --- |  | ----- | ---- | --- |  | ---- | ---- |  |  | ----- | ----- |  |  | ---- | ---- | 
|                  |                                      |  | 2003  |      | 2002 |  | 2001 
|                  |                                      |  |       |      |      |  |      
|                  |                                      |  | Gross |      | Net  |  | Gross |      | Net |  | Gross |      | Net
|                  |                                      |  |       |      |      |  |       |      |     |  |       |      |    
|Exploratory Wells |                                      |  |       |      |      |  |       |      |     |  |       |      |     |  |      |      |  |  |       |       |  |  |      |     
|                  | Productive and
Successful Appraisal* |  |       | 6.00 |      |  |       | 1.03 |     |  |       | 4.00 |     |  |      | 0.70 |  |  |       | 14.00 |  |  |      | 2.35 | 
|                  | Dry                                  |  |       | 4.00 |      |  |       | 0.66 |     |  |       | 1.00 |     |  |      | 0.18 |  |  |       | 1.00  |  |  |      | 0.18 | 
|                  |                                      |  |       |      |      |  |       |      |     |  |       |      |     |  |      |      |  |  |       |       |  |  |      |     
|Total             |                                      |  | 10.00 |      |      |  | 1.69  |      |     |  | 5.00  |      |     |  | 0.88 |      |  |  | 15.00 |       |  |  | 2.53 |     



---

|* |  | 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, 2003.

12



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##### Table of Contents






PART II




Item 5. Market for Registrants Common Stock and Related Stockholder Matters.

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 the Toronto Stock Exchange (TSE) since September 30, 1998 under the
symbol UP. The following table sets forth the high and low closing sales
prices on the AMEX and TSE for 2003, 2002 and 2001 as reported by each
exchange, respectively.

AMERICAN STOCK EXCHANGE (US$)
    
    TORONTO STOCK EXCHANGE (CDN$)2003
    
    
    High
    
    
    
    Low
    
    
    2003
    
    
    High
    
    
    
    LowFirst Quarter
    
    $
    10.24
    
    
    $
    8.60
    
    
    First Quarter
    
    $
    15.66
    
    
    $
    12.61Second Quarter
    
    $
    12.91
    
    
    $
    8.45
    
    
    Second Quarter
    
    $
    17.41
    
    
    $
    12.42Third Quarter
    
    $
    14.80
    
    
    $
    11.50
    
    
    Third Quarter
    
    $
    20.18
    
    
    $
    15.90Fourth Quarter
    
    $
    25.45
    
    
    $
    14.05
    
    
    Fourth Quarter
    
    $
    33.36
    
    
    $
    18.942002
    
    
    High
    
    
    
    Low
    
    
    2002
    
    
    High
    
    
    
    LowFirst Quarter
    
    $
    8.17
    
    
    $
    5.71
    
    
    First Quarter
    
    $
    13.10
    
    
    $
    9.25Second Quarter
    
    $
    9.22
    
    
    $
    7.50
    
    
    Second Quarter
    
    $
    14.50
    
    
    $
    11.34Third Quarter
    
    $
    8.59
    
    
    $
    5.94
    
    
    Third Quarter
    
    $
    13.51
    
    
    $
    9.35Fourth Quarter
    
    $
    9.99
    
    
    $
    7.90
    
    
    Fourth Quarter
    
    $
    15.62
    
    
    $
    12.472001
    
    
    High
    
    
    
    Low
    
    
    2001
    
    
    High
    
    
    
    LowFirst Quarter (beginning 1/17/01)
    
    $
    5.50
    
    
    $
    3.00
    
    
    First Quarter
    
    $
    8.70
    
    
    $
    3.90Second Quarter
    
    $
    7.34
    
    
    $
    4.34
    
    
    Second Quarter
    
    $
    10.95
    
    
    $
    6.76Third Quarter
    
    $
    5.92
    
    
    $
    3.54
    
    
    Third Quarter
    
    $
    9.00
    
    
    $
    5.65Fourth Quarter
    
    $
    6.41
    
    
    $
    4.00
    
    
    Fourth Quarter
    
    $
    10.05
    
    
    $
    6.30


On February 27, 2004, the last reported sale price of the common stock on
the AMEX was $29.16 per share. As of February 27, 2004 there were
approximately 457 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, 2003, 2002, 2001, 2000, the six months ended December
31, 1999 and the year ended June 30, 1999 is derived from the Consolidated
Financial Statements of the Company. Effective with the period ended December
31, 1999, the Company began utilizing a December 31 year-end.

|                             |           |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |      |        |        |  |   |       |            |  |      |       |       |  | 
|---------------------------- | --------- | ------------------ | -------------- | - | ------- | ------------------------------------- |  | -------- | ------ | ------ |  | ---- | ------ | ------ |  | ---- | ------ | ------ |  | - | ----- | ---------- |  | ---- | ----- | ----- |  | 
|                             |           |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |      |        |        |  |   |       | Six Months |  | Year
|                             |           |                    |                |   |         | Year Ended December 31,               |  | Ended    |        | Ended 
|                             |           |                    |                |   |         |                                       |  | December |        | June  
|                             |           |                    |                |   |         | 2003                                  |  | 2002     |        | 2001   |  | 2000 |        | 1999   |  | 1999
|                             |           |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |     
|                             |           |                    |                |   |         | (in thousands, except per share data)
|Statement of Operations Data |           |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |      |        |        |  |   |       |            |  |     
|                             | Revenues: |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |      |        |        |  |   |       |            |  |      |      
|                             |           | Natural gas sales  |                | $ | 114,841 |                                       |  | $        | 38,503 |        |  | $    | 38,204 |        |  | $    | 19,399 |        |  | $ | 4,352 |            |  | $    | 6,352 |      
|                             |           | Oil sales          |                |   | 6,740   |                                       |  |          | 3,839  |        |  |      | 2,997  |        |  |      | 1,604  |        |  |   | 434   |            |  |      | 670   |      
|                             |           | Interest and other |                |   | 37      |                                       |  |          | 23     |        |  |      | 393    |        |  |      | 171    |        |  |   | 18    |            |  |      | 287   |      
|                             |           |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |      |        |        |  |   |       |            |  |     
|                             |           |                    | Total revenues |   |         | 121,618                               |  |          |        | 42,365 |  |      |        | 41,594 |  |      |        | 21,174 |  |   |       | 4,804      |  |      |       | 7,309 | 
|                             |           |                    |                |   |         |                                       |  |          |        |        |  |      |        |        |  |      |        |        |  |   |       |            |  |     

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| |           |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |      |       |  |        |   |        |            |       |      |        |   |        | 
| | --------- | ----------------------------------------------------- |  | -------------- | ------ | ------------------------------------- | ------ | -------- | ------ | ----- | ------ | ---- | ------ | ---- | ------ | ---- | ----- |  | ------ | - | ------ | ---------- | ----- | ---- | ------ | - | ------ | 
| |           |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |      |       |  |        |   |        | Six Months |       | Year
| |           |                                                       |  |                |        | Year Ended December 31,               |        | Ended    |        | Ended
| |           |                                                       |  |                |        |                                       |        | December |        | June 
| |           |                                                       |  |                |        | 2003                                  |        | 2002     |        | 2001  |        | 2000 |        | 1999 |        | 1999
| |           |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |     
| |           |                                                       |  |                |        | (in thousands, except per share data)
| | Expenses: |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |      |       |  |        |   |        |            |       |      |       
| |           | Production expenses and taxes                         |  |                | 25,224 |                                       |        |          | 11,411 |       |        |      | 9,023  |      |        |      | 4,241 |  |        |   | 1,329  |            |       |      | 2,571  |  
| |           | Depreciation, depletion and amortization              |  |                | 16,216 |                                       |        |          | 9,712  |       |        |      | 6,687  |      |        |      | 3,163 |  |        |   | 1,186  |            |       |      | 1,794  |  
| |           | General and administrative                            |  |                | 5,733  |                                       |        |          | 4,199  |       |        |      | 3,894  |      |        |      | 2,828 |  |        |   | 1,668  |            |       |      | 5,861  |  
| |           | Stock compensation                                    |  |                | 1,018  |                                       |        |          | 1,211  |       |        |      | 337    |      |        |      | 250   |  |        |   |       |            |       |      |       |  
| |           | Interest                                              |  |                | 2,851  |                                       |        |          | 2,691  |       |        |      | 1,687  |      |        |      | 802   |  |        |   | 344    |            |       |      | 577    |  
| |           | Ceiling test write-down                               |  |                |       |                                       |        |          |       |       |        |      |       |      |        |      |      |  |        |   |       |            |       |      | 3,417  |  
| |           | Bad debt expense (recovery)                           |  |                |       |                                       |        |          |       |       |        |      |       |      |        |      |      |  |        |   | (35    | )          |       |      | 2,019  |  
| |           | Lawsuit settlement                                    |  |                |       |                                       |        |          |       |       |        |      |       |      |        |      |      |  |        |   | 1,876  |            |       |      |       |  
| |           |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |      |       |  |        |   |        |            |       |     
| |           |                                                       |  | Total expenses |        |                                       | 51,042 |          |        |       | 29,224 |      |        |      | 21,628 |      |       |  | 11,284 |   |        |            | 6,368 |      |        |   | 16,239 | 
| |           | Income from continuing operations before
income taxes |  |                | 70,576 |                                       |        |          | 13,141 |       |        |      | 19,966 |      |        |      | 9,890 |  |        |   | (1,564 | )          |       |      | (8,930 | )
| |           | Income tax provision  deferred                       |  |                | 25,254 |                                       |        |          | 5,059  |       |        |      | 2,087  |      |        |      |      |  |        |   |       |            |       |      |       |  
| |           |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |      |       |  |        |   |        |            |       |     
| |           | Net income                                            |  | $              | 45,323 |                                       |        | $        | 8,082  |       |        | $    | 17,879 |      |        | $    | 9,890 |  |        | $ | (1,564 | )          |       | $    | (8,930 | )
| |           |                                                       |  |                |        |                                       |        |          |        |       |        |      |        |      |        |      |       |  |        |   |        |            |       |     
| |           | Basic income per common share                         |  | $              | 0.61   |                                       |        | $        | 0.11   |       |        | $    | 0.25   |      |        | $    | 0.17  |  |        | $ | (0.03  | )          |       | $    | (0.16  | )
| |           | Diluted income per common share                       |  | $              | 0.58   |                                       |        | $        | 0.10   |       |        | $    | 0.24   |      |        | $    | 0.17  |  |        | $ | (0.03  | )          |       | $    | (0.16  | )

|                             |                                 |                      |  |                         |         |          |  |       |         |      |  |                |         |      |  |   |         |   |  |            |        |      |  |   |        |  
|---------------------------- | ------------------------------- | -------------------- |  | ----------------------- | ------- | -------- |  | ----- | ------- | ---- |  | -------------- | ------- | ---- |  | - | ------- | - |  | ---------- | ------ | ---- |  | - | ------ | -
|                             |                                 |                      |  |                         |         |          |  |       |         |      |  |                |         |      |  |   |         |   |  | Six Months |        | Year
|                             |                                 |                      |  | Year Ended December 31, |         | Ended    |  | Ended
|                             |                                 |                      |  |                         |         | December |  | June 
|                             |                                 |                      |  | 2003                    |         | 2002     |  | 2001  |         | 2000 |  | 1999           |         | 1999
|                             |                                 |                      |  |                         |         |          |  |       |         |      |  |                |         |     
|                             |                                 |                      |  |                         |         |          |  |       |         |      |  | (in thousands) |         |      |  |   |         |   |  |           
|Statement of Cash Flows Data |                                 |                      |  |                         |         |          |  |       |         |      |  |                |         |      |  |   |         |   |  |            |        |      |  |  
|                             | Net cash provided by (used in): |                      |  |                         |         |          |  |       |         |      |  |                |         |      |  |   |         |   |  |            |        |      |  |   |       
|                             |                                 | Operating activities |  | $                       | 76,461  |          |  | $     | 21,490  |      |  | $              | 34,136  |      |  | $ | 9,046   |   |  | $          | 674    |      |  | $ | 1,913  |  
|                             |                                 | Investing activities |  |                         | (90,033 | )        |  |       | (64,360 | )    |  |                | (59,862 | )    |  |   | (24,541 | ) |  |            | (1,624 | )    |  |   | (1,017 | )
|                             |                                 | Financing activities |  |                         | 13,988  |          |  |       | 42,908  |      |  |                | 25,961  |      |  |   | 16,236  |   |  |            | 569    |      |  |   | (6,010 | )

