SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to SectionANNUAL REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange
Act ofOF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001.2002.
[ ] Transition Report Pursuant to SectionTRANSITION REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities
Exchange Act ofOF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM __________TO ___________.
Commission File Number:COMMISSION FILE NUMBER: 0-29370
ULTRA PETROLEUM CORP.
(Exact Name of Registrant as specifiedSpecified in its charter)
YUKON TERRITORY, CANADA N/A
(Jurisdiction of incorporation (I.R.S. Employer
or organization) Identification No.)
16801 GREENSPOINT PARK DRIVE, SUITE 370
Houston, Texas 77060
(Address of principal executive offices)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)Telephone Number, Including Area Code)
SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------
Common Shares American Stock Exchange
without par value 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. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). YES [ ] NO [ X ]
As of March 1, 2002,3, 2003, the Registrant had 73,383,41874,087,668 common shares outstanding,
and the aggregate market value of the common shares held by non-affiliates was
approximately $496,805,739.90$659,380,245 based upon the closing price of $6.77$ 8.90 per share for
the common stock on March 1, 2002,3, 2003, as reported on the American Stock Exchange.
Documents incorporated by reference: The definitive Proxy Statement for the 20022003
Annual Meeting of Stockholders, which will be filed with the Securities and
Exchange Commission within 120 days after December 31, 2001,2002, is incorporated by
reference in Part III of this Form 10-K.
1
TABLE OF CONTENTS
Page
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PART I
ItemITEM 1. Business........................................................................DESCRIPTION OF BUSINESS ...................................... 3
ItemITEM 2. Property........................................................................ 13
ItemDESCRIPTION OF PROPERTY ...................................... 8
ITEM 3. Legal Proceedings............................................................... 17
ItemLEGAL PROCEEDINGS ............................................ 12
ITEM 4. Submission of matters to a vote of security holders............................. 17SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .......... 12
PART II
ItemITEM 5. Market for registrant's common equity and related stockholder matters............ 17
ItemMARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS .......................................... 12
ITEM 6. Selected Financial Data.......................................................... 18
ItemSELECTED FINANCIAL DATA ...................................... 13
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................. 19
ItemMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS .................................... 14
ITEM 7A Quantitative and Qualitative Disclosures About Market Risk....................... 33
ItemQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ... 28
ITEM 8. Financial Statements and Supplementary Data...................................... 33
ItemFINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .................. 29
ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial
Disclosures................................................................. 33CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES .................................... 45
PART III
ItemITEM 10. Directors and Executive Officers of Registrant................................... 33
ItemDIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT ............... 45
ITEM 11. Executive Compensation........................................................... 34
ItemEXECUTIVE COMPENSATION ....................................... 45
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.................. 34
ItemSECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 45
ITEM 13. Certain Relationships and Related Transactions................................... 34CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............... 46
ITEM 14. CONTROLS AND PROCEDURES ...................................... 46
PART IV
Item 14. Exhibits, Consolidated Financial Statement Schedules and Reports on
Form 8-K.................................................................... 34
Signatures....................................................................... 36ITEM 15. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K .......................................... 46
SIGNATURES ................................................... 48
2
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. Ultra is an
independent oil and gas company engaged in the development, production,
operation, exploration and acquisition of oil and gas properties. The Company's
operations are focused primarily in the Green River Basin of southwest Wyoming
and Bohai Bay, offshore China. On January 16, 2001,From time to time, the Company completedevaluates other
opportunities for the acquisition through a Planexploration and development of Arrangement of all of the outstanding shares of Pendaries Petroleum Ltd., a
Houston based independent oil and gas exploration company with its primary focus
in the Bohai Bay, China. In exchange, the Company issued 14,994,958 shares of
its common stock. The transaction was valued at approximately $40 million based
on share price ofproperties.
Ultra and is recorded using the purchase method of accounting.
In July 2001 Ultra implemented a restructuring of the Company's
subsidiaries; Ultra Resources, Inc., Ultra Petroleum (USA) Inc., Pendaries
Petroleum Ltd. and Sino-American Energy Corporation. This restructuring allowed
the Company to maximize the tax benefits from the net operating losses (NOL) in
the various entities and simplify the overall corporate structure and
administration of the Company. To accomplish this goal, the Company formed on
July 11, 2001 UP Energy Corporation, a Nevada corporation, so as to transfer all
of the stock of Ultra Resources, Inc. and Sino-American Energy Corporation in
exchange for UP Energy Corporation stock. On July 13, 2001 Pendaries Petroleum
Ltd was dissolved in New Brunswick, Canada, its place of incorporation. Ultra
Petroleum (USA) Inc. was merged into Ultra Resources, Inc. on July 16, 2001.
Thus after the restructuring, UP Energy Corporation is the wholly-owned
subsidiary of Ultra Petroleum Corp., the parent, and Ultra Resources, Inc. and
Sino-American Energy Corporation are wholly owned subsidiaries of UP Energy
Corporation and now form a consolidated group for federal income taxes.
GREEN RIVER BASIN - WYOMING
Ultra holdsowns interests in approximately 265,395187,773 gross (163,547(122,393 net) acres
in Wyoming covering approximately 410300 square miles. The Company owns working
interest in approximately 119 gross producing wells and is operator of 60% 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 southwestSouthwest Wyoming. In 2002, 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 2002, capital expenditures
in Wyoming comprised approximately 83% of the Company's total, and the Company
plans to spend approximately 75% of its 2003 capital budget in Wyoming.
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 2002, the Company reported no production or reserves attributable
to its China property. The Company spent approximately 17% of its 2002 capital
budget and plans on spending approximately 25% of its 2003 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, four additional discoveries have
been made on the Blocks.
The Company's annual report on Form 10-K, quarterly reports on Form
10-Q and current reports on Form 8-K, are made available to the public on the
Company's website at www.ultrapetroleum.com.
BUSINESS STRATEGY
Green River Basin, drilling program targets the upper Cretaceous Lance
and Mesaverde sands. These together, form a thick sequence of tight, over-
pressured, gas charged sands which were deposited some 65 million years ago in
the developing basin which is bounded on the east by the Wind River Mountains
and to the west by the Western Overthrust and LaBarge Platform. The thickest
accumulations of these potential play sands underlie the Pinedale Anticline
which trends northwest to southeast just west of the Wind River Mountains.
The Lance and Mesaverde reservoirs are characterized as, Basin Center Tight
Gas Sand reservoirs. As such there are several characteristics of these
reservoirs that set them apart from normal hydrocarbon accumulations. These
types of reservoirs are generally formed in the deep portions of sedimentary
basins. The sands have porosity and permeability levels lower than normally
associated with productive zones. Pressures within the reservoir are abnormal,
in the case of this accumulation they are greater than normal due to the gas
migrating into the reservoir rock from a rich hydrocarbon source bed at rates
exceeding those at which the gas can escape.
3
The Lance and Mesaverde consist of a thick sequence of inter-bedded sand
and shale which were deposited over the broad depositional basin by a major
braided river system which drained across this area from the highlands in the
Idaho area to the Cretaceous Seaway which was located in south central Wyoming
at the time. Due to the nature of the depositional environment there exists an
abundance of stacked sand bodies all of which are relatively small in size and
extent but when taken together form a major accumulation of interconnected
reservoir bodies that contribute to the high production potential from these
zones.
The Lance can be over 5000 feet thick with 1000 feet or more being
potential reservoir. The underlying Mesaverde section can be up to an additional
1000 feet thick with 300 or more feet of pay sand. The Mesaverde sections
differs from the overlying Lance in that, during deposition the area was more
stable and closer to the coast thus the sands are somewhat better developed,
coal beds are present in parts of the area and the reservoir pressures are
somewhat higher than the Lance.
Exploratory Wells. During the year-ended December 31, 2001, the Company
drilled or caused to be drilled a total of 23 gross exploratory (9.09 net)
wells. Of these, 22 gross (8.67 net) wells were considered productive and the
one non-productive location was abandoned by the operator due to mechanical
reasons. From January 1, 2002 through March 1, 2002, the Company drilled one
gross (.425 net) well which is undergoing completion at this time and which
appears to be productive. During the second half of 2001, the Company drilled
four field extension wells on the flanks of the then identified productive
fairway of the Pinedale Anticline based on 3-D seismic. All four (3.23 net)
wells were commercially productive. Initial production rates for these wells
ranged from 8.8 Mmcf to 12.5 Mmcf per day. Because of the rapid decline
normally experienced in the first six months of a well's production life, the
Company typically only places two production units on a well site, which can
constrain initial production to 12-12.5 Mmcf per day. The success of these
wells confirmed the Company's geologic interpretation in these areas of the
Anticline and proved that the currently defined fairway can be expanded.
Additionally during the second half of 2001, the Company participated in the
drilling of 2 (0.74 net) wells that penetrated the Mesaverde, a productive
horizon underlying the Lance formation, the primary productive interval in the
Company's producing wells. These wells have been successfully completed in the
Mesaverde and are currently producing from that horizon. One of these wells was
drilled in northern and the other was drilled in the southern portion of the
Pinedale Anticline. During the first quarter of 2002 another one gross (0.43
net) well in the southern portion of the Pinedale Anticline was drilled into the
Mesaverde formation and appears to be productive in that horizon. However, the
Company does not anticipate that the Mesaverde will be productive across the
entire Pinedale Anticline.
Development Wells. In addition to the 23 gross (9.10 net) exploratory
wells, the Company drilled 8 gross (5.1 net) successful development wells in the
Jonah Field area as well as one gross (.425 net) development well in the
Warbonnet area of the Pinedale Anticline which was successful.
During 2001, the Company acquired a new 100 square mile 3-D seismic survey
on the west flank of the Pinedale Anticline. The Company has received the first
of several data sets to be received from this survey. The Company expects to
receive the remaining data sets by the end of the first quarter of 2002. The
Company anticipates that the data sets will provide a clear picture of the
structural and stratigraphic attributes of the acreage just to the west of the
Anticline where it is thought that additional productive structures may be
located. This survey, which overlaps the existing 3-D surveys owned by the
Company, provides the Company with 330 total square miles of modern (1999-2001),
high quality 3-D seismic data over most of the Company's Pinedale Anticline area
acreage. The Company believes that this data and the proprietary processing and
interpretation techniques utilized by the Company provide the clearest view of
the objective formations and structures in this area. The Company believes that
these techniques
4
have greatly contributed to the high success rate for both development and
exploratory drilling that the Company has achieved over the last two years.
Ultra plans to drill and or participate in up to 25 gross (11.4 net) wells
in 2002. The Company plans to drill the majority of these wells in and around
the current activity areas on the Pinedale Anticline. Additionally, the Company
expects to drill at least one wildcat well to test one or more areas identified
by the 3-D seismic outside the current fairway. The drilling plans are a
combination of development, step-out and exploratory locations selected with the
objective of expanding the proved acreage of the Anticline and extended areas
while maintaining a good balance of production, risk management, reserves
bookings and economic prudence in the current operating market.
The Company had estimated net proved reserves as of December 31, 2001 of
444,727 Mmcfe, 36% of which were proved developed, with a PV-10 of approximately
$182,460,000. The Company's net daily gas sales at December 31, 2001 were
approximately 41.6 Mmcf per day from a total of 72 producing wells. Total sales
of hydrocarbons were approximately 43.3 Mmcfe per day.
The Company plans to continue to identify, develop and explore the
gas-rich acreage in the Green River Basin. At year-end 2001,The Green River Basin drilling
program targets the Company had 133
commercialupper Cretaceous Lance locations classified as proved undeveloped onand Mesaverde sands in the area of
the Pinedale Anticline and another 174 classified as probable under its SEC pricing case.
There can be no assurance that the Company will drill these locations or that
those drilled will prove to be commercially productive.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 intercept deepertest other potentially productive horizons.
The Company is utilizing its 3-D seismic to map these deeper potentialpotentially
productive intervals and to identify further extensions of the productive Lance
fairway.
BOHAI BAY - CHINA
Bohai Bay, History
With the acquisition of Pendaries Petroleum Ltd. on January 16, 2001, the
Company became active in oil and gas exploration and development in Bohai Bay,
China. The acquisition brought to Ultra an 18.182% working interest in Block
04/36 (454,000 gross acres), a 15.0% working interest in Block 05/36 (311,000
gross acres) (jointly the "Blocks") and a 10.0% working interest in the (76,107
gross acres) Getuo block. A wholly-owned subsidiary of Kerr-McGee Corporation is
the operator of all three blocks.
At the time of the acquisition, three oil discoveries had been made on the
Blocks. The CFD 2-1 and CFD 11-1 discoveries are located in the 04/36 block and
the CFD 12-1 discovery is located in the 05/36 block. The discoveries were in
various stages of appraisal and a 1,100 square kilometer 3-D seismic survey had
recently been acquired covering the discoveries and a large number of high
potential exploration targets on the two blocks.
Petroleum Sharing Contracts
Contracts covering offshore exploration blocks are Petroleum Sharing
Contracts (PSCs) entered into by and between China National Offshore Oil Company
("CNOOC") and foreign oil and gas companies ("Contractor"). CNOOC has the
exclusive rights to offshore hydrocarbon leases granted in law from the Chinese
government and has the right to enter into PSCs with foreign oil and gas
companies. These PSCs have a maximum term of 30 years and are divided into
three periods: exploration, development and production. The Contractor pays 100%
of the exploration costs required for exploration operations and has the right
to act as operator until any
5
development has repaid all of the exploration and development costs. CNOOC has
the right to acquire a 51% working interest in any commercial development and
will pay their proportionate 51% share of all development costs. The Contractor
receives up to a 71% share of the oil and gas produced until it has recovered
the exploration costs. After recovery of exploration expenses, the Contractor's
share of production is approximately 40-45%. Contractors have the right to take
their share of production in kind and sell it on the international market.
The Contract is divided into three (3) periods not to exceed 30 years in
total. Extensions to any of the three periods of the contract can be negotiated
with CNOOC. A brief description of the 3 periods of the contracts is presented
below.
The exploration period is a 7-year period consisting of an initial term of
3 years, followed by two terms of 2 years each. A relinquishment of 25% of the
then contracted acreage is made at the beginning of the second and third terms.
All acreage not under appraisal, development or production is relinquished at
the end of the seven-year period.
The development period for any oil or gas field discovered within the
contract area during the exploration period begins upon approval of the Overall
Development Plan (ODP) by the Chinese government. The contract does not impose
a time limit on the development period of individual fields.
The production period for any oil and gas field within the contract area is
for 15 years following commencement of commercial production. The contract
calls for negotiated extensions to the production period due to circumstances
warranting longer field production.
Status of Petroleum Sharing Contracts
Block 04/36: The PSC covering this block became effective October 1, 1994.
Negotiations with the Chinese government in 1997 resulted in the contractor not
having to make the mandatory 25% acreage relinquishment at the beginning of the
second exploration term. In September 1999 a 25% relinquishment was made to
fulfill the required relinquishment schedule at the beginning of the third
exploration term. Negotiations at this time resulted in the addition of 31,876
acres to the south side of the block to completely include certain prospects
within the block boundary. These negotiations also included a one-year
extension of the third exploration term to September 30, 2002. As the contract
now stands, the exploration period will end at the end of September 2002.
Barring an extension, at that time all acreage not under appraisal, development
or production must be relinquished. Negotiations are ongoing to extend the
exploration period.
Block 05/36: The PSC covering this block became effective March 1, 1996.
At the end of the first exploration term in February 1999, a 25% relinquishment
was made. At the same time, a one-year extension to the second exploration term
was negotiated, extending the total exploration period to 8 years. The second
exploration term ended in February 2002 with another 25% acreage relinquishment
submitted. The third (and final) exploration term will continue until the end
of February 2004 when, barring an extension, all acreage not under appraisal,
development or production must be relinquished.
The relinquished areas of the Blocks were selected using geologic and
geophysical modeling. The Company believes that the relinquishments were made to
minimize the relinquishment of prospective acreage.
Drilling Activity
In 2001, utilizing the newly received 3-D seismic data, the Company
participated in drilling 4 (0.61 net) exploratory and 12 (2.02 net) appraisal
wells on the Blocks. The exploratory drilling
6
resulted in 2 new discoveries on the Blocks and the appraisal drilling brought
the CFD 11-1 and CFD 11-2 fields to commercial status and partially appraised
the CFD 12-1 and CFD 12-1S field discoveries. One of the exploratory wells was a
dry hole and resulted in the relinquishment of the Getuo Block. Individual block
activity is listed below:
Block 04/36 (18.2% W.I.): The Company participated in drilling a total of 9
(1.64 net) wells in the 04/36 block in 2001. This included 2 (0.36 net)
exploratory wells in the block. One exploratory well discovered the CFD 11-2
field and the other was a dry hole at the CFD 10-1 prospect resulting in a 50%
success rate. Ultra drilled 7 (1.27 net) successful appraisal wells on the block
in 2001. Five of these appraisal wells were drilled on the CFD 11-1 field thus
completing the appraisal process on that field. Two of the appraisal wells were
drilled on the CFD 11-2 field (discovered in June 2001) to bring commercial
status to that accumulation.
Block 05/36 (15.0% W.I.): During 2001, Ultra drilled 6 (0.90 net) wells in
the 05/36 block. This included one (0.15 net) exploratory well that was the new
field discovery CFD 12-1S-1 that tested in excess of 6,000 BOPD from multiple
zones. This resulted in the 05/36 block having a 100% success rate for
exploratory drilling. A total of 5 (0.75 net) successful appraisal wells were
drilled on the CFD 12-1 (4 wells, 0.60 net) and CFD 12-1S (1 well, 0.15 net)
discovery areas.
Getuo block (10.0% W.I.): At the time of the Pendaries acquisition, the
Getuo block was burdened by a drilling commitment of one well to be drilled by
June of 2001. Due to the lack of prospectivity, the partners attempted
unsuccessfully to fulfill this commitment through a cash payment to the Chinese.
The commitment well was drilled to the required depth and abandoned. With the
commitment fulfilled, the Getuo block was relinquished as planned. Thus during
2001, Ultra participated in drilling one (0.10 net) well in the Getuo block.
Ultra had placed negative value in the amount of the net commitment on the block
in the acquisition of Pendaries.
The Company expects to submit a finalized development plan for the CFD 11-1
and CFD 11-2 fields to the Chinese government by mid-year 2002 with first
production scheduled in 2004.
The Company plans to drill additional exploration and appraisal wells
in 20022003 on the two blocksBlocks and to continue appraisal activitydevelopment planning on the CFD
12-1, CFD 12-1S and CFD 2-1appraised
discovery areas. PENNSYLVANIA
During the past year Ultra entered into a joint venture in Pennsylvania
covering 10,801 gross (5,401 net) acres of undeveloped leasehold acreage and is
continuing to acquire additional acreage.
