Edgar Filing: PATINA OIL & GAS CORP

Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended September 30, 2003

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

For the transition period from to

Commission file number 1-14344

PATINA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

75-2629477

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)

1625 Broadway		80202
Denver, Colorado		(zip code)
(Address of principal executive offices)

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

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

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

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

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨.

There were 34,121,363 shares of common stock outstanding on October 30, 2003, exclusive of 1,356,154 common shares held in treasury stock.

PART I. FINANCIAL INFORMATION

The financial statements included herein have been prepared in conformity with generally accepted accounting principles. The statements are unaudited but reflect all adjustments, which, in the opinion of management, are necessary to fairly present the Company’s financial position and results of operations. All such adjustments are of a normal recurring nature. 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 May 27, 2003 with a payment date of June 4, 2003.

PATINA OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands except share data)

	December 31, 2002			September 30, 2003
				(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	1,920		$	278
Accounts receivable		33,555			47,183
Inventory and other		5,453			6,029
Deferred income taxes		—			10,822
Unrealized hedging gains		8,294			2,772

		49,222			67,084

Unrealized hedging gains		15,558			3,652

Oil and gas properties, successful efforts method		1,104,205			1,312,066
Accumulated depletion, depreciation and amortization		(466,947	)		(532,351	)

		637,258			779,715

Field equipment and other		12,194			16,351
Accumulated depreciation		(5,087	)		(6,751	)

		7,107			9,600

Other assets		9,945			9,091

	$	719,090		$	869,142

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	41,773		$	43,531
Accrued liabilities		14,298			19,533
Unrealized hedging losses		13,001			31,252

		69,072			94,316

Senior debt		200,000			220,000
Deferred income taxes		96,569			112,178
Other noncurrent liabilities		15,012			43,692
Unrealized hedging losses		1,787			16,197
Deferred compensation liability		38,070			57,316

Commitments and contingencies

Stockholders’ equity
Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued		—			—
Common Stock, $.01 par, 156,250,000 shares authorized, 35,162,233 and 35,346,292 shares issued		352			353
Less Common Stock Held in Treasury, at cost, 1,295,339 and 1,358,154 shares		(6,817	)		(8,709	)
Capital in excess of par value		175,537			173,055
Deferred compensation		—			(861	)
Retained earnings		123,707			187,040
Accumulated other comprehensive income (loss)		5,801			(25,435	)

		298,580			325,443

	$	719,090		$	869,142

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

PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2003		2002		2003
Revenues
Oil and gas sales	$	50,309	$	97,848	$	149,265	$	278,329
Other		1,337		1,332		4,960		3,235

		51,646		99,180		154,225		281,564

Expenses
Lease operating		6,397		14,420		20,133		39,066
Production taxes		2,715		7,155		7,649		20,047
Exploration		1,006		618		1,353		2,788
General and administrative		2,506		4,355		8,552		13,037
Interest and other		525		1,742		1,775		5,843
Deferred compensation adjustment		348		5,966		6,417		15,885
Depletion, depreciation and amortization		16,625		24,571		47,590		68,928

		30,122		58,827		93,469		165,594

Pre-tax income		21,524		40,353		60,756		115,970

Provision for income taxes
Current		2,014		5,750		6,322		16,526
Deferred		5,537		9,584		14,997		27,543

		7,551		15,334		21,319		44,069

Net income before change in accounting principle	$	13,973	$	25,019	$	39,437	$	71,901

Cumulative effect of change in accounting principle		—		—		—		(2,613	)

Net Income	$	13,973	$	25,019	$	39,437	$	69,288

Net income per share before cumulative effect of change in accounting principle
Basic	$	0.42	$	0.74	$	1.21	$	2.12

Diluted	$	0.40	$	0.70	$	1.14	$	2.02

Net loss per share from cumulative effect of change in accounting principle
Basic	$	0.00	$	0.00	$	0.00	$	(0.08	)

Diluted	$	0.00	$	0.00	$	0.00	$	(0.07	)