|                   |                            |  |                    |         |      |  |      |         |      |  |      |         |   |  |   |        |  |  |   |        | 
|------------------ | -------------------------- |  | ------------------ | ------- | ---- |  | ---- | ------- | ---- |  | ---- | ------- | - |  | - | ------ |  |  | - | ------ | 
|                   |                            |  | As of December 31,
|                   |                            |  |                   
|                   |                            |  | 2003               |         | 2002 |  | 2001 |         | 2000 |  | 1999
|                   |                            |  |                    |         |      |  |      |         |      |  |     
|Balance Sheet Data |                            |  |                    |         |      |  |      |         |      |  |      |         |   |  |   |        |  |  |   |       
|                   | Cash and cash equivalents  |  | $                  | 1,834   |      |  | $    | 1,418   |      |  | $    | 1,379   |   |  | $ | 1,144  |  |  | $ | 402    | 
|                   | Working capital (deficit)  |  |                    | (22,057 | )    |  |      | (4,415  | )    |  |      | (6,635  | ) |  |   | 241    |  |  |   | 195    | 
|                   | Oil and gas properties     |  |                    | 307,864 |      |  |      | 207,362 |      |  |      | 155,221 |   |  |   | 59,729 |  |  |   | 33,773 | 
|                   | Total assets               |  |                    | 345,770 |      |  |      | 221,874 |      |  |      | 167,583 |   |  |   | 73,177 |  |  |   | 38,063 | 
|                   | Total long-term debt       |  |                    | 104,120 |      |  |      | 89,859  |      |  |      | 48,885  |   |  |   | 24,731 |  |  |   | 8,767  | 
|                   | Deferred income taxes      |  |                    | 33,446  |      |  |      | 10,033  |      |  |      | 4,974   |   |  |   |       |  |  |   |       | 
|                   | Total stockholders equity |  |                    | 149,453 |      |  |      | 104,067 |      |  |      | 95,320  |   |  |   | 35,694 |  |  |   | 25,632 | 

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.

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.

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

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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. Decreases in prices, for example, may cause a
reduction in some proved reserves due to the production of such resources
becoming uneconomic.

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. Capitalized costs applicable to each full cost center are depleted
using the units of production method based on conversion to a common unit of
measure using one barrel of oil as an equivalent to six thousand cubic feet of
natural gas. A reserve is also provided for estimated future development costs
related to proved reserves and for estimated future costs of site restoration,
dismantlement and abandonment as a component of depletion expense. 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.

Oil and gas properties include costs that are excluded from capitalized
costs being amortized. These amounts represent costs of investments in unproved
properties, pending the determination of the existence of proved reserves. 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 quarterly to determine if impairment has occurred.
Any impairment is transferred to the costs to be amortized. Costs excluded for
oil and gas properties are generally classified and evaluated as significant or
individually insignificant properties.

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.

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. This
ceiling is compared to the net book value of the oil and gas properties 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 write down 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 following is a
summary of major issues related to the Companys ceiling test calculation.

The Company did not have any writedowns related to the full cost ceiling
limitation in 2003, 2002 or 2001. As of December 31, 2003, the ceiling
limitation exceeded the carrying value of the Companys oil and gas properties
by approximately $900 million in the U.S. The Companys China properties have
not yet been subject to a ceiling test, as there have not been any proved
reserves identified to date. Estimates of discounted future net cash flows at
December 31, 2003 were based on average natural gas prices of approximately
$5.59 per MCF in the U.S. and on average liquids prices of approximately $31.01
per barrel in the U.S. A reduction in oil

15



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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.

In China, the existence of proved reserves has not yet been confirmed,
therefore, leasehold costs, seismic costs and other costs incurred during the
exploration phase remain capitalized as unproved property costs until proved
reserves have been established or until exploration activities cease. If
exploration activities result in the establishment of proved reserves as the
Company expects, amounts are reclassified as proved properties and become
subject to depreciation, depletion and amortization and the application of the
ceiling test. If exploration and appraisal efforts are unsuccessful in
establishing proved reserves and exploration activities cease, the amounts
accumulated as unproved costs are charged against earnings as impairments. As
of December 31, 2003, costs related to these international projects of
approximately $81.0 million were not being depleted pending confirmation of the
existence of proved reserves.

Changes in estimates of reserves, future development costs or future
abandonment costs are accounted for prospectively in the depletion
calculations.

Entitlements Method of Accounting for Oil and Gas Sales. 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. At December 31, 2003, the Company had taken
approximately 264 MMcf more than its entitled share of production. The
estimated value of this imbalance of approximately $1.3 million was recorded as
a long-term liability under the Notes Payable category on the Balance Sheet.

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). Future income tax assets and liabilities are measured
using the tax rates expected to be in effect when the temporary differences are
likely to reverse. The effect on future income tax assets and liabilities of a
change in tax rates is included in operations in the period in which the change
is enacted. The amount of future income tax assets recognized is limited to the
amount of the benefit that is more likely than not to be realized.

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, 2003, the Company
will need to generate future taxable income prior to the expiration of the net
operating loss carryforwards in 2004 to 2023. 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
deductible differences, net of the existing valuation allowances at December
31, 2003. 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.

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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 a cash flow hedge.

Legal, Environmental and Other Contingencies.A provision for legal,
environmental and other contingencies is charged to expense when the loss is
probably 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.




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 its revenue, earnings and cash 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 2001-2003 have ranged from $2.33 to $4.16 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
derivative and forward sales contracts for gas in southwest Wyoming (see Item
7A). The Company also has oil properties offshore Bohai Bay, China which are
expected to begin production in late 2004. At that time, the price of oil in
east Asia would become critical to the Company.

The Company has grown its natural gas and oil production significantly
over the past three 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
oilfields in China. The Company has experienced significant production growth
over the last three years and expects this growth to continue in 2004:

|                  |  |      |      |      |  |      |      |      |  |  |      |  |  |          |      | 
|----------------- |  | ---- | ---- | ---- |  | ---- | ---- | ---- |  |  | ---- |  |  | -------- | ---- | 
|                  |  |      |      |      |  |      |      |      |  |  |      |  |  | Forecast
|                  |  | 2001 |      | 2002 |  | 2003 |      | 2004
|                  |  |      |      |      |  |      |      |     
|Production  Bcfe |  |      | 12.2 |      |  |      | 17.4 |      |  |  | 28.9 |  |  |          | 40.0 | 

The anticipated 2004 production growth of 40 Bcfe is expected to be achieved by
drilling wells in Wyoming. The Company also expects to maintain its cost
structure in Wyoming on a unit of production basis during 2004 as follows:

17



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##### Table of Contents



Cost Item
    
    $/McfeLease Operating Expense
    
    $
    0.15Gathering Expense
    
    $
    0.30DD&A
    
    $
    0.57
 The Company will provide further guidance on expected production and costs
related to the China project at such time as production and costs become more
certain. The Company uses the full cost method of accounting for oil and gas
operations whereby all costs associated with the exploration for and
development of oil and gas reserves are capitalized to the Companys cost
centers. Such costs include land acquisition costs, geological and geophysical
expenses, carrying charges on non-producing properties, costs of drilling both
productive and non-productive wells and overhead charges directly related to
acquisition, exploration and development activities. 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. 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. On a unit of production basis, costs were $0.13 per Mcfe in 2003, as
compared to $0.14 per Mcfe in 2002 primarily due to increased production.
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
borrowing 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 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. Results
of Operations  Year Ended December 31, 2002 Compared to Year Ended
December 31, 2001 Oil and gas revenues increased to $42.3 million for the year ended
December 31, 2002 from $41.2 million for the same period in 2001. This increase
was attributable to an increase in the Companys production
offsetting a decline in the price received for that production. During
this period the Companys production increased to 16.5 Bcf of gas and 151.2
thousand barrels of condensate, up from 11.5 Bcf of gas and 116.4 18




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##### Table of Contents



thousand barrels of condensate for the same period in 2001. This 43% increase on a Mcfe
basis was attributable to the Companys successful drilling activities during
2001 and 2002. During the year ended December 31, 2002, the average product
prices were $2.33 per Mcf and $25.39 per barrel, compared to $3.32 per Mcf and
$25.74 per barrel for the same period in 2001. Production costs increased to $2.4 million in 2002 from $1.4 million in
2001. On a unit of production basis, costs were $0.135 per Mcfe in 2002, as
compared to $0.118 per Mcfe in 2001. Production taxes in 2002 were $4.1
million, compared to $4.4 million in 2001, or $0.237 per Mcfe in 2002, compared
to $0.363 per Mcfe in 2001. Production taxes are calculated based on a
percentage of revenue from production. Therefore, lower prices received
reduced the cost on a per unit basis. Gathering fees for the period increased
to $4.9 million in 2002 from $3.2 million in 2001, attributable to higher
production volumes and slightly higher gathering rates related to capacity
constraints. Depletion, depreciation and amortization (DD&A) expenses increased to
$9.7 million during the year ended December 31, 2002 from $6.7 million for the
same period in 2001. On a unit basis, DD&A increased slightly to $0.558 per
Mcfe in 2002, from $0.548 per Mcfe in 2001 primarily as a result of increases
in future development costs relative to increases in the proved reserves used
to calculate depletion of the full cost pool. General and administrative expenses increased to $4.2 million during the
year ended December 31, 2002 from $3.9 million for the same period in 2001. The
increase was primarily attributable to increases in personnel and overhead
expenses arising from the increases in activity on the Wyoming properties. Stock compensation expense increased to $1.2 million in 2002 from $0.3
million in 2001. This increase is attributable to the increased number of
shares granted and the share price at the time the stock was granted. Interest expense for the period increased to $2.7 million in 2002 from
$1.7 million in 2001. This increase was attributable to the increase in
borrowing under the senior credit facility. Deferred income tax expense for the period increased to $5.1 million in
2002 from $2.1 million in 2001. This increase was attributable to an increase
in the effective tax rate due to the absence of book tax losses available to
offset book taxable income as compared to 2001. The Company was not liable for
current payment of any material income taxes for the period ending December 31,
2002. Liquidity and Capital Resources In the year ended December 31, 2003, the Company primarily relied on its
cash provided by operations of $76.4 million and borrowings under its existing
senior credit facility of ($13 million net) to finance its capital
expenditures. The Company participated in the drilling of 63 gross (23.99 net)
wells in Wyoming of which 48 gross (17.06 net) were successfully drilled and
completed, one gross (0.32 net) was abandoned due to hole condition and 14
gross (6.61 net) were either still drilling at year-end or had been suspended
due to lease stipulations that prohibit winter drilling. The Company
participated in 10 gross (1.69 net) wells in the China blocks. For the twelve-month period ending December 31, 2003, net capital
expenditures were $115.8 million, of which $26.5 million was accrued at year
end for a net cash expenditure of $90 million. At December 31, 2003, the
Company reported a cash position of $1.8 million compared to $1.4 million at
December 31, 2002. Working capital at December 31, 2003 was $(22.0) million as
compared to $(4.4) million at December 31, 2002. As of December 31, 2003, the
Company had incurred bank indebtedness of $99.0 million and other long-term
debt of $7.1 million which was comprised of items payable in more than one
year. 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 2004, which are currently projected
to be $190.0 million. Of the $190.0 million budget, the Company plans to spend
approximately $162.0 million of its 2004 budget in Wyoming and approximately
$25.0 million in China, with the balance allocated to evaluating other areas.
With the $162.0 million for Wyoming, the Company plans to drill or participate
in an estimated 80 gross wells in 2004, of which approximately 35% will be for
exploration wells and the remaining will be for development wells. Of the $25.0
million budgeted for China, approximately 30% will be for
exploratory/appraisal activity and the balance will be for development
activity. The Company does not have a budget for acquisitions. 19