Texas
The Company operates one (0.66 net) wellis utilizing its 3-D seismic to map potential
productive intervals and owns working interests in two
(0.22 net) other wells in Pecos and Winkler Counties, Texas.to identify further prospects. The Company believes these interests are not materialsubmitted an
Overall Development Plan ("ODP") for the CFD 11-1 and 11-2 fields to the Company.Chinese
National Offshore Oil Company ("CNOOC") in December 2002. The Company does not generate any revenuesODP was approved
by CNOOC and forwarded to the Chinese government with final approval expected in
Canada.the second quarter of 2003. Construction of the Floating Production Storage
Offloading ("FPSO") vessel and offshore platforms has begun and it is
anticipated that oil production will commence in the second half of 2004.
3
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.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 7
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 greatly 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.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-plannedfund 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 2002, the Company experienced significant pricing differentials
in southwestern Wyoming relative to the rest of the country primarily due to
production in the region exceeding interstate pipeline capacity to deliver gas
to the consuming west and east. The ability to market oil andproblem was especially pronounced during the
summer months when local demand for natural gas depends on numerous factors beyondin the Company's control. These factors include:
.Rocky Mountain region is
typically extremely low. Without sufficient pipeline capacity to move the extentgas to
markets, gas was `bid down' at the inlet of domestic production and imports of oil and natural gas;
. the proximity of natural gas production to natural gas pipelines;
. the availability of pipeline capacity;
. the demand for oil and natural gas by utilities and other end users;
. the availability of alternative fuel sources;
. the effects of inclement weather;
. state and federal regulations of oil and natural gas marketing; and
. federal regulation of natural gas sold or transported in interstate commerce.pipelines. Because of
these factors,this large differential, the Company may be unable to market allreceived prices significantly lower than
those received by companies with production in other regions of the oilU.S.
Currently, significant capacity expansions are planned or under
construction that should relieve this shortage of `export' capacity from
southwestern Wyoming. Kern River Pipeline which serves southern California,
Nevada, Arizona and natural gas it produces, including oilnorthern Mexico is expanding by over 900 MMcf/d or 100% to
1.73 Bcf/d and natural gas that mayis scheduled to be produced
fromin service May 2003. Additionally, Northwest
Pipeline, which serves the Bohai Bay properties. In addition, it mayPacific Northwest, has announced an expansion of 175
MMcf/d and should be unablein service by late 2003. These expansions are anticipated
to obtain favorable
pricesmoderate the price differentials between southwestern Wyoming and the rest of
the oil and natural gas it produces.country. However, there can be no assurance that the expansions will
eliminate large differentials.
The Company is dependent on oiluses forward sales and gas leases in Wyoming and two petroleum
contracts in China in orderfinancial derivations 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 onreduce the
lease extends the lease terms
until cessation of that production. The China petroleum contracts are for a
maximum of 30 years and are divided into 3 periods; exploration period,
development period and production period. 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 approvalvolatility of the Ministry of Energy. There is no limit on the time
required 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.prices it receives. 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 the major oil 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 8
activity is
proposed. This EIS encompasses approximately 200,000 gross acres
under lease by the Companyarea north of the Jonah Field, including the
Pinedale Anticline, which is where most of the Company's exploration and
development is taking place. This environmental study included an analysis of
the geological and reservoir characteristics of the area plus the necessary
environmental studies related to wildlife, surface use, socio-economic and air
quality issues. This has been an important step in
giving the Company the ability to develop its natural gas resources in the
region. 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; rather Ultra must submit
applications to the BLM's Pinedale field manager for permits to drill and for
other required authorizations, such as rights-of-waysrights-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.
4
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 isare deemed reasonably necessary to
mitigate the impactsimpact of drilling and production operations in the area.
To date, the Company has been required to expendexpended 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, and it is expected that the
Company's costs of complying with these regulations willmay continue to be
substantial. Compliance costs under the ROD/EIS and any revisions to the ROD/EIS
could become material. In addition,Further, any additional limitations and mitigation
measures could further increase production costs, further, delay exploration, development
and production activities and curtail exploration, development and production
activities altogether.
The Company also co-owns leases on a significant area of 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 of 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-
acre40-acre spacing, the Company has drilled an additional 22 gross
(14.0 net) wells.
Eight gross (5.1 net) of these were drilledwells during 2000 and 2001. All 43 of the wells drilled by the
Company in Jonah Field have been productive. Another operator in Jonah Field is
currently investigating the feasibility of downspacing the field to 20 acres per
location. While preliminary results appear encouraging, there are no assurances
that the field will ultimately be further downspaced. Downspacing will require
further environmental review and may require an additional EA or EIS.
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 "Corporation"Agency/Corporation of the Year" Awardaward from the Wyoming
Wildlife Federation primarily for its support of the Pinedale area
wildlife studies. Also during 2001, the Company receivedand the "Regional Administrator's Award for Environmental
Achievement" from the U.S. Environmental Protection Agency for its work in protecting the air quality in Wyoming's Class
I wilderness area through the participation in installation of advanced
9
burner technology at the coal burning Naughton power plant which is upwind of
the Pinedale area. The technology installed reduced nitrogen dioxide emissions
by 1,000-2,000 tons per year.Agency.
REGULATION
Oil and Gas Regulation
The availability of a ready market for oil and gas production depends
upon numerous factors beyond the Company's control. These factors include state
and federal regulation of oil and gas production and transportation, as well as
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the amount of oil
and gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive gas well may be "shut-in" because of an over-supply of
gas ora lack of an
available gas pipeline in the areas in which the Company may conduct operations.
State and Federalfederal 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,federal, state and local
agencies.
The Company's sales of natural gas are affected by the availability,
terms and costs of transportation.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
5
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-
servicecost-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 state or Indianstate oil
and gas leases, such operations must comply with numerous regulatory
restrictions, including various nondiscrimination statutes, royalty and related
valuation requirements, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management ("BLM")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""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
10
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 RegulationRegulations
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.control and its activities in China are subject to the
laws and regulations of China. It is anticipated that, absent the occurrence of
an extraordinary event, compliance with existing federal, state and local laws,
rules and regulations governing the release of materials in the environment or
otherwise relating to the protection of the environment will not have a material
effect upon the Company's operations, capital expenditures, earnings or
competitive position.
Ultra'sThe Company's activities with respect to exploration, drilling and
production from wells, 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.
Waste Disposal. UltraSolid 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.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
6
federal laws applicable to oil and gas wastes and properties have gradually
become stricter.stricter over time. Under these 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 hasand various state agencies have limited the
disposal options for certain wastes, that areincluding wastes designated as hazardous
under 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 RCRA or the 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 ("PRP"PRPs"), include the current and certain
past owners and operators of a facility where there is or has been a release or threat
of release of a Hazardous Substance and persons who disposed of or arranged for
the
11
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 may havehas generated and maywill generate wastes that fall within CERCLA's
definition of Hazardous Substances.Substance. The Company may also be an owner or operator
of facilities on which Hazardous Substances have been released by previous owners or operators. Ultrareleased. 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. TheTo
its knowledge, the Company has not been named a PRP under CERCLA nor does the Company
know ofhave any
prior owners or operators of its properties that arebeen 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
Federalfederal regulations for the control of emissions from sources of air pollution.
Local air
quality districts do much of the air quality regulation of sources in
California. California requiresFederal 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 permitting
requirements including
additional permits. Because of the severity of the
ozone (smog) problems in portions of California, theFederal and state has the most severe
restrictions on the emissions of volatile organic compounds (VOC) and nitrogen
oxides (Nox) of any state. Producing wells, gas plants and electric generating
facilities, all of which are owned by us generate VOC and Nox. Some of the
Company's producing wells are in counties that are designated as nonattainment
for ozone and are therefore potentially subject to restrictive emission
limitations and permitting requirements. If the ozone problems in the state are
not resolved by the deadlines imposed by the federal Clean Air Act (2005 -
2010), even more restrictive requirements may be imposed including financial
penalties based upon the quantity of ozone producing emissions. California also
operates a stringent programlaws designed to control hazardous (toxic)
air pollutants, which 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, although the Company believes that in the latter cases the
Company would have enough permitted or permittable capacity to continue its
operations without a material adverse effect on any particular producing field.sources.
Clean Water Act. The Clean Water Act ("CWA") imposes restrictions and
strict controls regarding the discharge of wastes, including produced waters and
other oil and natural gas wastes, into waters of the United States, a term
broadly defined. These controls have become more stringent over the years, and
it is probable that additional restrictions will be imposed in the future.
Permits must be obtained to discharge pollutants into federal waters. The CWA
provides for civil, criminal and administrative penalties for unauthorized
discharges of pollutants and of oil and hazardous substances. It imposes
substantial potential liability for the costs of removal or remediation
associated with discharges of oil or hazardous substances. State laws governing
discharges to water also provide varying civil, criminal and administrative
penalties and impose liabilities in the case of a discharge of petroleum or its
derivatives, or other hazardous substances, into state waters. In addition, the
EPA has promulgated regulations that may require usthe 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.
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.
127
EMPLOYEES
As of March 1, 2002,3, 2003, the Company had 2022 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. 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, 2001,2002, the Company owned developed oil and gas leases
totaling 4,6805,449 gross (2,169(2,564 net) acres of which 85% are located in the Green River Basin of Sublette
County, Wyoming andwhich represents 88% of the remaining 15% are located in
Texas. The Company also owned production equipment associated with certain
developed leases.Company's total gross acreage. The
Company owned undeveloped oil and gas leases totaling 272,236182,324 gross (167,160(119,829
net) acres of which 97% are located in the Green River Basin of Sublette County, Wyoming. Pennsylvania acreage totals 10,801 gross
(5,401 net)Wyoming which is 3%represents
92.5% 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 a large
undeveloped block northwestwest of the Anticline. The Company also owns 2,160 gross
(1,322 net) acresPinedale
Anticline as well as acreage in the Jonah Field. Holding costs of leases in
Wyoming not held by production were approximately $183,127$242,710 for the fiscal year
ending December 31, 2001.2002. The primary target on the Company's Wyoming acreage is
the tight gas sands of the upper Cretaceous Lance formation.
Exploratory Wells. During the year-ended December 31, 2002, the Company
drilled or caused to be drilled a total of 10 gross (5.22 net) exploratory wells
on the Green River Basin properties. All the wells were completed and are
producing. The exploratory wells in which the Company participated during 2002
were field extension wells around the perimeter of the known accumulation of the
Pinedale Anticline.
Development Wells. The Company drilled 16 gross (5.5 net) successful
development wells in the Pinedale Field area. 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 2002 resulted in an extension of the third exploration term to September
2003. As the contract now stands, the exploration period will end at the end of
September 2003. Barring an extension, at that time all acreage not under
appraisal, development or production must be relinquished. Negotiations are
ongoing to extend the exploration period beyond September 2003. 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. The second exploration term of this PSC ended in February 2002 with
another 25% acreage relinquishment submitted. The third (and final) exploration
term will continue through the end of February 2004 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.
8
The relinquished areas of the Blocks were selected using geologic and
geophysical modeling. The Company believes that the relinquishments were made to
minimize the relinquishment of prospective acreage.
Exploration / Appraisal Activity
In 2002, utilizing 3-D seismic data, the Company participated in
drilling 3 gross (0.55 net) exploratory and 2 gross (0.33 net) appraisal wells
on the Blocks. The exploratory drilling resulted in 2 new discoveries on the
Blocks. The other exploratory well was termed by the Operator as a
non-commercial oil discovery and is classified herein as a dry hole. Although
currently not economic, at some point in the future, changes in development
economics may allow for the commercial exploitation of this discovery. Both
appraisal wells were successful. The primary target formations on the Blocks are
the Tertiary Minghuazhen, Guantuao and Dongying formations.
Development Activity
The Company submitted an ODP for the CFD 11-1 and 11-2 fields to CNOOC
in December 2002. The ODP was approved by CNOOC and forwarded to the Chinese
government with final approval expected in the second quarter of 2003. Letters
of Intent (LOI) for contracts have been signed and construction started for
offshore production platforms and a Floating Production Storage Offloading
(FPSO) vessel, which will be leased from CNOOC under an operating lease for
these fields. The final contracts for these facilities will be signed upon
Chinese government approval of the ODP. The platform jackets are expected to be
installed offshore in summer 2003 with development well drilling scheduled to
start in fourth quarter 2003. The FPSO contract calls for the vessel to be on
offshore station in the third quarter of 2004 with oil production starting soon
thereafter.
The Company has signed a LOI for a 15 year contract (extensions up to
25 years provided) to lease its net share of an FPSO. The FPSO contract
specifies a 110,000-150,000 dead weight tons (DWT) double-hull FPSO with
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 (14,271 net) acres in Pennsylvania, which
represents 7.5% of the Company's total domestic undeveloped gross acreage.
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 12% of the Company's total
developed gross acreage. In 2002, the Company participated in the drilling of
one gross (0.15 net) well, which was not successful.
OIL AND GAS RESERVES
The following table below sets forth the Company's quantities of proved
reserves, for the year-endedyears-ended December 31, 2002, 2001 2000 and 19992000 as estimated by
independent petroleum engineers Netherland, Sewell & Associates, Inc. All of the
Company's proved oil and gas reserves are located in the United States.Green River Basin,
Wyoming. The table summarizes Ultra'sthe 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, 2002, 2001
2000 and 1999.2000.
9
December 31,
-------------------------------------
2002 2001 2000
1999
------- --------- ---------- ---- ----
Proved Undeveloped Reserves
Natural gas (MMcf)......................................... .................................... 444,513 273,433 75,249
34,751
Oil (MBbl)................................................. ............................................ 3,556 2,187 602
278
Proved Developed reservesReserves
Natural gas (MMcf)......................................... .................................... 222,608 150,397 85,141
36,480
Oil (MBbl)................................................. ............................................ 2,003 1,295 688 297
Total Proved Reserves (Mcfe).................................(MMcfe) ............................ 700,474 444,727 168,130 74,681168,132
Estimated future net cash flows, before income tax........... 531,676 1,052,126 92,938tax ....... $1,308,595 $531,676 $1,052,126
Standardized measure of discounted future net cash flows before. 473,528 $182,460 $ 493,243
Standardized measure of discounted future net cash flows,
after income tax............................. 182,460 493,243 41,275tax ...................................... $ 316,965 $119,258 $ 310,001
UncertaintyPRODUCTION 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 Estimatesoil and natural gas for the periods
indicated.
Year Ended December 31,
-----------------------
2002 2001 2000
---- ---- ----
PRODUCTION
Natural gas (Mcf) 16,495,751 11,500,446 5,297,421
Oil (Bbl) 151,215 116,413 50,386
----------- ----------- -----------
Total (Mcfe) 17,403,041 12,198,924 5,599,737
REVENUES
Gas sales $38,502,971 $38,204,298 $19,399,001
Oil sales 3,839,421 2,996,955 1,603,635
----------- ----------- -----------
Total Revenues 42,342,392 41,201,253 21,002,636
LEASE OPERATING EXPENSES
Production costs* 2,356,986 1,439,026 665,999
Severance/production taxes 4,116,012 4,425,345 2,253,793
Gathering 4,937,870 3,158,901 1,321,228
----------- ----------- -----------
Total Lease Operating Expenses $11,410,868 $ 9,023,271 $ 4,241,020
REALIZED PRICES
Natural gas (Mcf) $ 2.33 $ 3.32 $ 3.66
Oil (Bbl) $ 25.39 $ 25.74 $ 31.83
OPERATING COSTS PER MCFE
Production costs $ 0.14 $ 0.12 $ 0.12
Severance/production taxes $ 0.24 $ 0.36 $ 0.40
Gathering $ 0.28 $ 0.26 $ 0.24
----------- ----------- -----------
Total Operating Costs per Mcfe $ 0.66 $ 0.74 $ 0.76
- ----------
* Average production costs include lifting costs and remedial workover expenses.
10
PRODUCTIVE WELLS
As of Reserves and Future Revenues. The financial
statements included in this report contain estimates ofDecember 31, 2002, the Company's oiltotal gross and gas reserves and the discounted future net revenues from those reserves,wells were
as prepared by independent petroleum engineers and/or the Company. Therefollows:
Productive Wells* Gross Wells Net Wells
- ---------------- ----------- ---------
Natural Gas and Condensate 122 56.81
- ----------
*Productive wells are numerous uncertainties inherent in estimating quantities of proved oil and gas
reserves, including many factors beyond the control of the Company. Those
estimates are based on several assumptions that the United States Securities and
Exchange Commission (the "SEC") requires oil and gas companies to use, for
example, constant oil and gas prices. Such estimates are inherently imprecise
indications of future net revenues. Actual future production, revenues, taxes,
operating expenses, development expenditures and quantities of recoverable oil
and gas reserves might vary substantially from those assumed in the estimates.
Any significant variance in these assumptions could materially affect the
estimated quantity and value of reserves. In addition, the Company's reserves
might be subject to revisions based upon future production, results of future
exploration and development, prevailing oil and gas prices and other factors.
Moreover, estimates of the economically
13
recoverable oil and gas reserves, classifications of such reserves, and
estimates of future net cash flows, prepared by different engineers or by the
same engineers at different times, may vary substantially. Information about
reserves constitutes forward-looking information.
Ability to Replace Reserves. The Company's future success depends upon its
ability to find, develop and acquire oil and gas reserves that are economically
recoverable. As a result,producing wells plus shut-in wells the Company must locate and develop or acquire new oil
and gas reserves to replace those being depleted bydeems
capable of production. A gross well is a well in which a working interest is
owned. The Company must
do this even during periodsnumber of low oil and gas prices when it is difficult to
raisenet wells represents the capital necessary to finance these activities. Without successful
exploration or acquisition activities, the Company's reserves, production and
revenues will decline rapidly. No assurances can be made thatsum of fractional working
interests the Company will
be able to find and develop or acquire additional reserves at an acceptable
cost.owns in gross wells.
OIL AND GAS ACREAGE
As of December 31, 2001,2002, the Company had total gross and net developed
and undeveloped oil and gas leasehold acres 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 3,960 1,787 261,435 161,7605,449 2,564 182,324 119,829
Pennsylvania 0 0 10,801 5,40114,741 14,271
Texas 720 382 0 0
----- ----- ------- -------
All States 4,680 2,169 272,236 167,161
Bohai Bay Acreage:
The table below sets out Ultra's Bohai acreage held as of March 1, 2002:6,169 2,946 197,065 134,100
Bohai Bay Acreage:
The table below sets out Ultra's Bohai acreage held as of March 3,
2003:
Developed Acres Undeveloped Acres
------------------------ ---------------------------------------- -----------------
Gross Net Gross Net
--------- ------------ ----------- ---------------- --- ----- ---
Block 04/36 0 0 454,000 82,546
Block 05/36*36 0 0 233,300 34,995
- ------ ----- ------- -------
Total Bohai Acreage 0 0 687,300 117,541
____________
* A 25% relinquishment was made on February 28, 2002 as a requirement for
entering the third exploration period.
