Prepared by R.R. Donnelley Financial -- Form 10-K/A dated 12/31/2001

10-K/A 1 d10ka.htm FORM 10-K/A DATED 12/31/2001 Prepared by R.R. Donnelley Financial -- Form 10-K/A dated 12/31/2001

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K / A

Amendment No. 1

(Mark one)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transaction period from to

Commission file number 1-14344

PATINA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		75-2629477 (IRS Employer Identification No.)

1625 Broadway Denver, Colorado (Address of principal executive offices)		80202 (Zip Code)

Registrant’s telephone number, including area code (303) 389-3600

Securities registered pursuant to Section 12(b) of the Act

Title of each class		Name of each exchange on which registered
Common Stock, $.01 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

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 requirements for the past 90 days. x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

The aggregate market value of the 17,959,000 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on March 1, 2002 of $22.00 per share as reported on the New York Stock Exchange, was $395,093,000. Shares of common stock held by each officer and director and by each person who owns 5% or more of the outstanding common stock have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes. The preceding amounts were adjusted to reflect the June 20, 2002 25% stock dividend.

As of March 1, 2002, the registrant had 25,950,635 shares of common stock outstanding (amount has been adjusted for the June 20, 2002 25% stock dividend and excludes 1,124,289 common shares held as treasury stock).

DOCUMENT INCORPORATED BY REFERENCE

Part III of the report is incorporated by reference to the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 2002.

PATINA OIL & GAS CORPORATION

Annual Report on Form 10-K / A

Amendment No. 1

December 31, 2001

EXPLANATORY NOTE—THIS AMENDMENT NO. 1 ON FORM 10-K /A TO THE REGISTRANT’S FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001 IS BEING FILED FOR THE PURPOSES OF GIVING EFFECT TO THE RESTATEMENT OF THE COMPANY’S CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001. SEE NOTE 1 TO THE FINANCIAL STATEMENTS FOR A SUMMARY OF THE SIGNIFICANT EFFECTS OF THE RESTATEMENT. THE RESTATEMENT RELATED TO APPLYING REQUIRED ACCOUNTING TREATMENT FOR CERTAIN STOCK BASED COMPENSATION ARRANGEMENTS. IN ADDITION, ALL SHARE AND PER SHARE AMOUNTS FOR ALL PERIODS HAVE BEEN RESTATED TO REFLECT THE 5-FOR-4 STOCK SPLIT WHICH WAS EFFECTED IN THE FORM OF A STOCK DIVIDEND TO COMMON STOCKHOLDERS OF RECORD AS OF JUNE 10, 2002 WITH A PAYMENT DATE OF JUNE 20, 2002. GENERAL INFORMATION IN THE ORIGINALLY FILED 10-K WAS PRESENTED AS OF THE MARCH 5, 2002 FILING DATE OR EARLIER. UNLESS OTHERWISE STATED HEREIN, SUCH INFORMATION HAS NOT BEEN UPDATED IN THIS AMENDED FILING.

PART I

ITEM 1. BUSINESS

General

Patina Oil & Gas Corporation (“Patina” or the “Company”) is an independent energy company engaged in the acquisition, development, exploitation and production of oil and natural gas. The Company’s properties and oil and gas reserves are predominantly located in the Wattenberg Field (“Wattenberg”) of Colorado’s Denver-Julesburg Basin (“D-J Basin”). Patina is one of the largest producers in the field, currently accounting for over 30% of its production. Wattenberg is one of the ten largest natural gas fields in the U.S. Since its discovery in 1970, cumulative production exceeds three trillion cubic feet of natural gas equivalents. The Field is located approximately 35 miles northeast of Denver and stretches over portions of Adams, Boulder, Broomfield and Weld Counties. One of Wattenberg’s most attractive features is that it contains eight potentially productive formations at depths ranging from 2,000 to 8,000 feet. Three of the formations, the Codell, the Niobrara and the J-Sand, are “blanket” zones in the area of the Company’s holdings. Other formations, including the Sussex, Shannon and Dakota are more localized. The existence of several pay sands allows for multiple completions within a single wellbore, reducing drilling risks and operating costs.

The Company was formed in 1996 to hold the Wattenberg assets of Snyder Oil Corporation (“SOCO”) and to facilitate the acquisition of SOCO’s then largest competitor in the field, Gerrity Oil & Gas Corporation (“Gerrity”). In the Gerrity acquisition, SOCO retained 17.5 million shares of the Company’s common stock and Gerrity’s shareholders received 7.5 million shares of common stock, $40.0 million of 7.125% convertible preferred stock and 3.8 million $10.00 common stock warrants. In 1997, a series of transactions eliminated SOCO’s ownership in the Company. The 7.125% preferred stock was fully retired in January 2000 and the remaining $10.00 warrants were converted into common stock with the Company receiving cash proceeds of $36.0 million in May 2001.

Through Elysium Energy, L.L.C. (“Elysium”), a limited liability company in which the Company holds a 50% interest, Patina acquired various property interests out of bankruptcy in November 2000. Patina invested $21.0 million to acquire 50% of Elysium and provided it with a $60.0 million credit facility, on which $49.0 million was outstanding at December 31, 2000. In May 2001, Elysium refinanced this loan with outside banks and repaid Patina. The Company’s 50% interest in Elysium’s assets, liabilities, revenues and expenses is proportionately consolidated in its financial statements. Elysium’s oil and gas properties are located primarily in central Kansas, the Illinois Basin, and the San Joaquin Basin of California. Elysium sold certain properties in the Lake Washington Field in Louisiana for $30.5 million in March 2001 ($15.25 million net to the Company). Approximately 90% of Elysium’s production is oil. In late 2001, Patina assumed direct management control of Elysium’s properties as the Elysium office in Texas was closed and relocated to Denver.

At December 31, 2001, the Company had 719.2 Bcfe of proved reserves, of which Wattenberg represented 647.7 Bcfe or 90%. The reserves had an estimated pretax present value of $527.2 million based on unescalated prices and costs in effect on that date. Total proved reserves fell 59 Bcfe, or 8%, from the prior year’s level. The decrease was largely the result of sharply lower oil and gas prices at December 31, 2001, which reduced reserves by 112 Bcfe. Reserve additions and discoveries added 80 Bcfe, upward performance revisions added 13 Bcfe and acquisitions, net of sales, added 17 Bcfe, offset by 57 Bcfe of production during the year. Exclusive of the impact of lower prices, the Company replaced roughly 200% of production in 2001. Approximately 73% of the reserves on a Mcf equivalent basis were natural gas and over 94% of the pretax present value was attributable to proved developed reserves. The Company operates over 95% of the roughly 3,300 producing wells in which it holds a direct working interest in Wattenberg. At December 31, 2001, the Company’s inventory of proven development projects included 293 drilling or deepening locations, 177 recompletions, 1,783 restimulation (“refrac”) projects and over 500 proven production enhancement projects in Wattenberg. During 2001, the Company’s production averaged 156.1 MMcfe per day, of which 140.9 MMcfe per day or 90% was attributed to Wattenberg. Based on year-end reserves, the Company had a reserve life index of 12.6 years.

From inception, the Company has focused on consolidating ownership of its properties, developing an efficient organization, improving operations and diversifying the asset base through acquisitions and initiating grassroots projects. In 2001, revenues and net cash provided from operations totaled $214.2 million and $172.8 million, respectively. This operating cash flow, combined with $36.0 million in proceeds from the exercise of the $10.00 warrants, the sale of Elysium’s interest in the Lake Washington Field and the subsequent refinancing of the Elysium loan, funded $88.1 million of capital expenditures, repayment of $100.0 million of bank debt and repurchases of $51.5 million of the Company’s equity securities. Roughly $10.2 million was spent on acquisitions and $77.8 million on further development of properties. The development expenditures included $65.6 million in Wattenberg for the drilling or deepening of 61 J-Sand wells, 323 refracs, seven recompletions and the drilling of seven Codell wells, $9.5 million on grassroots exploration and development and $2.7 million on the Elysium properties. The benefits of these projects, the full year contribution of the Elysium acquisition and continued success in production enhancement allowed production to increase 31% over the prior year.

As Wattenberg accounted for over 90% of annual production in 2001, it remains the Company’s key asset. With over 2,600 proven development projects in inventory at year-end, Wattenberg will remain a significant factor in production growth over the next couple of years. Future Wattenberg activity will focus primarily on refracing existing Codell wells and the development of J-Sand reserves through drilling new wells or deepening within existing wellbores.

The purchase of Elysium in November 2000 marked the beginning of a more aggressive diversification effort. The acquisition provided the Company a presence in several areas believed to have significant growth and consolidation potential, including the Illinois Basin, the San Joaquin Basin of California and central Kansas. With the move of Elysium’s headquarters from Texas to Denver in late 2001, the Company intends to more fully evaluate and further develop these properties.

Over the past twelve months, the Company accumulated sizable acreage positions in three Rocky Mountain basins and acquired a leasehold position with existing production in West Texas. The focus has been on aggregating prospects with significant reserve potential and long-term development prospects. The Company has attempted to target areas where it can apply the tight sand fracture technology expertise it developed in Wattenberg. While the grassroots projects to date have contributed only a minimal amount to production growth and financial results, they should add significant long-term growth potential to the Company.

With over 2,600 proven development projects in Wattenberg combined with the upside potential in the development of the Elysium properties and our exposure to significant reserves in the long-term development of our grassroots projects, the Company anticipates reporting increases in production in 2002.

Business Strategy

The Company’s sizable asset base and cash flow, along with its low production costs and efficient operating structure, provide it with a competitive advantage in Wattenberg and in certain analogous basins. These advantages, combined with management’s operational expertise, positions the Company to increase its reserves, production and cash flows in a cost-efficient manner primarily through: (i) further Wattenberg development; (ii) generation of grassroots drilling prospects, and (iii) selectively pursuing consolidation and acquisition opportunities. The size and timing of such purchases will depend on market conditions. The Company’s strong financial position appears to afford it the financial flexibility to execute this strategy.

Development, Acquisition and Exploration

During 2001, the Company spent $77.8 million on the further development of properties and $10.2 million on acquisitions. The development expenditures included $65.6 million in Wattenberg for the drilling or deepening of 61 J-Sand wells, 323 Codell refracs, seven recompletions and the drilling of seven Codell wells, $9.5 million on grassroots exploration and development and $2.7 million on the Elysium properties. These projects, the full year contribution of the Elysium acquisition and the continued success in production enhancement allowed production to increase 31% over the prior year. The Company anticipates incurring approximately $77.0 million on the further development of its properties during 2002.

Production, Revenue and Price History

The following table sets forth information regarding oil and gas production, revenues and direct operating expenses attributable to such production, average sales prices and other related data for the last five years. The information reflects the acquisition of 50% of Elysium in November 2000.

	Year Ended December 31,
	1997		1998		1999		2000		2001
	(Dollars in thousands, except prices and per Mcfe information)
Production
Oil (MBbl)		1,889		1,699		1,653		1,685		2,661
Gas (MMcf)		26,863		25,522		29,477		33,463		41,002
MMcfe(a)		38,194		35,715		39,396		43,572		56,969
Revenues
Oil	$	37,197	$	22,583	$	26,218	$	38,741	$	68,447
Gas(b)		62,342		49,594		64,189		109,924		142,824

Subtotal		99,539		72,177		90,407		148,665		211,271
Other		794		2,603		1,259		1,677		2,902

Total		100,333		74,780		91,666		150,342		214,173

Direct operating expenses
Lease operating expenses		11,735		12,399		11,902		13,426		25,356
Production taxes		7,055		4,941		6,271		10,628		13,462

Total		18,790		17,340		18,173		24,054		38,818

Direct operating margin	$	81,543	$	57,440	$	73,493	$	126,288	$	175,355

Average sales price
Oil (Bbl)	$	19.70	$	13.29	$	15.86	$	23.00	$	25.72
Gas (Mcf)(b)		2.32		1.94		2.18		3.28		3.48
Mcfe(a)		2.61		2.02		2.29		3.41		3.71
Lease operating expense per Mcfe	$	0.31	$	0.35	$	0.30	$	0.31	$	0.45
Production tax expense per Mcfe		0.18		0.14		0.16		0.24		0.24

Direct operating expense per Mcfe		0.49		0.49		0.46		0.55		0.69
Production margin per Mcfe	$	2.12	$	1.54	$	1.83	$	2.86	$	3.02

(a)

Oil production is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf.

(b)

Sales of natural gas liquids are included in gas revenues.

Gathering, Processing and Marketing

The Company’s oil and gas production is principally sold to end users, marketers, refiners and other purchasers having access to pipeline facilities or the ability to truck oil to local refineries. The marketing of oil and gas can be affected by a number of factors that are beyond the Company’s control and which cannot be accurately predicted.

Natural Gas. The natural gas produced in Wattenberg is high in heating content (BTU’s) and must be processed to extract natural gas liquids (“NGL”). Residue gas is sold to utilities, independent marketers and end users through intrastate and interstate pipelines. The Company utilizes two separate arrangements to gather, process and market its gas production. Approximately 30% of production is sold to Duke Energy Field Services (“Duke Energy”) at the wellhead under percentage of proceeds contracts. Pursuant to this type of contract, the Company receives a fixed percentage of the proceeds from Duke Energy’s sale of residue gas and NGL’s. Substantially all of the Company’s remaining natural gas production is dedicated for gathering to Duke Energy or Kerr McGee Gathering, LLC, formerly HS Gathering, LLC (“KMG”) and is processed at plants owned by Duke Energy or BP Amoco Production Company (“BP Amoco”). Under this arrangement, the Company retains the right to market its share of residue gas at the tailgate of the plant and sells it under spot market arrangements along the front range of Colorado or transports it to Midwestern markets under transportation agreements. NGL’s are sold by the processor and the Company receives payment net of applicable processing fees. A portion of the natural gas processed by BP Amoco at the Wattenberg Processing Plant is under a favorable “keepwhole” contract that not only provides payment for a percentage of the NGL’s stripped from the natural gas, but also redelivers at the tailgate the same amount of MMBtu’s as was delivered to the plant. This agreement extends through December 2012.

Oil. Oil production is principally sold to refiners, marketers and other purchasers that truck it to local refineries or pipelines. The price is based on a local market posting, which generally approximates a West Texas Intermediate posting, and is adjusted upward to reflect local demand and quality. BP Amoco has the right to purchase oil produced from certain of the Company’s properties at market price.

Hedging Activities

The Company regularly enters into hedging agreements to reduce the impact on its operations of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge prices and limit volatility. The Company’s current policy is to hedge between 50% and 75% of its production, when futures prices justify, on a rolling twelve to eighteen month basis. Due to the exceptional gas prices in 2001, the Company extended their hedging program into 2005. At December 31, 2001, hedges were in place covering 42.1 Bcf at prices averaging $3.84 per MMBtu and 710,000 barrels of oil averaging $25.70 per barrel. The estimated fair value of the Company’s hedge contracts, excluding hedge contracts with Enron North America Corp. (“Enron”), that would be realized on termination, approximated a net unrealized pre-tax gain of $52.0 million ($33.3 million gain net of $18.7 million of deferred taxes) at December 31, 2001, which is presented on the balance sheet as a current asset of $20.1 million and a non-current asset of $31.9 million based on contract expiration. The gas contracts expire monthly through December 2005 while the oil contracts expire monthly through December 2002. Gains or losses on both realized and unrealized hedging transactions are determined as the difference between the contract price and a reference price, generally NYMEX for oil and the Colorado Interstate Gas (“CIG”) index for natural gas. Transaction gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net pre-tax losses relating to these derivatives in 1999 and 2000 were $4.1 million, $23.9 million, respectively, with a pretax gain of $4.1 million in 2001. Over the last three years, the Company has recorded cumulative net pre-tax hedging losses of $23.9 million against income. Effective January 1, 2001, the unrealized gains (losses) on these hedging positions were recorded at an estimate of fair value which the Company based on a comparison of the contract price and a reference price, generally NYMEX or CIG, on the Company’s balance sheet in Accumulated other comprehensive income (loss), a component of Stockholders’ Equity.

Competition

The oil and gas industry is highly competitive. The Company encounters competition in all of its operations, including the acquisition of exploration and development prospects and producing properties. Patina competes for acquisitions of oil and gas properties with numerous entities, including major oil companies, other independents, and individual producers and operators. Many competitors have financial and other resources substantially greater than those of the Company. The ability of the Company to increase reserves in the future will be dependent on its ability to select and successfully acquire suitable producing properties and prospects for future development and exploration.

Title to Properties

Title to the Company’s oil and gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the industry, to liens incident to operating agreements and for current taxes not yet due and other comparatively minor encumbrances. As is customary in the oil and gas industry, only a perfunctory investigation as to ownership is conducted at the time undeveloped properties are acquired. Prior to the commencement of drilling operations, a detailed title examination is conducted and curative work is performed with respect to identified title defects.

Government Regulation

Regulation of Drilling and Production. The Company’s operations are affected by political developments and by federal, state and local laws and regulations. Legislation and administrative regulations relating to the oil and gas industry are periodically changed for a variety of political, economic and other reasons. Numerous federal, state and local departments and agencies issue rules and regulations binding on the oil and gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the industry increases the cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects.

In the past, the federal government has regulated the prices at which oil and gas could be sold. Prices of oil and gas sold by the Company are not currently regulated. In recent years, the Federal Energy Regulatory Commission (“FERC”) has taken significant steps to increase competition in the sale, purchase, storage and transportation of natural gas. FERC’s regulatory programs allow more accurate and timely price signals from the consumer to the producer and, on the whole, have helped natural gas become more responsive to changing market conditions. To date, the Company believes it has not experienced any material adverse effect as the result of these initiatives. Nonetheless, increased competition in natural gas markets can and does add to price volatility and inter-fuel competition, which increases the pressure on the Company to manage its exposure to changing conditions and position itself to take advantage of changing markets.