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##### Table of Contents



As of December 12, 2003, the revolving senior credit facility provides for
a $250.0 million revolving credit line with a current borrowing base of $200.0
million. The credit facility matures on March 1, 2006. The notes bear
interest at either Bank Ones prime rate plus a margin of one-half of one
percent (0.50%) to one and one-quarter percent (1.25%) based on the percentage
of available credit drawn or at LIBOR plus a margin of one and one-half percent
(1.50%) to two and one-quarter percent (2.25%) based on the percentage of
available credit drawn. An average annual commitment fee of 0.375% is charged
quarterly for any unused portion of the credit line. The borrowing base is
subject to periodic (at least semi-annual) review and re-determination by the
banks and may be increased or decreased depending on a number of factors,
including the Companys proved reserves and the banks forecast of future oil
and gas prices. 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, the Companys subsidiary that owns the
Chinese interests. In the event of a default under the covenants, the Company
may not be able to access funds otherwise available under the facility and may,
in certain circumstances, be required to repay the credit facilities. The notes
are collateralized by a majority of the Companys proved domestic oil and gas
properties. At December 31, 2003 the Company had $99.0 million of outstanding
borrowings under this credit facility, with a current average interest rate of
approximately 2.8%.Kristen to confirm The Company was in compliance with all
loan covenants at December 31, 2003. During the year ended December 31, 2003, net cash provided by operating
activities was $76.5 million as compared to $21.5 million for the year ended
December 31, 2002 and $34.1 million for the year ended December 31, 2001. The
increase in cash provided by operating activities was attributable to the
increase in earnings, which were driven primarily by higher production and gas
prices received. During the year ended December 31, 2003, cash used in investing activities
was $90.0 million as compared to $64.4 million for the year ended December 31,
2002 and $59.9 million for the year ended December 31, 2001. The change is
primarily attributable to increased drilling and completion activity in
Wyoming. During the year ended December 31, 2003, cash provided by financing
activities was $14.0 million as compared to $42.9 million for the year ended
December 31, 2002 and $26.0 million for the year ended December 31, 2001. The
change is primarily attributable to a reduced level of borrowings under the
senior credit facility ($13.0 million in 2003 as compared to $43.0 million
during 2002 and $25.4 million during 2001). Although the Company projects that the cash provided by operating
activities and the availability under the senior credit facility will be
sufficient to fund the Companys budgeted capital expenditures for 2004, future
cash provided by operating activities and continued availability of financing
are subject to a number of uncertainties beyond the Companys control such as
the price of gas and oil, production rates, continued results of the Companys
drilling program and the general condition of the capital and credit markets
for oil and gas companies. There can be no assurances that adequate funding
will be available to execute the Companys planned future capital program. Contractual Obligations The following table summarizes our contractual obligations as of December
31, 2003: After2003
    
    2004-2005
    
    2006-2007
    
    2007
    
    TotalCapital expenditures for
operations in progress
    
    $
    
    
    
    $
    12,384,391
    
    
    $
    
    
    
    $
    
    
    
    $
    12,384,391Long-term debt
    
    
    
    
    
    
    
    
    
    
    99,000,000
    
    
    
    
    
    
    
    99,000,000Operating leases
    
    
    291,015
    
    
    
    198,030
    
    
    
    132,020
    
    
    
    
    
    
    
    621,065Office space lease
    
    
    73,458
    
    
    
    497,519
    
    
    
    455,084
    
    
    
    73,458
    
    
    
    1,099,519Total contractual obligations
    
    $
    364,473
    
    
    $
    13,079,940
    
    
    $
    99,587,104
    
    
    $
    73,458
    
    
    $
    113,104,975
 As of December 31, 2003 the Company had committed to drilling obligations
in progress that will continue into 2004. The Companys senior credit facility with its group of banks matures on
March 1, 2006. Unless the facility is extended or a new facility put into
place, the full amount drawn under the facility would become due and 20




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##### Table of Contents



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 March
1, 2006. On October 16, 2003 a 15 year contract, which provides for up to an
additional 10 years, was signed by the Operator to lease an 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. Lease
cancellation on the part of the Company prior to the FPSO starting offshore
operations would commit the Company to its 8.92% share of up to $50 million in
cancellation fees. The lease cancellation fee, after commencement of offshore
operations, would be based on a sliding time-scale (cancellation fee decreases
with time) with 8.92% of $50 million being the maximum cancellation fee. 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. In May of 2003 the Company amended its prior office lease in Englewood,
Colorado, which it has committed to through June 2008. The Companys total
commitment of this lease is $734,578. 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 commitment of $364,941. The total commitment for both
offices is $1,099,519. 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 2003, total holding costs for all of the
Companys leases not held by production were $190,000. 
 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 primarily driven 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 $3.35 per Mcf to a monthly high of
$4.94 per Mcf during 2003. Realized natural gas prices are derived from the
financial statements, 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 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, 2003 the Company had a current
derivative liability of $4,781,069, which is included in current liabilities in
our balance sheet. The Company designates these derivatives as cash flow
hedges. During 2003, the Company made payments to counter-parties totaling
$4,527,061 as its net cost from hedging activities. This total includes
$518,350 for the first quarter of 2003, $773,125 for the second quarter of
2003, $1,910,000 for the third quarter of 2003, and $1,325,586 for the fourth
quarter of 2003. At December 31, 2003, 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.) Volume-
    
    Average
    
    Unrealized gainType
    
    Contract Period
    
    MMBTU / day
    
    Price / MMbtu
    
    (loss) at 12/31/03*Swap
    
    January 2004
    
    
    20,000
    
    
    $
    5.47
    
    
    $
    82,394Swap
    
    February 2004
    
    
    5,000
    
    
    $
    5.60
    
    
    $
    24,728Swap
    
    Calendar 2004
    
    
    20,000
    
    
    $
    4.09
    
    
    $
    (4,888,191
    )
  *
    
    Unrealized Gain/(Loss) is not adjusted for income tax effect. 21




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##### Table of Contents



The Company also utilizes fixed price forward gas sales at southwest
Wyoming delivery points to economically 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, 2003. (The Companys average net
interest in physical gas sales is approximately 80%.) Contract
    
    Volume -
    
    AveragePeriod
    
    MMBTU / day
    
    Price / MMbtuJan-Mar 2004
    
    
    10,000
    
    
    $
    6.04April-Oct 2004
    
    
    5,000
    
    
    $
    4.44Calendar 2004
    
    
    30,000
    
    
    $
    4.22Calendar 2005
    
    
    25,000
    
    
    $
    4.07Calendar 2006
    
    
    10,000
    
    
    $
    4.00
 Subsequent to December 31, 2003 and through February 27, 2004, the Company
has entered into the following additional contracts: Contract
    
    Volume -
    
    AverageType
    
    Period
    
    MMBTU / day
    
    Price / MMbtuSwap
    
    April-Oct 2004
    
    
    5,000
    
    
    $
    4.76Physical
    
    April-Oct 2004
    
    
    10,000
    
    
    $
    4.62Physical
    
    Calendar 2005
    
    
    10,000
    
    
    $
    4.42Swap
    
    Calendar 2005
    
    
    5,000
    
    
    $
    4.50Swap
    
    Calendar 2006
    
    
    5,000
    
    
    $
    4.20
 The above contracts represent net volumes equal to approximately 48% of
the Companys currently forecasted production for calendar 2004, 24% for
Calendar 2005 and 7% for Calendar 2006. 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. 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 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. The availability of a market for oil and
natural gas production depends upon numerous factors beyond the control of the
Company, including, but not limited to, the availability of other domestic or
imported production, the locations and capacity of pipelines, and the effect of
federal and state regulations on production. 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 22




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##### Table of Contents



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 on certain areas of its business. 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. 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. 23




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##### Table of Contents



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
capitalizes all direct costs of drilling an unsuccessful exploratory well in
the period in which the well is determined not to be producible in commercial
quantities. Under the full-cost method of accounting these costs are then
depleted using the units of production method based on the Companys proven
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. 24




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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 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 25




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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. Certain Definitions Terms used to describe quantities of oil and natural gas  
    
    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.
    
    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. 26




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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. (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. 27




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
    
    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. 28




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Item 8. Financial Statements and Supplementary Data. MANAGEMENTS REPORT 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. The Company maintains a system of internal controls that provides management
with reasonable assurance that the Companys assets are protected and that its
published financial statements are reliable and free of material misstatement.
Management is responsible for the effectiveness of internal controls. This is
accomplished through established internal accounting control systems, policies
and procedures, employee selection, appropriate delegation of authority and
segregation of responsibilities. The Audit Committee of the Board of Directors, composed solely of directors who
are not officers or employees, meets regularly with the independent
accountants. To ensure complete independence, the independent accountants have
full and free access to the Audit Committee to discuss the results of their
audits and the quality of financial reporting. The independent accountants do
not provide any other services to the Company. The independent accountants provide an objective independent review by their
audit of the Companys financial statements. Their audit is conducted in
accordance with auditing standards generally accepted in the United States of
America and includes a review of internal accounting controls to the extent
deemed necessary for the purposes of their audit. -s- Michael D. Watford
    
    -s- F. Fox Benton IIIMichael D. Watford
    
    F. Fox Benton IIIChief Executive Officer

March 10, 2004
    
    Chief Financial Officer
 29




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##### Table of Contents



INDEPENDENT AUDITORS REPORT To Shareholders of
Ultra Petroleum Corp.: We have audited the consolidated balance sheets of Ultra Petroleum Corp. and
subsidiaries as of December 31, 2003 and 2002, and the consolidated statements
of operations and deficit, shareholders equity and comprehensive loss, and cash
flows for each of the years in the three-year period ended December 31, 2003.
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 auditing standards generally
accepted in the United States of America. 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, 2003 and 2002, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 2003, in accordance with accounting principles
generally accepted in the United States of America. As discussed in Note 1 to the Consolidated Financial Statements, effective January 1, 2003,
the Company changed its method of accounting for asset retirement obligations. -s- KPMG LLP 
 30