14
Drilling ActivitiesDRILLING ACTIVITIES
For each of the three fiscal years ended December 31, 2002, 2001 2000 and
1999,2000, the number of gross and net wells drilled by the Company was as follows:
WyomingWYOMING - Green River BasinGREEN RIVER BASIN
2002 2001 2000
1999
----- ----- --------- ---- ----
Gross Net Gross Net Gross Net
---------- --------- ----------- ------- --------- -------------- --- ----- --- ----- ---
Development Wells
Productive........................Productive ...... 16.00 5.50 9.00 5.52 14.00 8.92
0.00 0.00
Dry...............................Dry ............. 0.00 0.00 0.00 0.00 0.00 0.00
----- ---- ----- ---- ---- ----
Total.............................----- ----- ----- -----
Total 16.00 5.50 9.00 5.52 14.00 8.92
0.00 0.00
Exploratory Wells
Productive......................Productive ...... 10.00 5.22 22.00 8.67 10.00 3.16
2.00 0.92
Dry............................... 1.00*Dry ............. 0.00 0.00 1.00 0.42 1.00*1.00 0.09
4.00 2.13
----- ---- ----- ---- ---- ----
Total.............................----- ----- ----- -----
Total 10.00 5.22 23.00 9.09 11.00 3.25 6.00 3.05
____________
* The exploratory dry holes drilled in 2000 and 2001 (2 gross wells) were both
abandoned at TD due to mechanical failure during drilling operations.
China - Bohai Bay
Block 04/36 (18.2% W.I.)11
TEXAS
2002 2001 2000 1999
---- ---- ----
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- -------------- --- ----- --- ----- ---
Exploratory Wells
Productive ............... 0.00 0.00 0.00 0.00 0.00 0.00
Dry ...................... 1.00 0.15 0.00 0.00 0.00 0.00
----- ----- ----- ----- ----- -----
Total ........................ 1.00 0.15 0.00 0.00 0.00 0.00
CHINA - BOHAI BAY
2002 2001 2000
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Exploratory Wells
Productive and
Successful Appraisal*........ 8.00 1.45 2.00 0.36 1.00 0.18 4.00 0.70 14.00 2.35 4.00 0.66
Dry Holes............................................ 1.00 0.18 1.00 0.18 0.00 0.00
---- ---- ---- ---- ---- ----1.00 0.18
----- ----- ----- ----- ----- -----
Total Wells........................ 9.00 1.63 3.00 0.54 1.00 0.18........................ 5.00 0.88 15.00 2.53 5.00 0.84
____________- ------------
* Successful Appraisal well is a well that 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.
Block 05/36 (15.0% W.I.)
2001 2000 1999
---- ---- ----
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
Exploratory Wells
Productive and
Successful Appraisal*........ 6.00 0.90 2.00 0.30 0.00 0.00
Dry Holes...................... 0.00 0.00 0.00 0.00 0.00 0.00
---- ---- ---- ---- ---- ----
Total Wells........................ 6.00 0.90 2.00 0.30 0.00 0.00
__________
* Successful Appraisal well is a well that 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.
15
Getuo Block (10.0% W.I.)
2001 2000 1999
---- ---- ----
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
Exploratory Wells
Productive and
Successful Appraisal*........ 0.00 0.00 0.00 0.00 0.00 0.00
Dry Holes...................... 1.00 0.10 0.00 0.00 0.00 0.00
---- ---- ---- ---- ---- ----
Total Wells........................ 1.00 0.10 0.00 0.00 0.00 0.00
____________
* Successful Appraisal well is a well that 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.
PRODUCTIVE WELLS
As of December 31, 2001, the Company's total gross and net wells were as
follows:
Productive Wells* Gross Wells Net Wells
- ---------------- ----------- ---------
Natural Gas and Condensate ......... 97 46.41
__________
*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.
PRODUCTION VOLUMES, AVERAGE SALES PRICE 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,
-----------------------------------------------
2001 2000 1999
----------- ----------- ----------
(unaudited)
PRODUCTION
Natural gas (Mcf) 11,500,446 5,297,421 4,525,570
Oil (Bbl) 116,413 50,386 45,702
-----------------------------------------------
Total (Mcfe)* 12,198,924 5,599,737 4,799,782
REVENUES
Gas sales $38,204,298 $19,399,001 $8,229,984
Oil sales 2,996,955 1,603,635 746,722
-----------------------------------------------
Total Revenues 41,201,253 21,002,636 8,976,706
LEASE OPERATING EXPENSES
Production costs** 1,439,026 665,999 554,257
Severance/production taxes 4,425,345 2,253,793 863,540
Gathering 3,158,901 1,321,228 1,297,169
-----------------------------------------------
Total Lease Operating Expenses 9,023,271 4,241,020 2,714,966
REALIZED PRICES
Natural gas (Mcf) $ 3.32 $ 3.66 $ 1.82
Oil (Bbl) $ 25.74 $ 31.83 $ 16.34
OPERATING COSTS PER MCFE
Production costs $ 0.12 $ 0.12 $ 0.12
Severance/production taxes $ 0.36 $ 0.40 $ 0.18
Gathering $ 0.26 $ 0.24 $ 0.27
-----------------------------------------------
Total Operating Costs per Mcfe $ 0.74 $ 0.76 $ 0.57
16
__________
*Equivalent barrels have been calculated on the basis of six thousand cubic feet
(6 Mcf) of natural gas equals one barrel of oil.
**Average production costs includes lifting costs, remedial workover expenses
and production taxes.
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, 2001.2002.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS.
The common shares of the Company are 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 for 2002 and 2001 and on the TSE from December 31, 1999 though December 31,for 2002, 2001 and 2000 as
reported by such exchanges, respectively.
TORONTO STOCK EXCHANGE (CDN$)
1999 High Low
---- ---- ---
First Quarter $ 1.54 $1.06
Second Quarter $ 1.37 $0.96
Third Quarter $ 2.00 $1.07
Fourth Quarter $ 1.49 $0.93
2000 High Low
---- ---- ---
First Quarter $ 1.10 $0.75
Second Quarter $ 2.80 $0.78
Third Quarter $ 3.90 $0.95
Fourth Quarter $ 4.70 $2.95
2001 High Low
---- ---- ---
First Quarter $ 8.70 $3.76
Second Quarter $10.95 $7.01
Third Quarter $ 9.00 $5.65
Fourth Quarter $10.05 $6.30
17
AMERICAN STOCK EXCHANGE (US$) TORONTO STOCK EXCHANGE (CDN$)
2002 High Low 2002 High Low
- ---- ---- --- ---- ---- ---
First Quarter $ 8.17 $ 5.71 First Quarter $13.10 $ 9.25
Second Quarter $ 9.22 $ 7.50 Second Quarter $14.50 $11.34
Third Quarter $ 8.59 $ 5.94 Third Quarter $13.51 $ 9.35
Fourth Quarter $ 9.99 $ 7.90 Fourth Quarter $15.62 $12.47
2001 High Low 2001 High Low
- ---- ---- --- ---- ---- ---
First Quarter (beginning 1/17/01) $ 5.50 $ 3.00 First Quarter $ 8.70 $ 3.90
Second Quarter $ 7.34 $ 4.34 Second Quarter $10.95 $ 6.76
Third Quarter $ 5.92 $ 3.54 Third Quarter $ 9.00 $ 5.65
Fourth Quarter $ 6.41 $ 4.00 Fourth Quarter $10.05 $ 6.34
12
AMERICAN STOCK EXCHANGE (US$)
2001 High Low
---- ---- ---
First Quarter (beginning January 17, 2001) $ 5.50 $2.75
Second Quarter $ 7.34 $4.34
Third Quarter $ 5.92 $3.54
Fourth Quarter $ 6.41 $4.00
2000 High Low
---- ---- ---
First Quarter $ 1.05 $ 0.78
Second Quarter $ 2.80 $ 0.79
Third Quarter $ 3.90 $ 2.03
Fourth Quarter $ 4.50 $ 3.25
On March 26, 2002,3, 2003, the last reported sale price of the common stock on
the AMEX was $7.65$8.90 per share. As of March 1, 20023, 2003 there were approximately 470449
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 credit facility
restricts payment of dividends on its common stock.
Under current Canadian tax law and the United States-Canada Tax Convention
(1980) (the "Convention"), any dividends paid to U.S. resident shareholders
under the Convention are generally subject to a 15% Canadian withholding tax.
The Convention provides an exemption from withholding tax on dividends paid or
credited to certain tax-exempt organizations that are resident in the United
States for purposes of the Convention. Persons who are subject to the United
States federal income tax on dividends may be entitled, subject to certain
limitations, to either a credit or deduction with respect to Canadian income
taxes withheld with respect to dividends paid or credited on the Company's
shares.
ITEM 6. SELECTED FINANCIAL DATA.
The selected consolidated financial information presented below for the
years ended December 31, 2002, 2001, 2000, the six months ended December 31,
1999 and the years ended June 30, 1999 1998 and 19971998 is derived from the Consolidated
Financial Statements of the Corporation. Effective with the period ended
December 31, 1999, the Company began utilizing a December 31 year-end.
SIX MONTHS
ENDED
YEARS ENDED ENDED DECEMBER 31, DECEMBER 31, YEARS ENDED JUNE 30,
--------------------- ----------------- ------------------------------------------------------ ------------ --------------------
2002 2001 2000 1999 1999 1998
1997
----- ------ ------- ------- -------- ----------- ---- ---- ---- ---- ----
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Statement of Operations Data
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues:
Natural gas sales $38,503 $38,204 $19,399 $ 4,352 $ 6,352 $ 3,472
$ 405
Oil sales 3,839 2,997 1,604 434 670 174
21
Interest and other 23 393 171 18 287 121
14
---------------------------------------------------------------------------------- ------- ------- ------- -------- --------
Total revenues 42,365 41,594 21,174 4,804 7,309 3,767
440
================================================================================== ======= ======= ======= ======== ========
Expenses:
Production expenses and taxes 11,411 9,023 4,241 1,329 2,571 953
78
Depreciation, depletion and amortization 9,712 6,687 3,163 1,186 1,794 1,377
77
General and administrative 4,231 3,0784,199 3,894 2,828 1,668 5,861 3,406
1,381Stock compensation 1,211 337 250 -- -- --
Interest 2,692 1,687 802 344 577 406
-
Ceiling test write-down - - --- -- -- -- 3,417 2,081 -
Loss on abandonment of oil and gas property - - - --- -- -- -- -- 6,116 -
Bad debt expense (recovery) - --- -- -- (35) 2,019 - ---
Lawsuit settlement - --- -- -- 1,876 - - -
----------------------------------------------------------------------------- --
------- ------- ------- ------- -------- --------
Total expenses 29,225 21,628 11,284 6,368 16,239 14,339 1,536
Income from continuing operations before
income taxes 13,141 19,966 9,890 (1,564) (8,930) (10,572)
(1,096)
Income tax provision - deferred 5,059 2,087 - - - - -
----------------------------------------------------------------------------- -- -- --
------- ------- ------- ------- -------- --------
Net income $ 8,082 $17,879 $ 9,890 $(1,564) $(8,930)$ (8,930) $(10,572)
$(1,096)
================================================================================== ======= ======= ======= ======== ========
Basic income per common share $ 0.11 $ 0.25 $ 0.17 $ (0.03) $ (0.16) $ (0.26)
$ (0.04)
Diluted income per common share $ 0.240.10 $ 0.170.24 $ (0.03)0.17 $ (0.16)(0.03) $ (0.26)(0.16) $ (0.04)(0.26)
1813
SIX MONTHS
ENDED
YEARS ENDED ENDED DECEMBER 31, DECEMBER 31, YEARS ENDED JUNE 30,
------------------ ------------- ---------------------------------------------------- ------------ --------------------
2002 2001 2000 1999 1999 1998
1997
------ --------- ---- ---- ---- ---- ----
(IN THOUSANDS)
Statement of Cash Flows Data
- ----------------------------
Net cash provided by (used in):
Operating activities $ 35,61019,202 $ 35,098 $ 9,046 $ 674 $ 1,913 $ (7,915)
$(1,046)
Investing activities (61,335)(62,072) (60,824) (24,541) (1,624) (1,017) (30,032)
(8,899)
Financing activities 25,961 16,236 569 (6,010) 39,094 14,559
AS OF DECEMBER 31,42,908 25,961 16,236 569 (6,010) 39,094
AS OF
JUNE 30,
----------------------------------- -------------------2002 2001 2000 1999 1998
1997
------- ------ ---- ------- --------
(IN THOUSANDS)---- ---- ---- ----
Balance Sheet Data
- ------------------
Cash and cash equivalents $ 1,418 $ 1,379 $ 1,144 $ 402 $ 5,896
$ 4,690
Working capital (deficit) (9,227)(4,415) (6,635) 241 195 8,107 3,735
Oil and gas properties 207,362 155,221 59,729 33,773 37,392
16,304
Total assets 167,582221,874 167,583 73,177 38,063 56,137
22,542
Total long term obligations 51,166long-term debt 89,859 48,885 24,731 8,767 10,696
-Deferred income taxes 10,033 4,974 -- -- --
Total stockholders' equity 104,067 95,320 35,694 25,632 35,372 21,237
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
Statements that are not historical facts contained in this report are
forward-looking statements that involve risks and uncertainties that could cause
actual results to differ from projected results. Such statements address
activities, events or developments that the Company expects, believes, projects,
intends or anticipates will or may occur, including such matters as: future
availability of capital; development and exploration expenditures (including the
amount and nature thereof); drilling of wells; timing and amount of future
production of oil and gas; business strategies; operating costs and other
expenses; cash flow and anticipated liquidity; prospect development and property
acquisitions; and marketing of oil and gas. Factors that could cause actual
results to differ materially ("Cautionary Disclosures") are described below in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Certain Considerations." Cautionary Disclosures include, but
are not limited to: general economic conditions; the market prices of oil and
gas; the risks associated with exploration; the Company's ability to find,
acquire, market, develop and produce new properties; operating hazards attendant
to the oil and gas business; downhole drilling and completion risks that are
generally not recoverable from third parties or insurance; the outcome of the
Bureau of Land Management's EIS relating to the Company's core properties in the
Green River Basin of southwest Wyoming; uncertainties in the estimation of
proved reserves and in the projection of future rates of production and timing
of exploration and development expenditures; potential mechanical failure or
under performance of individually significant productive wells; the strength and
financial resources of the Company's competitors; the Company's ability to find
and retain skilled personnel; climatic conditions; labor relations; availability
and cost of material and equipment; delays in anticipated start-up dates;
environmental risks; the results of financing efforts; actions or inactions of
third-party operators of the Company's properties; and regulatory developments.
All statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entity by these Cautionary Disclosures. The
Company disclaims any obligation to update or revise any forward-looking
statement to reflect events or circumstances occurring hereafter or to reflect
the occurrence of anticipated or unanticipated events.
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.
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. Since its entry into the oil and
gas industry in 1993, the Company has continued to raise capital for its
exploration and development programs, most of which are based in the United
19
States. 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, 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 151.0 thousand barrels of
condensate, up from 11.5 Bcf of gas and 116.4 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.
14
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.
Interest and other income for the period decreased to $0.0 million in
2002 from $0.4 million in 2001. This decrease was primarily attributable to a
change in the way income from Company owned well service equipment was accounted
for and, secondarily, from lower interest received on balances in interest
bearing accounts in 2002.
Deferred income taxes 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
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.
RESULTS OF OPERATIONS - YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED
DECEMBER 31, 2000
Oil and gas revenues increased to $41.2 million for the year ended
December 31, 2001 from $21.0 million for the same period in 2000. This 96%
increase was attributable to an increase in the Company's production. During
this period the Company's production increased to 11.5 Bcf of gas and 116.4
thousand barrels of condensate, up from 5.3 Bcf of gas and 50.050.4 thousand barrels
of condensate for the same period in 2000. This 118% increase on an Mcfe basis
was attributable to the Company's successful drilling activities during 2000 and
2001. During the year ended December 31, 2001 the average product prices were
$3.32 per Mcf and $25.74 per barrel, compared to $3.66 per Mcf and $31.83 per
barrel for the same period in 2000.
Production costs increased 100% to $1.4 million in 2001 from $0.7
million in 2000 and on a unit of production basis were $.118$0.118 per Mcfe in 2001,
as compared to $.119$0.119 per Mcfe in 2000. Production taxes in 2001 were $4.4
million, compared to $2.3 million in 2000, or $.363$0.363 per Mcfe in 2001, compared
to $.402$0.402 per Mcfe in 2000. Production taxes are calculated based on a
percentage of revenue from production. Therefore, higher production and the
subsequent increase in revenue contributed to the increases. Gathering fees for
the period increased 146% to $3.2 million in 2001 from $1.3 million in 2000,
attributable to higher production volumes.
Depletion, depreciation and amortization (DD&A)DD&A expenses increased to $6.7 million during the year ended December
31, 2001 from $3.2 million for the same period in 2000. On a unit basis, DD&A
decreased to $0.548 per Mcfe in 2001, from $0.565 per Mcfe in 2000 primarily as
a result of increases in the proved reserves used to calculate depletion of the
full cost pool.
General and administrative expenses increased to $4.2$3.9 million during
the year ended December 31, 2001 from $3.1$2.8 million for the same period in 2000.
The increase was primarily attributable to increases in personnel and overhead
expenses arising from the acquisition and operations of the China properties and
increases in activity on the Wyoming properties.
Interest expense for the period increased to $1.7 million in 2001 from
$0.8 million in 2000. This increase was attributable to the increase in
borrowings under the senior credit facility.
Interest and other income for the period increased to $0.4 million in
2001 from $0.2 million in 2000. This increase was attributable to increased
utilization of companyCompany owned well service equipment and higher balances in
interest bearing accounts certainin 2001.
15
Deferred income taxes for the period increased to $2.1 million in 2001
from $0$0.0 in 2000. This increase was primarily attributable to the increase in
pre-tax net income relative to book net operating losses available to offset net
income. The Company expects to book deferred taxes at the statutory rate in
future periods. The Company was not liable for current payment of any material
income taxes for the period ending December 31, 2001.
On January 16, 2001, the Company acquired all of the outstanding
capital stock of Pendaries Petroleum Ltd., a New Brunswick company, in exchange
for 14,994,958 common shares of the Company.
20
RESULTS OF OPERATIONS - YEAR ENDED DECEMBER 31, 2000 COMPARED TO UNAUDITED YEAR
ENDED DECEMBER 31, 1999
Oil and gas revenues increased 133% to $21.0 million for the year ended
December 31, 2000 from $9.0 million for the same period in 1999. This increase
was attributable to an increase in both the Company's production and the
increase in prices received for that production. During this period the
Company's production increased to 5.3 Bcf of gas, and 50.0 thousand barrels of
condensate, up from 4.5 Bcf of gas and 45.7 thousand barrels of condensate for
the same period in 1999. During the year ended December 31, 2000 the average
product prices were $3.66 per Mcf and $31.83 per barrel, compared to $1.82 per
Mcf and $16.34 per barrel for the same period in 1999.