State statutes govern exploration and production operations, conservation of oil and gas resources, protection of the correlative rights of oil and gas owners and environmental standards. State Commissions implement their authority by establishing rules and regulations requiring permits for drilling, reclamation of production sites, plugging bonds, reports and other matters. Colorado, where the Company’s producing properties are primarily located, amended its statute concerning oil and natural gas development in 1994 to provide the Colorado Oil & Gas Conservation Commission (the “COGCC”) with enhanced authority to regulate oil and gas activities to protect public health, safety and welfare, including the environment. The COGCC has implemented several rules pursuant to these statutory changes concerning groundwater protection, soil conservation and site reclamation, setbacks in urban areas and other safety concerns, and financial assurance for industry obligations in these areas. To date, these rule changes have not adversely affected the operations of the Company, as the COGCC is required to enact cost-effective and technically feasible regulations, and the Company has been an active participant in their development. However, there can be no assurance that, in the aggregate, these and other regulatory developments will not increase the cost of operations in the future.

In Colorado, a number of city and county governments have enacted oil and gas regulations. These ordinances increase the involvement of local governments in the permitting of oil and gas operations, and require additional restrictions or conditions on the conduct of operations so as to reduce their impact on the surrounding community. Accordingly, these local ordinances have the potential to delay and increase the cost of drilling, refracing and recompletion operations.

Environmental Matters

Environmental Regulation. 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. The Company currently owns or leases numerous properties that have been used for many years for oil and gas production. Although the Company believes that it and previous owners have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company. In connection with its most significant acquisitions, the Company has performed environmental assessments and found no material environmental noncompliance or clean-up liabilities requiring action in the near or intermediate future. Such environmental assessments have not, however, been performed on all of the Company’s properties.

The Company’s operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency (“EPA”) issue regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent pollution from former operations such as plugging abandoned wells, and impose substantial liabilities for pollution resulting from operations. In addition, these laws, rules and regulations may restrict the rate of production. The regulatory burden on the oil and gas industry increases the cost of doing business and affects profitability. Changes in environmental laws and regulations occur frequently, and changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect the Company’s operations and financial position, as well as the industry in general. Management believes the Company is in substantial compliance with current applicable environmental laws and regulations. The Company has not experienced any material adverse effect from compliance with environmental requirements, however, there is no assurance that this will continue. The Company did not have any material expenditures in connection with environmental matters in 2001, nor does it anticipate that such expenditures will be material in 2002.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and that such wastes may become subject to liability and regulation under CERCLA. State initiatives to further regulate the disposal of oil and gas wastes are pending in certain states and these initiatives could have a significant impact on the Company.

The Federal Water Pollution Control Act (“FWPCA”) imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and the federal National Pollutant Discharge Elimination System permits applicable to the oil and gas industry generally prohibit the discharge of produced water, sand and some other substances into coastal waters. The cost to comply with zero discharges mandated under federal and state law have not had a material adverse

impact on the Company’s financial condition and results of operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans.

The Resources Conservation and Recovery Act (“RCRA”), as amended, generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing solid hazardous waste may be significant, the Company does not expect to experience more burdensome costs than similarly situated companies.

The Company operates its own exploration and production waste management facilities in Colorado, which enable it to treat, bioremediate and otherwise dispose of tank sludges and contaminated soil generated from the Company’s Colorado operations. There can be no assurance that these facilities, or other commercial disposal facilities utilized from time to time, will not give rise to environmental liability in the future. To date, expenditures for the Company’s environmental control facilities and for remediation of production sites have not been significant. The Company believes, however, that the trend toward stricter standards in environmental legislation and regulations will continue and could have a significant adverse impact on operating costs and the oil and gas industry in general.

Risk Factors and Cautionary Statement for purposes of the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995

Certain information included in this report, other materials filed or to be filed by the Company with the Securities and Exchange Commission (“SEC”), as well as information included in oral statements or other written statements made or to be made by the Company contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 capital, development and exploration expenditures (including the amount and nature thereof), drilling, deepening or refracing of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and natural gas, business strategies, expansion and growth of the Company’s operations, cash flow and anticipated liquidity, grassroots prospects and development and property acquisition, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. Factors that could cause actual results to differ materially (“Cautionary Disclosures”) are described, among other places, in the Gathering, Processing and Marketing, Competition, and Regulation sections in this Form 10-K / A and under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Without limiting the Cautionary Disclosures so described, Cautionary Disclosures include, among others: general economic conditions, the market price of oil and natural 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, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, 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, environmental risks, the results of financing efforts, and regulatory developments. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the 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.

With the previous paragraph in mind, you should consider the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by the Company or on its behalf.

Demand for Our Oil and Gas from Our Customer Base

We sell our oil and gas production to end-users, marketers and refiners and other similarly situated purchasers that have access to natural gas pipeline facilities near our properties or the ability to truck oil to local refineries or pipeline delivery points. The demand for oil and natural gas production and our ability to market it to our customers may be affected by a number of factors that are beyond our control and that we cannot accurately predict at this time. These factors include:

•

The performance of the U.S. and world economies;

•

Retail customers demand for oil and natural gas;

•

The competitive position of alternative energy sources;

•

The price of our oil and gas production as compared to that for similar product grades from other producing basins;

•

The availability of pipeline and other transportation facilities that may make oil and gas production from other producing areas competitive for our customers to use; and

•

Our ability to maintain and increase our current level of production over the long term.

Fluctuations in Profitability of the Oil and Gas Industry

The oil and gas industry is highly cyclical and historically has experienced severe downturns characterized by oversupply and weak demand. Many factors affect our industry, including general economic conditions, consumer preferences, personal discretionary spending levels, interest rates and the availability of credit and capital to pursue new production opportunities. We cannot guarantee that our industry will not experience sustained periods of decline in the future. Any such decline could have a material adverse affect on our business.

Competition for the Acquisition of New Properties

The oil and gas industry is very competitive. Other exploration and production companies compete with us for the acquisition of new properties. Among them are some of the largest oil companies in the United States and other substantial independent oil and gas companies. Many of these companies have greater financial and other resources than we do. Our ability to increase our reserves in the future will depend upon our ability to select and acquire suitable oil and gas properties in this competitive environment.

Operating Risks of Oil and Natural Gas Operations

The oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. As customary with industry practice, we maintain insurance against some, but not all, of these hazards and risks. The occurrence of such an event or events not fully covered by insurance could have a material adverse affect on our business.

The Effect of Regulation

Our business is heavily regulated by federal, state and local agencies. This regulation increases our cost of doing business, decreases our flexibility to respond to changes in the market and lengthens the time it may take for us to gain approval of and complete capital projects. We may be subject to substantial penalties if we fail to comply with any regulation. In particular, the Colorado Oil & Gas Conservation Commission has promulgated regulations to protect ground water, conserve soil, provide for site reclamation, ensure setbacks in urban areas, generally promote safety concerns and mandate financial assurance for companies in the industry. To date, these rules and regulations have not adversely affected us. We continue to take an active role in the development of rules and regulations that directly impact our operations. However, we cannot assure you that regulatory changes enacted by the Colorado Oil & Gas Conservation Commission or other regulatory agencies that have jurisdiction over us will not increase our operating costs or otherwise negatively impact the results of our operations.

The Potential for Environmental Liabilities

We are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. We currently own or lease numerous properties that have been used for many years for oil and natural gas production. Although we believe that we and previous owners used operating and disposal practices that were standard in the industry at the time, hydrocarbons and other waste products may have been disposed of or released on or under the properties owned or leased by us. In connection with our most significant acquisitions, we have conducted environmental assessments and have found no instances of material environmental non-compliance or any material clean-up liabilities requiring action in the near future. However, we have not performed such environmental assessments on all of our properties. As to all of our properties, we cannot assure you that past disposal practices, including those that were state-of-the-art at the time employed, will not result in significant future environmental liabilities. In addition, we cannot assure you that in the future regulatory agencies with jurisdiction over us will not enact additional environmental regulations that will negatively affect properties we currently own or acquire in the future.

We also operate exploration and production waste management facilities that enable us to treat, bioremediate and otherwise dispose of tank sludge and contaminated soil generated from our operations. We cannot assure you that these facilities or other commercial disposal facilities operated by third parties that we have used from time to time will not in the future give rise to environmental liabilities for which we will be responsible. The trend toward stricter standards in environmental regulation could have a significant adverse impact on our operating costs as well as our industry in general.

Hedging of Oil and Natural Gas Prices

We enter into hedging arrangements covering a portion of our future production to limit volatility and increase the predictability of cash flow. Hedging instruments are generally fixed price swaps but have at times included or may include collars, puts and options on futures. While hedging limits our exposure to adverse price movements, hedging limits the benefit of price increases and is subject to a number of risks, including the risk the counterparty to the hedge may not perform.

Estimates of Oil and Gas Reserves, Production Replacement

The information on proved oil and gas reserves included in this document are simply estimates. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment, assumptions used regarding quantities of oil and gas in place, recovery rates and future prices for oil and gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will vary from those assumed in our estimates, and such variances may be significant. If the assumptions used to estimate reserves later prove incorrect, the actual quantity of reserves and future net cash flow could be materially different from the estimates used herein. In addition, results of drilling, testing and production along with changes in oil and gas prices may result in substantial upward or downward revisions.

Without success in exploration, development or acquisitions, our reserves, production and revenues from the sale of oil and gas will decline over time. Exploration, the continuing development of our properties and acquisitions all require significant expenditures as well as expertise. If cash flow from operations proves insufficient for any reason, we may be unable to fund exploration, development and acquisitions at levels we deem advisable.

Chief Executive Officer’s Interest In Another Oil And Gas Company

Our Chief Executive Officer also serves as the Chairman of Range Resources Corporation, a publicly traded oil and gas company in which he is a significant investor. He is also an officer, director and/or significant investor in several other public and private companies engaged in various aspects of the energy industry. We currently have no business relationships with any of these companies, none of them owns our securities nor do we hold any of theirs. Historically, no material conflict has arisen with regard to these companies. However, conflicts of interests may arise. Board policies are in place that require Mr. Edelman, along with all other officers and directors, to give us notification of any potential conflicts that arise. However, we cannot assure you that we will not compete with one or more of these companies, particularly for acquisitions, or encounter other conflicts of interest in the future.

Key Members Of Our Management

The Company’s success is highly dependent on its senior management personnel, of which only one is currently subject to an employment contract. The loss of one or more of these individuals could have a material adverse effect on the Company.

Office and Operations Facilities

The Company leases its principal executive offices at 1625 Broadway, Denver, Colorado 80202. The lease covers approximately 36,000 square feet and expires in November 2005. The monthly rent is approximately $76,000 of which Elysium’s share is $15,000 ($7,500 net to the Company). The Company owns a 6,000 square foot production facility in Platteville, Colorado used to support its Wattenberg Field operations. Elysium maintains six field offices in the areas of its operations.

Employees

On December 31, 2001, the Company had 185 employees, including 98 that work in its field office. An additional 102 employees work for Elysium. None of these employees are represented by a labor union. The Company believes its relationships with its employees are satisfactory.

ITEM 2. PROPERTIES

General

During 2001, the Company’s production averaged 156.1 MMcfe per day, of which 140.9 MMcfe per day or 90% was attributed to the Wattenberg Field of Colorado’s D-J Basin. Accordingly, the Company’s proved reserves at December 31, 2001 were concentrated primarily in Wattenberg. The Company also has proven reserves associated with its Elysium acquisition made in late 2000 and the grassroots projects initiated in 2001. The following table sets forth summary information with respect to estimated proved reserves at December 31, 2001.

	Pre-tax Present Value 10%
	Amount		%	Oil	Natural Gas	Total
	(In thousands)			(MBbls)	(MMcf)	(MMcfe)
Wattenberg	$	493,916	94	26,563	488,325	647,703
Elysium		24,713	4	5,541	3,570	36,815
Grassroots projects		8,555	2	—	34,645	34,646

Total	$	527,184	100	32,104	526,540	719,164

Wattenberg

The Company’s reserves are primarily concentrated in the Wattenberg Field, which is located in the D-J Basin of north central Colorado. Discovered in 1970, the field is located approximately 35 miles northeast of Denver and stretches over portions of Adams, Boulder, Broomfield and Weld counties in Colorado. One of the most attractive features of Wattenberg is the presence of several productive formations. In a section only 4,500 feet thick, there are up to eight potentially productive formations. Three of the formations, the Codell, Niobrara and J-Sand, are considered “blanket” zones in the area of the Company’s holdings, while others, such as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman, are more localized.

Drilling in Wattenberg is considered low risk from the perspective of finding oil and gas reserves, with better than 95% of the wells drilled being completed as producers. In May 1998, the COGCC adopted new spacing rules for the Wattenberg Field that greatly enhanced the Company’s ability to more efficiently develop its properties. The rule also eliminated costly and time-consuming procedures required for certain development activities. All formations in Wattenberg can now be drilled, produced and commingled from any or all of ten “drilling windows” on a 320 acre parcel.

In 2001, development expenditures in Wattenberg totaled $65.6 million. The Company’s current Wattenberg activities are primarily focused on the development of J-Sand reserves through drilling new wells or deepening within existing wellbores and refracing existing Codell wells. A refrac consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. These projects, the benefits of the Elysium acquisition and continued success with the production enhancement program allowed the Company to increase its production and to add proved reserves in 2001 in what is considered a mature field.

During 2001, the Company drilled or deepened 61 wells to the J-Sand or Dakota formation in Wattenberg. The cost of drilling and completing a J-Sand well approximates $350,000 while a completed deepening within an existing wellbore costs roughly $210,000. The reserves associated with a typical J-Sand well are more prolific than those of a Codell/Niobrara, with over 95% of such per well reserves comprised of natural gas. Consequently, the economics of a J-Sand project are more dependent on gas prices. Finding and development costs for the J-Sand and Dakota drilling and deepening projects for 2001 averaged $0.86 per Mcfe with projected rates of return in excess of 30% based on actual prices received through year-end and futures prices thereafter. At December 31, 2001, the Company had 195 proven J-Sand drilling locations or deepening projects in inventory.

The Company performed 323 refracs in Wattenberg during 2001. The refrac program continues to be focused primarily on the Codell formation. A typical refrac costs approximately $135,000. The finding and development costs associated with the 2001 refrac program averaged $0.85 per Mcfe with projected rates of return in excess of 100% based on actual prices received through year-end and futures prices thereafter. At December 31, 2001, the Company had nearly 1,800 proven refrac projects. Given the exceptional results of the refrac program, the budgeted activity has been increased to over 400 refrac projects in 2001.

The Company also performed seven recompletions and drilled seven Codell wells in the DJ Basin in 2001. The finding and development costs associated with these projects averaged $1.05 per Mcfe with projected rates of return of approximately 50% based on actual prices received through year-end and futures prices thereafter. The Company had an additional 177 Codell / J-Sand proven recompletion opportunities and 98 Codell new drill opportunities at December 31, 2001. During 2001, tubing was installed in six wellbores and numerous well workovers, reactivations, and commingling of zones were performed. These projects, combined with the new drills, deepenings and refracs, were an integral part of the 2001 capital development program and helped fuel the 31% increase in the Company’s production over the prior year. The Company estimates it had over 500 of these minor projects in inventory at year-end 2001.

At December 31, 2001, the Company had working interests in approximately 3,272 gross (3,107 net) producing oil and gas wells in the D-J Basin with estimated proved reserves of 647.7 Bcfe, including 26.6 million barrels of oil and 488.3 Bcf of gas.

Elysium

In November 2000, Patina acquired various property interests out of bankruptcy through Elysium Energy, L.L.C., a New York limited liability company, in which Patina holds a 50% interest. The Company proportionately consolidates its 50% interest in Elysium’s assets, liabilities, revenues and expenses. Elysium’s oil and gas properties are located in central Kansas, the Illinois Basin and the San Joaquin Field in California. The Elysium properties primarily produce oil. During 2001, development expenditures for Elysium totaled $5.5 million ($2.7 million net to Patina), for the drilling of 16 wells and performing 20 recompletions, primarily in the Illinois Basin. Elysium sold certain properties in the Lake Washington Field in Louisiana for $30.5 million in March 2001 ($15.25 million net to the Company). Daily production from these properties (net to Patina) averaged 14,535 Mcfe, comprised of 2,189 barrels and 1,398 Mcf per day in 2001. Patina’s 50% share of Elysium’s estimated proved reserves totaled 36.8 Bcfe, including 5.5 million barrels of oil and 3.6 Bcf of gas.

Grassroots Projects

In 2001, the Company earned a 50% non-operated working interest in a coalbed methane project (“Castlegate”) near Price, Utah. This interest included nine existing producing coalbed methane wells and 49,100 gross acres (21,500 net acres). The Company’s interest was earned through a capital expenditure commitment of $7.5 million, which was fulfilled during the year by drilling nine additional wells and installing various gas processing and water disposal facilities. The project currently has 17 producing wells, with one waiting on completion. Current gross gas production is approximately 1,700 Mcf per day (700 Mcf per day net to the Company). At December 31, 2001, the Company had spent $8.3 million on this project, including the capital commitment and additional acquisition costs. Proved reserves at year-end totaled 27.1 Bcfe, all of which was natural gas. The Company anticipates completing additional water disposal facilities in 2002 and increasing drilling activity in 2003 and thereafter.

In early 2001, the Company acquired 68,200 gross acres (68,200 net acres) in central Wyoming (“Antelope Arch”) for $3.6 million and formed a Federal unit over a portion of the acreage. There are up to eight potentially productive formations at various depths targeted on the prospect. The Company drilled its first well in December 2001 and completed it in the Frontier, the deepest target formation. The well was productive and initially produced 350 Mcf per day. As of December 31, 2001, the Company had expended $5.5 million on this project. No proved reserves associated with the project were booked as of year-end. The Company anticipates drilling four wells on the prospect in the second half of 2002.

The Company also accumulated 23,200 gross acres (18,800 net acres) in the Piceance Basin of Northwest Colorado (“Sugarloaf”) in 2001. The primary objective of the prospect is the shallow coalbed methane, with additional objectives in the tight-sand Mesa Verde and a deeper fractured shale interval. This acreage position came with a shut-in well, which the Company completed and stimulated in the “Mancos” formation in late 2001. Upon stimulation, the well initially produced 200 Mcf per day (gross) and five barrels of oil per day. As of December 31, 2001, roughly $1.6 million had been expended on the project. No proved reserves were recorded as of year-end. The Company anticipates drilling two coalbed methane wells on the prospect in 2002.