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##### Table of Contents



ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS

|                                                                          |                                                 |      |              |            |   |   |             |            |  
|------------------------------------------------------------------------- | ----------------------------------------------- | ---- | ------------ | ---------- | - | - | ----------- | ---------- | -
|(Expressed in U.S. Dollars)                                               |                                                 |      |              |            |   |   |             |           
|                                                                          |                                                 |      | December 31,
|                                                                          |                                                 |      |             
|ASSETS                                                                    |                                                 | 2003 |              | 2002      
|                                                                          |                                                 |      |              |           
|Current Assets                                                            |                                                 |      |              |            |   |   |             |           
|                                                                          | Cash and cash equivalents                       |      | $            | 1,834,112  |   |   | $           | 1,417,711  |  
|                                                                          | Restricted cash                                 |      |              | 210,669    |   |   |             | 209,306    |  
|                                                                          | Accounts receivable                             |      |              | 19,348,861 |   |   |             | 11,398,483 |  
|                                                                          | Inventory                                       |      |              | 13,589,270 |   |   |             |           |  
|                                                                          | Prepaid drilling costs and other current assets |      |              | 1,711,737  |   |   |             | 474,279    |  
|                                                                          |                                                 |      |              |            |   |   |             |            |  
|                                                                          |                                                 |      | 36,694,649   |            |   |   | 13,499,779  |           
|Oil and gas properties, using the full
cost method of accounting (Note 3) |                                                 |      | 307,863,722  |            |   |   | 207,362,408 |           
|Capital assets (Note 4)                                                   |                                                 |      | 1,212,006    |            |   |   | 1,011,699   |           
|                                                                          |                                                 |      |              |            |   |   |             |            |  
|TOTAL ASSETS                                                              |                                                 | $    | 345,770,377  |            |   | $ | 221,873,886 |           
|                                                                          |                                                 |      |              |            |   |   |             |            |  
|LIABILITIES AND SHAREHOLDERS EQUITY                                      |                                                 |      |              |            |   |   |             |           
|Current liabilities                                                       |                                                 |      |              |            |   |   |             |           
|                                                                          | Accounts payable and accrued liabilities        |      | $            | 28,134,391 |   |   | $           | 13,839,031 |  
|                                                                          | Capital costs accrual                           |      |              | 30,616,912 |   |   |             | 4,075,829  |  
|Long-term debt (Note 5)                                                   |                                                 |      | 99,000,000   |            |   |   | 86,000,000  |           
|Deferred income taxes                                                     |                                                 |      | 33,446,131   |            |   |   | 10,033,174  |           
|Other long-term obligations                                               |                                                 |      | 5,120,213    |            |   |   | 3,858,810   |           
|Shareholders equity:                                                     |                                                 |      |              |            |   |   |             |           
|                                                                          | Common stock (Note 6)                           |      |              | 97,448,221 |   |   |             | 95,098,690 |  
|                                                                          | Treasury stock                                  |      |              | (1,193,650 | ) |   |             | (1,193,650 | )
|                                                                          | Other comprehensive loss                        |      |              | (2,940,357 | ) |   |             | (653,875   | )
|                                                                          | Retained earnings                               |      |              | 56,138,516 |   |   |             | 10,815,877 |  
|                                                                          |                                                 |      |              |            |   |   |             |            |  
|Total shareholders equity                                                |                                                 |      | 149,452,730  |            |   |   | 104,067,042 |           
|                                                                          |                                                 |      |              |            |   |   |             |            |  
|Commitments and contingencies (Note 11)                                   |                                                 |      |             |            |   |   |            |           
|                                                                         
|TOTAL LIABILITIES AND SHAREHOLDERS EQUITY                                |                                                 | $    | 345,770,377  |            |   | $ | 221,873,886 |           
|                                                                          |                                                 |      |              |            |   |   |             |            |  

See accompanying notes to consolidated financial statements.

Approved on behalf of the Board:

|                       |            |  |                      |           
|---------------------- | ---------- |  | -------------------- | ----------
|-s- Michael D. Watford | , Director |  | -s- James E. Nielson | , Director

31



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ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|---------------------------------------------------- | ---------------------------------------------- | ----------------------- | ----------- | ----------- | ---- | - | ---------- | ---------- | - | - | ----------- | ---------- | -
|(Expressed in U.S. Dollars)                          |                                                | Year Ended December 31,
|                                                     |                                                |                        
|                                                     |                                                |                         | 2003        |             | 2002 |   | 2001      
|                                                     |                                                |                         |             |             |      |   |           
|REVENUES:                                            |                                                |                         |             |             |      |   |            |            |   |   |             |           
|                                                     | Natural gas sales                              |                         | $           | 114,840,558 |      |   | $          | 38,502,971 |   |   | $           | 38,204,298 |  
|                                                     | Oil sales                                      |                         |             | 6,740,539   |      |   |            | 3,839,421  |   |   |             | 2,996,955  |  
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|                                                     |                                                |                         | 121,581,097 |             |      |   | 42,342,392 |            |   |   | 41,201,253  |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|EXPENSES:                                            |                                                |                         |             |             |      |   |            |            |   |   |             |           
|                                                     | Production expenses and taxes                  |                         |             | 25,223,679  |      |   |            | 11,410,868 |   |   |             | 9,023,271  |  
|                                                     | Depletion and depreciation                     |                         |             | 16,215,714  |      |   |            | 9,712,111  |   |   |             | 6,687,433  |  
|                                                     | General and administrative                     |                         |             | 5,733,147   |      |   |            | 4,199,104  |   |   |             | 3,894,185  |  
|                                                     | General and administrative, stock compensation |                         |             | 1,018,220   |      |   |            | 1,211,165  |   |   |             | 337,029    |  
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|                                                     |                                                |                         | 48,190,760  |             |      |   | 26,533,248 |            |   |   | 19,941,918  |           
|                                                    
|OPERATING INCOME                                     |                                                |                         | 73,390,337  |             |      |   | 15,809,144 |            |   |   | 21,259,335  |           
|                                                    
|OTHER INCOME (EXPENSE):                              |                                                |                         |             |             |      |   |            |            |   |   |             |           
|                                                     | Interest income                                |                         |             | 36,889      |      |   |            | 23,151     |   |   |             | 173,411    |  
|                                                     | Interest expense                               |                         |             | (2,850,916  | )    |   |            | (2,691,608 | ) |   |             | (1,687,172 | )
|                                                     | Other                                          |                         |             |            |      |   |            |           |   |   |             | 220,016    |  
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|                                                     |                                                |                         | (2,814,027  | )           |      |   | (2,668,457 | )          |   |   | (1,293,745  | )         
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|INCOME BEFORE INCOME TAXES                           |                                                |                         | 70,576,310  |             |      |   | 13,140,687 |            |   |   | 19,965,590  |           
|Income tax provision - deferred                      |                                                |                         | 25,253,671  |             |      |   | 5,059,166  |            |   |   | 2,086,762   |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|NET INCOME                                           |                                                |                         | 45,322,639  |             |      |   | 8,081,521  |            |   |   | 17,878,828  |           
|                                                    
|RETAINED EARNINGS (DEFICIT), beginning of period     |                                                |                         | 10,815,877  |             |      |   | 2,734,356  |            |   |   | (15,144,472 | )         
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|RETAINED EARNINGS, end of period                     |                                                | $                       | 56,138,516  |             |      | $ | 10,815,877 |            |   | $ | 2,734,356   |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|NET INCOME PER COMMON SHARE -  BASIC                 |                                                | $                       | 0.61        |             |      | $ | 0.11       |            |   | $ | 0.25        |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|NET INCOME PER COMMON SHARE - DILUTED                |                                                | $                       | 0.58        |             |      | $ | 0.10       |            |   | $ | 0.24        |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|Weighted average common shares
outstanding - basic   |                                                |                         | 74,231,553  |             |      |   | 73,770,841 |            |   |   | 72,371,839  |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  
|Weighted average common shares
outstanding - diluted |                                                |                         | 78,651,439  |             |      |   | 77,605,018 |            |   |   | 75,931,529  |           
|                                                     |                                                |                         |             |             |      |   |            |            |   |   |             |            |  

See accompanying notes to consolidated financial statements.

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ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY AND
COMPREHENSIVE LOSS
Common stock

Authorized
10,000,000 preferred shares
Unlimited common shares

|                                         |                                                                             |        |                   |            |                   |        |                   |            |   |        |            |            |   |   |            |            |   |  |            |            |  |   |            |            | 
|---------------------------------------- | --------------------------------------------------------------------------- | ------ | ----------------- | ---------- | ----------------- | ------ | ----------------- | ---------- | - | ------ | ---------- | ---------- | - | - | ---------- | ---------- | - |  | ---------- | ---------- |  | - | ---------- | ---------- | 
|                                         |                                                                             |        | Year Ended        |            | Year Ended        |        | Year Ended       
|                                         |                                                                             |        | December 31, 2003 |            | December 31, 2002 |        | December 31, 2001
|                                         |                                                                             |        |                   |            |                   |        |                  
|Issued                                   |                                                                             | Number |                   | Amount     |                   | Number |                   | Amount     |   | Number |            | Amount    
|                                         |                                                                             |        |                   |            |                   |        |                   |            |   |        |            |           
|Common Shares
Balance, beginning of year |                                                                             |        | 74,119,168        |            |                   | $      | 95,098,690        |            |   |        | 73,318,418 |            |   | $ | 92,585,148 |            |   |  | 56,939,762 |            |  | $ | 50,838,663 |           
|                                         | Employee stock option
exercises including income taxes                      |        |                   | 443,000    |                   |        |                   | 988,247    |   |        |            | 617,750    |   |   |            | 1,101,674  |   |  |            | 701,500    |  |   |            | 611,387    | 
|                                         | Employee stock plan grants                                                  |        |                   | 118,000    |                   |        |                   | 1,148,630  |   |        |            | 183,000    |   |   |            | 1,299,765  |   |  |            | 682,198    |  |   |            | 1,098,448  | 
|                                         | Fair value non-employee
stock option grants                                 |        |                   |           |                   |        |                   | 212,654    |   |        |            |           |   |   |            | 112,103    |   |  |            |           |  |   |            |           | 
|                                         | Merger with Pendaries
Petroleum Ltd.                                        |        |                   |           |                   |        |                   |           |   |        |            |           |   |   |            |           |   |  |            | 14,994,958 |  |   |            | 40,036,650 | 
|                                         |                                                                             |        |                   |            |                   |        |                   |            |   |        |            |            |   |   |            |            |   |  |            |            |  |   |            |           
|                                         | Balance, end of period                                                      |        |                   | 74,680,168 |                   |        | $                 | 97,448,221 |   |        |            | 74,119,168 |   |   | $          | 95,098,690 |   |  |            | 73,318,418 |  |   | $          | 92,585,148 | 
|                                         |                                                                             |        |                   |            |                   |        |                   |            |   |        |            |            |   |   |            |            |   |  |            |            |  |   |            |           
|                                         | Treasury stock                                                              |        |                   | (132,500   | )                 |        |                   | (1,193,650 | ) |        |            | (132,500   | ) |   |            | (1,193,650 | ) |  |            |           |  |   |            |           | 
|                                         |                                                                             |        |                   |            |                   |        |                   |            |   |        |            |            |   |   |            |            |   |  |            |            |  |   |            |           
|                                         | Other comprehensive loss -
Fair value of derivative
instruments, net of tax |        |                   |           |                   |        |                   | (2,940,357 | ) |        |            |           |   |   |            | (653,875   | ) |  |            |           |  |   |            |           | 
|                                         |                                                                             |        |                   |            |                   |        |                   |            |   |        |            |            |   |   |            |            |   |  |            |            |  |   |            |           

See accompanying notes to consolidated financial statements.