During the year ended December 31, 2000 production expenses and taxes
increased to $4.2 million from $2.7 million in 1999. Direct lease operating
expenses increased to $0.7 million in 2000 from $0.6 million in 1999 and on a
unit of production basis was $.12 per Mcfe in 2000, as compared to $.12 per Mcfe
in 1999. Production taxes in 2000 were $2.3 million, compared to $0.9 million in
1999 or $.40 per Mcfe in 2000, compared to $.18 per Mcfe in 1999. Production
taxes are calculated based on a percentage of revenue from production.
Therefore higher production and higher prices contributed to the increases.
Gathering fees for the period increased slightly in 2000 to $1.32 million from
$1.29 million in 1999, attributable to higher production volumes.
Depletion, depreciation and amortization expenses (DD&A) increased to $3.2
million during the year ended December 31, 2000 from $2.1 million for the same
period in 1999. On a unit basis, DD&A increased to $.57 per Mcfe, from $.44 per
Mcfe in 1999 primarily as a result of increases in the proved reserves' full
cost pool.
General and administrative expenses decreased to $3.1 million during the
year ended December 31, 2000 from $3.6 million for the same period in 1999. The
decrease was attributable to reductions in personnel and overhead expenses
during 2000.
Interest expense for the period increased to $0.8 million in 2000 from $0.7
million in 1999. This increase was attributable to the increase in borrowings
under the senior credit facility.
In November 1999, the Company settled litigation relating to the plugging
and abandonment of the White Estate No. 1 well. The settlement and legal costs
relating to this litigation totaled $1.9 million. No such settlement occurred
during the year ended December 31, 2000.
RESULTS OF OPERATIONS - SIX MONTH PERIOD ENDED DECEMBER 31, 1999 COMPARED TO SIX
MONTH PERIOD YEAR ENDED DECEMBER 31, 1998
Oil and gas revenues increased to $4.8 million for the six-month period
ending December 31, 1999 from $3.1 million for the same period in 1998. The
Company incurred a net loss of $1.5 million for the six-month period ending
December 31, 1999 compared to a net loss of $6.7 million for the same period in
1998. The increase in gross revenues was attributable to an increase in both the
Company's production and the increase in prices received for that production.
During this period, the Company's cumulative production increased to 1.90 Bcf of
gas, and 20.0 thousand barrels of condensate, up from 1.76 Bcf of gas, and 9.43
thousand barrels of condensate for the same period in 1998. During the six-month
period ending December 31, 1999, the average product prices were $2.29 per Mcf
and $21.69 per barrel, compared to $1.72 per Mcf and $11.77 per barrel for the
same period in 1998.
During the six-month period ending December 31, 1999 production expenses
and taxes increased to $1.3 million from $1.2 million in 1998. Direct lease
operating expenses decreased to
21
$0.3 million in 1999 from $0.4 million in 1998 and on a unit of production
basis, to $0.136 per Mcfe in 1999, from $0.225 per Mcfe in 1998. This reduction
was primarily attributable to the effects of restructuring operations and
reductions in operating field staff. Production taxes for this period in 1999
were $0.5 million, compared to $0.25 million in 1998 or $0.238 per Mcfe in 1999,
from $0.143 per Mcfe in 1998. Production taxes are calculated based on a
percentage of revenue from production. Therefore, higher production and higher
prices contributed to the increases.
Depletion and depreciation expenses remained relatively constant for the
six-month period ending December 31, 1999 to the same period in 1998. On a unit
basis, such expenses decreased to $0.578 per Mcf, from $0.648 in 1998 primarily
as a result of increases in proved reserves.
General and administrative expenses decreased 58% to $1.7 million during
the six-month period ending December 31, 1999 from $4.0 million for the same
period in 1998. The decrease was attributable to the restructuring implemented
during 1999. Net interest expense for the period increased to $0.3 million in
1999 from $0.1 million in 1998. This increase was attributable to both the
increase in borrowings under the senior credit facility and reduction in cash
balances earning interest. In November 1999, the Company settled litigation
relating to the plugging and abandonment of the White Estate No. 1 well. The
settlement and legal costs relating to this litigation totaled $1.9 million.
RESULTS OF OPERATIONS - FISCAL YEAR ENDED JUNE 30, 1999 COMPARED TO FISCAL YEAR
ENDED JUNE 30, 1998
The Company incurred a net loss of $8.9 million for the year ended June 30,
1999 compared to a net loss of $10.6 million for the year ended June 30, 1998.
Oil and gas revenues increased to $7.0 million in fiscal 1999 from $3.6 million
in 1998. This was directly attributable to the Company's drilling and completion
activities in the Green River Basin of Wyoming. The Company's annual production
increased to 4.1 Bcf of gas and 41.9 thousand barrels of condensate during 1999,
up from 1.8 Bcf of gas and 14.0 thousand barrels of condensate during 1998.
During 1999 the average product prices received were $1.54 per Mcf and $15.95
per barrel, compared to an average of $1.81 per Mcf and $13.26 per barrel in
1998.
Depletion and depreciation expense increased to $1.8 million in 1999 from
$1.4 million in 1998. The increase in depletion and depreciation expense was
attributable to increased production. The per Mcf equivalent oil and gas
depletion and depreciation rate fell to $0.41 in 1999. The decline in the per
Mcfe depletion and depreciation rate was attributable to the effects of the
ceiling test writedown of $3.4 million incurred in December 1998, additions to
reserves and reduced finding and development costs. The book value of oil and
gas properties was $33.8 million at June 30, 1999, compared to $37.3 million at
June 30, 1998. The causes of this decrease were the sale and write-downs of oil
and gas properties and the costs of drilling of additional wells.
Production taxes and gathering fees increased to $1.7 million in 1999 from
$0.7 million in 1998. Both increases were directly attributable to increases in
production in the Green River Basin of Wyoming.
During 1999, the Company recognized a property impairment charge of $3.4
million, as a result of the capitalized cost of oil and gas properties exceeding
a "ceiling" on such costs computed in accordance with GAAP. This impairment was
caused by the lower commodity prices at December 31, 1998. The ceiling test
impairment is a direct line item on the income statement. In June 1999, the
Company sold a working interest in certain undeveloped leaseholds for $5 million
in cash, which had been split between proven and unproven properties and $8.2
22
million in carried work commitments which reduced the carrying value of unproven
properties. The $8.2 million in carried work commitments will not be reflected
on the books until they are incurred which will be in December 1999.
General and administrative expenses increased to $5.8 million in 1999 from
$3.4 million in 1998. This increase in total general and administrative expenses
was primarily attributable to increases in staffing and activity during the
first and second quarters of fiscal 1999. During the third and fourth quarters,
the Company implemented a restructuring plan to reduce general and
administrative expenses. During fiscal 1999, the Company wrote-off $2.0 million
of debt that had been on the books in excess of two years. These debts were owed
primarily by junior joint venture partners for amounts expended by the Company
in drilling farm-out prospects on these partners' behalf for which the Company
was never reimbursed. The Company evaluated the ability of the joint venture
partners to repay the debts and determined that repayment was unlikely.
Included in unproven properties is $2.5 million of prepaid environmental
costs, which relate to the Company's agreement to purchase specified nitrogen
oxide emission offsets. These offsets are to be utilized by the Company in the
future development of its oil and gas properties in the Mesa Area as the asset
that will generate the offsets is under construction. Of the total payment, $2.0
million was in the form of a note that bears interest at 10% payable in
installments of $0.75 million and $1.25 million on July 15, 1999 and 2000,
respectively. The $0.2 million of interest on this note at June 30, 1999 has
been capitalized as part of the prepaid environmental cost.
LIQUIDITY AND CAPITAL RESOURCES
In the twelve-month periodyear ending December 31, 20012002, the Company relied on its
existing senior credit facility and cash provided by operations to finance its
capital expenditures. The Company participated in the drilling of 3226 gross
(14.62(10.72 net) wells in Wyoming, and 155 gross (2.53(0.88 net) wells in the China blocks and
one gross (0.1(0.15 net) commitment well on the Getuo block.in Texas. For the twelve-month period ending December
31, 20012002 net capital expenditures were $58.4$62.1 million. At December 31, 2001,2002, the
Company reported a cash position of $1.4 million compared to $1.1$1.4 million at
December 31, 2000.2001. Working capital at December 31, 20012002 was $(9.3)$(4.4) million as
compared to $0.2$(6.6) million at December 31, 2000.2001. As of December 31, 2001,2002, the
Company had incurred bank indebtedness of $43.0$86.0 million and other long termlong-term debt
of $3.1$3.9 million which was comprised of accrued capital
expenditures that the Company will finance by drawing on the available bank
facility.items payable in more than one year.
The positive cash flowprovided by operating activities that the Company
continues to produce, along with the availability under the senior credit
facility, are projected to be sufficient to fund the Company's budgeted capital
expenditures for 2001,2003, which are currently projected to be $50.0$80.0 million. Of the
$50.0$80.0 million budget, the Company plans to spend approximately $35.0$60.0 million of
its 2003 budget in Wyoming and approximately $12.5$20.0 million in China in 2002. The remaining $2.5 million will go towards seismic,
land and other miscellaneous costs in both areas.China. Of the
$35.0$60.0 million for Wyoming, the Company plans to drill or participate in an
estimated 2530 gross (11.4
net) wells in 2002,2003, of which approximately $17.9 million is50% will be for
exploration wells and the remaining $17.1 million will be for development wells. All ofOf the $12.5$20.0
million budgeted for China, approximately 50% will be for exploratory/appraisal
wells.activity and the balance will be for development activity. The Company currently
has no budget for acquisitions of properties in 2002.2003.
As of March 1, 2002,3, 2003, the revolving senior credit facility provides for
a $150.0 million revolving credit line with a current borrowing base of $80.0$120.0
million. The credit facility matures on March 1, 2005. The notes bearsbear interest
at either the bank'sBank 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 (1.5%(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 23
borrowing base is subject to periodic (at
least semi-annual) review and redeterminationre-determination by the bankbanks and may be decreasedincreased
or increaseddecreased 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, G&A expenditures and advances to Sino-American Energy. In the
event of a default under the covenants, the Company may not be able to access
funds otherwise available under the facility.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 and guaranteed by UP Energy and
Ultra Petroleum Corp.properties. At December
31, 20012002 the Company had $43.0$86.0 million of outstanding borrowings under this
credit facility, with a current average interest rate of 4.1%approximately 3.3%. The total amount outstanding at March 1, 2002 was $51.0
million. The
Company was in compliance with all loan covenants at December 31, 2001 and 2000.2002.
During the year ended December 31, 2001, the Company generated2002, net cash fromprovided by operating
activities of $35.6was $19.2 million as compared to $35.1 million for the year ended
December 31, 2001 and $9.0 million for the year ended December 31, 2000 and $0.3 million for the year ended December 31, 1999.2000. Cash
flow from operations before changes in non-cash working capital was $27.5$24.1
million for the year ended December 31, 2002 as compared to $27.0 million for
the year ended December 31, 2001 and $13.0 million for the year ended December
31, 2000 and
$0.3 million for the year ended December 31, 1999.2000. The increasedecrease in cash fromprovided by operating activities was attributable
to the increasedecrease in earnings and DD&A and
the increasedecrease in net changes to non-cash working
capital items.
During the year ended December 31, 20012002, cash used in investing
activities was to $61.3$62.1 million as compared to $60.8 million for the year ended
December 31, 2001 and $24.5 million for the year ended December 31, 2000 and $4.3 million for the year ended December 31, 1999.2000. The
change is primarily attributable to increased drilling and completion activity.activity
in Wyoming.
16
During the year ended December 31, 20012002, cash provided by financing
activities was $26.0$42.9 million as compared to $26.0 million for the year ended
December 31, 2001 and $16.2 million for the year ended December 31, 2000 and $0.5 million for the year ended December 31, 1999.2000. The
change is primarily attributable to increased borrowing under the senior credit
facility.
CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations as of
December 31, 2002:
2003 2004-2005 2006-2007 After 2007 Total
---- --------- --------- ---------- -----
Long-term debt $ -- $86,000,000 $ -- $ -- $86,000,000
Operating Leases 291,015 198,030 132,020 -- 621,065
----------- -------- ---- -----------
Total contractual obligations $291,015 $86,198,030 $132,020 $-- $86,621,065
======== =========== ======== ==== ===========
The Company's senior credit facility with its group of banks matures on
March 1, 2005. Unless the facility is extended or a new facility put into place,
the full amount drawn under the facility would become due and payable at that
time. The Company believes that it will be able to extend or renew the facility
or one substantially similar to the existing facility prior to March 1, 2005.
The Company has signed a LOI for its 8.92% share of a 15 year contract
(extensions up to 25 years provided) to lease a FPSO. The LOI provides for the
lease to be signed and come into force when and if the government of China
approves the ODP, which is expected during the first half of 2003. 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.
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 2002, total holding costs for all of the Company's
leases not held by production were $313,122.
Although the Company projects that the positive cash flow that the Company continues to produceprovided by
operating activities and the availability under the senior credit facility are projected towill
be sufficient to fund the Company's budgeted capital expenditures for 2002. However,2003,
future cash flowsprovided by operating activities and continued availability of
financing are subject to a number of uncertainties beyond the Company's control
such as production rates, the price of gas and oil, production rates, continued results of the
Company's drilling program and the general condition of the capital 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.
CRITICAL ACCOUNTING POLICIES
The discussion and analysis of the Company's significant accounting policies are described in the notes to
thefinancial condition and
results of operations is based upon consolidated financial statements. It is increasingly important to
understand that thestatements, which
have been prepared in accordance with U.S. GAAP. In addition, application of
generally accepted accounting principles involve certainrequires 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 that affect reported
amounts of assets, liabilities, revenues and expenses. The application of
principles can result in varying results from company to company.
The most significant principles that impact the Company and its
subsidiaries relate to volumes of oil and gas reserves
used in calculating depletion, depreciation and amortization, 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.
17
The Company emphasizes that the volumes of reserves are estimates
which, by their nature, are subject to revision. The estimates are made using
all available geological and reservoir data as well as production performance
data. These estimates, made by the Company's engineers, or by independent
petroleum engineers, are reviewed and revised, either upward or downward, as
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 uneconomic
conditions.
Due to the volatility of commodity prices, the oil and gas prices on
the last day of the quarter 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 common units of
measure using one barrel of oil as an equivalent to six thousand cubic feet of
natural gas. A reserve estimatesis 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 taxes.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 financial statements includedfollowing 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 this report contain estimates2002, 2001 or 2000. As of December 31, 2002, the ceiling
limitation exceeded the carrying value of the Company's oil and gas properties
by approximately $200 million in the U.S. The Company's China properties have
not yet been subject
18
to a ceiling test, as there have not been any proved reserves and thebooked to date.
Estimates of discounted future net revenues from those
reserves, as prepared by independent petroleum engineerscash flows at December 31, 2002 were based on
average natural gas prices of approximately $2.94 per MCF in the U.S. and on
average liquids prices of approximately $30.55 per barrel in the U.S. A
reduction in oil and gas prices and/or the Company.
There are numerous uncertainties
24
inherent in estimatingestimated quantities of proved oil and gas
reserves including many
factors beyondwould reduce the controlceiling limitation in the U.S. and could result in a
ceiling test writedown.
In China, the existence of proved reserves has not yet been determined,
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, amounts
are reclassified as proved properties and become subject to depreciation,
depletion and amortization and the application of the Company;ceiling test. If
exploration efforts are unsuccessful in establishing proved reserves and
therefore,exploration activities cease, the amounts accumulated as unproved costs are
charged against earnings as impairments. As of December 31, 2002, costs related
to these international projects of approximately $65.0 million dollars were not
being depleted pending determination 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 its 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 is
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 are subjectadjusted to change.
We usereflect any
over-produced or under-produced positions. Receivables or payables are
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, 2002, the Company had taken
approximately 1,000 MMcf more than its entitled share of production. The
estimated value of this imbalance of approximately $2 million was recorded as a
long-term liability.
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 amountsvalues and their respective income tax bases
(temporary differences). Management regularly
reviews itsFuture 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 taxestax assets, for recoverability and establishes a valuation
allowance based on historicalmanagement 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, 2002, the expected timingCompany will need to
generate future taxable income prior to the expiration of the reversals of existing temporary differences.
During the year, the Company completed the acquisition of Pendaries Petroleum,
Ltd., which gave rise to a deferred tax liability. Additionally, the Company
fully utilized all of its available net operating loss
carry-forwards attributablein 2003 to continuing operations2022. Based upon the level of historical taxable
income and projections for financial statement purposes. The change in valuation
allowance reflects management's assessment regardingfuture taxable income over the future realization of
U.S.periods, which the
deferred tax assets andare deductible, management believes it is more likely than
not the Company will realize the benefits of these
19
deductible differences, net of the existing valuation allowances at December 31,
2002. The amount of the deferred tax asset considered realizable, however, could
be reduced in the near term if estimates of future earnings.taxable income during the
carry-forward periods are reduced.
Commodity Derivative Instruments and Hedging Activities. The Company
periodically enters into commodity derivative contracts and fixed-price physical
contracts to manage its exposure to oil and natural gas price volatility. The
Company primarily utilizes price swaps, which are generally placed with major
financial institutions or with counter-parties of high credit quality that it
believes are minimal credit risks. The oil and natural gas reference prices of
these commodity derivatives contracts are based upon crude oil and natural gas
futures, which have a high degree of historical correlation with actual prices
the Company receives. Under SFAS No. 133 all derivative instruments are recorded
on the balance sheet at fair value. Changes in the derivative's fair value are
recognized currently in earnings unless specific hedge accounting criteria are
met. For qualifying cash flow hedges, the gain or loss on the derivative is
deferred in accumulated other comprehensive income (loss) to the extent the
hedge is effective. For qualifying fair value hedges, the gain or loss on the
derivative is offset by related results of the hedged item in the income
statement. Gains and losses on hedging instruments included in accumulated other
comprehensive income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered. Derivative
contracts that do not qualify for hedge accounting treatment are recorded as
derivative assets and liabilities at market value in the consolidated balance
sheet, and the associated unrealized gains and losses are recorded as current
expense or income in the consolidated statement of operations. The Company
currently does not have any derivative contracts in place that do not qualify as
a cash flow hedge.
RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, Business Combinations ("SFAS No. 141") and SFAS No. 142, Goodwill
and Other Intangible Assets ("SFAS No. 142"). SFAS No. 141 was effective as of
July 1, 2001 and SFAS No. 142 was effective January 1, 2002. SFAS No. 141
requires that the purchase method of accounting be used for all business
combinations. SFAS 141 specifies criteria that intangible assets acquired in a
business combination must meet to be recognized and reported separately from
goodwill. SFAS No. 142 requires that goodwill and intangible assets with
indefinite useful lives no longer be amortized, but instead tested for
impairment at least annually in accordance with the provisions of SFAS No. 142.