In July 2001, the Company acquired 19,600 gross acres (19,400 net acres) with 95 producing gas wells in West Texas (“Adams Baggett”). Current gross gas production is approximately 1,500 Mcf per day (1,100 Mcf per day net to the Company). The Company anticipates increasing value in the project through improved operating mechanics, recompletions and restimulations in existing wellbores and down-spaced, infill drilling. Proved reserves at year-end totaled 7.5 Bcfe, all of which was natural gas. The Company had expended $3.9 million on this project during 2001. The Company anticipates drilling and refracing ten wells on the project in 2002.

Proved Reserves

The following table sets forth estimated net proved reserves for the three years ended December 31, 2001. The 2000 and 2001 estimates include Patina’s 50% share of Elysium’s net proved reserves:

	December 31,
	1999		2000		2001
Oil (MBbl)
Developed
Producing		12,103		18,496		14,898
Non-producing		4,530		16,650		13,322

Total Developed		16,633		35,146		28,220
Undeveloped		787		7,568		3,884

Total		17,420		42,714		32,104

Natural gas (MMcf)
Developed
Producing		225,798		247,934		272,848
Non-producing		81,762		161,169		157,639

Total Developed		307,560		409,103		430,487
Undeveloped		53,701		112,447		96,053

Total		361,261		521,550		526,540

Total MMcfe		465,781		777,831		719,164

Pretax PV10% Value	$	457,542	$	2,217,825	$	527,184

Oil price (Bbl)	$	24.27	$	26.07	$	19.72
Gas price (Mcf)	$	2.34	$	8.27	$	2.35

The following table sets forth the estimated pretax future net revenues as of year-end 2001 from the production of proved reserves and the pretax present value discounted at 10% of such revenues, net of estimated future capital costs, including an estimate of $78.3 million of future development costs in 2002 (in thousands):

	December 31, 2001
Future Net Revenues	Developed		Undeveloped			Total
2002	$	71,267	$	(12,973	)	$	58,294
2003		68,152		(22,320	)		45,832
2004		66,676		(2,883	)		63,793
Remainder		674,417		159,873			834,290

Total	$	880,512	$	121,697		$	1,002,209

Pretax PV10% Value(a)	$	495,886	$	31,298		$	527,184

(a)

The after tax present value discounted at 10% of the proved reserves totaled $390.9 million at year-end 2001. If the reserve estimates were made with futures prices in effect at December 31, 2001 resulting in average wellhead prices of $2.94 per Mcf and $20.42 per barrel over the life of the properties, reserves would have approximated 808 Bcfe with a pretax PV10% value of $682.0 million.

The Wattenberg field represents 94% of the pretax PV10% value and 647.7 Bcfe or 90% of Patina’s proved reserves.

The quantities and values in the preceding tables are based on constant prices in effect at December 31, 2001, which averaged $19.72 per barrel of oil and $2.35 per Mcf of gas. Price declines decrease reserve values by lowering the future net revenues attributable to the reserves and reducing the quantities of reserves that are recoverable on an economic basis. Price increases have the opposite effect. A significant decline in the prices of oil or natural gas could have a material adverse effect on the Company’s financial condition and results of operations.

Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods under current economic conditions. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production.

Future prices received from production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.

The present values shown should not be construed as the current market value of the reserves. The quantities and values shown in the preceding tables are based on oil and natural gas prices in effect on December 31, 2001. The value of the Company’s assets is in part dependent on the prices the Company receives for oil and natural gas, and a significant decline in the price of oil or gas could have a material adverse effect on the Company’s financial condition and results of operations. The 10% discount factor used to calculate present value, which is specified by the Securities and Exchange Commission (the “SEC”), is not necessarily the most appropriate discount rate, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties operated by the Company, expenses exclude Patina’s share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things general and administrative costs and interest expense.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the above tables represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered.

The proved oil and gas reserves and future revenues as of December 31, 2001 were audited by Netherland, Sewell & Associates, Inc. (“NSAI”). On an annual basis, the Company files the Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by operators of domestic oil and gas properties. There are differences between the reserves as reported on Form EIA-23 and reserves as reported herein. Form EIA-23 requires that operators report on total proved developed reserves for operated wells only and that the reserves be reported on a gross operated basis rather than on a net interest basis.

Producing Wells

The following table sets forth the producing wells in which the Company owned a working interest at December 31, 2001. Wells are classified as oil or natural gas wells according to their predominant production stream.

Principal Production Stream	Gross Wells	Net Wells
Wattenberg
Oil	2,890	2,757
Natural gas	382	350

Total	3,272	3,107

Elysium
Oil	1,087	523
Natural gas	12	4

Total	1,099	527

Texas, Utah, Wyoming and other
Oil	—	—
Natural gas	113	104

Total	113	104

Total
Oil	3,977	3,280
Natural gas	507	458

Total	4,484	3,738

The Company had 168 wells (161 net) in Wattenberg and 1,505 wells (703 net) in Elysium that were shut-in at December 31, 2001. The Company’s average working interest in the Wattenberg wells was approximately 97%, while the average working interest in the Elysium wells was approximately 47%.

Drilling Results

The following table sets forth the number of wells drilled or deepened by the Company during the past three years. All wells in 1999 and 2000 were development wells and drilled in Wattenberg. During 2001, the Company drilled or deepened 68 development wells (64 net) in Wattenberg, drilled 16 development wells (eight net) in the Illinois Basin (through Elysium) and drilled nine development coalbed methane wells (five net) in Utah. The Company drilled one exploratory well in Wyoming at the end of 2001. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.

	1999	2000	2001
Productive
Gross	36.0	60.0	93.0
Net	35.0	59.0	77.0

Dry
Gross	0.0	0.0	0.0
Net	0.0	0.0	0.0

At December 31, 2001 the Company had one well in Utah waiting on completion at year-end. The above table does not include the exploratory well drilled in Wyoming, which was productive. The Company owns a 100% working interest in this well.

Acreage

The following table sets forth the leasehold acreage held by the Company at December 31, 2001. Undeveloped acreage is acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well, including leasehold interests identified for development or exploratory drilling. Developed acreage is acreage assigned to producing wells.

	Developed		Undeveloped
	Gross	Net	Gross	Net
Patina
Colorado	199,000	179,000	70,000	60,000
Texas	19,000	19,000	—	—
Wyoming	—	—	68,000	68,000
Utah	2,000	1,000	47,000	20,000
Michigan	—	—	34,000	33,000

Subtotal	220,000	199,000	219,000	181,000

Elysium *
California	14,000	7,000	3,000	1,000
Illinois / Indiana	46,000	19,000	8,000	4,000
Kansas	6,000	3,000	11,000	5,000
Louisiana / Texas	27,000	7,000	27,000	4,000

Subtotal	93,000	36,000	49,000	14,000

Total	313,000	235,000	268,000	195,000

—Patina’s 50% interests in the Elysium acreage.

ITEM 3. LEGAL PROCEEDINGS

The Company is a party to various lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the fourth quarter of 2001.

PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS

The Company’s Common Stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “POG”. On May 23, 2002, the Company’s Board of Directors approved a 5-for-4 stock split to be effected in the form of a stock dividend to common stockholders of record as of June 10, 2002 with a payment date of June 20, 2002. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock split. Prior to their expiration in May 2001, the Company had $10.00 Warrants ($12.50 prior to the stock dividend adjustment) listed on the NYSE under the symbol “POGWT”. Prior to their redemption in January 2000, the Company’s 7.125% Preferred Stock was listed on the NYSE under the symbol “POGPr”. The Company’s 8.50% Preferred Stock, which was privately held, was converted into Common Stock in September 2000. The following table sets forth the range of high and low closing prices of the Common Stock and Warrants as reported on the NYSE Composite Tape.

	Common Stock				Warrants
	High		Low		High		Low
2000
First Quarter	$	10.85	$	6.45	$	2.50	$	0.45
Second Quarter		16.60		9.00		7.15		1.75
Third Quarter		17.75		11.35		8.30		3.20
Fourth Quarter		19.20		13.95		9.55		4.65
2001
First Quarter	$	21.36	$	15.58	$	11.44	$	5.98
Second Quarter		26.72		18.40		11.20		8.24
Third Quarter		21.30		16.84		—		—
Fourth Quarter		23.26		17.65		—		—

On March 1, 2002, the closing price of the Common Stock was $22.00.

Holders of Record

As of February 27, 2002, there were 115 holders of record of the common stock and 26.0 million shares outstanding, exclusive of the 1.1 million common shares held in treasury stock.

Dividends

Adjusted for the stock dividend, a quarterly cash dividend of $0.008 per common share was initiated in December 1997 and continued through the third quarter of 1999. The dividend was increased to $0.016 per share in the fourth quarter of 1999, to $0.032 per share in the fourth quarter of 2000, to $0.04 per share in the fourth quarter of 2001. The Company expects to continue to pay dividends on its common stock. However, continuation of dividends and the amounts thereof will depend upon the Company’s earnings, financial condition, capital requirements and other factors. Under the terms of its bank Credit Agreement, the Company had $39.9 million available for dividends and or other restricted payments as of December 31, 2001.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected historical financial data of the Company for the five-year period ended December 31, 2001. As further described in Note 1 to the Consolidated Financial Statements, the historical results have been restated to reflect certain stock based compensation adjustments. In addition, all share and per share amounts for all periods presented have been restated to reflect the 5-for-4 stock split which was affected in the form of a stock dividend to common stockholders of record as of June 10, 2002 with a payment date of June 20, 2002. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the financial statements and notes thereto and Management’s Discussion and Analysis of Financial Condition and Results of Operations, presented elsewhere herein. The data reflects the acquisition of 50% of Elysium in November 2000.

	As of or for the Year Ended December 31,
	1997			1998			1999			2000			2001
	(In thousands except per share data)
	(As Restated)
Statement of Operations Data
Revenues	$	100,333		$	74,780		$	91,666		$	150,342		$	214,173
Expenses
Lease operating		11,735			12,399			11,902			13,426			25,356
Production taxes		7,055			4,941			6,271			10,628			13,462
Exploration		131			59			666			293			513
General and administrative		7,154			7,244			6,212			7,165			10,994
Interest and other		16,038			13,001			10,844			10,117			7,034
Impairment of hedges		—			—			—			—			6,370
Deferred compensation adjustments		—			(110	)		2,167			12,734			3,236
Depletion, depreciation and amortization		49,076			41,695			40,744			40,600			49,916
Impairment of oil and gas properties		26,047			—			—			—			—

Total expenses		117,236			79,229			78,806			94,963			116,881

Pretax income (loss)		(16,903	)		(4,449	)		12,860			55,379			97,292
Provision for income taxes		—			—			—			12,953			35,025

Net income (loss)	$	(16,903	)	$	(4,449	)	$	12,860		$	42,426		$	62,267


Net income (loss) per share
Basic	$	(0.89	)	$	(0.56	)	$	0.32		$	1.87		$	2.50

Diluted	$	(0.89	)	$	(0.56	)	$	0.31		$	1.53		$	2.31


Weighted average shares outstanding
Basic		22,905			19,377			19,082			20,930			24,957
Diluted		22,905			19,377			19,705			27,373			26,916

Cash dividends per common share	$	0.008		$	0.032		$	0.040		$	0.080		$	0.136

Balance Sheet Data
Current assets	$	31,068		$	23,325		$	19,350		$	39,368		$	40,671
Oil and gas properties, net		342,833			324,777			308,035			355,904			378,011
Total assets		376,875			351,829			330,765			422,578			455,524
Current liabilities		30,297			23,579			19,108			30,867			45,065
Debt		146,435			142,021			132,000			177,000			77,000
Stockholders’ equity		188,441			174,436			159,922			160,151			249,574

Cash Flow Data
Net cash provided by operating activities	$	68,645		$	34,331		$	49,660		$	109,384		$	172,777
Net cash used in investing activities		(18,801	)		(23,145	)		(23,669	)		(86,134	)		(82,357	)
Net cash used in financing activities		(43,388	)		(13,709	)		(35,451	)		(21,223	)		(92,823	)

The following tables set forth unaudited summary financial results on a quarterly basis for the last two years.

	2000
	First		Second		Third		Fourth
	(As Previously Reported)
	(In thousands, except per share data)
Revenues	$	31,576	$	31,857	$	36,136	$	50,763
Lease operating expenses		3,388		2,883		2,947		4,208
Production taxes		2,195		2,026		2,457		3,950
General and administrative		1,639		1,755		1,646		2,011
Deferred compensation adjustment		—		—		—		—
Depletion, depreciation and amortization		10,281		9,528		9,867		10,924
Net income		9,194		10,613		13,439		19,195
Net income per share(1)
Basic		0.38		0.47		0.58		0.77
Diluted		0.32		0.37		0.46		0.69

Average daily production
Oil (Bbl)		4,607		4,249		4,313		5,240
Gas (Mcf)		89,502		87,564		90,390		98,202
Equivalent Mcfe		117,144		113,057		116,269		129,639

Average prices
Oil (Bbl)	$	21.53	$	21.92	$	23.64	$	24.60
Gas (Mcf)		2.73		2.90		3.16		4.24
Equivalent Mcfe		2.93		3.07		3.34		4.20

	2000
	First		Second		Third			Fourth
	(As Restated)
	(In thousands, except per share data)
Revenues	$	31,613	$	31,874	$	36,137		$	50,718
Lease operating expenses		3,388		2,883		2,947			4,208
Production taxes		2,195		2,026		2,457			3,950
General and administrative		1,639		1,869		1,646			2,011
Deferred compensation adjustment		4,273		5,894		(579	)		3,146
Depletion, depreciation and amortization		10,281		9,528		9,867			10,924
Net income		5,806		5,819		13,904			16,897
Net income per share(1)
Basic		0.22		0.25		0.63			0.70
Diluted		0.20		0.21		0.44			0.62

Average daily production
Oil (Bbl)		4,607		4,249		4,313			5,240
Gas (Mcf)		89,502		87,564		90,390			98,202
Equivalent Mcfe		117,144		113,057		116,269			129,639

Average prices
Oil (Bbl)	$	21.53	$	21.92	$	23.64		$	24.60
Gas (Mcf)		2.73		2.90		3.16			4.24
Equivalent Mcfe		2.93		3.07		3.34			4.20

(1)

Adjusted for the June 20, 2002 25% stock dividend (5-for-4 split).

	2001
	First		Second		Third		Fourth
	(As Previously Reported)
	(In thousands, except per share data)
Revenues	$	64,452	$	54,703	$	47,457	$	47,532
Lease operating expenses		6,535		6,213		6,246		6,362
Production taxes		5,367		3,697		2,695		1,703
General and administrative		2,566		2,840		2,547		2,649
Deferred compensation adjustment		—		—		—		—
Depletion, depreciation and amortization		11,901		11,840		12,159		14,016
Net income		22,355		18,088		14,237		9,890
Net income per share(1)
Basic		0.91		0.69		0.54		0.38
Diluted		0.80		0.63		0.50		0.35

Average daily production
Oil (Bbl)		7,421		7,189		6,933		7,621
Gas (Mcf)		108,176		108,448		112,161		120,422
Equivalent Mcfe		152,702		151,580		153,761		166,150

Average prices
Oil (Bbl)	$	27.44	$	26.56	$	25.97	$	23.08
Gas (Mcf)		4.65		3.63		2.97		2.81
Equivalent Mcfe		4.63		3.86		3.34		3.10

	2001
	First		Second			Third			Fourth
	(As Restated)
	(In thousands, except per share data)
Revenues	$	64,431	$	54,770		$	47,335		$	47,637
Lease operating expenses		6,535		6,213			6,246			6,362
Production taxes		5,367		3,697			2,695			1,703
General and administrative		2,566		3,230			2,547			2,650
Deferred compensation adjustment		2,669		(154	)		(3,223	)		3,944
Depletion, depreciation and amortization		11,901		11,840			12,159			14,016
Net income		20,634		17,980			16,221			7,432
Net income per share(1)
Basic		0.88		0.71			0.63			0.29
Diluted		0.77		0.62			0.50			0.28

Average daily production
Oil (Bbl)		7,421		7,189			6,933			7,621
Gas (Mcf)		108,176		108,448			112,161			120,422
Equivalent Mcfe		152,702		151,580			153,761			166,150

Average prices
Oil (Bbl)	$	27.44	$	26.56		$	25.97		$	23.08
Gas (Mcf)		4.65		3.63			2.97			2.81
Equivalent Mcfe		4.63		3.86			3.34			3.10

(1)

Adjusted for the June 20, 2002 25% stock dividend (5-for-4 split).

The total of the earnings per share for each quarter does not equal the earnings per share for the full year, either because the calculations are based on the weighted average shares outstanding during each of the individual periods or rounding.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXPLANATORY NOTE—THIS AMENDMENT NO. 1 ON FORM 10-K /A TO THE REGISTRANT’S FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001 IS BEING FILED FOR THE PURPOSES OF GIVING EFFECT TO THE RESTATEMENT OF THE COMPANY’S CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001. SEE NOTE 1 TO THE FINANCIAL STATEMENTS FOR A SUMMARY OF THE SIGNIFICANT EFFECTS OF THE RESTATEMENT. THE RESTATEMENT RELATED TO APPLYING REQUIRED ACCOUNTING TREATMENT FOR CERTAIN STOCK BASED COMPENSATION ARRANGEMENTS. THE FOLLOWING DISCUSSION AND ANALYSIS GIVES EFFECT TO THE RESTATEMENT. IN ADDITION, ALL SHARE AND PER SHARE AMOUNTS FOR ALL PERIODS HAVE BEEN RESTATED TO REFLECT THE 5-FOR-4 STOCK SPLIT WHICH WAS EFFECTED IN THE FORM OF A STOCK DIVIDEND TO COMMON STOCKHOLDERS OF RECORD AS OF JUNE 10, 2002 WITH A PAYMENT DATE OF JUNE 20, 2002.