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ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOW

|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |             |            |             |            |  
|----------------------------------------------------------------------------- | ------------------------------------- | ----------------------------------------- | ------------------------------------------------------------------- | ----------------------------------------- | ---------- | ----------------------- | ----------- | ----------- | ---------- | ----------- | ---------- | ----------- | ---------- | ----------- | ---------- | -
|                                                                              |                                       |                                           |                                                                     |                                           |            | Year Ended December 31,
|                                                                              |                                       |                                           |                                                                     |                                           |            |                        
|                                                                              |                                       |                                           |                                                                     |                                           |            | 2003                    |             | 2002        |            | 2001       
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |            
|Cash flows from operating activities:                                         |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|Income for the year                                                           |                                       | $                                         | 45,322,639                                                          |                                           |            | $                       | 8,081,521   |             |            | $           | 17,878,828 |            
|Adjustments to reconcile income to net cash provided by
operating activities: |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              |                                       |                                           |                                                                     | Depletion and depreciation                |            |                         | 16,215,714  |             |            |             | 9,712,111  |             |            |             | 6,687,433  |  
|                                                                              |                                       |                                           |                                                                     | Deferred income taxes                     |            |                         | 25,253,671  |             |            |             | 5,059,166  |             |            |             | 2,086,762  |  
|                                                                              |                                       |                                           |                                                                     | Stock compensation                        |            |                         | 1,018,220   |             |            |             | 1,211,165  |             |            |             | 337,030    |  
|                                                                              |                                       | Net changes in working capital:           |                                                                     |                                           |            |                         |             |             |            |             |            |             |            |            
|                                                                              |                                       |                                           |                                                                     | Restricted cash                           |            |                         | (1,363      | )           |            |             | (2,127     | )           |            |             | (7,053     | )
|                                                                              |                                       |                                           |                                                                     | Accounts receivable                       |            |                         | (7,950,378  | )           |            |             | (4,039,741 | )           |            |             | 919,796    |  
|                                                                              |                                       |                                           |                                                                     | Inventory                                 |            |                         | (13,589,270 | )           |            |             |           |             |            |             |           |  
|                                                                              |                                       |                                           |                                                                     | Prepaid expenses and other current assets |            |                         | (1,237,458  | )           |            |             | 1,695,459  |             |            |             | (1,983,721 | )
|                                                                              |                                       |                                           |                                                                     | Accounts payable and accrued liabilities  |            |                         | 10,168,164  |             |            |             | 1,799,538  |             |            |             | 12,104,974 |  
|                                                                              |                                       |                                           |                                                                     | Other long-term obligations               |            |                         | 1,261,403   |             |            |             | (2,026,604 | )           |            |             | (3,887,684 | )
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              |                                       | Net cash provided by operating activities |                                                                     |                                           | 76,461,342 |                         |             |             | 21,490,488 |             |            |             | 34,136,365 |            
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              | Cash flows from investing activities: |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |             |           
|                                                                              |                                       |                                           | Oil and gas property expenditures                                   |                                           |            | (115,837,250            | )           |             |            | (61,257,518 | )          |             |            | (56,575,708 | )         
|                                                                              |                                       |                                           | Change in oil and gas property expenditures in
accounts payable     |                                           |            | 26,541,083              |             |             |            | (2,288,540  | )          |             |            | (3,280,946  | )         
|                                                                              |                                       |                                           | Purchase of capital assets                                          |                                           |            | (737,021                | )           |             |            | (814,205    | )          |             |            | (317,592    | )         
|                                                                              |                                       |                                           | Proceeds from sale of oil and gas properties                        |                                           |            |                        |             |             |            |            |            |             |            | 312,365     |           
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              | Net cash used in investing activities |                                           |                                                                     | (90,033,188                               | )          |                         |             | (64,360,263 | )          |             |            | (59,861,881 | )         
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|Cash flows from financing activities:                                         |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              |                                       |                                           |                                                                     | Borrowings of long-term debt, gross       |            |                         | 43,000,000  |             |            |             | 43,000,000 |             |            |             | 26,850,000 |  
|                                                                              |                                       |                                           |                                                                     | Payments on long-term debt, gross         |            |                         | (30,000,000 | )           |            |             |           |             |            |             | (1,500,000 | )
|                                                                              |                                       |                                           |                                                                     | Proceeds from issuance of common stock    |            |                         | 988,247     |             |            |             | 1,101,674  |             |            |             | 611,387    |  
|                                                                              |                                       |                                           |                                                                     | Repurchase of common stock                |            |                         |            |             |            |             | (1,193,650 | )           |            |             |           |  
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|Net cash provided by financing activities                                     |                                       |                                           | 13,988,247                                                          |                                           |            |                         | 42,908,024  |             |            |             | 25,961,387 |            
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|Net increase in cash and cash equivalents                                     |                                       |                                           | 416,401                                                             |                                           |            |                         | 38,249      |             |            |             | 235,871    |            
|                                                                             
|Cash and cash equivalents, beginning of year                                  |                                       |                                           | 1,417,711                                                           |                                           |            |                         | 1,379,462   |             |            |             | 1,143,591  |            
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|Cash and cash equivalents, end of year                                        |                                       | $                                         | 1,834,112                                                           |                                           |            | $                       | 1,417,711   |             |            | $           | 1,379,462  |            
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|SUPPLEMENTAL INFORMATION                                                      |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              |                                       |                                           | Cash paid for:                                                      |                                           |            |                         |             |             |            |             |            |             |            |             |           
|                                                                              |                                       |                                           |                                                                     | Interest                                  |            | $                       | 2,850,916   |             |            | $           | 2,691,608  |             |            | $           | 1,687,172  |  
|                                                                              |                                       |                                           |                                                                     | Income taxes                              |            | $                       |            |             |            | $           |           |             |            | $           | 10,000     |  
|                                                                              |                                       |                                           | Supplemental schedule of non-cash investing activities
Acquisitions |                                           |            |                         |             |             |            |             |            |             |            |             |           
|                                                                              |                                       |                                           |                                                                     | Fair value of assets acquired             |            | $                       |            |             |            | $           |           |             |            | $           | 43,950,263 |  
|                                                                              |                                       |                                           |                                                                     | Less: liabilities assumed                 |            |                         |            |             |            |             |           |             |            |             | (4,225,978 | )
|                                                                              |                                       |                                           |                                                                     | Cash acquired                             |            |                         |            |             |            |             |           |             |            |             | 312,365    |  
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            
|                                                                              |                                       |                                           |                                                                     | Fair value of stock issued                |            | $                       |            |             |            | $           |           |             |            | $           | 40,036,650 |  
|                                                                              |                                       |                                           |                                                                     |                                           |            |                         |             |             |            |             |            |            

See accompanying notes to consolidated financial statements

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ULTRA PETROLEUM CORP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Expressed in U.S. dollars unless otherwise noted)
Years ended December 31, 2003, 2002 and 2001

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 oil and gas operations whereby all costs associated with the
exploration for and development of oil and gas reserves are capitalized to the
Companys cost centers. Such costs include land acquisition costs, geological
and geophysical expenses, carrying charges on non-producing properties, costs
of drilling both productive and non-productive wells and overhead charges
directly related to acquisition, exploration and development activities. 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.

In January 2003 the Company adopted 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. Based on current estimates, the
Company would record asset retirement obligations (using a 10% discount rate)
and a cumulative effect of change in accounting principle on prior years,
related to the depreciation and accretion expense that would have been reported
had the fair value of the asset retirement obligation, and corresponding
increase in the carrying amount of the related long-lived asset. Currently the
Companys assessment has been deemed not material.

The capitalized costs, together with the costs of production equipment,
are depleted using the units-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 upon relative energy
content.

Costs of acquiring and evaluating unproved properties are initially
excluded from the costs subject to depletion. These unproved properties are
assessed periodically to ascertain whether impairment has occurred. When
proved reserves are assigned or the property is considered to be impaired, the
cost of the property or the amount of the impairment is added to the costs
subject to depletion.

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The total capitalized cost of oil and gas properties less accumulated
depletion is limited to an amount equal to the estimated future net cash flows
from proved reserves, discounted at 10%, using year-end prices, plus the cost
(net of impairment) of unproved properties as adjusted for related tax effects
(the full cost ceiling test limitation).

Proceeds from the sale of oil and gas properties are applied against
capitalized costs, with no gain or loss recognized, unless such a sale would
significantly alter the rate of depletion.

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

(g)  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 counter parties. 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.

(h)  Income taxes: The Company uses the asset and liability method of
accounting for income taxes under which deferred tax assets and liabilities are
recognized for the future tax consequences. Accordingly, deferred tax
liabilities and assets are determined based on the temporary differences
between the financial statement and tax basis of assets and liabilities, using
the enacted tax rates in effect for the year in which the differences are
expected to reverse.

(i)  Earnings (loss) per share: Basic earnings (loss) per share is computed by
dividing net earnings (loss) attributable to common stock by the weighted
average number of common shares outstanding during each period. Diluted
earnings (loss) per share is computed by adjusting the average number of common
shares outstanding for the dilutive effect, if any, of stock options. 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, 2003,
2002 and 2001:

|                                                                                                                                                                                         |  |                         |            |      |  |      |            |  |  |   |            | 
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | ---------- | ---- |  | ---- | ---------- |  |  | - | ---------- | 
|                                                                                                                                                                                         |  | Year Ended December 31,
|                                                                                                                                                                                         |  | 2003                    |            | 2002 |  | 2001
|                                                                                                                                                                                         |  |                         |            |      |  |     
|Net income                                                                                                                                                                               |  | $                       | 45,322,639 |      |  | $    | 8,081,521  |  |  | $ | 17,878,828 | 
|                                                                                                                                                                                         |  |                         |            |      |  |      |            |  |  |   |            | 
|Weighted average common
shares outstanding during the
period                                                                                                                             |  |                         | 74,231,553 |      |  |      | 73,770,841 |  |  |   | 72,371,839 | 
|Effect of dilutive instruments                                                                                                                                                           |  |                         | 4,419,886  |      |  |      | 3,834,177  |  |  |   | 3,559,690  | 
|                                                                                                                                                                                         |  |                         |            |      |  |      |            |  |  |   |            | 
|Weighted average common
shares outstanding during the
period including the effects
of dilutive instruments                                                                               |  |                         | 78,651,439 |      |  |      | 77,605,018 |  |  |   | 75,931,529 | 
|Basic earnings per share                                                                                                                                                                 |  | $                       | 0.61       |      |  | $    | 0.11       |  |  | $ | 0.25       | 
|                                                                                                                                                                                         |  |                         |            |      |  |      |            |  |  |   |            | 
|Diluted earnings per share                                                                                                                                                               |  | $                       | 0.58       |      |  | $    | 0.10       |  |  | $ | 0.24       | 
|                                                                                                                                                                                         |  |                         |            |      |  |      |            |  |  |   |            | 
|Number 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    |  |  |   | 373,942    | 
|                                                                                                                                                                                         |  |                         |            |      |  |      |            |  |  |   |            | 

(j)  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

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financial statements, and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates.

(k)  Reclassifications: Certain amounts in the financial statements of the
prior years have been reclassified to conform to the current year financial
statement presentation.

(l)  Accounting for stock-based compensation: In December 2002, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards (SFAS No. 148), Accounting for Stock-Based Compensation-Transaction
and Disclosure, SFAS No. 148 amends SFAS No. 123, Accounting for Stock-Based
Compensation to provide alternative methods of transactions for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements
of SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on the reported results. The
provisions of SFAS No. 148 are effective for financial statements for fiscal
years ending after December 15, 2002.

SFAS No. 123, Accounting
for Stock  Based Compensation, 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,
|                             |             |             |   | 2003                            |      | 2002 |   | 2001     
|                             |             |             |   |                                 |      |      |   |          
|Net income:                  |             |             |   |                                 |      |      |   |           |      |  |   |           
|                             | As reported |             | $ | 45,322,639                      |      |      | $ | 8,081,521 |      |  | $ | 17,878,828 |     
|                             | Pro forma   |             | $ | 43,799,671                      |      |      | $ | 5,167,990 |      |  | $ | 14,924,923 |     
|Net income per common share: |             |             |   |                                 |      |      |   |           |      |  |   |           
|                             | Basic:      |             |   |                                 |      |      |   |           |      |  |   |            |     
|                             |             | As reported |   | $                               | 0.61 |      |   | $         | 0.11 |  |   | $          | 0.25 | 
|                             |             | Pro forma   |   | $                               | 0.59 |      |   | $         | 0.07 |  |   | $          | 0.21 | 
|                             | Diluted:    |             |   |                                 |      |      |   |           |      |  |   |            |     
|                             |             | As reported |   | $                               | 0.58 |      |   | $         | 0.10 |  |   | $          | 0.24 | 
|                             |             | Pro forma   |   | $                               | 0.56 |      |   | $         | 0.07 |  |   | $          | 0.20 | 

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, 2003, expected volatility of approximately 25%, at December 31, 2002,
expected volatility of 30%, at December 31, 2001, expected volatility of 30%.
All options have expected lives of ten years.