SFAS No. 142 also requires that intangible assets with estimable useful lives be
amortized over their respective estimated useful lives to their estimated
residual values, and reviewed for impairment in accordance with SFAS No. 121 and
subsequently, SFAS No. 144 after its adoption. The Canadian Institute of
Chartered Accountants ("CICA") has adopted similar standards and accordingly,
there will be no U.S. - Canadian GAAP differences arising from the addition of
these standards. The Company has no goodwill or intangible assets.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations ("SFAS No. 143"). SFAS No. 143 requires the Company to
record the fair value of an asset retirement obligation as a liability in the
period in which it incurs a legal obligation associated with the retirement of
tangible long-lived assets that result from the acquisition, construction,
development and/or normal use of the assets. TheBased on current estimates, the
Company will alsowould record asset retirement obligations (using a corresponding asset which is depreciated over the life10% discount rate)
and a cumulative effect of the asset. Subsequentchange in accounting principle on prior years,
related to the initial measurementdepreciation and accretion expense that would have been reported
had the fair value of the asset retirement obligation, the obligation
will be adjusted at the end of each period to reflect the passage of time and changescorresponding
increase in the estimated future cash flows underlyingcarrying amount of the obligation. The
Company is required to adopt SFAS No. 143 on January 1, 2003. The Company is
currently assessing the impact, if any, onrelated long-lived asset. Currently the
Company's consolidated financial
statements for future periods.assessment has been deemed not material.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). SFAS No. 144
addresses financial accounting and reporting for the impairment or disposal of
long-lived assets. This Statement requires that long-lived assets be reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Recoverability of assets to
be held and used is measured by a comparison of the carrying amount of an asset
to future net cash flows expected to be generated by the asset. If the carrying
amount of an asset exceeds its estimated future cash flows, an impairment charge
is recognized by the amount by which the carrying amount of the asset exceeds
the fair value of the asset. SFAS No. 144 also broadens the definition of
discontinued operations to include all distinguishable components of an entity
that 25
will be eliminated from ongoing operations. The Company has adopted SFAS
No. 144 as of January 1, 2002. Because the Company has elected the full-cost
method of accounting for oil and gas exploration and development activities, the
impairment provisions of SFAS No. 144 do not apply to the Company's oil and gas
assets, which are subject to ceiling limitations. For the Company's non-oil and
gas assets, the method of impairment assessment is unchanged from SFAS No. 121.
The adoption of SFAS No. 144 had no impact on the Company's consolidated
financial statements.
CERTAIN CONSIDERATIONSStatement 145, Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections ("SFAS No. 145")
was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains
and Losses from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. The Company
expects adoption of this
20
statement to result in the reclassification of losses on extinguishment of debt
for all periods from extraordinary to other income and expense.
Statement 146, Accounting for Exit or Disposal Activities ("SFAS No.
146"), was issued in June 2002. SFAS No. 146 addresses significant issues
regarding the recognition, measurement and reporting of costs that are
associated with exit and disposal activities, including restructuring activities
that are currently accounted for pursuant to the guidance set forth in EITF
Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity." SFAS No. 146 will be effective for the
Company in January 2003. The Company expects the adoption of SFAS No. 146 to
have no impact on its financial statements.
In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-based Compensation-Transition and Disclosure ("SFAS No. 148"). SFAS No.
148 amended FASB Statement No. 123, Accounting for Stock-Based Compensation
("Statement 123") to provide alternative methods of transition 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
Statement 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 have no material impact on the Company, as it does not
plan to adopt the fair-value method of accounting for stock options at the
current time. The Company has included the required disclosures in Note 1 to the
Consolidated Financial Statements.
In November 2002, the FASB issued Financial Interpretation No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others - an interpretation of FASB
Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34 ("FIN
45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under certain
guarantees that it has issued. It also clarifies that a guarantor is required to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligation undertaken in issuing the guarantee. The initial recognition and
initial measurement provisions of FIN 45 are applicable on a prospective basis
to guarantees issued or modified after December 31, 2002, irrespective of the
guarantor's fiscal year-end. The disclosure requirements are effective for
financial statements of interim or annual periods ending after December 15,
2002. As of March 3, 2003, the Company had no guarantees, other than to wholly
owned subsidiaries that are consolidated in place.
In January 2003, the FASB issued Financial Interpretation No. 46,
Consolidation of Variable Interest Entities - an interpretation of ARB No. 51
("FIN 46" or "Interpretation"). FIN 46 is an interpretation of Accounting
Research Bulletin 51, Consolidated Financial Statements, and addresses
consolidation by business enterprises of variable interest entities ("VIE"). The
primary objective of the Interpretation is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. The Interpretation requires an enterprise to consolidate a VIE if that
enterprise has a variable interest that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's expected
residual returns if they occur, or both. An enterprise shall consider the rights
and obligations conveyed by its variable interests in making this determination.
This guidance applies immediately to variable interest entities created after
January 31, 2003, and to variable interest entities in which an enterprise
obtains an interest after that date. It applies in the first fiscal year or
interim period beginning after June 15, 2003, to variable interest entities in
which an enterprise holds a variable interest that it acquired before February
1, 2003. At this time, the Company does not have any VIEs.
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
21
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 the major oil 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 personalpersonnel 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 producers,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.
TheHistorically, the Company's projects have been financed through debt
and internally generated cash flow. There is competition for capital to finance
oil and gas drilling. The ability of the Company to obtain such financing is
uncertain and can be affected by numerous factors beyond its control. The
inability of the Company to raise capital in the future could have an adverse
effect on certain areas of the 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, it 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
would 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 effect the price received for the
Company's Wyoming production than production in the other U.S. regions.
22
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;
and
.- require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells.wells; and
- require governmental approval of the overall development plan
prior to 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.
A significant percentage of the Company's United States operations are
conducted on publicfederal lands. These operations are subject to a variety of on-site
security regulations as well as other permits and authorizations issued by the
U.S.
Bureau of Land Management ("BLM"),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 May 15, 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 26
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 willmay 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--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.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--LiquidityOperations -- 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
23
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 late Novembermid-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 27
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 determined by independent petroleum engineers.that are
economically recoverable. Without successful exploration, development or
acquisition activities, the Company's reserves and production will decline. The
Company can give no assurance that it will be able to find, develop or acquire
additional reserves at acceptable costs.
Operating Hazards and Uninsured Risks. The oil and gas business
involves a variety of operating risks, including fire, explosion, pipe failure,
casing collapse, abnormally pressured formations, and environmental hazards such
as oil spills, gas leaks, and discharges of toxic gases. The occurrence of any
of these events with respect to any property operated or owned (in whole or in
part) by the Company could have a material adverse impact on the Company. The
Company and the operators of its properties maintain insurance in accordance
with customary industry practices and in amounts that management believes to be
reasonable. However, insurance coverage is not always economically feasible and
is not obtained to cover all types of operational risks. The occurrence of a
significant event that is not fully insured could have a material adverse effect
on the Company's financial condition.
Drilling and Operating Risks. The Company's oil and gas operations are
subject to all of the risks and hazards typically associated with drilling for,
and production and transportation of, oil and gas. These risks include the
necessity of spending large amounts of money for identification and acquisition
of properties and for drilling and completion of wells. In the drilling of
exploratory or development wells, failures and losses may occur before any
deposits of oil or gas are found. The presence of unanticipated pressure or
irregularities in formations, blow-outs or accidents may cause such activity to
be unsuccessful, resulting in a loss of the Company's investment in such
activity. If oil or gas is encountered, there can be no assurance that it can be
produced in quantities sufficient to justify the cost of continuing such
operations or that it can be marketed satisfactorily.
Drilling Plans Subject to Change. This report includes certain
descriptions of the Company's future drilling plans with respect to its
prospects. A prospect is a
property onan 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 BLM's EIS.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.
24
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
28
decreases could result in reductions in the carrying value of such assets and an
equivalent charge to earnings.
Restrictions on Production Due toRisks 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 lose
interest inshift its focus from
this project, then unless the Bohai Bay properties are sold to
another party, the pace of development of the blocksBlocks could slow down or stop
altogether and the blocks may never be developed.altogether. The Company currently does not believe it has sufficient funds to
purchase Kerr-McGee's interests in these blocksBlocks 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 provide
cash to meetfund 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 ourits share of costs, it could
lose or be forced to sell its interest in the Bohai bayBay properties or be forced
to not participate in the exploration or development of specific prospects or
fields on the blocks,Blocks, potentially diminishing the value of theits 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-
governmentalquasi-governmental agencies;
.- change in laws and policies governing operations of foreign
based companies;
.- labor problems;
.- other uncertainties arising out of foreign government
sovereignty over ourits international operations; and
.- currency restrictions and exchange rate fluctuations;fluctuations.
Tensions between China and its neighbors or various Western countries,
especially the United States,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 possiblelikely participation by China National Offshore Oil CompanyCNOOC 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 addition, 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 the 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 United States.productive life of the fields.
Operating RiskRisks in China. Offshore operations, such as ourthe 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
25
from typhoonsstorms or other adverse weather conditions. These conditions can
29
cause
substantial damage to facilities and interrupt production. As a result, the
Company could incur substantial liabilities that could result in financial
losses or failure.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 USU.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 Bbls.
.barrels.
- Mcf -- One thousand cubic feet of natural gas.
.- Mcfe -- One thousand cubic feet of natural gas equivalent.
.- MMBbl -- One million Bblsbarrels of oil or other liquid
hydrocarbons.
.- MMcf -- One million cubic feet of natural gas.
.- MBOE -- One thousand BOE.
.- MMBOE -- One million BOE.
- MMBTU -- One million British Thermal Unit.
TERMS USED TO DESCRIBE THE COMPANY'S INTERESTS IN WELLS AND ACREAGE
.- Gross oil and gas wells or acres -- The Company's gross wells
or gross acres represent the total number of wells or acres in
which the Company owns a working interest.
.- Net oil and gas wells or acres -- Determined by multiplying
"gross" oil and natural gas wells or acres by the working
interest that the Company owns in such wells or acres
represented by the underlying properties.
TERMS USED TO ASSIGN A PRESENT VALUE TO THE COMPANY'S RESERVES
. Standard- Standardized measure of proved reservesdiscounted 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-
taxafter-tax cash flows are discounted at 10% to
result in the standardized measure of the Company's proved
reserves.
3026
. Pre-tax- Standardized measure of discounted present valuefuture 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 OURTHE COMPANY'S RESERVE QUANTITIES
. Proved reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering
data, appear with reasonable certainty to be recoverable in the future
from known oil and natural gas reservoirs under existing economic and
operating conditions.
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 (A)(1) that portion delineated by drilling
and defined by gas-oil and/or oil-water contacts, if any; and (B)(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.
.- 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.
31
TERMS WHICH DESCRIBE THE COST TO ACQUIRE THE COMPANY'S RESERVES
. Finding costs -- The Company's finding costs compare the amount the
Company spent to acquire, explore and develop its oil and gas properties,
explore for oil and gas and to drill and complete wells during a period,
with the increases in reserves during the period. This amount is
calculated by dividing the net change in the Company's evaluated oil and
property costs during a period by the change in proved reserves plus
production over the same period. The Company's finding costs as of
December 31 of any year represent the average finding costs over the
three-year period ending December 31 of that year.
TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES
. Reserve life -- A measure of the productive life of an oil and gas
property or a group of oil and gas properties, expressed in years.
Reserve life for the years ended December 31, 2001, 2000 or 1999 equal
the estimated net proved reserves attributable to a property or group of
properties divided by production from the property or group of properties
for the four fiscal quarters preceding the date as of which the proved
reserves were estimated.
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS
PROPERTIES
. Royalty interest -- A real property interest entitling the owner to
receive a specified portion of the gross proceeds of the sale of oil and
natural gas production or, if the conveyance creating the interest
provides, a specific portion of oil and natural gas produced, without any
deduction for the costs to explore for, develop or produce the oil and
natural gas. A royalty interest owner has no right to consent to or
approve the operation and development of the property, while the owners
of the working interests have the exclusive right to exploit the mineral
on the land.
.- 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.
.27
- 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.
32
.- 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.
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 primarily driven by the
prevailing price for crude oil and spot prices applicable to Ultra's USUnited
States 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 $1.72$1.85 per Mcf to a
monthly high of $7.61$3.23 per Mcf during 2001.2002. Realized wellhead prices are from the
financial statements, and include the effects of hedging, receipt of deferred
revenues from Jonah Gas Gathering, and gas balancing between working interest
owners.
The Company periodically enters into various hedging arrangements for
its natural gas production. During 2002, the Company received payments from
counterparties totaling $1,835,800 as its net proceeds from hedging activities.
This total includes $312,000 for the second quarter of 2002, $1,130,100 for the
third quarter of 2002, and $393,700 for the fourth quarter of 2002.
At year-end 2002, the Company had hedges in place covering
approximately 15,000 MMBtu or approximately 13 MMcf of gas per day for calendar
2003 at an average price of $3.11 per MMBtu or approximately $3.35 per Mcf. Of
these hedges 10,000 MMBtu are in the form of swaps and 5,000 MMBtu are fixed
price forward sales at Opal, Wyoming. The swaps are priced relative to the index
price at the first of each month at Opal, Wyoming, where the Company delivers
most of its gas to the purchasers.
In the first quarter of 2003, the Company entered into additional swaps
covering an additional 10,000 MMBtu or approximately 9 MMcf of gas for the
period from April 1, 2003 to October 31, 2003 at a price of $3.75 per MMBtu or
approximately $3.95 per Mcf (pricing referenced to Opal), plus an additional
5,000 MMBtu or approximately 4 MMcf of gas per day for the same period at a
price of $4.25 per MMBtu or approximately $4.48 per Mcf (pricing referenced to
Opal).
The table below summarizes the hedges in place as of March 3, 2003:
Type Period Volume Price / MMBtu
---- ------ ------ -------------
Fixed Price Sale Calendar 2003 5,000 $ 3.06
Swap Calendar 2003 5,000 $3.005
Swap Calendar 2003 5,000 $ 3.27
Swap April-Oct 2003 10,000 $ 3.75
Swap April-Oct 2003 5,000 $ 4.25
These hedges represent approximately 50% of the Company's forecasted
production for the period from April 1, 2003 to October 31, 2003, and
approximately 35% of the Company's forecasted production for calendar 2003.
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report
Consolidated Balance Sheets December 31, 2001 and 2000
Consolidated Statements of Operations and Deficit for the
Years Ended December 31, 2001, 2000, the Six-Months Ended
December 31, 1999 and Year Ended June 30, 1999
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2001, 2000, the Six-Months Ended
December 31, 1999 and Year Ended June 30, 1999
Consolidated Statements of Cash Flow for the Years Ended
December 31, 2001, 2000, the Six-Months Ended December 31,
1999 and Year Ended June 30, 1999
Notes to Consolidated Financial Statements
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this item will be included in our definitive
proxy statement, which will be filed not later than 120 days after December 31,
2001 and is incorporated herein by reference.
33
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this item will be included in our definitive
proxy statement, which will be filed not later than 120 days after December 31,
2001 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this item will be included in our definitive
proxy statement, which will be filed not later than 120 days after December 31,
2001 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this item will be included in our definitive
proxy statement, which will be filed not later than 120 days after December 31,
2001 and is incorporated herein by reference.
PART IV
ITEM 14. 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: None
3. Exhibits. The following Exhibits are filed herewith pursuant to
Rule 601 of the Regulation S-K or are incorporated by reference to
previous filings. Exhibits designated with a "+" constitute a
management contract or compensatory plan or arrangement required to
be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
Exhibit Number 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)
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 First Amended and Restated Credit Agreement dated March 1,
2002 among Bank One, NA, Union Bank of California, N.A.,
Guaranty Bank, FSB, Hibernia National Bank, Ultra Resources,
Inc. and Banc One Capital Markets, Inc.
34
10.2 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)
10.3 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)
10.4 Ratification of and Amendment to Mortgage dated February 15,
2001 (incorporated by reference to Exhibit 10.2 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2001)
10.5 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)
10.6 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
23.1 Consent of Netherland Sewell & Associates, Inc.
(b) Reports on Form 8-K
None
35
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 29, 2002 By: /s/ Michael D. Watford
------------------------------------------
Name: Michael D. Watford
Title: Director, Chairman of the Board, CEO
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, Chief Executive March 29, 2002
- ------------------------- Officer and President
Michael D. Watford
/s/ W. Charles Helton Director March 29, 2002
- -------------------------
W. Charles Helton
/s/ James E. Nielson Director March 29, 2002
- -------------------------
James E. Nielson
/s/ Robert E. Rigney Director March 29, 2002
- -------------------------
Robert E. Rigney
/s/ James C. Roe Director March 29, 2002
- -------------------------
James C. Roe
/s/ F. Fox Benton III Vice President, March 29, 2002
- ------------------------- Business Development
F. Fox Benton III and Finance
36
MANAGEMENT'S REPORT
The consolidated financial statements and all other information in the annual
report are the responsibility of management. The consolidated financial
statements and the financial information appearing in the annual report have
been prepared in accordance with accounting principles generally accepted in Canada, except for the supplemental disclosures regarding oil and gas producing
activities which have been prepared in accordance with disclosure standards
generally accepted in the
United States of America.States. Management has designed and maintains a system of internal
accounting controls, policies and procedures in order to provide for the
safeguarding of assets and preparation of relevant, reliable and timely
financial information. External auditors, appointed by the shareholders, have
examined the consolidated financial statements. The Board of Directors has
reviewed the consolidated financial statements with management and the auditors,
and has approved the statements.
/s/ Michael D. Watford /s/ Kristen J. Miller
- ------------------------------- --------------------------------F. Fox Benton III
Michael D. Watford Kristen J. MillerF. Fox Benton III
Chief Executive Officer Chief Financial Reporting ManagerOfficer
March 18, 200225, 2003
AUDITORS' REPORT
To the Shareholders of
Ultra Petroleum CorporationCorp.
We have audited the consolidated balance sheets of Ultra Petroleum CorporationCorp. and
subsidiaries as atof December 31, 20012002 and 2000,2001, and the consolidated statements
of operations, and deficit, shareholders' equity and comprehensive income and cash flows for
each of the years in the three- year period ended December 31, 2001 and 2000, the six months ended December
31,1999 and the year ended June 30, 1999.2002. These
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.States. Those standards require that we plan and perform an 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, thesethe consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Company and
subsidiaries as atof December 31, 20012002 and 2000,2001, and the results of itstheir
operations and itstheir cash flows for each of the years in the three-year period
ended December 31, 2001 and 2000, the six months ended December 31,1999 and the year
ended June 30, 1999,2002, in accordance with accounting principles generally
accepted in Canada. As required by the Company Act (British Columbia), we report that, in
our opinion, these principles have been applied on a consistent basis.United States.
/s/ KPMG, LLP
- ---------------------------
KPMG, LLP
Denver, Colorado
March 18, 2002February 28, 2003
29
ULTRA PETROLEUM CORPORATIONCORP.