Critical Accounting Policies and Estimates

The Company’s discussion and analysis of its financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements. The Company recognizes revenues from the sale of oil and gas in the period delivered. We provide an allowance for doubtful accounts for specific receivables we judge unlikely to be collected. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments in value are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis through depletion, depreciation and amortization expense over the life of the associated oil and gas reserves. Oil and gas property costs are periodically evaluated for possible impairment. Impairments are recorded when management believes that a property’s net book value is not recoverable based on current estimates of expected future cash flows. Depletion, depreciation and amortization of oil and gas properties and the periodic assessments for impairment are based on underlying oil and gas reserve estimates and future cash flows using then current oil and gas prices combined with operating and capital development costs. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The Company regularly enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The contracts, which are generally placed with major financial institutions or with counter parties which management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures, which have a high degree of historical correlation with actual prices received by the Company. Currently, the Company’s oil and gas swap contracts are designated as cash flow hedges.

Factors Affecting Financial Condition and Liquidity

Liquidity and Capital Resources

At December 31, 2001, the Company had $455.5 million of assets. Total capitalization was $326.6 million, of which 76% was represented by stockholders’ equity and 24% by bank debt. During 2001, net cash provided by operations totaled $172.8 million, as compared to $109.4 million in 2000 ($148.1 million and $108.4 million prior to changes in working capital, respectively). At December 31, 2001, there were no significant commitments for capital expenditures. Based upon a $77.0 million capital budget for 2002, the Company expects production to continue to increase in the coming year. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition and exploration expenditures and additional equity repurchases using internal cash flow, proceeds from asset sales and bank borrowings. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized.

During 2001, the Company repurchased 2,941,000 shares of its common stock for $51.5 million. The Company received proceeds totaling approximately $36.0 million from the exercise of the $10.00 common stock warrants in May 2001. The unexercised warrants expired on May 2, 2001.

The Company’s primary cash requirements will be to finance acquisitions, fund development expenditures, repurchase equity securities, repay indebtedness, and general working capital needs. However, future cash flows are subject to a number of variables, including the level of production and oil and gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken.

The Company believes that borrowings available under its Credit Agreement, projected operating cash flows and the cash on hand will be sufficient to cover its working capital, capital expenditures, planned development activities and debt service requirements for the next 12 months. In connection with consummating any significant acquisition, additional debt or equity financing will be required, which may or may not be available on terms that are acceptable to the Company.

The following summarizes the Company’s contractual obligations at December 31, 2001 and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):

	Less than One Year		1-3 Years			After 3 Years		Total
Long term debt	$	—	$	77,000	*	$	—	$	77,000
Non-cancelable operating leases		880		2,770			900		4,550

Total contractual cash obligations	$	880	$	79,770		$	900	$	81,550

Due at termination dates in each of the Company’s credit facilities, which the Company expects to renew.

Banking

The following summarizes the Company’s borrowings and availability under Patina’s and Elysium’s revolving credit facilities (in thousands):

	December 31, 2001
Revolving Credit Facilities	Borrowing Base		Outstanding		Available
Patina	$	125,000	$	71,000	$	54,000
Elysium (net to Patina)		10,000		6,000		4,000

Total	$	135,000	$	77,000	$	58,000

In July 1999, the Company entered into an Amended Bank Credit Agreement (the “Credit Agreement”). The Credit Agreement is a revolving credit facility in an aggregate amount up to $200.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $125.0 million at December 31, 2001. The borrowing base was reduced at Patina’s election to minimize commitment fees on the facility, as the additional availability was not needed. Patina had $54.0 million available under the Credit Agreement at December 31, 2001. In the course of 2001, $100.0 million of debt was retired, leaving $77.0 million of bank debt outstanding at year-end. The debt reduction, equity repurchases and capital expenditures were funded with internal cash flow, $36.0 million in proceeds from the exercise of the $10.00 warrants, the sale of Elysium’s interest in the Lake Washington Field and the subsequent refinancing of the Elysium loan.

The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.00% to 1.50%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.50%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility was 5.8% during 2001 and 3.1% at December 31, 2001.

The Credit Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and non-speculative commodity hedging. Borrowings under the Credit Agreement mature in July 2003, but may be prepaid at anytime. The Company has periodically extended the Credit Agreement; however, there is no assurance it will be able to do so in the future. The Company had a restricted payment basket under the Credit Agreement of $39.9 million as of December 31, 2001, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

The Company loaned Elysium $53.0 million at the closing of the Elysium transaction in November 2000. In May 2001, Elysium refinanced this loan with outside banks and entered into a Bank Credit Agreement (the “Elysium Credit Agreement”). The Elysium Credit Agreement is a revolving credit facility in an aggregate amount up to $60.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $20.0 million ($10.0 million net to Patina) at December 31, 2001. Elysium had $8.0 million available under the Elysium Credit Agreement at December 31, 2001.

The Elysium facility is non-recourse to Patina and contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, a minimum current ratio and minimum tangible net worth. Borrowings under the Elysium Credit Agreement mature in May 2004, but may be prepaid at anytime. Elysium may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.50% to 2.00%, or (ii) the prime rate plus a margin which fluctuates from 0.25% to 0.75%. The margin is determined by a utilization of borrowing base percentage. The weighted average interest rate under the facility was 6.8% during 2001 and 4.0% at December 31, 2001.

Cash Flow

The Company’s principal sources of cash are operating cash flow and bank borrowings. The Company’s cash flow is highly dependent on oil and gas prices. Pricing volatility will be somewhat reduced as the Company has entered into favorable hedging agreements for 2002, 2003, 2004 and 2005, respectively. The $88.1 million of capital expenditures for 2001 were funded entirely with internal cash flow. The 2002 capital budget of $77.0 million, comprised of approximately $67.0 million of development expenditures in Wattenberg, is expected to increase production by approximately 10%. The Company expects the capital program to be funded with internal cash flow, even in this lower price environment. As such, exclusive of any acquisitions or significant equity repurchases, management expects to continue to reduce long-term debt in 2002.

Net cash provided by operating activities in 1999, 2000 and 2001 was $49.7 million, $109.4 million and $172.8 million, respectively. Cash flow from operations increased with the rise in oil and gas production combined with higher prices and lower interest expense, more than offsetting the increases in lease operating expenses, production taxes and general and administrative expenses.

Net cash used in investing activities in 1999, 2000 and 2001 totaled $23.7 million, $86.1 million and $82.4 million, respectively. The 1999 expenditures were primarily for development of properties in Wattenberg, totaling $21.1 million. The increase in expenditures in 2000 was due largely to the purchase of Elysium for $47.5 million and the increase in development expenditures in Wattenberg to $40.0 million. The further increase in expenditures in 2001 was due to the increase in development expenditures to $77.3 million ($65.6 million in Wattenberg) and the initiation of our grassroots projects, somewhat offset by $16.5 million of proceeds from sales of assets, primarily Elysium’s properties in the Lake Washington Field in Louisiana.

Net cash used in financing activities in 1999, 2000 and 2001 was $35.5 million, $21.2 million and $92.8 million, respectively. Sources of financing have been primarily bank borrowings. During 1999, as operating cash flow exceeded capital expenditures, $10.0 million of bank debt was repaid and $24.6 million of common and preferred stock was repurchased. In 2000, the Company borrowed $45.0 million of bank debt. These borrowing were used in conjunction with operating cash flow to fund the Elysium acquisition, repurchase $42.0 million of equity securities and loan Elysium $24.5 million. During 2001, the combination of operating cash flow, proceeds from the exercise of the Company’s $10.00 Warrants for $36.0 million, the refinancing of Elysium loan, and proceeds from the sale of the Lake Washington properties, allowed the Company to repay $100.0 million of bank debt, repurchase $51.5 million of equity securities and fund capital development and acquisition expenditures of $88.1 million.

Capital Requirements

During 2001, $88.1 million of capital was expended, primarily on development projects. This represented approximately 51% of internal cash flow. The Company manages its capital budget with the goal of funding it with internal cash flow. The 2002 capital budget of $77.0 million is expected to increase production by approximately 10%. The Company expects the capital program to be funded with internal cash flow, even in this lower price environment. As such, exclusive of any acquisitions or significant equity repurchases, management expects to continue to reduce long-term debt in 2002. Development and exploration activities are highly discretionary, and, for the foreseeable future, management expects such activities to be maintained at levels equal to or below internal cash flow.

Hedging

taxes) at December 31, 2001, which is presented on the balance sheet as a current asset of $20.1 million and a non-current asset of $31.9 million based on contract expiration. The gas contracts expire monthly through December 2005 and the oil contracts expire monthly through December 2002. Gains or losses on both realized and unrealized hedging transactions are determined as the difference between the contract price and a reference price, generally NYMEX for oil and the Colorado Interstate Gas (“CIG”) index for natural gas. Transaction gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net pre-tax losses relating to these derivatives in 1999 and 2000 were $4.1 million, $23.9 million, respectively, with a pretax gain of $4.1 million in 2001. Over the last three years, the Company has recorded cumulative net pre-tax hedging losses of $23.9 million against income. Effective January 1, 2001, the unrealized gains (losses) on these hedging positions were recorded at an estimate of fair value which the Company based on a comparison of the contract price and a reference price, generally NYMEX or CIG, on the Company’s balance sheet in Accumulated other comprehensive income (loss), a component of Stockholders’ Equity.

Inflation and Changes in Prices

While certain costs are affected by the general level of inflation, factors unique to the oil and gas industry result in independent price fluctuations. Over the past five years, significant fluctuations have occurred in oil and gas prices. Although it is particularly difficult to estimate future prices of oil and gas, price fluctuations have had, and will continue to have, a material effect on the Company.

The following table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 2000 and 2001. Average price computations exclude hedging gains and losses and other nonrecurring items to provide comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.

	Average Prices
	Oil		Natural Gas		Equivalent Mcf
	(Per Bbl)		(Per Mcf)		(Per Mcfe)
Annual
1997	$	19.54	$	2.25	$	2.55
1998		13.13		1.87		1.96
1999		17.71		2.21		2.40
2000		29.16		3.69		3.96
2001		24.99		3.42		3.63

Quarterly

2000
First	$	27.30	$	2.70	$	3.13
Second		27.75		3.23		3.55
Third		30.85		3.63		3.96
Fourth		30.53		5.03		5.05

2001
First	$	27.86	$	6.09	$	5.67
Second		26.96		3.70		3.93
Third		25.81		2.21		2.77
Fourth		19.69		1.94		2.31

Results of Operations

Comparison of 2001 to 2000. Revenues for 2001 totaled $214.2 million, a 42% increase over 2000. Net income for 2001 totaled $62.3 million compared to $42.4 million in 2000. The increases in revenue and net income were due primarily to increases in production and higher oil and gas prices.

Average daily oil and gas production in 2001 totaled 7,291 barrels and 112.3 MMcf (156.1 MMcfe), an increase of 31% on an equivalent basis from 2000. The rise in production was due to the increased level of capital expenditures in Wattenberg, a full year's contribution of the Elysium acquisition and, to a minor degree, the grassroots projects. During 2001, 68 wells were drilled or deepened and 323 refracs and seven recompletions were performed in Wattenberg, compared to 60 new wells or deepenings and 193 refracs and nine recompletions in 2000. Over the past year, the Company accumulated significant acreage positions in three Rocky Mountain basins and a leasehold position with production in West Texas in efforts to expand and diversify through grassroots projects. The Company drilled nine wells in 2001 on one of the grassroots projects, a coalbed methane play in Castlegate, Utah. Based upon a $77.0 million development budget for 2002, the Company expects production to continue to increase in the coming year.

Average oil prices increased 12% from $23.00 per barrel in 2000 to $25.72 in 2001. Average gas prices increased 6% from $3.28 per Mcf in 2000 to $3.48 in 2001. Average oil prices include hedging losses of $10.4 million or $6.17 per barrel in 2000 and hedging gains of $1.9 million or $0.73 per barrel in 2001. Average gas prices included hedging losses of $13.5 million or $0.40 per Mcf in 2000 and hedging gains of $2.1 million or $0.05 per Mcf in 2001. Lease operating expenses totaled $25.4 million or $0.45 per Mcfe for 2001 compared to $13.4 million or $0.31 per Mcfe in the prior year. The increase in operating expenses was primarily attributed to $8.9 million of additional operating expenses associated with the oil properties acquired in the Elysium purchase and $1.4 million associated with the grassroots projects. Production taxes totaled $13.5 million in 2001 compared to $10.6 million in 2000 or $0.24 per Mcfe in both years. The $2.9 million increase was a result of higher oil and gas and production.

General and administrative expenses in 2001, net of reimbursements, totaled $11.0 million, an increase of $3.8 million or 53% from 2000. The increase was primarily due to $3.2 million of expenses associated with Elysium. In December 2001, Elysium's administrative offices in Texas were closed down and their functions were moved to Denver, Colorado. This move should result in over $500,000 of savings in 2002. Included in general and administrative expenses was $279,000 in 2000 of non-cash expenses related to the common stock grants to officers and managers in conjunction with the redistribution of SOCO's ownership of the Company in 1997. These grants were fully amortized in 2000.

Interest and other expenses fell to $7.0 million in 2001, a decrease of 30% from the prior year. Interest expense decreased as a result of lower average debt balances and lower average interest rates. The Company's average interest rate in 2001 was 5.8% compared to 7.7% in 2000.

Deferred compensation adjustment totaled $3.2 million in 2001, a decrease of $9.5 million from the prior year. The decrease relates to the smaller increase in value of the Company's common shares and other investments held in a rabbi trust for the benefit of participants in the Company's deferred compensation plan during 2001. The Company's common stock price appreciated by 15% or $2.80 per share in 2001 versus 178% or $12.30 per share in 2000.

Depletion, depreciation and amortization expense for 2001 totaled $49.9 million, an increase of $9.3 million or 23% from 2000. Depletion expense totaled $48.9 million or $0.86 per Mcfe for 2001 compared to $39.6 million or $0.91 per Mcfe for 2000. The increase in depletion expense resulted primarily from the 31% increase in oil and gas production in 2001, somewhat offset by a lower depletion rate. The depletion rate was lowered in the first quarter of 2001 in conjunction with the completion of the year-end 2000 reserve report. The reduction reflects additional oil and gas reserves due primarily to the identification of additional refrac projects and drilling locations, upward revisions due to performance and the increase in oil and gas prices. This was somewhat mitigated by an increase in the depletion rate in the fourth quarter of 2001 as a result of lower oil and gas reserves resulting from lower year-end oil and gas prices. Depreciation and amortization expense in 2000 and 2001 totaled $1.0 million or $0.02 per Mcfe.

Provision for income taxes for 2001 totaled $35.0 million, an increase of $22.1 million from the same period in 2000. The increase was due to higher earnings and reversal of the deferred tax asset valuation allowance in 2000. The Company recorded a 36% tax provision for 2001 compared to a 23% tax provision in 2000.

Comparison of 2000 to 1999. Revenues for 2000 totaled $150.3 million, a 64% increase over 1999. Net income for 2000 totaled $42.4 million compared to $12.9 million in 1999. The increases in revenue and net income were due primarily to increases in production and higher oil and gas prices.

Average daily oil and gas production in 2000 totaled 4,603 barrels and 91.4 MMcf (119.0 MMcfe), an increase of 11% on an equivalent basis from 1999. During 2000, 60 wells were drilled or deepened and 193 refracs and nine recompletions were performed in Wattenberg, compared to 36 new wells or deepenings and 113 refracs and three recompletions in 1999.

Average oil prices increased 45% from $15.86 per barrel in 1999 to $23.00 in 2000. Average gas prices increased 50% from $2.18 per Mcf in 1999 to $3.28 in 2000. Average oil prices include hedging losses of $3.1 million or $1.85 per barrel in 1999 and $10.4 million or $6.17 per barrel in 2000. Average gas prices include hedging losses of $1.0 million or $0.03 per Mcf in 1999 and $13.5 million or $0.40 per Mcf in 2000. Lease operating expenses totaled $13.4 million or $0.31 per Mcfe for 2000 compared to $11.9 million or $0.30 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to one month of operating expense associated with the Elysium properties. Production taxes totaled $10.6 million or $0.24 per Mcfe for 2000 compared to $6.3 million or $0.16 per Mcfe in 1999. The $4.3 million increase was a result of higher average oil and gas prices and production.

General and administrative expenses in 2000, net of reimbursements, totaled $7.2 million, an increase of $953,000 or 15% from 1999. The increase was primarily due to the Company receiving lower reimbursements from working interest owners as a result of the Company acquiring various third party working interests in its oil and gas properties in late 1999. Included in general and administrative expenses was $279,000 and $1.0 million for 2000 and 1999 of non-cash expenses related to the common stock grants to officers and managers in conjunction with the redistribution of SOCO's ownership of the Company in 1997. These grants were fully amortized in 2000.

Interest and other expenses fell to $10.1 million in 2000, a decrease of $727,000 or 7% from the prior year. Interest expense decreased as a result of lower average debt balances and lower average interest rates on the Company's debt due to the redemption of the 11.75% Subordinated Notes in July 1999. The redemption was financed with borrowings under the bank credit facility. The Company's average interest rate for 2000 was 7.7% compared to 8.1% in 1999.

Deferred compensation adjustment totaled $12.7 million in 2002, an increase of $10.6 million from the prior year. The increase relates to the significant increase in value of the Company's common shares and other investments held in a rabbi trust for the benefit of participants in the Company's deferred compensation plan during 2000. The Company's common stock price appreciated by 178% or $12.30 per share in 2000 versus 193% or $4.54 per share in 1999.

Depletion, depreciation and amortization expense for 2000 totaled $40.6 million, a decrease of $144,000 from 1999. Depletion expense totaled $39.6 million or $0.91 per Mcfe for 2000 compared to $39.8 million or $1.01 per Mcfe for 1999. The decrease in depletion expense resulted primarily from a lower depletion rate, partially offset by higher oil and gas production. The depletion rate was lowered in the fourth quarter of 1999 and the second quarter of 2000 in conjunction with the completion of the year-end 1999 and mid-year 2000 reserve reports. The reduction reflects additional oil and gas reserves due primarily to the identification of additional refrac projects and drilling locations, upward revisions due to performance and the increase in oil and gas prices. Depreciation and amortization expense for 2000 totaled $987,000 compared to $947,000 or $0.02 per Mcfe for both years.

Recent Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations,” which addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001. The adoption of SFAS No. 141 did not have a material impact on the Company’s financial position or results of operations.