Net income per share
Basic	$	0.42	$	0.74	$	1.21	$	2.04

Diluted	$	0.40	$	0.70	$	1.14	$	1.95

Weighted average shares outstanding
Basic		33,136		33,907		32,750		34,003

Diluted		34,849		35,686		34,409		35,557

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

PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Preferred Stock Amount		Common Stock					Treasury Stock			Capital in Excess of Par Value			Deferred Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Preferred Stock Amount		Shares		Amount			Treasury Stock			Capital in Excess of Par Value			Deferred Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 2001	$	—	33,191		$	332		$	(5,866	)	$	146,234		$	—		$	71,513		$	37,361		$	249,574
Repurchase of common		—	—			—			—			(9	)		—			—			—			(9	)
Issuance of common stock		—	1,971			20			—			22,996			—			—			—			23,016
Deferred compensation stock issued, net		—	—			—			(951	)		2,820			—			—			—			1,869
Tax benefit from stock options		—	—			—			—			3,496			—			—			—			3,496
Dividends		—	—			—			—			—			—			(5,513	)		—			(5,513	)

Comprehensive income:
Net income		—	—			—			—			—			—			57,707			—			57,707
Contract settlements reclassed to income		—	—			—			—			—			—			—			(11,953	)		(11,953	)
Change in unrealized hedging gains		—	—			—			—			—			—			—			(19,607	)		(19,607	)

Total comprehensive income		—	—			—			—			—			—			57,707			(31,560	)		26,147

Balance, December 31, 2002		—	35,162			352			(6,817	)		175,537			—			123,707			5,801			298,580

Issuance of common stock		—	775			7			—			7,669			(861	)		—			—			6,815
Repurchase of common		—	(591	)		(6	)		—			(17,225	)		—			—			—			(17,231	)
Deferred compensation stock issued, net		—	—			—			(1,892	)		214			—			—			—			(1,678	)
Tax benefit from stock options		—	—			—			—			6,860			—			—			—			6,860
Dividends		—	—			—			—			—			—			(5,955	)		—			(5,955	)

Comprehensive income:
Net income		—	—			—			—			—			—			69,288			—			69,288
Contract settlements reclassed to income		—	—			—			—			—			—			—			22,711			22,711
Change in unrealized hedging gains		—	—			—			—			—			—			—			(53,947	)		(53,947	)

Total comprehensive income		—	—			—			—			—			—			69,288			(31,236	)		38,052

Balance, September 30, 2003	$	—	35,346		$	353		$	(8,709	)	$	173,055		$	(861	)	$	187,040		$	(25,435	)	$	325,443

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

PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2002			2003
Operating activities
Net income	$	39,437		$	69,288
Adjustments to reconcile net income to net cash provided by operations
Cumulative effect of change in accounting principle, net of tax		—			2,613
Exploration expense		1,353			2,788
Depletion, depreciation and amortization		47,590			68,928
Deferred income taxes		14,997			27,543
Tax benefit from stock options		3,496			6,860
Deferred compensation adjustment		6,417			15,885
Loss (gain) on deferred compensation asset		1,297			(1,141	)
Reversal of hedging impairment, net		(3,459	)		—
Other		70			402
Changes in working capital and other assets and liabilities
Decrease (increase) in
Accounts receivable		(513	)		(9,487	)
Inventory and other		(935	)		828
Increase (decrease) in
Accounts payable		6,632			(2,703	)
Accrued liabilities		(4,792	)		833
Other assets and liabilities		(6,732	)		3,912

Net cash provided by operations		104,858			186,549

Investing activities
Development and exploration		(67,895	)		(121,476	)
Acquisitions, net of cash acquired		—			(67,395	)
Disposition of oil and gas properties		2,270			1,719
Other		(2,000	)		(3,523	)

Net cash used by investing		(67,625	)		(190,675	)

Financing activities
Increase (decrease) in indebtedness		(43,000	)		20,000
Loan origination fees		—			(1,074	)
Issuance of common stock		9,821			6,744
Repurchase of common stock		(9	)		(17,231	)
Common dividends		(3,830	)		(5,955	)

Net cash provided (used) by financing		(37,018	)		2,484

Increase (decrease) in cash		215			(1,642	)
Cash and equivalents, beginning of period		250			1,920

Cash and equivalents, end of period	$	465		$	278

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

PATINA OIL & GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) 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 21.9 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 held a 50% interest. Patina invested $21.0 million. In January 2003, the Company purchased the remaining 50% interest in Elysium for $23.1 million, comprised of $16.0 million and the assumption of $7.1 million in debt and other liabilities.