CONSOLIDATED BALANCE SHEETS
(Expressed in U.S. Dollars)
December 31,
-------------------------------------------ASSETS 2002 2001
2000
------------ ------------- ------ ---- ----
ASSETS
Current Assets
Cash and cash equivalents $ 1,379,4621,417,711 $ 1,143,5911,379,462
Restricted cash 209,306 207,179 200,126
Accounts receivable less allowance of $250,00011,398,483 7,358,742 8,278,538
at December 31, 2000 and 1999
Prepaid drilling costs and other current assets 474,279 2,823,613
839,892
Note receivable (Note 8) - 2,530,976------------- ------------
------------13,499,779 11,768,996 12,993,123
Oil and gas properties, using the full
cost method of accounting (Note 3) 207,362,408 155,221,187 59,728,715
Capital assets (Note 4) 1,011,699 592,605
455,448
------------------------- ------------
TOTAL ASSETS $ 221,873,886 $167,582,788
$ 73,177,286
========================= ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 21,096,34817,914,860 $ 12,752,48318,403,862
Long-term debt (Note 5) 46,092,928 24,530,61286,000,000 43,000,000
Deferred income taxes 10,033,174 4,974,008
Deferred revenue 100,000 200,000Notes payable 3,858,810 5,885,414
Shareholders' equity:
Share capitalCommon stock (Note 6) 95,098,690 92,585,148
50,838,663
Retained Earnings (Deficit)Treasury stock (1,193,650) --
Other comprehensive loss (653,875) --
Accumulated retained earnings 10,815,877 2,734,356
(15,144,472)
------------ ------------
95,319,504 35,694,191
------------------------- ------------
Commitments and contingencies (Note 12)11) 104,067,042 95,319,504
------------- ------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 221,873,886 $167,582,788
$ 73,177,286
========================= ============
See accompanying notes to consolidated financial statements.
Approved on behalf of the Board:
/s/ Michael D. Watford /s/ James E. Nielson
- ------------------------------- ----------------------------------
Michael D. Watford, Director /s/ James E. Nielson, Director
30
ULTRA PETROLEUM CORPORATIONCORP.
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
Six Months
(Expressed in U.S. Dollars) Year Ended Ended Year Ended
---------------------------------------------- ------------- -------------
December 31,
December 31, December 31, December 31, June 30-----------------------
2002 2001 2000
1999 1999 1999
---------------------------------------------- ------------ ------------
(unaudited)---- ---- ----
REVENUES:
Natural gas sales $ 38,502,971 $ 38,204,298 $ 19,399,001
$ 8,229,984 $ 4,352,184 $ 6,352,315
Oil sales 3,839,421 2,996,955 1,603,635 746,722 433,627 670,023
------------ ------------ ------------
------------ ------------42,342,392 41,201,253 21,002,636 8,976,706 4,785,811 7,022,338
------------ ------------
------------ ------------ ------------
EXPENSES:
Production expenses and taxes 11,410,868 9,023,271 4,241,020 2,714,966 1,329,034 2,571,081
Depletion and depreciation 9,712,111 6,687,433 3,162,568 2,105,663 1,186,395 1,794,307
Ceiling test write-down - - - - 3,416,786
Bad debt expense (recovery) - - 1,983,828 (35,588) 2,019,416
General and administrative 4,231,214 3,078,156 3,556,564 1,667,846 5,861,125
Interest 1,687,172 802,364 679,491 344,284 576,5064,199,104 3,894,185 2,828,156
Stock compensation 1,211,165 337,029 250,000
------------ ------------ ------------
------------ ------------
21,629,090 11,284,108 11,040,512 4,491,971 16,239,22126,533,248 19,941,918 10,481,744
OPERATING INCOME (LOSS) 19,572,163 9,718,528 (2,063,806) 293,840 (9,216,883)15,809,144 21,259,335 10,520,892
OTHER INCOME (EXPENSE):
Interest income 23,151 173,411 87,879
33,900 18,219 151,709Interest expense (2,691,608) (1,687,172) (802,364)
Other -- 220,016 83,519 135,008 - 135,008
Lawsuit settlement (Note 12) - - (1,875,610) (1,875,610) -
------------ ------------ ------------
------------ ------------
393,427 171,398 (1,706,702) (1,857,391) 286,717(2,668,457) (1,293,745) (630,966)
------------ ------------ ------------
------------ ------------NET INCOME (LOSS) FOR THE PERIOD BEFORE INCOME TAXES 13,140,687 19,965,590 9,889,926 (3,770,508) (1,563,551) (8,930,166)
INCOME TAXES
Income tax provision - deferred 5,059,166 2,086,762 - - - ---
NET INCOME (LOSS) FOR THE PERIOD8,081,521 17,878,828 9,889,926
(3,770,508) (1,563,551) (8,930,166)
DEFICIT,RETAINED EARNINGS (DEFICIT), beginning of period 2,734,356 (15,144,472) (25,034,398) (21,263,890) (23,470,847) (14,540,681)
------------ ------------ ------------
------------ ------------
DEFICIT,RETAINED EARNINGS (DEFICIT), end of period $ 10,815,877 $ 2,734,356 $ (5,254,546) $(28,804,906) $(26,597,949) $(23,470,847)$(15,144,472)
============ ============ ============
============ ============NET INCOME (LOSS) PER COMMON SHARE - BASIC $ 0.11 $ 0.25 $ 0.17
$ (0.07) $ (0.03) $ (0.16)
============ ============ ============
============ ============NET INCOME (LOSS) PER COMMON SHARE - FULLY DILUTED $ 0.10 $ 0.24 $ 0.17 $ (0.07) $ (0.03) $ (0.16)
============ ============
============ ============ ============
Weighted average common shares
outstanding - basic 73,770,841 72,371,839 56,821,748 56,446,086 56,670,808 55,804,459
============ ============
============ ============ ============
Weighted average common shares
outstanding - fully diluted 77,605,018 75,931,529 58,438,783 56,446,086 56,670,808 55,804,459
============ ============
============ ============ ============
See accompanying notes to consolidated financial statements.31
ULTRA PETROLEUM CORPORATIONCORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE LOSS
Common stock
Share Capital
Authorized
10,000,000 preferred shares
100,000,000 common shares Year Ended Year Ended Year Ended
December 31, 2002 December 31, 2001 December 31, 2000
December 31, 1999
------------------------------------------------------------ --------------------------------------------- ----------------- -----------------
Issued Number Amount Number Amount Number Amount
------------------------------------------------------------ ----------------------------- ------ ------ ------ ------ ------ ------ ------
Common Shares
Balance, beginning of year 73,318,418 $ 92,585,148 56,939,762 $ 50,838,663$50,838,663 56,751,125 $ 50,666,631 56,493,725 $ 50,485,327$50,666,631
Employee stock option plan 617,750 1,101,674 701,500 611,387 5,000 4,032
257,400 181,304
Employee stock plan 183,000 1,299,765 682,198 1,098,448 119,403 80,000
- -Fair value non-employee
stock options -- 112,103 -- -- -- --
Acreage option purchase - --- -- -- -- 64,234 88,000 - -
Merger with Pendaries
Petroleum Ltd. -- -- 14,994,958 40,036,650 - - - - -
------------ --
----------- ------------ ---------- ----------------------- ---------- -----------------------
Balance, end of period 74,119,168 $ 95,098,690 73,318,418 $ 92,585,148$92,585,148 56,939,762 $ 50,838,663 56,751,125 $ 50,666,631
==========$50,838,663
=========== ============ ========== =========== ========== ===========
Treasury stock (132,500) (1,193,650) -- -- -- --
=========== ============ ========== ============
Retained earnings (deficit)
Balance, beginning of year (15,144,472) (25,034,398) (21,263,890)
Earnings for period 17,878,828 9,889,926 (3,770,508)
------------ ------------ ------------
Balance, end of period 2,734,356 (15,144,472) (25,034,398)
============ ============ ============
Six Months Ended Year Ended
December 31, 1999 June 30, 1999
------------------------------------------------------------
Issued Number Amount Number Amount
------------------------------------------------------------
Common Shares
Balance, beginning of year 56,493,725 $ 50,485,327 48,091,715 $ 32,312,036
Employee stock option plan 257,400 181,304 1,165,910 572,849
Conversion of special warrants - - 7,236,100 17,600,442
---------- ------------ ---------- ------------
Balance, end of period 56,751,125 $ 50,666,631 56,493,725 $ 50,485,327=========== ========== ===========
Other comprehensive loss -- (653,875) -- -- -- --
=========== ============ ========== ============
Retained earnings (deficit)
Balance, beginning of year (23,470,847) (14,540,681)
Earnings for period (1,563,551) (8,930,166)
------------ ------------
Balance, end of period (25,034,398) (23,470,847)
============ ======================= ========== ===========
32
ULTRA PETROLEUM CORPORATIONCORP.
CONSOLIDATED STATEMENTS OF CASH FLOW
Six Months
Year Ended Ended Year Ended
-------------------------------------------- -----------------------------
December 31,
December 31, December 31, December 31, June 30,-----------------------
2002 2001 2000
1999 1999 1999
------------ ------------ ------------ ------------- -------------- ---- ----
(unaudited)
CASH PROVIDED BY (USED IN):
OPERATING ACTIVITIES:Cash flows from operating activities:
Income (loss) for the year $ 8,081,521 $ 17,878,828 $ 9,889,926
$(3,770,508) $(1,563,551) $ (8,930,166)
Add (deduct):
Items not involving cash:Adjustments to reconcile income to net cash provided by
operating activities:
Depletion and depreciation 9,712,111 6,687,433 3,162,568 2,105,663 1,186,395 1,794,307
Deferred income taxes 5,059,166 2,086,762 Ceiling test write-down - - - - 3,416,786
Provision for bad debts - - 1,983,828 - 2,019,416--
Stock compensation 848,448 - - - -1,211,165 337,030 250,000
Net changes in non-cash working capital:
Restricted cash (2,127) (7,053) 390,145
(413,802) 379,272 (856,062)
Accounts receivable (4,039,741) 919,796 (5,740,728) 2,748,840 26,782 6,640,176
Prepaid expenses and other current assets 1,695,459 (1,983,721) (511,023)
2,348,214 49,896 (186,058)
Note receivable -- (683,137) - - - 750,000--
Accounts payable and accrued liabilities (2,415,606) 9,962,508 1,955,546 (4,570,146) 645,533 (2,635,020)1,705,546
Deferred revenue (100,000) (100,000) (100,000)
(50,000) (100,000)
------------------------------------------------------------------------------
35,609,864------------ ------------ ------------
Net cash provided by operating activities 19,201,948 35,098,446 9,046,434
332,089 674,327 1,913,379
------------------------------------------------------------------------------
INVESTING ACTIVITIES:------------ ------------ ------------
Cash flows from investing activities:
Oil and gas property expenditures (61,330,153)(61,257,518) (60,818,735) (22,157,020) (9,318,200) (6,187,786) (21,996,324)
Note receivable --- -- (2,530,976) - - -
Purchase of capital assets (814,205) (317,592) (212,300) (22,392) (45,054) (58,319)
Proceeds from sale of oil and gas properties -- 312,365 359,764
5,000,000 4,608,712 21,038,000
------------------------------------------------------------------------------
(61,335,380)------------ ------------ ------------
Net cash used in investing activities (62,071,723) (60,823,962) (24,540,532)
(4,340,592) (1,624,128) (1,016,643)
FINANCING ACTIVITIES:
Long-term------------ ------------ ------------
Cash flows from financing activities:
Borrowings on long-term debt, net 43,000,000 25,350,000 16,063,966
116,646 387,485 (6,583,126)
IssuanceProceeds from issuance of sharescommon stock 1,101,674 611,387 172,032
369,183 181,304 572,849
------------------------------------------------------------------------------Repurchase of common stock (1,193,650) -- --
------------ ------------ ------------
Net cash provided by financing activities 42,908,024 25,961,387 16,235,998
485,829 568,789 (6,010,277)
------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
DURING THE PERIOD------------ ------------ ------------
Net increase in cash and cash equivalents 38,249 235,871 741,900
(3,522,674) (381,012) (5,113,541)
CASH AND CASH EQUIVALENTS,Cash and cash equivalents, beginning of periodyear 1,379,462 1,143,591 401,691
3,924,365 782,702 5,896,243
------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,------------ ------------ ------------
Cash and cash equivalents, end of periodyear $ 1,417,711 $ 1,379,462 $ 1,143,591
$ 401,691 $ 401,691 $ 782,702
========================================================================================= ============ ============
SUPPLEMENTAL INFORMATION
Cash paid for:
Interest $ 2,691,608 $ 1,687,172 $ 802,364
$ 679,491 $ 564,810 $ 454,742
Income taxes $ -- $ 10,000 $ 25,000 $ 3,000 $ 3,000 $ -
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
33
ULTRA PETROLEUM CORPORATIONCORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in U.S. dollars unless otherwise noted)
Years ended December 31, 2002, 2001 and 2000, six months ended December 31, 1999 and
year ended June 30, 1999.2000.
DESCRIPTION OF THE BUSINESS
Ultra Petroleum CorporationCorp. (the "Company") is an independent oil and gas
company engaged in the acquisition, exploration, development, and production of
oil and gas properties. The Company was incorporated under the laws of British
Columbia, Canada. At March 1, 2000 the "Company"Company was continued 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:
Fiscal year change. The Company changed its fiscal year-end to a calendar year-
end effective December 31, 1999. The six month transition period ended December
31, 1999 is presented herein.
(a) Basis of presentation and principles of consolidation: The consolidated
financial statements include the accounts of the Company and its wholly owned
subsidiaries Ultra Petroleum (U.S.A.) Inc.,UP Energy Corporation, Ultra Resources, Inc, Pendaries Petroleum Ltd.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 Canada.the United States.
(c) Revenue recognition and deferred revenue:
Revenues from oil and gas operations are recognized at the time the oil is sold
or natural gas is delivered. The cash received upon dedicating certain
production volumes to a gas pipeline is deferred and is being included in
natural gas sales on a straight line basis over the term of the five year
dedication.
(d) Cash and cash equivalents: We consider all highly liquid investments with an
original maturity of three months or less to be cash equivalents.
(e)(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.
(f)(e) Capital assets: Capital assets are recorded at cost and depreciated using
the declining-balance method based on a seven-year useful life.
(g)(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. During 2000 and 1999, the Company's
primary oil and gas operations were conducted in the United States. During
2001, the Company began drilling activities in Bohai Bay, China.
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.
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.
34
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) Hedging 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 a financial institution 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) Foreign currency translation:
The Company has adopted the United States dollar as its reporting currency,
which is also its functional currency. The Company and its subsidiaries are
considered to be integrated operations and accounts in Canadian dollars are
translated using the temporal method. Under this method, monetary assets and
liabilities are translated at the rates of exchange in effect at the balance
sheet date; non-monetary assets at historical rates and revenue and expense
items at the average rates for the period other than depletion and depreciation
which are translated at the same rates of exchange as the related assets. The
net effect of the foreign currency translation is included in current
operations.
(j) 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,
2002, 2001 and 2000, the six months ended December 31, 1999 and the year ended June 30, 1999:2000:
For the six
months ended For the year
For the years ended December 31,
December 31, ended June 30,2002 2001 2000
1999 1999
--------------------------------- ------------- ------------------ ---- ----
Net income (loss) $ 8,081,521 $17,878,828 $ 9,889,926 $(1,563,551) $(8,930,166)
===========
=========== =========== ===========
Weighted average common shares outstanding
during the period 73,770,841 72,371,839 56,821,748 56,670,808 55,804,459
Effect of dilutive instruments 3,834,177 3,559,690 1,617,035 - -
-----------
----------- ----------- -----------
Weighted average common shares outstanding
during the period including the
effects of dilutive instruments 77,605,018 75,931,529 58,438,783 56,670,808 55,804,459
=========== =========== =========== ===========
Basic earnings (loss) per share $ 0.11 $ 0.25 $ 0.17 $ (0.03) $ (0.16)
===========
=========== =========== ===========
Diluted earnings (loss) per share $ 0.10 $ 0.24 $ 0.17 $ (0.03) $ (0.16)
===========
=========== =========== ===========
Number of shares not included in dilutive
earnings (loss) per share that would have
been antidilutive because the exercise price
was greater than the average market price of
the common shares.shares 130,570 373,942 - 1,026,122 359,167
===========--
=========== =========== ===========
(k)(j) Use of estimates: Preparation of consolidated financial statements in
accordance with accounting principles generally accepted accounting principles in Canadathe United States
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and
liabilities at the date of the financial statements, and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
(l)(k) Reclassifications: Certain amounts in the financial statements of the prior
years have been reclassified to conform to the current year financial statement
presentation.
35
(l) Accounting for stock-based compensation. Statement of Financial Accounting
Standards No. 123, "Accounting for Stock - Based Compensation" (SFAS No. 123)
defines a fair value method of accounting for employee stock options and similar
equity instruments. SFAS No. 123 allows for the continued measurement of
compensation cost for such plans using the intrinsic value based method
prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees"
(APB No. 25), provided that pro forma results of operations are disclosed for
those options granted. The Company accounts for stock options granted to
employees and directors of the Company under the intrinsic value method. Had the
Company reported compensation costs as determined by the fair value method of
accounting for option grants to employees and directors, net income (loss) and
net income (loss) per common share would approximate the following pro forma
amounts:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
(In thousands, except per share amounts)
Net income:
As reported $8,081,521 $17,878,828 $9,889,926
Pro forma $5,167,990 $14,924,923 $9,056,297
Net income per common share:
Basic:
As reported $0.11 $0.25 $0.17
Pro forma $0.07 $0.21 $0.16
Diluted:
As reported $0.10 $0.24 $0.17
Pro forma $0.07 $0.20 $0.16
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, 2000, expected volatility of approximately 45%, at
December 31, 2001, expected volatility of approximately 30%, at December 31,
2002, expected volatility of 30%. All options have expected lives of ten years.
(m) Impact of recently issued accounting pronouncements:
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No.
141, Business Combinations ("SFAS No. 141") and SFAS No. 142, Goodwill and Other
Intangible Assets ("SFAS No. 142"). SFAS No. 141 was effective as of July 1,
2001 and SFAS No. 142 was effective January 1, 2002. SFAS No. 141 requires that
the purchase method of accounting be used for all business combinations. SFAS
141 specifies criteria that intangible assets acquired in a business combination
must meet to be recognized and reported separately from goodwill. SFAS No. 142
requires that goodwill and intangible assets with indefinite useful lives no
longer be amortized, but instead tested for impairment at least annually in
accordance with the provisions of SFAS No. 142. SFAS No. 142 also requires that
intangible assets with estimable useful lives be amortized over their respective
estimated useful lives to their estimated residual values, and reviewed for
impairment in accordance with SFAS No. 121 and subsequently, SFAS No. 144 after
its adoption. The Canadian Institute of Chartered Accountants ("CICA") has
adopted similar standards and accordingly, there will be no U.S. - Canadian GAAP
differences arising from the addition of these standards. The Company has no
goodwill or intangible assets. In June 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No.