In June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which addresses, among other things, the financial accounting and reporting for goodwill subsequent to an acquisition. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill shall be reviewed at least annually for impairment. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 142 did not have a material impact on the Company’s financial position or results of operations.

In July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The statement is effective for fiscal years beginning after June 15, 2002. The Company has not yet determined the impact of adoption of this statement.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which provides a single accounting model for long-lived assets to be disposed of and changes the criteria that would have to be met to classify an asset as held-for-sale. The statement also requires expected future operating losses from discontinued operations to be recognized in the periods in which the losses are incurred, which is a change from the current requirement of recognizing such operating losses as of the measurement date. The statement is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 did not have a material impact on the Company’s financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The Company’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing domestic price for oil and spot prices applicable to the Rocky Mountain and Mid-Continent regions for its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Natural gas price realizations during 2001, exclusive of any hedges, ranged from a monthly low of $2.13 per Mcf to a monthly high of $7.65 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $18.76 per barrel to a monthly high of $28.87 per barrel during 2001. Oil and natural gas prices have decreased significantly from late 2000 and early 2001 levels. A significant decline in prices of oil or natural gas could have a material adverse effect on the Company’s financial condition and results of operations.

In 2001, a 10% reduction in oil and gas prices, excluding oil and gas quantities that were fixed through hedging transactions, would have reduced revenues by $8.1 million. If oil and gas future prices at December 31, 2001 had declined by 10%, the unrealized hedging gains at that date would have increased by $12.8 million (from $52.0 million to $64.8 million).

The Company regularly enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The contracts, which are generally placed with major financial institutions or with counter parties which management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures, which have a high degree of historical correlation with actual prices received by the Company. Currently, the Company’s oil and gas swap contracts are designated as cash flow hedges.

The Company entered into various swap contracts for oil based on NYMEX prices, recognizing losses of $3.1 million and $10.4 million in 1999 and 2000, respectively, and a gain of $1.9 million in 2001, related to these contracts. The Company entered into various swap contracts for natural gas based on the Colorado Interstate Gas (“CIG”) index, recognizing losses of $1.0 million and $13.5 million in 1999 and 2000, respectively, and a gain of $2.1 million in 2001, related to these contracts.

At December 31, 2001, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 1,950 barrels of oil per day for 2002 at fixed prices ranging from $23.11 to $27.32 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $25.70 per barrel for 2002. The unrecognized gains on these contracts totaled $3.8 million based on NYMEX futures prices at December 31, 2001.

At December 31, 2001, the Company was a party to swap contracts for natural gas based on CIG index prices covering approximately 25,400 MMBtu’s per day for 2002 at fixed prices ranging from $3.72 to $5.51 per MMBtu. The overall weighted average hedged price for the swap contracts is $3.84 per MMBtu for 2002. The Company also entered into natural gas swap contracts for 2003, 2004 and 2005 as of December 31, 2001, which are summarized in the table below. The unrecognized gains on these contracts totaled $48.2 million based on CIG futures prices at December 31, 2001.

At December 31, 2001, the Company was a party to the fixed price swaps summarized below:

	Oil Swaps (NYMEX)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain
			($/thousands)
01/01/02-03/31/02	3,750	26.47	$	2,150
04/01/02-06/30/02	3,100	25.51		1,409
07/01/02-09/30/02	500	23.65		139
10/01/02-12/31/02	500	23.24		115


	Natural Gas Swaps (CIG Index)
Time Period	Daily Volume MMBtu	$/MMBtu)	Unrealized Gain
			($/thousands)
01/01/02-03/31/02	25,000	5.23	$	6,966
04/01/02-06/30/02	36,650	3.58		5,480
07/01/02-09/30/02	25,000	3.12		2,579
10/01/02-12/31/02	15,000	3.42		1,296
2003	30,000	3.78		11,896
2004	30,000	3.85		10,306
2005	30,000	3.90		9,671

Interest Rate Risk

At December 31, 2001, the Company had $71.0 million outstanding under its credit facility with an average interest rate of 3.1% and $6.0 million (net to Patina) outstanding under its Elysium credit facility with an average interest rate of 4.0%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.00% to 1.50% on the Patina facility or 1.50% to 2.00% on the Elysium facility or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.50% on the Patina facility or 0.25% to 0.75% on the Elysium facility. The weighted average interest rates under the Patina and Elysium facilities approximated 5.8% and 6.8%, respectively during 2001. Assuming no change in the amount outstanding at December 31, 2001, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $300,000, net of tax. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to the Index to Consolidated Financial Statements on page F-1 for a listing of the Company’s financial statements and notes thereto and for the financial statement schedules contained herein.

Management Responsibility for Financial Statements

The financial statements have been prepared by management in conformity with generally accepted accounting principles. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.

The Company maintains accounting and other controls which management believes provide reasonable assurance that financial records are reliable, assets are safeguarded and transactions are properly recorded. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived.

ITEM 9. CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On July 16, 2002, the Board of Directors of the Company approved the Audit Committee’s recommendation to hire Deloitte & Touche LLP (“Deloitte”) as the Company’s independent auditors to replace Arthur Andersen LLP (“Arthur Andersen”), who was dismissed immediately. Deloitte’s appointment was announced on July 29, 2002.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

The officers and directors are listed below with a description of their experience and certain other information. Each director was elected for a one-year term at the Company’s 2001 annual stockholders’ meeting of stockholders. Officers are appointed by the Board of Directors.

Directors and Executive Officers

The following table sets forth-certain information about the officers and directors of the Company:

Name	Age	Position
Thomas J. Edelman	51	Chairman and Chief Executive Officer, Chairman of the Board
Jay W. Decker	50	President and Director
David J. Kornder	41	Executive Vice President and Chief Financial Officer
Andrew M. Ashby	46	Senior Vice President—Operations
John M. Stafford	45	Vice President and General Counsel
Barton R. Brookman	39	Vice President
James A. Lillo	47	Vice President
Terry L. Ruby	43	Vice President
David W. Siple	42	Vice President
Robert J. Clark	57	Director
Elizabeth K. Lanier	50	Director
Alexander P. Lynch	49	Director
Paul M. Rady	48	Director

Thomas J. Edelman founded the Company and has served as Chairman of the Board, Chairman and Chief Executive Officer since its formation. He co-founded SOCO and was its President from 1981 through early 1997. From 1980 to 1981, he was with The First Boston Corporation and from 1975 through 1980, with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from Princeton University and his Masters Degree in Finance from Harvard University’s Graduate School of Business Administration. Mr. Edelman serves as Chairman of Range Resources Corporation and Bear Cub Investments LLC, and is a Director of Star Gas Corporation.

Jay W. Decker has served as President since March 1998 and as a Director since 1996. He had been the Executive Vice President and a Director of Hugoton Energy Corporation, a public independent oil company since 1995. From 1989 until its merger into Hugoton Energy, Mr. Decker was the President and Chief Executive Officer of Consolidated Oil & Gas, Inc., a private independent oil company and President of a predecessor company. Prior to 1989, Mr. Decker served as Vice President—Operations for General Atlantic Energy Company and in various capacities with Peppermill Oil Company, Wainoco Oil & Gas and Shell Oil Company. Mr. Decker received his Bachelor of Science Degree in Petroleum Engineering from the University of Wyoming.

David J. Kornder has served as Executive Vice President and Chief Financial Officer since 1996. Prior to that time, he served as Vice President—Finance of Gerrity beginning in early 1993. From 1989 through 1992, Mr. Kornder was an Assistant Vice President of Gillett Group Management, Inc. Prior to that, Mr. Kornder was an accountant with the independent accounting firm of Deloitte & Touche LLP for five years. Mr. Kornder received his Bachelor of Arts Degree in Accounting from Montana State University. Mr. Kornder serves as a Director of the Colorado Oil & Gas Association.

Andrew M. Ashby has served as Senior Vice President since November 2001. From 2000 to 2001, Mr. Ashby served as Executive Vice President and Chief Operating officer for Omega Oil Company. From 1997 to 2000, Mr. Ashby served as the Vice President of Operations for Westport Oil and Gas, a public independent oil company. From 1989 to 1997, Mr. Ashby worked as a drilling consultant on various international oil projects. Prior to that, Mr. Ashby worked for Amoco Production Company as a petroleum engineer and an exploration geologist. Mr. Ashby received his Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines.

John M. Stafford has served as Vice President and General Counsel since February 2001. From 1998 to January 2001, Mr. Stafford was an attorney with Holme Roberts and Owen, LLP. Mr. Stafford worked as an attorney for Holland & Hart, LLP from 1997 to 1998 and for Michael Best & Friedrich, LLP from 1996 to 1997. Prior to becoming an attorney, he was a Senior Geologist with ARCO Oil and Gas Company from 1982 to 1993. Mr. Stafford received his Bachelor of Science Degree in Geology from Syracuse University, his Master of Science Degree in Geological Oceanography from Texas A&M University and his Juris Doctorate Degree from the University of Denver. From 1999 to 2001, Mr. Stafford served as an ex-officio Director of the Association of International Petroleum Negotiators.

Barton R. Brookman has served as a Vice President of Operations since January 2001. From 1996 to 2000, Mr. Brookman was the District Operations Manager for the Company. From 1988 to 1996, Mr. Brookman was a District Operations Manager for SOCO. From 1986 to 1988, Mr. Brookman was a Petroleum Engineer for Ladd Petroleum Corporation, an affiliate of General Electric. Mr. Brookman received his Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines and his Master of Science—Finance Degree from the University of Colorado, Denver.

James A. Lillo has served as a Vice President since 1998. From 1995 to 1998, Mr. Lillo was President of James Engineering, Inc., an independent petroleum engineering consulting firm. Previously, he served as Vice President of Engineering for Consolidated Oil & Gas, Inc., until its merger into Hugoton Energy Corporation, and President of a predecessor operating company since 1989. Prior to 1989, Mr. Lillo worked as an engineering consultant and as Manager of Reservoir Engineering for Hart Exploration and in various engineering capacities with Champlin Petroleum Company and Shell Oil Company. Mr. Lillo received his Bachelor of Science Degree in Chemical and Petroleum Refining Engineering from the Colorado School of Mines and is a Registered Professional Engineer.

Terry L. Ruby has served as a Vice President since 1996. Prior to that time, Mr. Ruby served as a senior landman of Gerrity beginning in 1992 and was appointed Vice President—Land in 1995. From 1990 to 1992, Mr. Ruby worked for Apache Corporation and from 1982 to 1990, he was employed by Baker Exploration Company. Mr. Ruby received his Bachelor of Science Degree in Minerals Land Management from the University of Colorado and his M.B.A. from the University of Denver.

David W. Siple has served as a Vice President since 1996. He joined SOCO’s land department in 1994 and was appointed a Land Manager in 1995. From 1990 through May 1994, Mr. Siple was the Land Manager of Gerrity. From 1981 through 1989, Mr. Siple was employed by PanCanadian Petroleum Company in the Land Department. Mr. Siple received his Bachelor of Science Degree in Minerals Land Management from the University of Colorado.

Robert J. Clark has served as a Director since 1996. Mr. Clark is the President of Bear Cub Investments LLC, a private gas gathering and processing company. In 1995, Mr. Clark formed a predecessor company, Bear Paw Energy LLC, which was sold in early 2001. From 1988 to 1995, he was President of SOCO Gas Systems, Inc. and Vice President—Gas Management for SOCO. Mr. Clark was Vice President Gas Gathering, Processing and Marketing of Ladd Petroleum Corporation, an affiliate of General Electric from 1985 to 1988. Prior to 1985, Mr. Clark held various management positions with NICOR, Inc. and its affiliate NICOR Exploration, Northern Illinois Gas and Reliance Pipeline Company. Mr. Clark received his Bachelor of Science Degree from Bradley University and his M.B.A. from Northern Illinois University.

Elizabeth K. Lanier has served as a Director since 1998. Effective April 2002, Mrs. Lanier will be the Senior Vice President, General Counsel of TrizecHahn Corporation, a public real estate investment trust. Mrs. Lanier served as Vice President and General Counsel of General Electric Power Systems from 1998 until March 2002. From 1996 to 1998, Mrs. Lanier served as Vice President and Chief of Staff of Cinergy Corp. Mrs. Lanier received her Bachelor of Arts Degree with honors from Smith College and her Juris Doctor from Columbia Law School where she was a Harlan Fiske Stone Scholar. Mrs. Lanier was awarded an Honorary Doctorate of Technical Letters by Cincinnati Technical College and an Honorary Doctorate of Letters from the College of Mt. St. Joseph. From 1982 to 1984 she was an associate with Frost & Jacobs, a law firm in Cincinnati, Ohio and a partner from 1984 to 1996. From 1977 to 1982 she was with the law firm of Davis Polk & Wardwell in New York City. She is past Chair of the Ohio Board of Regents.

Alexander P. Lynch has served as a Director since 1996. Mr. Lynch has been a Managing Director of J.P. Morgan & Company, a subsidiary of JPMorganChase, Inc., since July 2000. From 1997 to July 2000, Mr. Lynch was a General Partner of The Beacon Group, a private investment and financial advisory firm, which was merged with Chase Securities in July 2000. From 1995 to 1997, Mr. Lynch was Co-President and Co-Chief Executive Officer of The Bridgeford Group, a financial advisory firm, which was merged into the Beacon Group. From 1991 to 1994, he served as Senior Managing Director of Bridgeford. From 1985 until 1991, Mr. Lynch was a Managing Director of Lehman Brothers, a division of Shearson Lehman Brothers Inc. Mr. Lynch received his Bachelor of Arts Degree from the University of Pennsylvania and his M.B.A. from the Wharton School of Business at the University of Pennsylvania. Mr. Lynch also serves as a Director of Range Resources Corporation.

Paul M. Rady has served as a Director since April 2001. Mr. Rady previously served as Chief Executive Officer, President, and Chairman of the Board of Directors of Pennaco Energy, Inc., an oil and gas exploration company. Pennaco was sold to Marathon Oil Company in early 2001. He joined Pennaco in June 1998 as its Chief Executive Officer, President and Director. Mr. Rady was with Barrett Resources Corporation, an oil and gas exploration and production company, for approximately eight years. During his tenure at Barrett, Mr. Rady held various executive positions including his most recent position as Chief Executive Officer, President and Director. Other positions held by Mr. Rady were Chief Operating Officer, Executive Vice President-Exploration, and Chief Geologist-Exploration Manager. Prior to his employment at Barrett, Mr. Rady was with Amoco Production Company based in Denver, Colorado for approximately ten years. Mr. Rady received his Bachelor of Science Degree in Geology from Western States College of Colorado and his Master of Science Degree in Geology from Western Washington University.

The Board has established four committees to assist it in the discharge of its responsibilities.

Audit and Governance Committee. The Audit and Governance Committee reviews the professional services provided by independent public accountants and the independence of such accountants from management. This Committee also reviews the scope of the audit coverage, the quarterly and annual financial statements and such other matters with respect to the accounting, auditing and financial reporting practices and procedures as it may find appropriate or as have been brought to its attention. Messrs. Clark, Lanier, Lynch and Rady are the members of the Audit and Governance Committee.

Compensation Committee. The Compensation Committee reviews and approves officers’ salaries and administers the bonus, incentive compensation and stock option plans. The Committee advises and consults with management regarding benefits and significant compensation policies and practices. This Committee also considers nominations of candidates for officer positions. The members of the Compensation Committee are Messrs. Clark, Lanier, Lynch and Rady.

Dividend Committee. The Dividend Committee is authorized and directed to approve the payment of dividends. The members of the Dividend Committee are Messrs. Edelman and Kornder.

Executive Committee. The Executive Committee reviews and authorizes actions required in the management of the business and affairs of Patina, which would otherwise be determined by the Board, where it is not practicable to convene the full Board. The members of the Executive Committee are Messrs. Edelman, and Lynch.

ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

Information with respect to officers’ compensation is incorporated herein by reference to the Company’s 2002 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information with respect to security ownership of certain beneficial owners and management is incorporated herein by reference to the Company’s 2002 Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND REPORTS

ON FORM 8-K

(a) 1. and 2. Financial Statements and Financial Statement Schedules

The items listed in the accompanying index to financial statements are filed as part of this Annual Report on

Form 10-K / A.

3. Exhibits.

The items listed on the accompanying index to exhibits are filed as part of this Annual Report on Form 10-K / A.

(b) Reports on Form 8-K.

None.

Exhibits required to be filed pursuant to Item 601 of Regulation S-K are contained in Exhibits listed in response to Item 14 (a)3, and are incorporated herein by reference.

(d) Financial Statement Schedules Required by Regulation S-X.

None.

The items listed in the accompanying index to financial statements are filed as part of this Annual Report on

Form 10-K / A.

GLOSSARY

The terms defined in this glossary are used throughout this Form 10-K / A.

Barrel or Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of six Mcf for each barrel of oil, which reflects the relative energy content.

Credit Facility. The Patina Oil & Gas Corporation $200.0 million revolving bank facility.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Deepening. The reentry into an existing wellbore and drilling to a deeper target formation.

Dry hole. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.

EBITDA. Earnings before interest, taxes, depletion, depreciation and amortization, as defined in the Company’s bank Credit Agreement.

Elysium Energy, L.L.C. A New York limited liability company in which Patina holds a 50% interest. Elysium is engaged in the development, exploration and acquisition of oil and gas properties primarily located in the Illinois Basin, the San Joaquin Basin of California and in central Kansas.

Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Infill well. A well drilled between known producing wells to better exploit the reservoir.

LIBOR. London Interbank Offer Rate, the rate of interest at which banks offer to lend to one another in the wholesale money markets in the City of London. This rate is a yardstick for lenders involved in high value transactions.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of six Mcf for each barrel of oil, which reflects the relative energy content.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

MMcf. One million cubic feet.

MMcfe. One million cubic feet of natural gas equivalents.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

Net oil and gas sales. Oil and natural gas sales less oil and natural gas production expenses.

Present Value. The present value, discounted at 10%, of future net cash flows from estimated proved reserves, using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions).

Productive well. A well that is producing oil or gas or that is capable of production.

Proved developed non-producing reserves. Reserves that consist of (i) proved reserves from wells that have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves. Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. 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.

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 for recompletion.

Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed.

Refrac. The restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves.