(m)  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 it is entitled, the underproduction is recorded as a
receivable. At December 31, 2003 and 2002, the Company had net gas imbalance
receivables of $2 million and $1 million, respectively.

(n)  Impact of recently issued accounting pronouncements: None that affect the
Company.

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2. ACQUISITION OF PENDARIES PETROLEUM LTD:

Effective January 16, 2001, the Company completed its acquisition of 100%
of the outstanding shares of Pendaries Petroleum Ltd. (Pendaries) and its
wholly owned subsidiary Sino-American Energy Corporation in exchange for
14,994,958 shares of Ultra Petroleum Corp. common stock valued at $2.67 per
share. The value of the shares was based on the average price of the shares a
few days prior to and a few days subsequent to
the date the transaction was closed. The transaction was accounted for using
the purchase method of accounting and was valued at $40 million. The impact of
the acquisition increased the undeveloped portion of the Companys full cost
pool by $43 million and also carried to the balance sheet a net deferred tax
liability of $962,081. This deferred tax liability was created as a result of
a difference between the book and tax basis in Sino-American Energy
Corporations oil and gas properties. Accordingly, Pendaries results of
operations have been included in the consolidated financial statements of
income from the effective date of acquisition. The consolidated balance sheet
dated December 31, 2003 includes the assets and liabilities, as well as the
adjustments required to record the acquisition in accordance with purchase
accounting.

3. OIL AND GAS PROPERTIES:

|                                                                                  |  |   |              |   |              |   |             |   | 
|--------------------------------------------------------------------------------- |  | - | ------------ | - | ------------ | - | ----------- | - | 
|                                                                                  |  |   | December 31, |   | December 31,
|                                                                                  |  |   | 2003         |   | 2002        
|                                                                                  |  |   |              |   |             
|Developed Properties:                                                             |  |   |              |   |              |   |             |  
|Acquisition, equipment, exploration, development
drilling and environmental costs |  | $ | 249,784,562  |   |              | $ | 150,986,843 |  
|Less accumulated depletion, depreciation and amortization                         |  |   | (38,495,605  | ) |              |   | (22,816,605 | )
|                                                                                  |  |   |              |   |              |   |             |  
|                                                                                  |  |   | 211,288,957  |   |              |   | 128,170,238 |  
|                                                                                 
|Unproved
properties  China                                                       |  |   | 80,970,244   |   |              |   | 64,873,186  |  
|Unproved properties  Wyoming                                                     |  |   | 15,604,521   |   |              |   | 14,318,984  |  
|                                                                                  |  |   |              |   |              |   |             |  
|                                                                                  |  | $ | 307,863,722  |   |              | $ | 207,362,408 |  
|                                                                                  |  |   |              |   |              |   |             |  

4. CAPITAL ASSETS:

|                   |  |                   |           |              |  |                   |           |                   |  |   |           |  |  |   |           | 
|------------------ |  | ----------------- | --------- | ------------ |  | ----------------- | --------- | ----------------- |  | - | --------- |  |  | - | --------- | 
|                   |  |                   |           |              |  | December 31, 2003 |           |                   |  |   |           |  |  |  
|                   |  | December 31, 2003 |           | Accumulated  |  | December 31, 2003 |           | December 31, 2002
|                   |  | Cost              |           | Depreciation |  | Net Book Value    |           | Net Book Value   
|                   |  |                   |           |              |  |                   |           |                  
|Computer equipment |  | $                 | 686,165   |              |  | $                 | 497,789   |                   |  | $ | 188,376   |  |  | $ | 199,302   | 
|Office equipment   |  |                   | 233,255   |              |  |                   | 155,028   |                   |  |   | 78,227    |  |  |   | 90,401    | 
|Field equipment    |  |                   | 304,626   |              |  |                   | 188,985   |                   |  |   | 115,641   |  |  |   | 44,191    | 
|Other              |  |                   | 1,532,917 |              |  |                   | 703,155   |                   |  |   | 829,762   |  |  |   | 677,805   | 
|                   |  |                   |           |              |  |                   |           |                   |  |   |           |  |  |   |           | 
|                   |  | $                 | 2,756,963 |              |  | $                 | 1,544,957 |                   |  | $ | 1,212,006 |  |  | $ | 1,011,699 | 
|                   |  |                   |           |              |  |                   |           |                   |  |   |           |  |  |   |           | 

5. LONG-TERM DEBT:

|                            |  |                   |             |                   |  |   |            | 
|--------------------------- |  | ----------------- | ----------- | ----------------- |  | - | ---------- | 
|                            |  | December 31, 2003 |             | December 31, 2002
|                            |  |                   |             |                  
|Bank indebtedness           |  | $                 | 99,000,000  |                   |  | $ | 86,000,000 | 
|Other long-term obligations |  |                   | 5,120,213   |                   |  |   | 3,858,810  | 
|                            |  |                   |             |                   |  |   |            | 
|                            |  | $                 | 104,120,213 |                   |  | $ | 89,858,810 | 
|                            |  |                   |             |                   |  |   |            | 

Bank indebtedness: 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 an aggregate borrowing base of $200 million at December 12,
2003. At December 31, 2003, the Company had $99 million borrowings outstanding
and $101 million in unused borrowings available under the credit facility.

The credit facility matures on March 1, 2006. The notes bear interest at
either the banks prime rate plus a margin of one-half of one percent (0.50%)
to one and one-quarter percent (1.25%) based on the percentage of available
credit drawn or at LIBOR plus a margin of one and one-half percent (1.50%) to
two and one-quarter percent (2.25%) based on the percentage of available credit
drawn. An average annual commitment fee of 0.375% is charged quarterly for any
unused portion of the credit line.

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The borrowing base is subject to periodic (at least semi-annual) review
and re-determination by the bank 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. 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 and may be
required to make immediate principal repayment. As of December 31, 2003, the
Company was in compliance with the covenants and required ratios.

Other long-term obligations: These costs relate to the long-term portion of
production taxes payable and dollars associated with imbalanced production.

6. COMMON STOCK:

(a)  Stock options: The following table summarizes the changes in stock options
for the three-year period ending December 31, 2003:

|                           |  |           |           |                      |  |   |                |  | 
|-------------------------- |  | --------- | --------- | -------------------- |  | - | -------------- |  | 
|                           |  | Number of |           | Weighted Average    
|                           |  | Options   |           | Exercise Price (US$)
|                           |  |           |           |                     
|Balance, December 31, 2000 |  |           | 4,525,000 |                      |  | $ | 0.51 to  $2.65
|Granted                    |  |           | 1,630,000 |                      |  | $ | 2.99 to  $5.23
|Exercised                  |  |           | (701,500  | )                    |  | $ | 0.64 to  $3.12
|Cancelled                  |  |           | (22,500   | )                    |  | $ | 1.14 to  $5.23
|                           |  |           |           |                      |  |   |               
|Balance, December 31, 2001 |  |           | 5,431,000 |                      |  | $ | 0.51 to  $5.23
|Granted                    |  |           | 748,500   |                      |  | $ | 7.82 to  $8.86
|Exercised                  |  |           | (617,750  | )                    |  | $ | 0.64 to  $5.23
|                           |  |           |           |                      |  |   |               
|Balance, December 31, 2002 |  |           | 5,561,750 |                      |  | $ | 0.51 to  $8.86
|Granted                    |  |           | 797,500   |                      |  | $ | 9.66 to $14.21
|Exercised                  |  |           | (443,000  | )                    |  | $ | 0.64 to  $8.86
|Cancelled                  |  |           | (13,750   | )                    |  | $ | 8.86 to  $9.66
|                           |  |           |           |                      |  |   |               
|Balance, December 31, 2003 |  |           | 5,902,500 |                      |  | $ | 0.51 to $14.21

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. The Companys stock options vest each
quarter over a one-year period. At the end of the one year the stock options
are fully vested.

The following table summarizes information about the stock options
outstanding at December 31, 2003:

|              |  |                     |           |                     |  |             |      |             |  |             |      |             |  |           |           |          |  |  |      |  |  |   |      | 
|------------- |  | ------------------- | --------- | ------------------- |  | ----------- | ---- | ----------- |  | ----------- | ---- | ----------- |  | --------- | --------- | -------- |  |  | ---- |  |  | - | ---- | 
|              |  | OPTIONS OUTSTANDING |           | OPTIONS EXERCISABLE
|              |  |                     |           |                    
|              |  |                     |           |                     |  | Weighted    |      |             |  |             |      |             |  |           |           | Weighted |  |  |      | 
|              |  |                     |           |                     |  | Average     |      | Weighted    |  |             |      |             |  | Average   |           | Weighted
|Range of      |  |                     |           |                     |  | Remaining   |      | Average     |  |             |      |             |  | Remaining |           | Average 
|Exercise      |  | Number              |           | Contractual         |  | Exercise    |      | Number      |  | Contractual |      | Exercise   
|Price ($US)   |  | Outstanding         |           | Life                |  | Price ($US) |      | Exercisable |  | Life        |      | Price ($US)
|              |  |                     |           |                     |  |             |      |             |  |             |      |            
|$0.51 - 1.14  |  |                     | 3,023,500 |                     |  |             | 5.65 |             |  | $           | 0.89 |             |  |           | 3,023,500 |          |  |  | 5.65 |  |  | $ | 0.89 | 
|$2.65 - 5.23  |  |                     | 1,378,000 |                     |  |             | 7.24 |             |  | $           | 4.02 |             |  |           | 1,378,000 |          |  |  | 7.24 |  |  | $ | 4.02 | 
|$7.82 - 14.21 |  |                     | 1,501,000 |                     |  |             | 8.89 |             |  | $           | 9.45 |             |  |           | 1,081,000 |          |  |  | 6.40 |  |  | $ | 9.13 | 

7. 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 Company recognizes
all derivative instruments as

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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 non-operating income or expense. At December 31, 2003, the Company
had a current derivative liability of $4,781,069, which is included in current
liabilities in the balance sheet. The Company has designated these derivatives
as cash flow hedges.

During 2003, the Company made payments to counter-parties totaling
$4,527,061 as its net cost from hedging activities. This total includes
$518,350 for the first quarter of 2003, $773,125 for the second quarter of
2003, $1,910,000 for the third quarter of 2003, and $1,325,586 for the fourth
quarter of 2003.