143"). SFAS No. 143 requires the Company to record the fair value of an asset
retirement obligation as a liability in the period in which it incurs a legal
obligation associated with the retirement of tangible long-lived assets that
result from the acquisition, construction, development and/or normal use of the
assets. TheBased on current estimates, the Company will alsowould record asset retirement
obligations (using a corresponding
asset which is depreciated over the life10% discount rate) and a cumulative effect of the asset. Subsequentchange in
accounting principle on prior years, related to the initial measurementdepreciation and accretion
expense that would have been reported had the fair value of the asset retirement
obligation, the obligation will be
adjusted at the end of each period to reflect the passage of time and changescorresponding increase in the estimated future cash flows underlyingcarrying amount of the obligation. The Company is
required to adopt SFAS No. 143 on January 1, 2003. The Company is currently
assessing the impact, if any, onrelated
long-lived asset. Currently the Company's consolidated financial statements
for future periods.assessment has been deemed not
material.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). SFAS No. 144
addresses financial accounting and reporting for the impairment or disposal of
long-lived assets. This Statement requires that long-lived assets be reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Recoverability of assets to
be held and used is measured by a comparison of the carrying amount of an asset
to future net cash flows expected to be generated by the asset. If the carrying
amount of an asset exceeds its estimated future cash flows, an impairment charge
is recognized by the amount by which the carrying amount of the asset exceeds
the fair value of the asset. SFAS No. 144 also broadens the definition of
discontinued operations to include all distinguishable components of an entity
that will be eliminated from ongoing operations. The Company has adopted SFAS
No. 144 as of January 1, 2002. Because the Company has elected the full-cost
method of accounting for oil and gas exploration and development activities, the
impairment provisions of SFAS No. 144 todo not apply to the Company's oil and gas
assets, which are subject to ceiling limitations. For the Company's non-oil and
gas assets, the method of impairment assessment is unchanged from SFAS No. 121.
The adoption of SFAS No. 144 had no impact on the Company's consolidated
financial statements.
36
Statement 145, Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections ("SFAS No. 145")
was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains
and Losses from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. We expect
adoption of this statement to result in the reclassification of losses on
extinguishment of debt for all periods from extraordinary to other income and
expense.
Statement 146, Accounting for Exit or Disposal Activities ("SFAS No.
146"), was issued in June 2002. SFAS No. 146 addresses significant issues
regarding the recognition, measurement and reporting of costs that are
associated with exit and disposal activities, including restructuring activities
that are currently accounted for pursuant to the guidance set forth in EITF
Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity ("Issue No. 94-3"). SFAS No. 146 will be
effective for the Company in January 2003. We expect the adoption of SFAS No.
146 to have no impact on our financial statements.
In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-based Compensation-Transition and Disclosure ("SFAS No. 148"). SFAS No.
148 amended FASB Statement No. 123, Accounting for Stock-Based Compensation
("Statement No. 123"), to provide alternative methods of transition 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 Statement 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 provision of SFAS No. 148 has no material impact on us, as
we do not plan to adopt the fair-value method of accounting for stock options at
the current time. We have included the required disclosures in Note 1 to the
Consolidated Financial Statements.
In November 2002, the FASB issued Financial Interpretation No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others - an interpretation of FASB
Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34 ("FIN
45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under certain
guarantees that it has issued. It also clarifies that a guarantor is required to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligation undertaken in issuing the guarantee. The initial recognition and
initial measurement provisions of FIN 45 are applicable on a prospective basis
to guarantees issued or modified after December 31, 2002, irrespective of the
guarantor's fiscal year-end. The disclosure requirements are effective for
financial statements of interim or annual periods ending after December 15,
2002. The Company currently does not have any guarantees other than to wholly
owned subsidiaries that are consolidated in place.
In January 2003, the FASB issued Financial Interpretation No. 46,
Consolidation of Variable Interest Entities - an interpretation of ARB No. 51
("FIN 46" or "Interpretation"). FIN 46 is an interpretation of Accounting
Research Bulletin 51, Consolidated Financial Statements, and addresses
consolidation by business enterprises of variable interest entities (VIEs). The
primary objective of the Interpretation is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. The Interpretation requires an enterprise to consolidate a VIE if that
enterprise has a variable interest that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's expected
residual returns if they occur, or both. An enterprise shall consider the rights
and obligations conveyed by its variable interests in making this determination.
This guidance applies immediately to variable interest entities created after
January 31, 2003, and to variable interest entities in which an enterprise
obtains an interest after that date. It applies in the first fiscal year or
interim period beginning after June 15, 2003, to variable interest entities in
which an enterprise holds a variable interest that it acquired before February
1, 2003. At this time, the Company does not have any VIEs.
2. ACQUISITION OF PENDARIES PETROLEUM LTD.:LTD:
Effective January 16, 2001, the Company completed the previously
announced agreement to acquire 100% of the outstanding shares of Pendaries
Petroleum Ltd. (Pendaries)("Pendaries") and its wholly owned subsidiary Sino-American
Energy Corporation in exchange for 14,994,958 shares of Ultra Petroleum Corp.
common stock valued
37
at $2.67. 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. 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, 2001, includes the assets and liabilities, as well as the
adjustments required to record the acquisition in accordance with purchase
accounting. 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.
If the acquisition had occurred at the
beginningAccordingly, Pendaries' results of 2000, the Company would have reported no additional expense for
operating expenses related to the China property as these properties still
remain in the development phase. Since the properties are not producing, there
would notoperations have been any impact to revenues, net income or earnings per share.
Additionally, no deferred tax liability would have been recorded as the net
operating losses on a consolidated level would have equaled the variance between
the book and tax basis. There would be no material change toincluded in the
consolidated financial statements forof income from the year endedeffective date of
acquisition. The consolidated balance sheet dated December 31, 2001, sinceincludes
the assets and liabilities, as well as the adjustments required to record the
acquisition occurred close to the beginning of the year.in accordance with purchase accounting.
3. OIL AND GAS PROPERTIES:
DECEMBER 31, DECEMBER 31,
2001 2000
---------------------------
Developed Properties:
Acquisition, equipment, exploration, development
drilling and environmental costs $100,574,404 $54,362,982
Less accumulated depletion, depreciation and
amortization (13,499,605) (7,047,605)
------------- ------------
87,074,799 47,315,377
Unproved properties - China 55,894,246 -
Unproved properties - Wyoming 12,252,142 12,413,338
------------- -----------
$ 155,221,187 $59,728,715
December 31, December 31,
2002 2001
---- ----
Developed Properties:
Acquisition, equipment, exploration, development drilling
and environmental costs $ 150,986,843 $ 100,574,404
Less accumulated depletion, depreciation and amortization (22,816,605) (13,499,605)
------------- -------------
128,170,238 87,074,799
Unproved properties - China 64,873,186 55,894,246
Unproved properties - Wyoming 14,318,984 12,252,142
------------- -------------
$ 207,362,408 $ 155,221,187
============= =============
===========
4. CAPITAL ASSETS:
December 31, December 31, December 31, December 31,
2001 20012002 2002 Accumulated 20012002 Net 20002001 Net
Cost Depreciation Book Value Book Value
------------------------------------------------------------------ ------------ ---------- ----------
Computer equipment $ 591,854 $337,648617,439 $ 418,137 $ 199,302 $254,206 $241,223
Office equipment 228,880 122,051138,479 90,401 106,829 67,325
Field equipment 183,775 118,934139,584 44,191 64,841
50,420
Other 258,625 91,8961,007,917 330,112 677,805 166,729
96,480---------- ---------- ---------- --------
-------- --------
$1,263,134 $670,529$2,038,011 $1,026,312 $1,011,699 $592,605
$455,448
========== ======== ================== ========== ========
5. LONG-TERM DEBT:
December 31, December 31,
2001 2000
----------- -----------
Bank indebtedness $43,000,000 $17,650,000
Short term obligations to be refinanced 3,092,928 6,880,612
----------- -----------
$46,092,928 $24,530,612
December 31, December 31,
2002 2001
---- ----
Bank indebtedness $86,000,000 $43,000,000
Other long-term obligations 3,858,810 2,892,486
Short-term obligations to be refinanced -- 3,092,928
----------- -----------
$89,858,810 $48,985,414
=========== ===========
Bank indebtedness: On March 22, 2000, theThe Company entered into(through its subsidiary) participates in a
new senior revolvinglong-term credit facility (New Facility) with a group of banks led by Bank One Texas N.A. Proceeds from the New
Facility were used to pay off the outstanding balance of the Initial Facility at
March 22, 2000 and to fund the Company's drilling programs. This facility
provides forThe
agreement specifies a maximum lineloan amount of credit of $40$150 million withand an initialaggregate
borrowing base of $18 million. The borrowing base was increased on January 7,$120 million at November 4, 2002. At December 31, 2002, to $50
million. Thethe
Company had $86 million outstanding balanceand $34 million unused and available on the
line bears interest at the bank's Prime
Rate or LIBOR plus two and one half percent and is secured by all of the
Company's Wyoming oil and gas properties.credit facility.
The New Facility expirescredit facility matures on March 1, 2003.
On March 1, 2002, the Company closed a syndicated senior revolving credit
facility with an initial borrowing base of $80 million.2005. The syndicate of five
banks includes: Bank One, NA, Union Bank of California, Hibernia National Bank,
Guaranty Bank, and Compass Bank. The outstanding balance on the line bearsnotes 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 1.75%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 secured by allcharged quarterly for any
unused portion of the credit line.
38
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 Wyomingproved reserves and the bank's
forecast of future oil and gas properties.
The revolving credit facility contains various covenants and requiresprices. Additionally, the Company is subject to
maintain various financialquarterly reviews of compliance with the covenants under the bank facility
including minimum coverage ratios as defined inrelating to interest, working capital, general
and administrative expenditures and advances to Sino-American Energy Company. In
the agreement.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, 2002, the Company was in
compliance with the covenants and required ratios.
Short termOther long-term obligations: These costs relate to the long-term portion of
production taxes payable.
Short-term obligations to be refinanced: These costs relate toitems consist of drilling
obligations which will be funded on a long termlong-term basis through the use of the
available borrowing base of bank indebtedness.
6. SHARE CAPITAL:COMMON STOCK:
(a) AUTHORIZED:
100,000,000 common shares with no par value
(b) ISSUED:
Number of
Shares Amount
---------- -----------
Balance, June 30, 1998 48,091,715 $32,312,036
Shares issued during the year:
For cash 1,165,910 572,849
For conversion of special warrants 7,236,100 17,600,442
---------- -----------
Balance, June 30, 1999 56,493,725 50,485,327
Shares issued during the period:
For cash 257,400 181,304
---------- -----------
Balance, December 31, 1999 56,751,125 50,666,631
Shares issued during the period:
For cash 5,000 4,032
For services rendered 183,637 168,000
---------- -----------
Balance, December 31, 2000 56,939,762 50,838,663
Shares issued during the period:
For cash 1,383,698 1,709,835
For Pendaries Acquisition 14,994,958 40,036,650
---------- -----------
Balance, December 31, 2001 73,318,418 $92,585,148
========== ===========
(c) SHARE OPTIONSStock options: The following table summarizes the changes in stock options
for the three-year period ending December 31, 2001:
Weighted Average
Number of Exercise Price
Options (Cdn)
----------- ---------------
Balance, June 30, 1998 3,463,220 $0.50 to $7.10
Granted 2,150,000 $1.46 to $3.85
Exercised (545,600) $0.50 to $1.05
Cancelled (1,445,360) $3.79 to $7.10
----------- ---------------
Balance, June 30, 1999 3,622,260 $1.50 to $6.96
Granted 1,595,000 $1.00 to $1.20
Exercised (257,400) $ 1.05
Cancelled (440,000) $ 1.05
----------- ---------------
Balance, December 31, 1999 4,519,860 $1.00 to $6.63
Granted 1,255,000 $0.81 to $4.15
Exercised (5,000) $ 1.20
Cancelled (1,244,860) $1.20 to $6.63
----------- ---------------
Balance, December 31, 2000 4,525,000 $0.81 to $4.15
Granted 1,630,000 $4.69 to $8.20
Exercised (701,500) $1.00 to $4.90
Cancelled (22,500) $1.79 to $8.20
----------- ---------------
Balance, December 31, 2001 5,431,000 $0.81 to $8.20
=========== ===============
The share options outstanding at December 31, 2001 were held as follows:2002:
Number of Weighted Average
Options Exercise Price (US$)
------- --------------------
Balance, December 31, 1999 4,519,860 $0.64 to $4.22
Granted 1,255,000 $0.51 to $2.65
Exercised (5,000) $0.76
Cancelled (1,244,860) $0.76 to $4.22
---------- --------------
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 $8.86
No compensation resulted from the granting of these options as all were
granted at or above the market value of the common shares at the date of grant.
Stock options granted to consultants have been assessed at fair value and
capitalized to the full cost pool.
The following table summarizes information about the stock options
outstanding at December 31, 2001:2002:
Options Outstanding Options Exercisable
--------------------------------------- --------------------------------------------------------- -------------------
Weighted Weighted
Range of
Weighted Average Average Average
Range of Exercise Number Remaining Exercise Price Number Exercise
Price
Prices (Cdn)(Cdn$) Outstanding Contractual Life (Cdn)Price (US$) Exercisable (Cdn)Price (US$)
------------- ----------- ---------------- ----------- ----------- ----------------- -------------- ------------ --------------------------
$0.81-$0.51-$1.79 3,743,500 7.71.14 3,350,500 6.7 Years $1.40 3,743,500 $1.40
$4.15-8.20 1,687,500 9.2$0.89 3,350,500 $0.89
$4.15-$8.20 2,211,250 8.6 Years $6.20 1,023,750 $5.86$3.26 1,830,750 $2.12
(d) SHARE PURCHASE WARRANTS:(b) Share purchase warrants: The following table summarizes the changes in the
share purchase warrants for the three-year period ending December 31, 2001:2002:
39
Number of Special Warrants Price Range
(Cdn)
-------------------------------------Special Warrant (US$)
=============== =====
Balance, June 30, 1998 1,455,000 $0.35 to $3.35
Issued upon conversion of Special Warrants 5,832,100 $4.02 to $5.20
Exercised (205,000) $0.48 to $0.56
Expired (1,250,000) $4.02 to $4.62
-------------
Balance, June 30, 1999 5,832,100 $4.02 to $5.20
Expired (4,428,100) $4.02 to $4.62
-------------
Balance, December 31, 1999 1,404,000 $4.02$2.56 to $5.20
-------------$3.31
Expired (1,404,000) $4.02$2.56 to $5.20$3.31
-------------
Balance, December 31, 2000 ---
=============
Statement7. FINANCIAL INSTRUMENTS:
In April 2002, the Company began hedging a portion of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS 123) definesits production
with a fixed price to index price swap agreement. The purpose of the hedges is
to provide a measure of stability to the Company's cash flows in an environment
of volatile oil and gas prices and to manage the exposure to commodity price
risk. 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 methodas specified in FAS 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, 2002 the Company had a current derivative liability of accounting for employee
stock options and similar equity instruments. SFAS 123 allows$653,875, which is
included in other current assets in our balance sheet.
During 2002, the Company received payments from counter-parties
totaling $1,835,800 as its net proceeds from hedging activities. This total
includes $312,000 for the continued
measurementsecond quarter of
compensation cost2002, $1,130,100 for such plans using the intrinsic value based method
prescribed by APB Opinion No. 25, "Accountingthird
quarter of 2002, and the $393,700 for Stock Issued to Employees"
(APB 25), provided that pro forma resultsthe fourth quarter of operations are disclosed for those
options granted. The Company accounts for stock options granted to employees and
directors of2002.
At year-end 2002, the Company underhad hedges in place covering
approximately 15,000 MMBtu or approximately 13 MMcf of gas per day for calendar
2003 at an average price of $3.11 per MMBtu or approximately $3.35 per Mcf. Of
these hedges, 10,000 MMBtu are in the intrinsic value method. Hadform of swaps and 5,000 MMBtu are fixed
price forward sales at Opal, Wyoming. The swaps are priced relative to the index
price at the first of each month at Opal, Wyoming, where the Company reported compensation costsdelivers
most of its gas to the purchasers.
In the first quarter of 2003, the Company entered into additional swaps
covering an additional 10,000 MMBtu or approximately 9 MMcf of gas for the
period from April 1, 2003 to October 31, 2003 at a price of $3.75 per MMBtu or
approximately $3.95 per Mcf (pricing referenced to Opal), plus an additional
5,000 MMBtu or approximately 4 MMcf of gas per day for the same period at a
price of $4.25 per MMBtu or approximately $4.48 per Mcf (pricing referenced to
Opal).
The table below summarizes the hedges in place as determined by the fair value method of accounting
for option grants to employees and directors, net income (loss) and net income
(loss) per common share would approximate the following pro forma amounts:March 3, 2003:
For the Years Ended December 31,
--------------------------------------
2001 2000 1999
----------- ---------- -----------
(In thousands, except per share amounts)TYPE PERIOD VOLUME PRICE / MMBTU
---- ------ ------ -------------
Net income:
As reported $17,878,828 $9,889,926 $(3,770,508)
Pro forma $14,924,923 $9,056,297 $(6,000,150)
Net income per common share:
Basic:
As reportedFixed Price Sale Calendar 2003 5,000 $ 0.253.06
Swap Calendar 2003 5,000 $3.005
Swap Calendar 2003 5,000 $ 0.173.27
Swap April-Oct 2003 10,000 $ (0.03)
Pro forma3.75
Swap April-Oct 2003 5,000 $ 0.21 $ 0.16 $ (0.11)
Diluted:
As reported $ 0.24 $ 0.17 $ (0.03)
Pro forma $ 0.20 $ 0.16 $ (0.11)4.25
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
31,1999, expected volatility ofThese hedges represent approximately 68%, at December 31, 2000,
expected volatility of approximately 45%, at December 31, 2001, expected
volatility of 30%. All options have expected lives of ten years.
7. RELATED PARTY TRANSACTIONS:
The following amounts were paid to directors and officers of the Company or its
affiliates:
Six months ended Year ended
December 31, June 30,
1999 1999
-----------------------------
Office rent and administration services to a company
controlled by a director $ 106,899 $404,806
---------------- -------------
Management bonus to directors and officers $ - $190,743
---------------- -------------
Wages/fees to directors and officers $ - $193,320
---------------- -------------
Amounts due from related parties:
Enterprise Exploration and Production Inc. (a) - 22,601
Transglobe Energy Corporation (b) 4,299 3,010
---------------- -------------
Total $ 4,299 $ 44,206
================ =============
Amounts due to related parties:
Arrowhead Minerals Corporation $ - $ 12,200
Enterprise Exploration and Production Inc. - 39,869
---------------- -------------
Total $ - $ 52,069
================ =============
The above amounts due from and to related parties were incurred in the normal
course of oil and gas operations. There were no related party transactions for
the year ended December 31, 2001 and 2000.
Related party relationships:(a) Enterprise Exploration and Production Inc.
("Enterprise")
One50% of the Company's directors isforecasted
production for the owner of Enterprise. The Companyperiod from April 1, 2003 to October 31, 2003, and
Enterprise both own working interests in oneapproximately 35% of the Company's oil and gas
properties.