Reserve life index. The presentation of proved reserves defined in number of years of annual production.

Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after income taxes calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission’s rules for inclusion of oil and gas reserve information in financial statements filed with the Securities and Exchange Commission.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
PATINA OIL & GAS CORPORATION
Report of Independent Auditors		F-2
Consolidated Balance Sheets as of December 31, 2000 and 2001		F-3
Consolidated Statements of Operations for the years ended December 31, 1999, 2000 and 2001		F-4
Consolidated Statements of Changes in Stockholders’ Equity and Accumulated Other Comprehensive Income for the years ended December 31, 1999, 2000 and 2001		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 1999, 2000 and 2001		F-6
Notes to Consolidated Financial Statements		F-7

F-1

REPORT OF INDEPENDENT AUDITORS

To the Stockholders of

Patina Oil & Gas Corporation:

We have audited the accompanying consolidated balance sheets of Patina Oil & Gas Corporation (a Delaware corporation) and its subsidiaries (the “Company”) as of December 31, 2000 and 2001, and the related consolidated statements of operations, changes in stockholders’ equity and accumulated other comprehensive income and cash flows for each of the three years in the period ended December 31, 2001. 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Patina Oil & Gas Corporation and its subsidiaries as of December 31, 2000 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, on January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities to conform with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”.

As discussed in Note 1, the consolidated financial statements have been restated.

DELOITTE & TOUCHE LLP

Denver, Colorado,

September 20, 2002

F-2

PATINA OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands except share data)

	December 31,
	2000			2001
	(As Restated) (See Note 1)			(As Restated) (See Note 1)
ASSETS
Current assets
Cash and equivalents	$	2,653		$	250
Accounts receivable		31,830			16,407
Inventory and other		4,885			3,880
Unrealized hedging gains		—			20,134

		39,368			40,671

Unrealized hedging gains		—			31,872
Oil and gas properties, successful efforts method		709,248			780,224
Accumulated depletion, depreciation and amortization		(353,344	)		(402,213	)

		355,904			378,011

Field equipment and other		4,580			6,605
Accumulated depreciation		(3,098	)		(3,844	)

		1,482			2,761

Other assets, net		25,824			2,209

	$	422,578		$	455,524


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	23,073		$	27,380
Deferred income taxes		—			6,918
Accrued liabilities		7,794			10,767

		30,867			45,065

Senior debt		177,000			77,000
Deferred income taxes		12,953			39,355
Other noncurrent liabilities		21,165			18,891
Deferred compensation liability		20,442			25,639
Commitments and contingencies
Stockholders’ equity
Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued or outstanding		—			—
Common Stock, $.01 par, 125,000,000 shares authorized, 25,054,824 and 26,552,447 shares issued		251			266
Less Common Stock Held in Treasury, at cost, 995,753 shares and 1,076,689 shares		(4,503	)		(5,866	)
Capital in excess of par value		151,589			146,300
Retained earnings		12,814			71,513
Accumulated other comprehensive income		—			37,361

		160,151			249,574

	$	422,578		$	455,524

The accompanying notes are an integral part of these financial statements.

F-3

PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF OPERATION

(In thousands except per share data)

	Year Ended December 31,
	1999		2000		2001
	(As Restated)		(As Restated)		(As Restated)
	(See Note 1)		(See Note 1)		(See Note 1)
Revenues
Oil and gas sales	$	90,407	$	148,665	$	211,271
Other		1,259		1,677		2,902

		91,666		150,342		214,173

Expenses
Lease operating		11,902		13,426		25,356
Production taxes		6,271		10,628		13,462
Exploration		666		293		513
General and administrative		6,212		7,165		10,994
Interest and other		10,844		10,117		7,034
Impairment of oil and gas hedges		—		—		6,370
Deferred compensation adjustment		2,167		12,734		3,236
Depletion, depreciation and amortization		40,744		40,600		49,916

		78,806		94,963		116,881

Pretax income		12,860		55,379		97,292

Provision for income taxes
Current		—		—		11,466
Deferred		—		12,953		23,559

		—		12,953		35,025

Net income	$	12,860	$	42,426	$	62,267

Net income per common share
Basic	$	0.32	$	1.87	$	2.50

Diluted	$	0.31	$	1.53	$	2.31

Weighted average shares outstanding
Basic		19,082		20,930		24,957

Diluted		19,705		27,373		26,916

The accompanying notes are an integral part of these financial statements.

F-4

PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY AND ACCUMULATED OTHER COMPREHENSIVE INCOME

(In thousands)

	Preferred Stock Amount			Common Stock					Treasury Stock			Capital in Excess of Par Value			Deferred Compensation			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	Preferred Stock Amount			Shares		Amount			Treasury Stock			Capital in Excess of Par Value			Deferred Compensation			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 1998*	$	32		19,690		$	197		$	(3,717	)	$	206,859		$	959		$	(29,894	)	$	—		$	174,436
Repurchase of common and preferred		(7	)	(1,085	)		(11	)		—			(24,672	)		—			(489	)		—			(25,179	)
Conversion of preferred into common		(2	)	611			6			—			(2	)		—			—			—			2
Issuance of common stock *		—		948			10			—			3,134			(334	)		—			—			2,810
Deferred compensation stock issued, net *		—		—			—			(360	)		—			—			—			—			(360	)
Deferred compensation—contra equity *		—		—			—			—			—			(1,997	)		—			—			(1,997	)
Stock grant vesting				—			—			—			—			1,093			—			—			1,093
Dividends		1		—			—			—			3,319			—			(7,063	)		—			(3,743	)
Net income *		—		—			—			—			—			—			12,860			—			12,860

Balance, December 31, 1999	$	24		20,164			202			(4,077	)		188,638			(279	)		(24,586	)		—			159,922
Repurchase of common and preferred		(5	)	(2,048	)		(20	)		—			(41,571	)		—			(549	)		—			(42,145	)
Conversion of preferred into common		(19	)	6,168			61			—			(43	)		—			—			—			(1	)
Issuance of common stock *		—		771			8			—			4,565			—			—			—			4,573
Deferred compensation stock issued, net *		—		—			—			(426	)		—			—			—			—			(426	)
Stock grant vesting				—			—			—			—			279			—			—			279
Dividends		—		—			—			—			—			—			(4,477	)		—			(4,477	)
Net income *		—		—			—			—			—			—			42,426			—			42,426

Balance, December 31, 2000*		—		25,055			251			(4,503	)		151,589			—			12,814			—			160,151
Repurchase of common and warrants		—		(2,941	)		(29	)		—			(51,445	)		—			—			—			(51,474	)
Issuance of common stock *		—		841			8			—			8,052			—			—			—			8,060
Deferred compensation stock issued, net *		—		—			—			(1,363	)		—			—			—			—			(1,363	)
Conversion of warrants		—		3,598			36			—			35,939			—			—			—			35,975
Tax benefit from stock options		—		—			—			—			2,165			—			—			—			2,165
Dividends		—		—			—			—			—			—			(3,568	)		—			(3,568	)
Comprehensive income:
Net income *		—		—			—			—			—			—			62,267			—			62,267
Cumulative effect of change in accounting principle, net of income taxes		—		—			—			—			—			—			—			(25,077	)		(25,077	)
Contract settlements reclassed to income		—		—			—			—			—			—			—			822			822
Change in unrealized hedging gains		—		—			—			—			—			—			—			61,616			61,616

Total comprehensive income		—		—			—			—			—			—			62,267			37,361			99,628

Balance, December 31, 2001*	$	—		26,553		$	266		$	(5,866	)	$	146,300		$	—		$	71,513		$	37,361		$	249,574

*As

Restated, See Note 1

The accompanying notes are an integral part of these financial statements

F-5

PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	1999			2000			2001
	(As Restated)			(As Restated)			(As Restated)
	(See Note 1)			(See Note 1)			(See Note 1)
Operating activities
Net income	$	12,860		$	42,426		$	62,267
Adjustments to reconcile net income to net cash provided by operating activities
Exploration expense		666			293			513
Depletion, depreciation and amortization		40,744			40,600			49,916
Deferred income taxes		—			12,953			23,559
Tax benefit from exercise of stock options		—			—			2,165
Impairment of oil and gas hedges		—			—			6,370
Deferred compensation adjustment		2,167			12,734			3,236
Other		(13	)		(627	)		113
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable		(5,741	)		(13,068	)		15,423
Inventory and other		(180	)		(432	)		828
Increase (decrease) in
Accounts payable		(1,833	)		7,492			4,313
Income taxes payable		—			—			(2,623	)
Accrued liabilities		(2,412	)		334			3,123
Other assets and liabilities		3,402			6,679			3,574

Net cash provided by operating activities		49,660			109,384			172,777

Investing activities
Acquisition, development and exploration		(24,003	)		(89,304	)		(88,086	)
Disposition of oil and gas properties		—			—			16,468
Other		334			3,170			(10,739	)

Net cash used in investing activities		(23,669	)		(86,134	)		(82,357	)

Financing activities
Increase (decrease) in indebtedness		(10,021	)		45,000			(100,000	)
Repayment from (loan to) affiliate		—			(24,500	)		24,500
Deferred credits		2,087			1,446			(4,577	)
Loan origination fees		(455	)		—			(169	)
Issuance of common stock		2,040			3,568			42,465
Repurchase of common stock and warrants		(6,582	)		(28,750	)		(51,474	)
Repurchase of preferred stock		(18,106	)		(12,846	)		—
Preferred stock redemption premium		(489	)		(549	)		—
Preferred stock dividends		(3,113	)		(2,776	)		—
Common stock dividends		(812	)		(1,816	)		(3,568	)

Net cash used in financing activities		(35,451	)		(21,223	)		(92,823	)

Increase (decrease) in cash		(9,460	)		2,027			(2,403	)
Cash and equivalents, beginning of period		10,086			626			2,653

Cash and equivalents, end of period	$	626		$	2,653		$	250

The accompanying notes are an integral part of these financial statements

F-6

PATINA OIL & GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to the issuance of the Company’s financial statements for the year ended December 31, 2001, certain adjustments were made. The adjustments related to stock based compensation. The Company determined that the accounting treatment for its deferred compensation plan was not in accordance with guidance established under the Emerging Issues Task Force Abstracts 97-14 “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested,” (“EITF 97-14”). EITF 97-14 requires that assets of a rabbi trust and the related deferred compensation liability are to be recorded on the Company’s balance sheet; that fluctuations in asset values should result in deferred compensation expense or income; that based on the categories of assets underlying the plan, investment income and expense should be recorded in the income statement and unrealized increases or decreases in the value of the rabbi trust assets should be reported in accordance with Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”, and that Company stock held by the rabbi trust should be classified in stockholders’ equity as treasury stock. Historically, the Company had not consolidated the rabbi trust in its financial statements or recognized changes in the asset values of the trust through the income statement. For additional information on the deferred compensation plan, see Note (7).

In addition, the Company maintains a shareholder approved Stock Purchase Plan pursuant to which certain key employees were given the ability to purchase a limited number of restricted common shares at a discount or, separately, to receive annual bonuses or a portion of their base pay in restricted stock. Due to the one-year holding period restriction on shares under the plan, the Company originally recorded these shares at a discount to market. In accordance with the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (“APB No. 25”), “Accounting for Stock Issued to Employees,” the Company subsequently determined that all stock purchased under the Stock Purchase Plan or otherwise granted must be recorded or expensed based on the then quoted market prices of the common stock. See Note (7).

As a result, the accompanying financial statements for the years ended December 31, 1999, 2000 and 2001 have been restated from the amounts previously reported. Collectively, the restatement adjustments, net of tax benefits, decreased net income by $2.1 million in 1999, $10.0 million in 2000 and $2.3 million in 2001.

A summary of the significant effects of the restatement is as follows:

	Year Ended December 31,
	1999		2000		2001
	(In thousands except per share data)
Revenues as previously reported	$	91,571	$	150,332	$	214,144
Revenues as restated		91,666		150,342		214,173
General and administrative expense as previously reported	$	6,185	$	7,051	$	10,602
General and administrative expense as restated		6,212		7,165		10,994
Deferred compensation adjustment as previously reported	$	—	$	—	$	—
Deferred compensation adjustment as restated		2,167		12,734		3,236
Pretax income as previously reported	$	14,959	$	68,217	$	100,891
Pretax income as restated		12,860		55,379		97,292
Provision for income taxes as previously reported	$	—	$	15,776	$	36,321
Provision for income taxes as restated		—		12,953		35,025
Net income as previously reported	$	14,959	$	52,441	$	64,570
Net income as restated		12,860		42,426		62,267

F-7

	Year Ended December 31,
	1999		2000		2001
	(In thousands except per share data)
Net income per share as previously reported
Basic	$	0.42	$	2.25	$	2.48
Diluted		0.40		1.82		2.30
Net income per share as restated
Basic	$	0.32	$	1.87	$	2.50
Diluted		0.31		1.53		2.31
Weighted average shares outstanding as previously reported
Basic		19,965		21,941		26,043
Diluted		20,589		28,384		28,003
Weighted average shares outstanding as restated
Basic		19,082		20,930		24,957
Diluted		19,705		27,373		26,916

	December 31,
	2000		2001
Total assets as previously reported	$	421,254	$	453,573
Total assets as restated		422,578		455,524
Deferred income tax liability as previously reported	$	15,776	$	43,473
Deferred income tax liability as restated		12,953		39,355
Deferred compensation liability as previously reported	$	—	$	—
Deferred compensation liability as restated		20,442		25,639
Total stockholders’ equity as previously reported	$	176,446	$	269,144
Total stockholders’ equity as restated		160,151		249,574

(2) ORGANIZATION AND NATURE OF BUSINESS

Patina Oil & Gas Corporation (the “Company” or “Patina”), a Delaware corporation, was formed in 1996 to hold the assets of Snyder Oil Corporation (“SOCO”) in the Wattenberg Field and to facilitate the acquisition of Gerrity Oil & Gas Corporation (“Gerrity”). In conjunction with the Gerrity acquisition, SOCO received 17.5 million common shares of Patina. In 1997, a series of transactions eliminated SOCO’s ownership in the Company.

In November 2000, Patina acquired various property interests out of bankruptcy. The assets were acquired through Elysium Energy, L.L.C. (“Elysium”), a New York limited liability company, in which Patina holds a 50% interest. Patina invested $21.0 million and provided a $60.0 million credit facility to Elysium. See Note (10). The accompanying consolidated financial statements were prepared on a proportionate consolidation basis, including Patina’s 50% interest in Elysium’s assets, liabilities, revenues and expenses. All significant intercompany balances and transactions have been eliminated in consolidation.

The Company’s operations currently consist of the acquisition, development, exploitation and production of oil and gas properties. Historically, Patina’s properties were primarily located in the Wattenberg Field of Colorado’s D-J Basin. Over the past year, the Company accumulated significant acreage positions in three Rocky Mountain basins and a leasehold position with production in West Texas in efforts to expand and diversify through grassroots projects (“Grassroots Projects”). Through Elysium and these recently initiated exploration and development projects, the Company now has oil and gas properties in central Kansas, the Illinois Basin, Utah, Wyoming, Texas and the San Joaquin Basin of California.

F-8

(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Producing Activities

The Company utilizes the successful efforts method of accounting for its oil and gas properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis over the life of the associated oil and gas reserves. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has generally been provided on a field-by-field basis. An accrual of approximately $1.0 million had been provided for estimated future abandonment costs on certain Elysium properties as of December 31, 2001. No accrual has been provided for the Wattenberg properties, as management believes that salvage value will approximate abandonment costs.

The Company follows the provisions of Statement of Financial Accounting Standards No. 121 (“SFAS 121”), “Accounting for the Impairment of Long-Lived Assets and for Long Lived Assets to be Disposed of,” which requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a field-by-field basis. When the net book value of properties exceeds the undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined using the discounted future cash flows on a field-by field basis. In 1997, the Company recorded an impairment of $26.0 million to oil and gas properties as the estimated undiscounted future cash flows expected to result from these assets and their disposition, largely proven undeveloped drilling locations, was less than their net book value. The impairment primarily resulted from low year-end oil and gas prices. While no impairments have been necessary since 1997, changes in underlying assumptions or the amortization units could result in impairments in the future.

Field equipment and other

Depreciation of field equipment and other is provided using the straight-line method generally ranging from three to five years.

Other Assets

At December 31, 2000, Other Assets was comprised of $24.5 million advanced to Elysium by Patina and $1.3 million in assets held in a rabbi trust for the benefit of certain participants under the Company’s deferred compensation plan. In May 2001, Elysium entered into a credit facility with a third party bank. The proceeds from this facility were used to repay Patina. At December 31, 2001, the balance represented $2.0 million in assets held in a rabbi trust for the benefit of certain participants under the Company’s deferred compensation plan and $71,000 of net loan origination fees related to the credit facility Elysium entered into in May 2001. See Notes (7) and (10).

Section 29 Tax Credits

Between 1996 and 2000, the Company entered into certain arrangements to monetize its Section 29 tax credits. These arrangements resulted in revenue increases of approximately $0.40 per Mcf on production volumes from qualified properties. The Company recorded additional gas revenues of $2.9 million, $3.5 million and $600,000 during 1999, 2000 and 2001, respectively. As the Company’s profitability now allows it to utilize tax credits, they were reacquired in March 2001. Approximately $6.0 million in reacquired tax credits were utilized in the Company’s 2001 federal tax return.

F-9

Gas Imbalances

The Company uses the sales method to account for gas imbalances. Under this method, revenue is recognized based on the cash received rather than the Company’s proportionate share of gas produced. Gas imbalances at December 31, 2000 and 2001 were insignificant.

Accumulated Other Comprehensive Income

The Company follows the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The Company had no such changes prior to 2001. The components of accumulated other comprehensive income and related tax effects for the twelve months ended December 31, 2001 were as follows (in thousands):

	Gross			Tax Effect			Net of Tax
Cumulative effect of change in accounting principle	$	(39,183	)	$	14,106		$	(25,077	)
Change in fair value of hedges		89,905			(32,366	)		57,539
Impaired oil and gas hedging swaps		6,370			(2,293	)		4,077
Contract settlements during the year		1,284			(462	)		822

	$	58,376		$	(21,015	)	$	37,361

The impairment relates to a fourth quarter 2001 non-cash provision of $6.4 million ($4.1 million net of taxes) related to the write-off of all outstanding oil and gas hedges with Enron North America (“Enron”). The write-off reduced earnings per share in the quarter and year by $0.14 (fully diluted). In accordance with generally accepted accounting principles, the Company will record additional non-cash revenues of an identical amount in the course of 2002, as the impaired value of the hedges would have otherwise expired.