At December 31, 2003, 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 gain    
|     |  |               |  |             |        |               |  |                    
|Type |  | Period        |  | MMBTU / day |        | Price / MMbtu |  | (loss) at 12/31/03*
|     |  |               |  |             |        |               |  |                    
|Swap |  | January 2004  |  |             | 20,000 |               |  | $                   | 5.47 |  |  | $ | 82,394     |  
|Swap |  | February 2004 |  |             | 5,000  |               |  | $                   | 5.60 |  |  | $ | 24,728     |  
|Swap |  | Calendar 2004 |  |             | 20,000 |               |  | $                   | 4.09 |  |  | $ | (4,888,191 | )

*     Unrealized Gain/(Loss) is not adjusted for income tax effect

The Company also utilizes fixed price forward gas sales at southwest
Wyoming delivery points to economically 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, 2003. (The
Companys average net interest in physical gas sales is approximately 80%.)

|         |                |             |  |               |  |  |   |      | 
|-------- | -------------- | ----------- |  | ------------- |  |  | - | ---- | 
|Contract |                | Volume     |  | Average      
|         |                |             |  |              
|Period   |                | MMBTU / day |  | Price / MMbtu
|         |                |             |  |              
|         | Jan-Mar 2004   |             |  | 10,000        |  |  | $ | 6.04 | 
|         | April-Oct
2004 |             |  | 5,000         |  |  | $ | 4.44 | 
|         | Calendar 2004  |             |  | 30,000        |  |  | $ | 4.22 | 
|         | Calendar 2005  |             |  | 25,000        |  |  | $ | 4.07 | 
|         | Calendar 2006  |             |  | 10,000        |  |  | $ | 4.00 | 

Subsequent to December 31, 2003 and through February 27, 2004, the Company
has entered into the following additional contracts:

|         |  |                 |  |             |        |               |  |         |      |  |  | 
|-------- |  | --------------- |  | ----------- | ------ | ------------- |  | ------- | ---- |  |  | 
|         |  |                 |  |             |        | Volume       |  | Average
|         |  |                 |  |             |        |               |  |        
|Type     |  | Contract Period |  | MMBTU / day |        | Price / MMbtu
|         |  |                 |  |             |        |              
|Swap     |  | April-Oct 2004  |  |             | 5,000  |               |  | $       | 4.76 | 
|Physical |  | April-Oct 2004  |  |             | 10,000 |               |  | $       | 4.62 | 
|Physical |  | Calendar 2005   |  |             | 10,000 |               |  | $       | 4.42 | 
|Swap     |  | Calendar 2005   |  |             | 5,000  |               |  | $       | 4.50 | 
|Swap     |  | Calendar 2006   |  |             | 5,000  |               |  | $       | 4.20 | 

The above contracts represent net volumes equal to approximately 48% of
the Companys currently forecasted production for calendar 2004, 24% for
Calendar 2005 and 7% for Calendar 2006.

8. INCOME TAXES:

The (recovery of) provision for income taxes for the years ended December
31, 2003 and December 31, 2002 vary from the amounts that would be computed by
applying the U.S. Federal income tax rate of 35% to pretax income as a result
of the following:

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|                                      |  |                   |            |                   |  |   |           |  
|------------------------------------- |  | ----------------- | ---------- | ----------------- |  | - | --------- | -
|                                      |  | December 31, 2003 |            | December 31, 2002
|                                      |  |                   |            |                  
|Federal tax expense at statutory rate |  | $                 | 24,701,708 |                   |  | $ | 4,599,240 |  
|State income tax expense              |  |                   | 455,557    |                   |  |   | 456,497   |  
|Adjustment for foreign losses         |  |                   | 80,287     |                   |  |   | 94,087    |  
|Percentage depletion                  |  |                   | (87,500    | )                 |  |   | (185,016  | )
|Other                                 |  |                   | 103,619    |                   |  |   | 94,358    |  
|                                      |  |                   |            |                   |  |   |           |  
|Actual income tax expense             |  | $                 | 25,253,671 |                   |  | $ | 5,059,166 |  
|                                      |  |                   |            |                   |  |   |           |  

The tax effects of temporary differences that give rise to significant
portions of the future tax assets and liabilities are as follows:

|                                              |                                     |  |                   |             |                   |  |             |             |  
|--------------------------------------------- | ----------------------------------- |  | ----------------- | ----------- | ----------------- |  | ----------- | ----------- | -
|                                              |                                     |  | December 31, 2003 |             | December 31, 2002
|                                              |                                     |  |                   |             |                  
|Future tax assets:                            |                                     |  |                   |             |                   |  |             |            
|                                              | Net operating loss carryforward     |  | $                 | 9,090,091   |                   |  | $           | 9,878,862   |  
|                                              | Tax effect of hedging activity      |  |                   | 1,840,713   |                   |  |             |            |  
|                                              | Other                               |  |                   | 843,929     |                   |  |             | 797,440     |  
|                                              |                                     |  |                   |             |                   |  |             |             |  
|                                              |                                     |  | 11,774,733        |             |                   |  | 10,676,302  |            
|                                              | Less valuation allowance            |  |                   |            |                   |  |             |            |  
|                                              |                                     |  |                   |             |                   |  |             |             |  
|                                              | Total future assets                 |  |                   | 11,774,733  |                   |  |             | 10,676,302  |  
|Future tax liabilities
Property and equipment |                                     |  | (45,220,864       | )           |                   |  | (20,709,476 | )          
|                                              |                                     |  |                   |             |                   |  |             |             |  
|                                              | Net future tax assets (liabilities) |  | $                 | (33,446,131 | )                 |  | $           | (10,033,174 | )
|                                              |                                     |  |                   |             |                   |  |             |             |  

At December 31, 2003, the Company has available non-capital loss
carryforwards as follows:

|                           |  |                      |           |             |  |              |            |              |  |   |            |  |  |  |           | 
|-------------------------- |  | -------------------- | --------- | ----------- |  | ------------ | ---------- | ------------ |  | - | ---------- |  |  |  | --------- | 
|                           |  | Losses for Financial |           | Timing      |  | Losses for   |            |              |  |  
|                           |  | Statements           |           | Differences |  | Tax Purposes |            | Expiry Dates
|                           |  |                      |           |             |  |              |            |             
|Canada (Cdn dollars)       |  | $                    | 9,827,916 |             |  | $            | (122,633   | )            |  | $ | 9,705,283  |  |  |  | 2004-2010 | 
|United States (US dollars) |  | $                    |          |             |  | $            | 25,250,253 |              |  | $ | 25,250,253 |  |  |  | 2012-2021 | 

During 2001, the Company fully utilized available net operating loss
carryforwards attributable to continuing operations for financial statement
purposes.

The benefit of the Canadian loss carryforwards could only be utilized if
the Company were to generate taxable income in Canada. The Company currently
has no operations in Canada; any potential benefit from these losses has been
excluded from the calculation of deferred taxes.

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 $299,832, $236,765 and $187,255
for the years ended December 31, 2003, 2002 and 2001, respectively.

10. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES:

Currently under Canadian GAAP, there is not a provision in place to
expense stock-based compensation as with FASB Statement No. 123 Accounting for
Stock-Based Compensation. However, there was an exposure draft issued in
December 2002 that would essentially harmonize Canadian accounting standards to
U.S. GAAP. The proposed effective date for implementing Stock-Based
Compensation and Other Stock-Based Payments, Section 3870, is January 1, 2004.
In the year ending December 31, 2003, the Company recorded, to the full cost
pool under capitalized general and administrative expenses of $212,653, a
consultant stock-based compensation expense of $212,653. Under current
Canadian GAAP, this amount would have been recognized as a disclosure item,
with no impact on the financial statements.

Recorded in other comprehensive income in the Equity section of our
balance sheet is an offset to a liability that measures a future effect of the
fixed price to index price swap agreements that the Company

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currently has in place (Note 7). We have recorded
this in compliance with FAS 133 addressing accounting impacts of derivative
instruments.
Currently under Canadian GAAP the future effects of derivative
instruments are recorded through revenue in the period in which the production
is sold. The total future value of the swap is not captured as an asset or
liability, and the term Other Comprehensive Income, is not recognized in
Canada. In 2002, the Canadian Accounting Standards Board issued a draft
proposal to put in place Canadian standards harmonizing with U.S. standards on
financial instruments. Canadian enterprises would then have the choice to
apply accounting policies and practices that are in accordance with both U.S.
and Canadian GAAP. 11. COMMITMENTS AND CONTINGENCIES: In May of 2003 the Company amended its prior office lease in Englewood,
Colorado, which it has committed to through June 2008. The Companys total
commitment of this lease is $734,578. 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 commitment of $364,941. The total commitment for both
offices is $1,099,519. As of December 31, 2003 the Company committed to drilling obligations in
progress that will carry over into 2004. The total capital expenditures for
operations in progress were $12,384,391. On October 16, 2003
the 15 year contract, which provides for up to an additional 10 years,
was signed by the Operator to lease an 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. Lease cancellation
on the part of the Company prior to the FPSO starting offshore operations would
commit the Company to its 8.92% share of up to $50 million in cancellation
fees. The lease cancellation fee, after commencement of offshore operations,
would be based on a sliding time-scale (cancellation fee decreases with time)
with 8.92% of $50 million the maximum cancellation fee. The Company considers
it very unlikely that a lease cancellation situation will occur. Due to these
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 total operating leases
were $621,065. The Company is currently involved in various other 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. 12. 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. It is not practicable to estimate the fair values of amounts due
to and from related parties due to the related party nature of the amounts and
the absence of a ready market for such instruments. 13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): IncomeRevenues
    
    
    
    
    
    Beforefrom
    
    
    
    
    
    Income
    
    Income
    
    
    
    
    
    Basic
    
    DilutedContinuing
    
    
    
    
    
    Tax
    
    Tax
    
    Net
    
    Earnings
    
    EarningsOperations
    
    Expenses
    
    Provision
    
    Provision
    
    Income
    
    Per Share
    
    Per Share(in thousands, except for per share data)2003First 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
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##### Table of Contents



IncomeRevenues
    
    
    
    
    
    Beforefrom
    
    
    
    
    
    Income
    
    Income
    
    
    
    
    
    Basic
    
    DilutedContinuing
    
    
    
    
    
    Tax
    
    Tax
    
    Net
    
    Earnings
    
    EarningsOperations
    
    Expenses
    
    Provision
    
    Provision
    
    Income
    
    Per Share
    
    Per Share(in thousands, except for per share data)2002First Quarter
    
    $
    9,106
    
    
    $
    6,323
    
    
    $
    2,783
    
    
    $
    1,071
    
    
    $
    1,712
    
    
    $
    0.02
    
    
    $
    0.02Second Quarter
    
    $
    8,143
    
    
    $
    6,161
    
    
    $
    1,982
    
    
    $
    676
    
    
    $
    1,306
    
    
    $
    0.02
    
    
    $
    0.02Third Quarter
    
    $
    8,671
    
    
    $
    7,108
    
    
    $
    1,563
    
    
    $
    602
    
    
    $
    961
    
    
    $
    0.01
    
    
    $
    0.01Fourth Quarter
    
    $
    16,422
    
    
    $
    9,610
    
    
    $
    6,812
    
    
    $
    2,710
    
    
    $
    4,102
    
    
    $
    0.06
    
    
    $
    0.05$
    42,342
    
    
    $
    29,202
    
    
    $
    13,140
    
    
    $
    5,059
    
    
    $
    8,081
 14. 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, 2003, 2002 and
2001 are based upon estimates prepared by Netherland, Sewell & Associates, Inc.
dated January 23, 2004, January 21, 2003 and February 21, 2002, respectively.
These are estimated quantities of proved oil and gas reserves for the Company
and the changes in total proved reserves as of December 31, 2003, 2002 and
2001. All such reserves are located in the Green River Basin, Wyoming. B. ANALYSES OF CHANGES IN PROVEN RESERVES: Oil (Bbls)
    
    Gas (Mcf)Reserves, December 31, 2000
    
    
    1,290,300
    
    
    
    160,390,000Extensions, discoveries and additions
    
    
    2,222,900
    
    
    
    278,057,000Production
    
    
    (116,400
    )
    
    
    (11,500,000
    )Revisions
    
    
    86,000
    
    
    
    (3,117,400
    )Reserves, December 31, 2001
    
    
    3,482,800
    
    
    
    423,829,600Extensions, discoveries and additions
    
    
    1,101,500
    
    
    
    139,044,000Production
    
    
    (151,200
    )
    
    
    (16,496,000
    )Revisions
    
    
    1,125,900
    
    
    
    120,743,400Reserves, December 31, 2002
    
    
    5,559,000
    
    
    