(b) Transglobe Energy Corporation ("Transglobe")
One of the Company's previous directors is a director and Chairman of
Transglobe. The Company and Transglobe both own working interests in a number of
the same oil and gas properties.forecasted production for calendar 2003.
8. NOTES RECEIVABLE:
In conjunction with the arrangement pursuant to which Ultra would acquire all of
the issued and outstanding shares of Pendaries Petroleum Ltd (Pendaries) (Note
2), Ultra provided a line of credit to Pendaries' subsidiary, Sino-American
Energy Corporation
(Sino-American). The line of credit bears interest at the prime rate of Bank One
Texas, N.A (9.3% at December 31, 2000). The outstanding balance at December 31,
2000 was $2,530,976. As of January 16, 2001, the closing date of the Pendaries
acquisition, the note was converted to an inter-company receivable.
9. INCOME TAXES:
The recovery of (provision for)(recovery of) provision for income taxes for the years ended
December 31, 20002002 and 2001 vary from the amounts that would be computed by
applying the U.S. Federal income tax rate of 38.5%35% to pretax income as a result of
the following:
40
December 31, 20002002 December 31, 2001
----------------- -----------------
Federal tax expense at statutory rate $ 3,598,3454,599,240 $ 7,133,9936,987,957
State income tax expense 43,132456,497 468,024
Adjustment for foreign losses 94,087 146,036
Adjustment to estimated acquired net operating
losses and partnership income 1,162,921-- 169,417
Percentage depletion (477,417)(185,016) (523,929)
Other 5,57294,358 34,870
Decrease in valuation allowance (4,332,553)-- (5,195,612)
------------ ------------------------ -----------
Actual income tax expense $ -5,059,166 $ 2,086,763
------------ ------------------------ -----------
The tax effects of temporary differences that give rise to significant
portions of the future tax assets and liabilities are as follows:
December 31, 20002002 December 31, 2001
----------------------------------- -----------------
Future tax assets:
Property and equipment $ 6,690,227 $ 9,472,486
Net operating loss carry-forward 6,028,824 10,288,856$ 9,878,862 $ 9,998,935
Other - 36,182
----------- -------------
12,719,051 19,797,524797,440 560,111
------------ ------------
10,676,302 10,559,045
Less valuation allowance (5,208,618) -
----------- --------------- --
------------ ------------
Total future assets 7,510,433 19,797,52410,676,302 10,559,046
------------ ------------
Future tax liabilities
- propertyProperty and equipment (7,510,433) (24,771,533)
----------- -------------(20,709,476) (15,533,055)
------------ ------------
Net future tax assets (liabilities) $ -$(10,033,174) $ (4,974,009)
----------- -------------
At December 31, 2001,------------ ------------
At December 31, 2002, the Company has available non-capital loss
carry-forwards as follows:
Losses for Financial Timing Losses for
Statements Differences Tax Purposes Expiry Dates
----------------------------------------------------------------------------------------------- ----------- ------------ ------------
Canada (Cdn dollars) $9,082,955$9,506,844 $ 202,180421,910 $ 8,880,775 2001-2008
-------------------------------------------------------------------------------------9,928,754 2002-2008
United States (US dollars) $ - $25,967,537 $ 25,967,537-- $25,827,299 $25,827,299 2008-2021
-------------------------------------------------------------------------------------
During 2001, the Company fully utilized available net operating loss
carry-
forwardscarry-forwards attributable to continuing operations for financial statement
purposes.
The benefit of the Canadian loss carry-forwards 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.
10.9. 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% which
began in February 2000. The plan operates on a calendar year basis and began in
February 1998. The expense associated with the Company's contribution was
$236,765, $187,255 and $130,341 for the years ended 2002, 2001 and 2000,
respectively, $27,060
for the six months ended December 31, 1999 and $58,978 for the year ended June
30, 1999.
11.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 their accounting standards to
U.S. GAAP. The consolidated financial statements have been prepared in accordance with
generally accepted accounting principles in Canada ("Canadian GAAP"), which
differ in certain respects from generally accepted accounting principles inproposed effective date for implementing Stock-Based Compensation
and Other Stock-Based Payments, Section 3870, is January 1, 2004. In the United States ("US GAAP").
Hadyear
ending December 31, 2002, the Company followed US GAAP,recorded to the carrying value of the oil and gas
properties would not be materially different thanfull cost pool under
Canadian GAAP. Under US
GAAP, the Company is required to discount future net revenues at 10% for
purposes of calculating any required ceiling test write-down. Under Canadian
GAAP, future net revenues are not discounted, however, they are reduced for
estimated futurecapitalized general and administrative expenses and interest. Fora consultant stock-based
compensation expense of $112,103. Under current Canadian GAAP, this amount would
have been recognized as a disclosure item, with no impact on the year
ended,financial
statements.
41
Recorded in other comprehensive income in the six months ended December 31, 1999 and the years-ended June 1999 and
1998, the calculationsEquity section of our
balance sheet is an offset to a liability that measures a future effect of the
ceiling test write downsfixed price to index price swap agreements that werethe Company 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 approximated amounts determined under US GAAP.
Total Shareholders' Equity under US GAAP would be $169,199 lower due to the
mannerfuture effects of derivative instruments are recorded through revenue in the
period in which escrowed shares were accounted forthe 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 fiscal 1995.
12.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:
The Company is committed to payments,payment under an operating lease for office
space in Denver of $376,000$192,000 in 20022003; however, this amount may change because the
current office lease expires June 2003 and $380,000 in fiscal 2003 .the Company will be negotiating a new
lease. Approximately 50% of these
payments arethis payment is offset by a sublease with the same
term as the primary lease. During the six months endedIn December 31, 1999,2002, the Company settled the
litigation relatingsigned a sublease for
office space in Houston, which it has committed to the 1998 plugging and abandonmentthrough April 2007. The
Company's total liability of the White Estate No.
1 well in Henderson County, Texas. The settlement and the legal fees associated
with this litigation resulted in a charge of $1,875,610.sublease is $429,065.
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.
13.12. FAIR VALUE OF FINANCIAL INSTRUMENTS:
For certain of the Company's financial instruments including accounts
receivable, notenotes 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.
14.13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
As discussed in Note 9, during the year the Company fully utilized all available
net operating loss carry-forwards attributable to continuing operations for
financial statement purposes. The quarterly numbers presented below reflect
that fourth quarter adjustment spread proportionately throughout the year and as
a result differ from those previously filed.
Revenues
from Net Income Basic Diluted
Continuing Before Income Income Tax Net Earnings Per Earnings Per
Operations Expenses taxTax Provision Provision Net Income Per Share --------------------------------------------------------------------------------------Share
---------- -------- ------------- --------- ------ --------- -----
(in thousands, except for per share data)
2002
First Quarter $ 9,106 $ 6,323 $ 2,783 $ 1,071 $ 1,712 $ 0.02 $ 0.02
Second Quarter $ 8,143 $ 6,161 $ 1,982 $ 676 $ 1,306 $ 0.02 $ 0.02
Third Quarter $ 8,671 $ 7,108 $ 1,563 $ 602 $ 961 $ 0.01 $ 0.01
Fourth 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
======= ======= ======= ======= =======
2001
First Quarter $16,747 $ 5,717 $11,031 $1,146$ 1,146 $ 9,885 $0.14 $0.13$ 0.14 $ 0.13
Second Quarter $10,048 $ 5,274 $ 4,774 $ 500 $ 4,274 $0.06 $0.05$ 0.06 $ 0.05
Third Quarter $ 6,937 $ 5,091 $ 1,846 $ 199 $ 1,647 $0.02 $0.02$ 0.02 $ 0.02
Fourth Quarter $ 7,469 $ 5,155 $ 2,315 $ 242 $ 2,073 $0.03 $0.03$ 0.03 $ 0.03
------- ------- ------- ------------- -------
$41,201 $21,237 $19,966 $2,087$ 2,087 $17,879
======= ======= ======= ====== =======
2000
First Quarter $ 2,357 $ 1,987 $ 370 - $ 370 $0.01 $0.01
Second Quarter $ 2,652 $ 2,036 $ 616 - $ 616 $0.02 $0.02
Third Quarter $ 3,922 $ 2,122 $ 1,800 - $ 1,800 $0.03 $0.03
Fourth Quarter $12,072 $ 4,969 $ 7,103 - $ 7,103 $0.12 $0.12
------- ------- ------- ------ -------
$21,003 $11,114 $ 9,889 - $ 9,889
======= ======= ======= ====== =======
15.42
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. 69:69, 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, 2002, 2001 2000 and 19992000 are based upon estimates
prepared by Netherland, Sewell & Associates, Inc. dated January 21, 2003,
February 21, 2002 and February 12, 2001, and February 4, 2000, respectively. The reserve reports as of July 1, 1999
have been prepared by Gilbert Lausten Jung Associates Ltd. These are estimated
quantities of proved oil and gas reserves for the Company and the changes in
total proved reserves as of December 31, 2002, 2001 2000 and for the six months ended
December 31, 1999 and as of June 30, 1999.2000. All such reserves
are located in the United States.
Green River Basin, Wyoming.
B. ANALYSES OF CHANGES IN PROVEN RESERVES:
OIL (BBLS) GAS (MCF)
--------------------------------- ---------
Reserves, July 1, 1998 579,000 57,100,000
--------- -------------
Extensions, discoveries and additions 66,000 8,640,000
Production (42,000) (4,129,000)
Revisions 125,000 8,400,000
Acquisition of reserves in place - -
Sale of reserves in place (308,000) (28,575,000)
--------- -------------
Reserves, July 1, 1999 420,000 41,436,000
--------- -------------
Extensions, discoveries and additions 266,000 33,228,000
Production (19,600) (1,907,600)
Revisions (91,400) (1,525,400)
Acquisition of reserves in place - -
Sale of reserves in place - -
--------- -------------
Reserves, JulyJanuary 1, 2000 575,000 71,231,000
--------- ----------------------- ------------
Extensions, discoveries and additions 741,800 91,369,000
Production (50,400) (5,297,400)
Revisions 23,900 3,087,400
Acquisition of reserves in place - --- --
Sale of reserves in place - --- --
---------- -------------------------
Reserves, January 1, 2001 1,290,300 160,390,000
---------- -------------------------
Extensions, discoveries and additions 2,222,900 278,057,000
Production (118,800) (11,499,800)(116,400) (11,500,000)
Revisions 88,400 (3,117,600)86,000 (3,117,400)
Acquisition of reserves in place - --- --
Sale of reserves in place - -
------------- --
---------- ------------
Reserves, January 1, 2002 3,482,800 423,829,600
--------------------- ------------
Extensions, discoveries and additions 1,101,500 139,044,000
Production (151,200) (16,496,000)
Revisions 1,125,900 120,743,400
Acquisition of reserves in place -- --
Sale of reserves in place -- --
---------- ------------
Reserves, January 1, 2003 5,559,000 667,121,000
========== ============
Proved developed reserves:
July 1, 1999 350,000 34,400,000
========== ============
January 1, 2000 297,000 36,480,000
========== ============
January 1, 2001 683,000 84,550,000688,000 85,141,000
========== ============
January 1, 2002 1,295,000 150,397,000
========== ============
January 1, 2003 2,003,000 222,608,000
========== ============
C. STANDARDIZED MEASURE:
The standardized measure of discounted future net cash flows related to
proven oil and gas reserves are as follows (000)(US$000):
43
December 31, December 31, December 31,
June 30,2002 2001 2000
1999 1999
------------ ------------ ------------ ------------- ---- ----
Future cash inflows $ 2,132,521 $ 939,441 $1,301,456 $148,609 $ 81,7971,301,456
Future production costs (569,034) (257,960) (205,935) (34,708) (13,638)
Future development costs (254,892) (149,806) (43,395) (20,963) (3,677)
Future income taxes (25,135) (293,630) - -
------------ ------------ ------------(432,663) (184,164) (390,868)
----------- --------- -----------
Future net cash flows 506,541 758,496 92,938 64,482
Discount875,932 347,511 661,258
Discounted at 10% (332,707) (402,909) (51,663) $(38,451)
------------ ------------ ------------(558,967) (228,253) (351,257)
----------- --------- -----------
Standardized measure of
discounted future net cash flows $ 173,834316,965 $ 355,587119,259 $ 41,275 $ 26,031
============ ============ ============310,001
=========== ========= Pre tax===========
Pre-tax standardized measure SEC PV-10 $ 473,528 $ 182,460 $ 493,243
$ 41,275 $ 26,031
============ ============ ======================= ========= ===========
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 (000)(US$000)
December 31, December 31, December 31,
June 30,2002 2001 2000
1999 1999
------------ ------------ ------------ ------------- ---- ----
Standardized measure, beginning $ 355,587119,259 $ 41,275 $26,031310,001 $ 15,74933,822
Net revisions 119,995 (1,820) (371) (1,306) 8,511
Extensions, discoveries and other changes 136,194 177,819 140,348 24,771 6,641279,389
Sales of reserves in place - - - (21,751)-- -- --
Changes in future development costs (40,825) (31,066) (9,622) (7,677) (1,241)
Sales of oil and gas, net of production costs (39,985) (39,762) (18,083) (3,457) (4,451)
Net change in prices and production costs (313,708) 191,885 (4,330) 8,20191,501 (407,434) 160,675
Development costs incurred during the
period that reduce future development costs -1,573 -- 1,385 - 15,787
Accretion of discount 35,55918,246 49,324 4,127 2,603 1,575
Net change in income taxes (8,775) 4,643 4,640 (2,990)
------------ ------------ ------------(88,992) 62,196 (141,321)
--------- --------- ---------
Standardized measure, ending $ 173,834 $355,587 $41,275316,965 $ 26,031
============ ============ ============119,259 $ 310,001
========= ========= =========
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
E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES
(000)(US$000):
UNITED STATES
UNITED STATES
- -------------
Year Ended Year Ended Six Months Ended Year Ended
Years Ended December 31, December 31, December 31,
June 30,2002 2001 2000
1999 1999
------------------------------------------------------------------- ---- ----
Acquisition costs - unproved properties $ 937 $ 310 $ - $ 375 $ 598--
Exploration 22,722 33,845 11,175
3,505 3,907
Development 28,620 11,950 18,115
2,308 17,491
----------- ----------- ------------ -------------------- -------- --------
Total $46,105 $29,290 $ 6,188 $21,996
=========== =========== ============ ============52,279 $ 46,105 $ 29,290
======== ======== ========
CHINA
- -----
Year Ended Year Ended Six Months Ended Year Ended
Years Ended December 31, December 31, December 31,
June 30,2002 2001 2000
1999 1999
------------------------------------------------------------------- ---- ----
Acquisition costs - unproved properties $11,944 $ -8,979 $ -11,944 $ ---
Exploration - - - --- -- --
Development - - - -
----------- ----------- ------------ -------------- -- --
-------- -------- --------
Total $11,944 $ -8,979 $ 11,944 $ -
=========== =========== ============ ============--
======== ======== ========
F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (US$000):
Year Ended Year Ended Six Months Ended Year Ended
Years Ended December 31, December 31, December 31,
June 30,2002 2001 2000
1999 1999
------------------------------------------------------------------- ---- ----
Oil and gas revenue $41,201 $21,003 $ 4,78643,342 $ 7,02241,201 $ 21,003
Production expenses and taxes (11,411) (9,023) (4,241) (1,329) (2,571)
Depletion and depreciation (9,712) (6,687) (3,163)
(1,186) (1,794)
----------- ----------- ------------ -------------------- -------- --------
Total $25,491 $13,599 $ 2,27122,219 $ 2,657
=========== =========== ============ ============25,491 $ 13,599
======== ======== ========
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this item will be included in the Company's
definitive proxy statement, which will be filed not later than 120 days after
December 31, 2002 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, 2002 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
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, 2002, and is incorporated herein by reference.
45
NUMBER OF SECURITIES
REMAINING AVAILABLE FOR
FUTURE ISSUANCE UNDER
NUMBER OF SECURITIES TO WEIGHTED-AVERAGE EQUITY COMPENSATION PLANS
BE ISSUED UPON EXERCISE EXERCISE PRICE OF (EXCLUDING SECURITIES
OF OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, REFLECTED IN THE FIRST
PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS COLUMN)
------------- ------------------- ------------------- -------
Equity compensation plans
approved by security holders
at 12/31/2002 5,561,750 $2.79 5,651,500
Equity compensation plans not
approved by security holders n/a n/a n/a
--------- ----- ---------
Total 5,561,750 $2.79 5,651,500
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, 2002 and is incorporated herein by reference.
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures. Based on their
evaluation as of a date within 90 days of the filing date of this Annual Report
on Form 10-K, the Company's principal executive officer and principal financial
officer have concluded that the Company's disclosure controls and procedures (as
defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of
1934 (the "Exchange Act")) are effective to ensure that information required to
be disclosed by the Company in reports that it files or submits under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the Securities and Exchange
Commission.
(b) Changes in Internal Controls. There were no significant changes in
the Company's internal controls or in other factors that could significantly
affect these controls subsequent to the date of their evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
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: None
3. Exhibits. The following Exhibits are filed herewith pursuant
to Rule 601 of the Regulation S-K or are incorporated by
reference to previous filings. Exhibits designated with a "+"
constitute a management contract or compensatory plan or
arrangement required to be filed as an exhibit pursuant to
Item 14(c) of Form 10-K.
Exhibit Number 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)
46
3.2 By-Laws of Ultra Petroleum Corp. - (incorporated by reference
to Exhibit 3.2 of the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 2001)
4.1 Specimen Common Share Certificate - (incorporated by reference
to Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 2001)
10.1 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
10.2 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)
10.3 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)
10.4 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)
10.5 Ratification of and Amendment to Mortgage dated February 15,
2001 (incorporated by reference to Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the period ended
June 30, 2001)
10.6 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)
10.7 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.
99.1 Certification of Chief Executive Officer
99.2 Certification of Chief Financial Officer
(b) Reports on Form 8-K
None
47
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 25, 2003 By: /s/ Michael D. Watford
Name: Michael D. Watford
Title: 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,
---------------------- Chief Executive Officer and President March 25, 2003
Michael D. Watford
/s/ W. Charles Helton
----------------------
W. Charles Helton Director March 25, 2003
/s/ James E. Nielson
----------------------
James E. Nielson Director March 25, 2003
/s/ Robert E. Rigney
----------------------
Robert E. Rigney Director March 25, 2003
/s/ James C. Roe
----------------------
James C. Roe Director March 25, 2003
/s/ F. Fox Benton III
----------------------
F. Fox Benton III Chief Financial Officer March 25, 2003
48
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)
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 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
10.2 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)
10.3 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)
10.4 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)
10.5 Ratification of and Amendment to Mortgage dated February 15,
2001 (incorporated by reference to Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the period ended
June 30, 2001)
10.6 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)
10.7 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.
99.1 Certification of Chief Executive Officer
99.2 Certification of Chief Financial Officer