The following table schedules out the reversal of the impairment related to the Enron hedges recorded in accumulated other comprehensive income at December 31, 2001 and how it will impact earnings by quarter in 2002 (in thousands):

2002	Reported Revenues		Tax Impact			Reported Earnings
First quarter	$	3,568	$	(1,284	)	$	2,284
Second quarter		88		(32	)		56
Third quarter		1,749		(630	)		1,119
Fourth quarter		965		(347	)		618

	$	6,370	$	(2,293	)	$	4,077

Financial Instruments

The book value and estimated fair value of cash and equivalents was $2.7 million and $250,000 at December 31, 2000 and 2001, respectively. The book value and estimated fair value of the senior debt was $177.0 million and $77.0 million at December 31, 2000 and 2001, respectively. The book value of these assets and liabilities approximates fair value due to their short maturity or floating rate structure of these instruments.

F-10

Derivative Instruments and Hedging Activities

At December 31, 2001, the Company was a party to the fixed price swaps summarized below:

	Oil Swaps (NYMEX)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain
			($/thousands)
01/01/02-03/31/02	3,750	26.47	$	2,150
04/01/02-06/30/02	3,100	25.51		1,409
07/01/02-09/30/02	500	23.65		139
10/01/02-12/31/02	500	23.24		115


	Natural Gas Swaps (CIG Index)
Time Period	Daily Volume MMBtu	$/MMBtu	Unrealized Gain
			($/thousands)
01/01/02-03/31/02	25,000	5.23	$	6,966
04/01/02-06/30/02	36,650	3.58		5,480
07/01/02-09/30/02	25,000	3.12		2,579
10/01/02-12/31/02	15,000	3.42		1,296
2003	30,000	3.78		11,896
2004	30,000	3.85		10,306
2005	30,000	3.90		9,671

F-11

The Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, which establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting treatment. The Company adopted SFAS No. 133 on January 1, 2001.

The balance sheet impact of adopting of SFAS No. 133 on January 1, 2001 was as follows (in millions):

	Amount
Unrealized hedging losses	$	(43.2	)
Unrealized hedging gains		4.0
Deferred tax liability		(1.4	)
Deferred tax asset		15.5

Cumulative effect of a change in accounting principle (accumulated other comprehensive loss)	$	(25.1	)

During 2001 (excluding the impairment related to the Enron hedges), net hedging gains of $1.3 million ($822,000 after tax) were reclassified from Accumulated other comprehensive income to earnings and the changes in the fair value of outstanding derivative net liabilities decreased by $89.9 million ($57.5 million after tax). As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell their oil and gas, no ineffectiveness was recognized related to its hedge contracts in 2001. As of December 31, 2001 (excluding the impaired Enron hedges), the Company had net unrealized hedging gains of $52.0 million ($33.3 million after tax), comprised of $20.1 million of current assets and $31.9 million of non-current assets. The Company expects to reclassify as an increase to earnings during the next twelve months $20.1 million ($12.9 million after tax) of net unrealized hedging gains from Accumulated other comprehensive income based on estimated futures prices at December 31, 2001.

In October 1998, the Company entered into an interest rate swap contract for a two-year period. The contract was for $30.0 million principal with a fixed interest rate of 4.57% payable by the Company and the variable interest rate, the three-month LIBOR, payable by the third party. The difference between the fixed rate and the LIBOR rate was reset and received or paid by the Company in arrears every 90 days. The Company received $184,000 in 1999 and $422,000 in 2000 pursuant to this contract, which expired in October 2000.

Stock Options, Awards and Deferred Compensation Arrangements

The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (“APB No. 25”), “Accounting for Stock Issued to Employees.” Stock options awarded under the Employee Plan and the non-employee Directors Plan do not result in recognition of compensation expense. However, the restricted stock awarded under the Restricted Stock Plan is considered to be compensatory and the Company recognized $1.0 million and $279,000 of non-cash general and administrative expenses in 1999 and 2000, respectively. No costs were incurred in 2001 as these costs were fully amortized in 2000. See Note (7). The Company accounts for assets held in a rabbi trust for certain participants under the Company’s deferred compensation plan in accordance with EITF 97-14. See Note (7).

Per Share Data

On May 23, 2002, the Company’s Board of Directors approved a 5-for-4 stock split which was affected in the form of a 25% stock dividend to common stockholders of record as of June 10, 2002 with a payment date of June 20, 2002. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock split.

F-12

The Company uses weighted average shares outstanding in calculating earnings per share. When dilutive, options, warrants and common stock issuable upon conversion of convertible preferred securities are included as share equivalents using the treasury stock method and included in the calculation of diluted earnings per share. See Note (6)

Risks and Uncertainties

Historically, oil and gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in prices received could have a significant impact on future results.

Supplemental Cash Flow Information

Over the past three years, the Company incurred the following significant non-cash costs:

	Year Ended December 31,
	1999		2000		2001
Stock grant	$	335	$	—	$	—
Stock Purchase Plan		80		203		653
Dividends paid in kind—8.50% preferred stock		2,990		—		—
Accretion—8.50% preferred stock		331		—		—
401(k) profit sharing contribution in common stock		483		589		647

The 1999 stock grant represents 125,000 common shares, along with 375,000 stock options, granted to the Chief Executive Officer in conjunction with his voluntary reduction in cash salary, waiver of any 1998 bonus and other compensation arrangements in the second quarter of 1999. The Company recognized $1.0 million and $279,000 of non-cash general and administrative expenses for 1999 and 2000, respectively, related to these stock grants and the stock grants awarded to officers and managers in conjunction with the redistribution of SOCO’s ownership of the Company. See Note (10).

Other

All liquid investments with a maturity of three months or less are considered to be cash equivalents. Certain amounts in prior period consolidated financial statements have been reclassified to conform with the current classifications. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and 50% of the accounts of Elysium. All significant intercompany balances and transactions have been eliminated in consolidation.

The preparation of financial statements in conformity with accounting principles generally accepted in the Untied States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recent Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, “Business Combinations,” which addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001. The adoption of SFAS No. 141 did not have a material impact on the Company’s financial position or results of operations.

F-13

In July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations, “ which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The statement is effective for fiscal years beginning after June 15, 2002. The Company has not yet determined the impact of adoption of this statement.

(4) OIL AND GAS PROPERTIES

The cost of oil and gas properties at December 31, 2000 and 2001 included approximately $1.1 million and $4.8 million, respectively, in net unevaluated leasehold costs for acreage that is generally held for exploration or development to which proved reserves have not been assigned. These amounts have been excluded from amortization during the respective period. In addition, $2.5 million of costs incurred on the Company’s Grassroots Projects at December 31, 2001 have been excluded from amortization, as no determination had been made as to the extent of proved oil and gas reserves. The Company estimates that these costs will begin to be amortized in the first quarter of 2002 as production has been established. The following table sets forth costs incurred related to oil and gas properties:

	1999		2000		2001
	(In thousands, except per Mcfe amounts)
Development	$	21,122	$	39,996	$	77,343
Acquisition—evaluated		2,215		47,886		6,603
Acquisition—unevaluated		—		1,129		3,627
Exploration and other		666		293		513

	$	24,003	$	89,304	$	88,086

Disposition of properties	$	—	$	—	$	(16,468	)

Depletion rate (per Mcfe)	$	1.01	$	0.91	$	0.86

The disposition of properties relates primarily to the sale of Elysium properties in the Lake Washington Field in Louisiana for $30.5 million in March 2001 ($15.25 million net to the Company) and additional property sales in Wattenberg.

F-14

(5) INDEBTEDNESS

The following indebtedness was outstanding on the respective dates:

	December 31,
	2000		2001
	(In thousands)
Bank facility—Patina	$	177,000	$	71,000
Bank facility—Elysium, net		—		6,000
Less current portion		—		—

Senior debt, net	$	177,000	$	77,000

Scheduled maturities of indebtedness for the next five years are zero in 2002, $71.0 million in 2003 and $6.0 million in 2004. Management intends to extend the maturity of its credit facility on a regular basis; however, there can be no assurance it will be able to do so. Cash payments for interest totaled $14.3 million, $10.0 million and $7.2 million during 1999, 2000 and 2001, respectively.

F-15

(6) STOCKHOLDERS’ EQUITY

A total of 125.0 million common shares, $0.01 par value, are authorized of which 26.6 million were issued at December 31, 2001. The common stock is listed on the New York Stock Exchange. Prior to December 1997, no dividends had been paid on common stock. On May 23, 2002, the Company’s Board of Directors approved a 5-for-4 stock split which was affected in the form of a 25% stock dividend to common stockholders of record as of June 10, 2002 with a payment date of June 20, 2002. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock split. Adjusted for the stock dividend, a quarterly cash dividend of $0.008 per common share was initiated in December 1997, increased to $0.016 per share in the fourth quarter of 1999, to $0.032 per share in the fourth quarter of 2000, and to $0.04 per share in the fourth quarter of 2001. The Company has a stockholders’ rights plan designed to ensure that stockholders receive full value for their shares in the event of certain takeover attempts. The following is a schedule of the changes in the Company’s shares of common stock since January 1, 1999:

	1999		2000		2001
Beginning shares	19,690,500		20,164,100		25,054,800
Exercise of stock options	282,900		311,600		545,400
Issued under Stock Purchase Plan	116,100		65,500		122,400
Issued in lieu of salaries and bonuses	206,000		160,300		84,900
Issued for directors fees	10,700		3,500		1,900
Conversion of 7.125% preferred stock	611,000		185,000		—
Conversion of 8.50% preferred stock	—		5,982,000		—
Exercise of $10.00 warrants	—		3,000		3,597,500
Issued to deferred comp plan (salary match)	44,000		17,200		14,800
Vesting of stock grant	210,800		173,200		41,600
Contributed to 401(k) plan	76,600		37,000		30,300

Total shares issued	1,558,100		6,938,300		4,438,800
Repurchases	(1,084,500	)	(2,047,600	)	(2,941,200	)

Ending shares	20,164,100		25,054,800		26,552,400
Treasury shares held in rabbi trust (Note 7)	(865,500	)	(995,800	)	(1,076,700	)

Adjusted shares outstanding	19,298,600		24,059,000		25,475,700

During 1999, 2000 and 2001, the Company repurchased and retired shares of its common stock for $6.6 million, $28.8 million and $51.5 million, respectively.

During 2001, 3,597,500 $10.00 warrants ($12.50 prior to the stock split) were converted into common stock with the Company receiving cash proceeds of $36.0 million. The remaining unexercised warrants expired on May 2, 2001.

A total of 5,000,000 preferred shares, $0.01 par value, are authorized with no shares issued or outstanding at December 31, 2001.

In January 2000, the Company redeemed all remaining shares of the 7.125% preferred stock. Of the 564,800 shares called, 51,000 were converted into 185,000 shares of common stock and the remaining 513,800 were redeemed for $13.4 million in cash. The cash redemption was financed with borrowings under the bank credit facility. The Company paid $2.7 million and $600,000 in preferred dividends during 1999 and 2000, respectively. Included in the $2.7 million and $600,000 of preferred stock dividends paid in 1999 and 2000 was $489,000 and $549,000 of redemption premiums paid to shareholders that elected to redeem their preferred stock for cash in the fourth quarter of 1999 and the first quarter of 2000.

F-16

In August 2000, the Company called for redemption the remaining 1,618,500 shares of the 8.50% preferred stock outstanding. The shares were converted into 6.0 million shares of common stock. The Company paid $3.7 million and $2.6 million in preferred dividends during 1999 and 2000, respectively. Preferred dividends through October 1999 were paid in kind. As a result, the Company issued 119,577 of additional 8.50% preferred shares as dividends in 1999.

The Company follows SFAS No. 128, “Earnings per Share.” The following table specifies the calculation of basic and diluted earnings per share (in thousands except per share amounts):

	Year Ended December 31,
	1999						2000						2001
	Net Income			Common Shares	Per Share		Net Income			Common Shares	Per Share		Net Income		Common Shares	Per Share
Net income	$	12,860		19,082			$	42,426		20,930			$	62,267	24,957
7.125% preferred dividends		(2,681	)	—				(600	)	—				—	—
8.50% preferred dividends		(3,727	)	—				(2,610	)	—				—	—
Preferred stock accretion		(331	)	—				—		—				—	—

Basic net income attributable to common stock		6,121		19,082	$	0.32		39,216		20,930	$	1.87		62,267	24,957	$	2.50

Effect of dilutive securities:
7.125% preferred stock		—		—				—		—				—	—
8.50% preferred stock		—		—				2,610		4,052				—	—
Stock options		—		277				—		1,389				—	1,350
Unvested stock grant		—		346				—		164				—	9
$10.00 common stock warrants		—		—				—		838				—	600

Diluted net income attributable to common stock	$	6,121		19,705	$	0.31	$	41,826		27,373	$	1.53	$	62,267	26,916	$	2.31

The potentially dilutive securities related to the 7.125% and 8.50% preferred stock, and $10.00 common stock warrants were anti-dilutive in 1999.

(7) EMPLOYEE BENEFIT PLANS

401(k) Savings

The Company maintains a 401(k) profit sharing and savings plan (the “401(k) Plan”). Eligible employees may make voluntary contributions to the 401(k) Plan. The Company may, at its discretion, make additional matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions of $483,000, $589,000 and $647,000 for 1999, 2000 and 2001, respectively. The contributions were made in common stock. A total of 76,600, 37,000 and 30,300 common shares were contributed in 1999, 2000 and 2001, respectively.

Stock Purchase Plan

The Company maintains a shareholder approved stock purchase plan (“Stock Purchase Plan”). Pursuant to the Stock Purchase Plan, officers, directors and certain managers are granted options to purchase shares of common stock at prices ranging from 50% to 85% of the closing price of the stock on the trading day prior to the date of purchase (“Market Price”). To date, all purchase prices have been set at 75% of Market Price. In addition, employee participants may be granted the right to purchase shares pursuant to the Stock Purchase Plan with all or a part of their salary and bonus. A total of 625,000 shares of common stock are reserved for possible purchase under

F-17

the Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was approved by the stockholders allowing for the annual renewal of the 625,000 shares of common stock reserved for possible purchase under the Stock Purchase Plan. Plan years run from the date of the Annual Meeting through the next Annual Meeting. In 1999, the Board of Directors approved 170,400 common shares (exclusive of shares available for purchase with participants’ salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 1999, participants had purchased 116,100 shares of common stock at an average price of $4.54 per share ($3.40 net price per share), resulting in cash proceeds to the Company of $395,000. In 2000, the Board of Directors approved 145,400 common shares (exclusive of shares available for purchase with participants’ salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2000, participants had purchased 172,800 shares of common stock, including 107,300 shares purchased with participants’ 1999 bonuses, at an average price of $9.70 per share ($7.27 net price per share), resulting in cash proceeds to the Company of $665,000. In 2001, the Board of Directors approved 151,600 common shares (exclusive of shares available for purchase with participants’ salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2001, participants had purchased 122,500 shares of common stock at an average price of $21.33 per share ($16.00 net price per share), resulting in cash proceeds to the Company of $2.0 million. The Company recorded non-cash general and administrative expenses of $80,000, $203,000 and $653,000 associated with these purchases for 1999, 2000 and 2001, respectively. Participants had 54,300, 104,800 and 95,100 shares available for purchase under the Plan at December 31, 1999, 2000 and 2001, respectively.

Deferred Compensation Plan

The Company maintains a shareholder approved deferred compensation plan (“Deferred Compensation Plan”). This plan is available to officers and certain managers of the Company. The plan allows participants to defer all or a portion of their salary and annual bonuses (either in cash or Company stock). The Company can make discretionary matching contributions of the participant’s salary deferral and those assets are invested in instruments as directed by the participant. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi Trust (“Trust”) and, therefore, are available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest their salary and bonus deferrals into pre-approved mutual funds held by the Trust. In addition, participants have the right to request that the Plan Administrator re-allocate the portfolio of investments (i.e., cash, mutual funds, Company stock) in the participants’ individual account within the Trust, however, the Plan Administrator is not required to honor any such request. Company matching contributions are in the form of either cash or Company stock and vest ratably over a three-year period. Participants may elect to receive their payments in either cash or the Company’s common stock. At December 31, 2001, the balance of the assets in the Trust totaled $25.6 million, including 1,076,700 shares of common stock of the Company valued at $23.7 million. The Company accounts for the Deferred Compensation Plan in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested”.

Assets of the Trust, other than common stock of the Company, are invested in 11 mutual funds that cover the investment spectrum from equities to money market instruments. These mutual funds are publicly quoted and reported at market value. The Company accounts for these investments in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The Trust also holds common shares of the Company. The Company’s common stock that is held by the Trust has been classified as treasury stock in the stockholders’ equity section of the accompanying balance sheet. The market value of the assets held by the Trust, exclusive of the market value of the shares of the Company’s common stock that are reflected as treasury stock, at December 31, 2000 and 2001, was $1.3 million and $2.0 million, respectively, and is classified as Other Assets in the accompanying balance sheet. The amounts payable to the plan participants at December 31, 2000 and 2001, including the market value of the shares of the Company’s common stock that are reflected as treasury stock, was $20.4 million and $25.6 million, respectively, and is classified as Deferred Compensation Liability in the accompanying balance sheet.

F-18

In accordance with EITF 97-14, all market fluctuations in value of the Trust assets have been reflected in the respective income statements. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as Other income in the respective income statements. Increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are included as Deferred compensation adjustments in the respective income statement. In response to the changes in total market value of the Trust, the Company recorded deferred compensation adjustments of $2.2 million, $12.7 million, and $3.2 million in 1999, 2000 and 2001, respectively.