    667,121,000Extensions, discoveries and additions
    
    
    2,894,700
    
    
    
    361,298,700Production
    
    
    (211,600
    )
    
    
    (27,621,800
    )Revisions
    
    
    100,400
    
    
    
    22,569,400Reserves, December 31, 2003
    
    
    8,342,500
    
    
    
    1,023,367,300Proved developed reserves:December 31, 2000
    
    
    688,000
    
    
    
    85,141,000December 31, 2001
    
    
    1,295,000
    
    
    
    150,397,000December 31, 2002
    
    
    2,003,000
    
    
    
    222,608,000December 31, 2003
    
    
    3,028,000
    
    
    
    359,072,000
 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 $5.59, $2.94, and $2.05
per Mcf of gas at December 31, 2003, 2002 and 2001, respectively. 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 43




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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). December 31,
    
    December 31,
    
    December 31,2003
    
    2002
    
    2001Future cash inflows
    
    $
    5,986,603
    
    
    $
    2,132,521
    
    
    $
    939,441Future production costs
    
    
    (1,171,314
    )
    
    
    (569,034
    )
    
    
    (257,960
    )Future development costs
    
    
    (358,811
    )
    
    
    (254,892
    )
    
    
    (149,806
    )Future income taxes
    
    
    (1,620,437
    )
    
    
    (432,663
    )
    
    
    (184,164
    )Future net cash flows
    
    
    2,836,041
    
    
    
    875,932
    
    
    
    347,511Discounted at 10%
    
    
    (1,700,528
    )
    
    
    (558,967
    )
    
    
    (228,252
    )Standardized measure of
discounted future net cash flows
    
    $
    1,135,513
    
    
    $
    316,965
    
    
    $
    119,259Pre-tax standardized measure SEC PV-10
    
    $
    1,784,314
    
    
    $
    473,528
    
    
    $
    182,460
 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 31,2003
    
    2002
    
    2001Standardized measure, beginning
    
    $
    316,965
    
    
    $
    119,259
    
    
    $
    310,001Net revisions
    
    
    41,715
    
    
    
    119,995
    
    
    
    (1,820
    )Extensions, discoveries and other changes
    
    
    680,136
    
    
    
    136,194
    
    
    
    177,819Sales of reserves in place
    
    
    
    
    
    
    
    
    
    
    Changes in future development costs
    
    
    (10,603
    )
    
    
    (40,825
    )
    
    
    (31,066
    )Sales of oil and gas, net of production costs
    
    
    (96,357
    )
    
    
    (39,985
    )
    
    
    (39,762
    )Net change in prices and production costs
    
    
    605,892
    
    
    
    91,501
    
    
    
    (407,434
    )Development costs incurred during the
period that reduce future development costs
    
    
    8,886
    
    
    
    1,573
    
    
    
    Accretion of discount
    
    
    47,353
    
    
    
    18,246
    
    
    
    49,324Net change in income taxes
    
    
    (458,474
    )
    
    
    (88,993
    )
    
    
    62,197Standardized measure, ending
    
    $
    1,135,513
    
    
    $
    316,965
    
    
    $
    119,259
 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. 44




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##### Table of Contents



E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES (US$000): UNITED STATES Years Ended
    
    December 31,
    
    December 31,
    
    December 31,2003
    
    2002
    
    2001Acquisition costs  unproved properties
    
    $
    1,603
    
    
    $
    937
    
    
    $
    310Exploration
    
    
    55,095
    
    
    
    22,722
    
    
    
    33,845Development
    
    
    43,111
    
    
    
    28,620
    
    
    
    11,950Total
    
    $
    99,809
    
    
    $
    52,279
    
    
    $
    46,105
 CHINA Years Ended
    
    December 31,
    
    December 31,
    
    December 31,2003
    
    2002
    
    2001Acquisition costs  unproved properties
    
    $
    16,027
    
    
    $
    8,979
    
    
    $
    11,944Exploration
    
    
    
    
    
    
    
    
    
    
    Development
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    16,027
    
    
    $
    8,979
    
    
    $
    11,944
 F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (US$000): Years Ended
    
    December 31,
    
    December 31,
    
    December 31,2003
    
    2002
    
    2001Oil and gas revenue
    
    $
    121,581
    
    
    $
    43,342
    
    
    $
    41,201Production expenses and taxes
    
    
    (25,224
    )
    
    
    (11,411
    )
    
    
    (9,023
    )Depletion and depreciation
    
    
    (16,216
    )
    
    
    (9,712
    )
    
    
    (6,687
    )Total
    
    $
    80,141
    
    
    $
    22,219
    
    
    $
    25,491
 
 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. 
 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, 2003 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, 2003 and is incorporated herein by reference. 45




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##### Table of Contents



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, 2003, 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 12/31/2003
    
    
    5,902,500
    
    
    $
    3.80
    
    
    
    4,839,000Equity compensation plans
not approved by security
holders
    
    
    n/a
    
    
    
    n/a
    
    
    
    n/aTotal
    
    
    5,902,500
    
    
    $
    3.80
    
    
    
    4,839,000
 
 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, 2003 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, 2003 and is incorporated herein by reference. 
 Part IV 
 Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.  (a)
    
    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.  (b)
    
    The Company filed a current report on Form 8-K dated October 28, 2003
disclosing under Item 12 Results of Operations and Financial
Conditions its third quarter earnings conference call for November 4,
2003.  The Company filed a current report on Form 8-K dated November 4,
2003 disclosing under Item 12 Results of Operations and Financial
Conditions its earnings for the third quarter 2003. 46




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##### Table of Contents



Exhibit Number Description 3.1
    
    
    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)*3.3
    
    
    Code of Ethics for Chief Executive Officer and Senior
Financial Officers of Ultra Petroleum Corp.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
    
    
    Third Amendment to First Amended and Restated Credit
Agreement dated December 12, 2003 among Ultra Resources, Inc.,
Bank One, N.A., Union Bank of California, N.A., Guaranty Bank
FSB, Hibernia National Bank, Compass Bank, Bank of Scotland and
Fleet National Bank.10.2
    
    
    Second Amendment to First Amended and Restated Credit
Agreement dated May 14, 2003 among Ultra Resources, Inc., Bank
One N.A., Union Bank of California, N.A., Guaranty Bank FSB,
Hibernia National Bank, Compass Bank and Bank of Scotland
(incorporated by reference to Exhibit 10.1 of the Companys
Quarterly Report on Form 10-Q for the period ended June 30, 2003)10.3
    
    
    First Amendment to First Amended and Restated Credit
Agreement dated November 4, 2002 among Ultra Resources, Inc.,
Bank One N.A., Union Bank of California, N.A., Hibernia National
Bank, Guaranty Bank, FSB and Compass Bank (incorporated by
reference to Exhibit 10.1 to the Companys annual report on Form
10-Q for period ended December 31, 2002)10.4
    
    
    First Amended and Restated Credit Agreement dated March
1, 2002 among Bank One, N.A., Union Bank of California, N.A.,
Guaranty Bank, FSB, Hibernia National Bank, Ultra Resources, Inc.
and Banc One Capital Markets, Inc. (incorporated by reference to
Exhibit 10.1 to the Companys Annual Report on Form 10-K for the
period ended December 31, 2001)10.5
    
    
    First Amendment to Credit Agreement dated July 19, 2001
(incorporated by reference to Exhibit 10.1 to the Companys
Quarterly Report on Form 10-Q for the period ended September 30,
2001)10.6
    
    
    Credit Agreement dated March 22, 2000 (incorporated by
reference to Exhibit 10.1 of the Companys Quarterly Report on
Form 10-Q for the period ended June 30, 2001)10.7
    
    
    Articles of Merger dated July 16, 2001 (incorporated by
reference to Exhibit 10.1 to the Companys Quarterly Report on
Form 10-Q for the period ended September 30, 2001)10.8
    
    
    Plan of Merger and Reorganization dated July 16, 2001
(incorporated by reference to Exhibit 10.1 to the Companys
Quarterly Report on Form 10-Q for the period ended September 30,
2001)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.*31.1
    
    
    Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)*31.2
    
    
    Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
 47




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##### Table of Contents



*32.1
    
    
    Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)*32.2
    
    
    Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
  *
    
    Filed herewith 
 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 12, 2004
    
    By:
    
    -s- Michael D. WatfordName:
    
    Michael D. WatfordTitle:
    
    Chairman of the Board,Chief Executive Officer and President
 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. Watford
    
    Chairman of the Board,Michael D. Watford
    
    Chief Executive Officer and President
    
    March 12, 2004-s- W. Charles HeltonW. Charles Helton
    
    Director
    
    March 12, 2004-s- James E. NielsonJames E. Nielson
    
    Director
    
    March 12, 2004-s- Robert E. RigneyRobert E. Rigney
    
    Director
    
    March 12, 2004-s- James C. RoeJames C. Roe
    
    Director
    
    March 12, 2004-s- F. Fox Benton IIIF. Fox Benton III
    
    Chief Financial Officer
    
    March 12, 2004
 48




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##### Table of Contents



EXHIBIT INDEX Exhibit Number Description 3.1
    
    
    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)*3.3
    
    
    Code of Ethics for Chief Executive Officer and Senior
Financial Officers of Ultra Petroleum Corp.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
    
    
    Third Amendment to First Amended and Restated Credit
Agreement dated December 12, 2003 among Ultra Resources, Inc.,
Bank One, N.A., Union Bank of California, N.A., Guaranty Bank
FSB, Hibernia National Bank, Compass Bank, Bank of Scotland and
Fleet National Bank.10.2
    
    
    Second Amendment to First Amended and Restated Credit
Agreement dated May 14, 2003 among Ultra Resources, Inc., Bank
One N.A., Union Bank of California, N.A., Guaranty Bank FSB,
Hibernia National Bank, Compass Bank and Bank of Scotland
(incorporated by reference to Exhibit 10.1 of the Companys
Quarterly Report on Form 10-Q for the period ended June 30, 2003)10.3
    
    
    First Amendment to First Amended and Restated Credit
Agreement dated November 4, 2002 among Ultra Resources, Inc.,
Bank One N.A., Union Bank of California, N.A., Hibernia National
Bank, Guaranty Bank, FSB and Compass Bank (incorporated by
reference to Exhibit 10.1 to the Companys annual report on Form
10-Q for period ended December 31, 2002)10.4
    
    
    First Amended and Restated Credit Agreement dated March
1, 2002 among Bank One, N.A., Union Bank of California, N.A.,
Guaranty Bank, FSB, Hibernia National Bank, Ultra Resources, Inc.
and Banc One Capital Markets, Inc. (incorporated by reference to
Exhibit 10.1 to the Companys Annual Report on Form 10-K for the
period ended December 31, 2001)10.5
    
    
    First Amendment to Credit Agreement dated July 19, 2001
(incorporated by reference to Exhibit 10.1 to the Companys
Quarterly Report on Form 10-Q for the period ended September 30,
2001)10.6
    
    
    Credit Agreement dated March 22, 2000 (incorporated by
reference to Exhibit 10.1 of the Companys Quarterly Report on
Form 10-Q for the period ended June 30, 2001)10.7
    
    
    Articles of Merger dated July 16, 2001 (incorporated by
reference to Exhibit 10.1 to the Companys Quarterly Report on
Form 10-Q for the period ended September 30, 2001)10.8
    
    
    Plan of Merger and Reorganization dated July 16, 2001
(incorporated by reference to Exhibit 10.1 to the Companys
Quarterly Report on Form 10-Q for the period ended September 30,
2001)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.*31.1
    
    
    Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)*31.2
    
    
    Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
 49




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##### Table of Contents



*32.1
    
    
    Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)*32.2
    
    
    Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
  *
    
    Filed herewith 50