Stock Option and Award Plans

The Company maintains a shareholder approved stock option plan for employees (the “Employee Plan”) providing for the issuance of options at prices not less than fair market value at the date of grant. Options to acquire the greater of three million shares of common stock or 10% of outstanding diluted common shares may be outstanding at any time. The specific terms of grant and exercise are determinable by the Compensation Committee of the Board of Directors. The options vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Employee Plan:

Year	Options Granted	Weighted Range of Exercise Prices	Average Exercise Price
1999	788,000	$ 2.35 - $ 7.30	$	2.83
2000	631,000	$ 7.35 - $17.55	$	7.47
2001	792,000	$18.09 - $26.42	$	18.33

The Company also maintains a shareholder approved stock grant and option plan for non-employee Directors (the “Directors’ Plan”). The Directors’ Plan provides for each non-employee Director to receive common shares having a market value equal to $2,500 quarterly in payment of one-half of their retainer. A total of 10,700 shares were issued in 1999, 3,500 were issued in 2000 and 1,900 in 2001. It also provides for 6,250 options to be granted to each non-employee Director upon appointment and upon annual re-election, thereafter. The options vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Directors’ Plan:

Year	Options Granted	Weighted Range of Exercise Prices	Average Exercise Price
1999	38,000	$ 2.35 - $ 4.10	$	3.81
2000	31,000	$13.95	$	13.95
2001	31,000	$19.67 - $26.28	$	24.96

In 1997, the shareholders approved a special stock grant and purchase plan for certain officers and managers (“Management Investors”) in conjunction with the redistribution of SOCO’s ownership in the Company. The granted shares vested 25% per year on January 1, 1998, 1999, 2000 and 2001. The non-vested granted common shares were recorded as Deferred Compensation in the stockholders’ equity section of the accompanying consolidated balance sheets. The Management Investors simultaneously purchased additional common shares from the Company at $7.90 per share. A portion of the purchase was financed by the Company, all of which was repaid in January 2001. See Note (10). In conjunction with his appointment in March 1998, the Company’s President was granted 125,000 restricted common shares that vested 33% per year in March 1999, 2000 and 2001. The non-vested granted common shares were recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The President simultaneously purchased 125,000 common shares from the Company at $5.50 per share. A portion of this purchase ($584,000) was financed by the Company. As approved by the Board

F-19

of Directors, the President sold 62,500 common shares to the Company at $18.80 per share in March 2001, utilizing a portion of these proceeds to repay his note. See Note (10). In April 1999, the Chief Executive Officer was granted 125,000 restricted shares of common stock and 375,000 stock options in consideration of his voluntary reduction in cash salary, waiver of any 1998 bonus and other compensation arrangements. The shares vested ratably throughout 1999. The Company recognized $1.0 million and $279,000 of non-cash general and administrative expenses for 1999 and 2000 with respect to these stock grants.

At December 31, 2001, the Company had a stock option compensation plan, which is described above. The Company applies APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations in accounting for the plans. As all stock options have been issued at the market price on the date of grant, no compensation cost has been recognized for these stock option plans. Had compensation cost for the Company’s stock option plans been determined consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company’s net income (in thousands) and earnings per share would have been reduced to the pro forma amounts indicated below:

	1999		2000		2001
Net income
As Reported	$	12,860	$	42,426	$	62,267
Pro forma		11,855		41,276		60,698
Basic net income per common share
As Reported	$	0.32	$	1.87	$	2.50
Pro forma		0.27		1.82		2.43
Diluted net income per common share
As Reported	$	0.31	$	1.53	$	2.31
Pro forma		0.26		1.49		2.26

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1999, 2000 and 2001: dividend yield of 1%, 1% and 1%; expected volatility of 47%, 49% and 48%; risk-free interest rate of 5.2%, 6.6% and 4.7%; and expected life of 4.5 years, 4.0 years and 3.6 years, respectively.

A summary of the status of the Company’s stock option plans as of December 31, 1999, 2000 and 2001 and changes during the years are presented below:

	1999				2000				2001
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding at beginning of year	1,907,000		$	6.46	2,175,000		$	5.27	2,514,000		$	5.83
Granted	825,000			2.88	662,000			7.78	822,000			18.58
Exercised	(282,000	)		5.14	(311,000	)		6.02	(545,000	)		5.92
Forfeited	(275,000	)		6.44	(12,000	)		7.25	(40,000	)		9.46

Outstanding at end of year	2,175,000		$	5.27	2,514,000		$	5.83	2,751,000		$	9.58

Options exercisable at year-end	934,000				1,127,000				1,206,000

Weighted-average fair value of options granted during the year			$	1.18			$	3.39			$	7.18

F-20

The following table summarizes information about stock options outstanding at December 31, 2001:

	Options Outstanding				Options Exercisable
Exercise Price	Number Outstanding at December 31, 2001	Weighted-Avg. Remaining Contractual Life	Weighted-Average Exercise Price		Number Exercisable at December 31, 2001	Weighted-Average Exercise Price
$2.35 to 5.65	925,000	1.9 years	$	3.70	639,000	$	4.10
5.75 to 7.90	981,000	2.1 years		7.49	561,000		7.59
9.00 to 26.42	845,000	4.2 years		18.42	6,000		14.38

$2.35 to 26.42	2,751,000	2.7 years	$	9.58	1,206,000	$	5.78

(8) INCOME TAXES

A reconciliation of the federal statutory rate to the Company’s effective rate as it applies to the tax provision for the years ended December 31, 1999, 2000 and 2001 follows:

	1999		2000		2001
Federal statutory rate	35	%	35	%	35	%
State income tax rate, net of federal benefit	3	%	3	%	3	%
Decrease in valuation allowance against deferred tax asset	(38	)%	(12	)%	—
Section 29 tax credits and other	—		(3	)%	(2	)%

Effective income tax rate	—		23	%	36	%

Current income tax expenses in 2001 totaled $11.1 million for federal purposes and $0.4 million for state purposes. The Company utilized approximately $8.0 million of net operating loss carryforward in 2001 to reduce current taxes.

For book purposes the components of the net deferred tax asset and liability at December 31, 2000 and 2001 were:

	2000			2001
	(In thousands)
Deferred tax assets
NOL carry forwards	$	18,603		$	16,442
Deferred compensation deductions		2,823			4,118
Deferred deductions and other		1,721			6,692

		23,147			27,252

Deferred tax liabilities
Taxes relating to unrealized hedging gains		—			(18,392	)
Depreciable and depletable property		(36,100	)		(55,133	)

		(36,100	)		(73,525	)

Net deferred tax liability	$	(12,953	)	$	(46,273	)

Decrease in deferred tax valuation allowance	$	(8,153	)	$	—

For tax purposes, the Company had net operating loss carryforwards of approximately $41.0 million including alternative minimum tax (“AMT”) loss carryforwards of approximately $26.6 million at December 31, 2001. Utilization of $30.3 million of the net operating loss carryforwards will be limited to approximately $4.7 million per year as a result of the Gerrity acquisition in 1996. These carryforwards expire from 2010 through 2018. At December 31, 2001, the Company had AMT credit carryforwards of $4.1 million that are available indefinitely. No cash payments were made by the Company for federal taxes during 1999 and 2000. The Company paid $11.1 million in federal taxes during 2001.

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(9) MAJOR CUSTOMERS

During 1999, 2000 and 2001, Duke Energy Field Services, Inc. accounted for 37%, 32% and 29%, BP Amoco Production Company accounted for 24%, 19% and 13%, E-Prime accounted for 4%, 8%, and 10%, of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2000 and 2001 totaled $13.5 million and $7.5 million, respectively. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

(10) RELATED PARTY TRANSACTIONS

In October 1997, certain officers and managers purchased common shares at $7.90 per share from the Company. A portion of this purchase was financed by the Company through the issuance of 8.50% recourse promissory notes. The notes were fully repaid in January 2001. In conjunction with his appointment in March 1998, the President purchased 125,000 shares of common stock at $5.50 per share and was granted 125,000 shares. The Company loaned him $584,000, represented by an 8.50% recourse promissory note. As approved by the Board of Directors, the President sold 62,500 common shares to the Company at $18.80 per share in March 2001, utilizing a portion of these proceeds to repay his note. In March 2001, the Company loaned an officer $50,000, represented by a 7.00% recourse promissory note. The note is scheduled for annual principal reductions each March, with payment in full due in 2004. In May 2001, a director purchased 12,500 common shares from the Company under the Stock Purchase Plan. The Company loaned the director $136,000 to finance a portion of this purchase. The loan is due May 2004 and is represented by a 7.50% recourse promissory note.

In conjunction with the acquisition of Elysium in November 2000, Patina agreed to loan Elysium up to $60.0 million of which $49.0 million was outstanding at December 31, 2000. In May 2001, Elysium entered into a credit facility with a third party bank. The proceeds from this facility were used to repay Patina. Elysium paid interest of $371,000 in 2000 and $1.0 million in 2001 to Patina while the loan was outstanding.

Patina provides certain administrative services to Elysium under an operating agreement. The Company was paid $36,000 and $850,000 for these services in 2000 and 2001, respectively. In December 2001, Elysium’s office in The Woodlands, Texas was closed and all administrative functions were moved to Denver, Colorado. As such, the Company entered into a management agreement with Elysium providing for an indirect monthly reimbursement of $243,000 and any direct charges for providing this service.

(11) COMMITMENTS AND CONTINGENCIES

The Company leases office space and certain equipment under non-cancelable operating leases. Future minimum lease payments under such leases approximate $900,000 per year from 2002 through 2005.

The Company is a party to various lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations.

A recent ruling by the Colorado Supreme Court on the deductibility of gathering and transportation costs as to royalty interests has resulted in uncertainty of these deductions. The Company has not been named as a party to any related lawsuit and no determination has been made as to the financial impact to the Company, if any, in the event this decision stands.

F-22

(12) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

Netherland, Sewell & Associates, Inc., independent petroleum consultants, audited the Company’s total proved reserves at December 31, 1999, 2000 and 2001. All reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year-end were computed by applying then current prices to estimated future production less estimated future expenditures (based on current costs) to be incurred in producing and developing the reserves. All reserves are located onshore in the United States.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. With respect to certain properties that historically have experienced seasonal curtailment, the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the tables below represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown below. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. Results in drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered.

Quantities of Proved Reserves

	Oil		Natural Gas
	(MBbl)		(MMcf)
Balance, December 31, 1998	14,240		286,595
Revisions	1,665		18,498
Extensions, discoveries and additions	3,006		66,191
Production	(1,653	)	(29,477	)
Purchases	202		20,425
Sales	(40	)	(971	)

Balance, December 31, 1999	17,420		361,261
Revisions	1,354		1,493
Extensions, discoveries and additions	14,228		184,104
Production	(1,685	)	(33,463	)
Purchases	11,460		8,862
Sales	(64	)	(707	)

Balance, December 31, 2000	42,713		521,550
Revisions	(9,852	)	(40,737	)
Extensions, discoveries and additions	4,675		52,713
Production	(2,661	)	(41,002	)
Purchases	61		34,921
Sales	(2,832	)	(905	)

Balance, December 31, 2001	32,104		526,540

F-23

Proved Developed Reserves

	Oil	Natural Gas
	(MBbl)	(MMcf)
December 31, 1998	13,655	244,736

December 31, 1999	16,633	307,560

December 31, 2000	35,146	409,103

December 31, 2001	28,220	430,487

Standardized Measure

	December 31,
	1999			2000			2001
	(In thousands)
Future cash inflows	$	1,273,591		$	5,427,152		$	1,868,209
Future costs
Production		(323,859	)		(848,093	)		(486,526	)
Development		(126,978	)		(412,672	)		(379,474	)

Future net cash flows		822,754			4,166,387			1,002,209
Undiscounted income taxes		(192,956	)		(1,478,535	)		(279,461	)

After tax net cash flows		629,798			2,687,852			722,748
10% discount factor		(267,270	)		(1,248,907	)		(331,809	)

Standardized measure	$	362,528		$	1,438,945		$	390,939

Pretax Standardized measure (‘‘SEC PV10’’)	$	457,542		$	2,217,825		$	527,184

Changes in Standardized Measure

	December 31,
	1999			2000			2001
	(In thousands)
Standardized measure, beginning of year	$	205,404		$	362,528		$	1,438,945
Revisions:
Prices and costs		188,474			1,026,518			(1,820,512	)
Quantities		3,642			1,927			9,303
Development costs		(3,003	)		(6,170	)		(31,998	)
Accretion of discount		20,540			36,253			143,894
Income taxes		(75,287	)		(683,866	)		720,523
Production rates and other		(6,299	)		2,149			23,470

Net revisions		128,067			376,811			(955,320	)
Extensions, discoveries and additions		64,048			659,094			25,259
Production		(72,234	)		(124,611	)		(172,454	)
Future development costs incurred		21,122			39,996			77,343
Purchases(a)		17,026			128,376			9,241
Sales(b)		(905	)		(3,249	)		(32,075	)

Standardized measure, end of year	$	362,528		$	1,438,945		$	390,939

(a)

“Purchases” includes the present value at the end of the period acquired during the year plus cash flow received on such properties during the period, rather than their estimated present value at the time of the acquisition.

(b)

“Sales” represents the present value at the beginning of the period of properties sold, less the cash flow received on such properties during the period.

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PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. and 2. Financial Statements and Financial Statement Schedules

The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K / A.

3. Exhibits.

The items listed on the accompanying index to exhibits are filed as part of this Annual Report on Form 10-K / A.

(b) Reports on Form 8-K.

No reports on Form 8-K were filed by Registrant during the quarter ended December 31, 2001.

Exhibits required to be filed pursuant to Item 601 of Regulation S-K are contained in Exhibits listed in response to Item 14 (a)3, and are incorporated herein by reference.

2.1		Amended and Restated Agreement and Plan of Merger dated as of January 16, 1996 as amended and restated as of March 20, 1996 (Incorporated by reference to Exhibit 2.1 to Amendment No. 1 to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))

3.1		Certificate of Incorporation (Incorporated herein by reference to the Exhibit 3.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-572))

3.2		Bylaws (Incorporated herein by reference to Exhibit 3.3 to the Company’s Registration Statement on Form S-4 (Registration No. 333-572))

3.3		Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 3.2 of the Company’s Form 8-K filed on May 25, 2001)

3.4		Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation with and into the Company, effective March 21, 1997 (Incorporated herein by reference to Exhibit 4.3 of the Company’s Form 10-Q for the quarter ended March 31, 1997)

4.1		Rights Agreement. (Incorporated herein by reference to Exhibit 3.2 of the Company’s Form 8-K filed on May 25, 2001)

10.1.1		Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 10-Q for the quarter ended June 30, 1999)

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10.1.2		First Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1.2 of the Company’s Form 10-K for the year ended December 31, 1999)

10.1.3		Second Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1.2 of the Company’s Form 10-K for the year ended December 31, 1999)

10.1.4		Third Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 10-Q for the quarter ended June 30, 2000)

10.1.5		Fourth Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1.5 of the Company’s Form 10-K for the year ended December 31, 2000)

10.2		Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 1997. (Incorporated herein by reference to Exhibit 10.3 of the Company’s Form 10-K for the year ended, December 31, 1997)

10.3		Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan for Select Employees as adopted May 1, 1996 and amended as of September 30, 1997 and further amended as of August 1, 2001. (Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 10-Q for the quarter ended September 30, 2001)

10.4.1		Patina Oil & Gas Corporation 1998 Stock Purchase Plan. (Incorporated herein by reference to Exhibit 10.3.3 of the Company’s Form 10-K for the year ended December 31, 1997)

10.4.2		Amendment No. 1 to the Patina Oil & Gas Corporation 1998 Stock Purchase Plan. (Incorporated herein by reference to Exhibit 10.3 of the Company’s Form 10-Q for the quarter ended June 30, 1999)

10.4.3		Patina Oil & Gas Corporation 1996 Employee Stock Option Plan. (Incorporated by reference to Amendment No. 2 to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))

10.4.4		Amendment No. 1 to the 1996 Employee Stock Option Plan of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 10.2 of the Company’s Form 10-Q for the quarter ended June 30, 1999)

10.5		Lease Agreement dated as of December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant. (Incorporated herein by reference to Exhibit 10.5.1 of the Company’s Form 10-K for the year ended December 31, 2000)

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10.6		Employment Agreement dated July 31, 1997 by and between the Company and Thomas J. Edelman. (Incorporated herein by reference to Exhibit 10.7 of the Company’s Form 10-Q for the quarter ended September 30, 1997)

10.7		Standstill Agreement dated April 12, 2000 between the Company and Southwestern Eagle L.L.C. (Incorporated herein by reference to Exhibit 10.1.1 of the Company’s Form 10-Q for the quarter ended March 31, 2000)

10.8		First Amended and Restated Operating Agreement of Elysium Energy, L.L.C., a New York limited liability company, dated November 27, 2000. (Incorporated herein by reference to Exhibit 10.13 of the Company’s Form 10-K for the year ended December 31, 2000)

23.1		Consent of independent auditors. *

Filed herewith

(d) Financial Statement Schedules Required by Regulation S-X.

The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.

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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.

/s/ THOMAS J. EDELMAN Thomas J. Edelman	Chairman and Chairman of the Board (Principal Executive Officer)	October 4, 2002
/s/ JAY W. DECKER Jay W. Decker	President and Director	October 4, 2002
/s/ DAVID J. KORNDER David J. Kornder	Executive Vice President and Chief Financial Officer	October 4, 2002
/s/ ROBERT J. CLARK Robert J. Clark	Director	October 4, 2002
/s/ ELIZABETH K. LANIER Elizabeth K. Lanier	Director	October 4, 2002
/s/ ALEXANDER P. LYNCH Alexander P. Lynch	Director	October 4, 2002
/s/ PAUL M. RADY Paul M. Rady	Director	October 4, 2002

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I, Thomas J. Edelman, certify that:

1. I have reviewed this annual report on Form 10-K/A of Patina Oil & Gas Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.


/s/ THOMAS J. EDELMAN
Thomas J. Edelman, Chief Executive Officer

Date: October 4, 2002

I David J. Kornder, certify that:

1. I have reviewed this annual report on Form 10-K/A of Patina Oil & Gas Corporation;


/s/ DAVID J. KORNDER
David J. Kornder, Chief Financial Officer

Date: October 4, 2002

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