In November 2002, Patina acquired Le Norman Energy Corporation (“Le Norman”) for $62.0 million and the issuance of 256,626 shares of common stock. Le Norman’s properties are located primarily in the Anadarko and Ardmore-Marietta Basins of Oklahoma and primarily produce oil. The acquisition also included a 30% reversionary interest in LNP. See Note (3).

In December 2002, Patina acquired Bravo Natural Resources, Inc. (“Bravo”) for $119.0 million. Bravo’s properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western Oklahoma, within the Anadarko Basin and primarily produce gas. See Note (3).

In March 2003, Patina acquired the remaining 70% interest in Le Norman Partners (“LNP”) for $39.7 million, comprised of $18.5 million and the assumption of $21.2 million of debt and other liabilities. LNP’s properties are located in Stephens, Garvin, and Carter Counties of southern Oklahoma and primarily produce oil.

In October 2003, the Company acquired Cordillera Energy Partners, L.L.C. (the “Cordillera Acquisition”) for $244.5 million, comprised of $240.5 million of cash funded with borrowings under the Company’s bank facility and the issuance of five year warrants to purchase 500,000 shares of Patina common stock for $45.00 per share. The Cordillera properties are primarily located in the Mid Continent, the San Juan Basin, and the Permian Basin and primarily produce gas. See Note (12).

The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Prior to the purchase of the remaining 50% interest in Elysium in January 2003, Patina’s 50% interest in Elysium’s assets, liabilities, revenues and expenses were included in the accounts of the Company on a proportionate consolidation basis. 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 two years, the Company accumulated acreage positions in three Rocky Mountain basins and a small producing field in West Texas in efforts to expand and diversify through grassroots projects (“Grassroots Projects”). Through Le Norman, LNP and Bravo (collectively, “Mid Continent”) and Elysium and the Grassroots Projects (collectively, “Other”), the Company currently has oil and gas properties in central Kansas, the Illinois Basin, Utah, Texas, and Oklahoma. At October 1, 2003, inclusive of the Cordillera Acquisition (see Note 12), Wattenberg accounted for approximately 61%, Mid Continent for 26%, San Juan for 3% and Other for 10% of daily oil and gas production on an equivalent basis.

(2) 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.

The Company follows the provisions of Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 their undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined using discounted future cash flows on a field-by field basis. While no impairments have been necessary since 1997, changes in oil and gas prices, underlying assumptions including development costs, lease operating expenses, production rates, production taxes or oil and gas reserves could result in impairments in the future.

Asset Retirement Costs and Obligations

The Company adopted the provision of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS No. 143”) on January 1, 2003. This statement 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 asset. The asset retirement liability is allocated to operating expense by using a systematic and rational method.

Upon adoption of the statement, the Company recorded an asset retirement obligation of approximately $21.4 million to reflect the Company’s estimated obligations related to the future plugging and abandonment of the Company’s wells. In addition, the Company recorded an addition to oil and gas properties of approximately $17.2 million for the related asset retirement costs, and recorded a one-time, non-cash charge of approximately $2.6 million (net of $1.6 million of deferred taxes) for the cumulative effect of change in accounting principle. At September 30, 2003 an asset retirement obligation of $24.8 million is recorded in Other noncurrent liabilities. This statement would not have had a material impact on the three or nine-month periods ended September 30, 2002 assuming adoption on a pro forma basis.

Field Equipment and Other

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

Other Assets

At December 31, 2002, the balance represented $5.3 million in assets held in a deferred compensation plan and $4.6 million representing the value assigned for the 30% reversionary interest in Le Norman Partners which the Company acquired in conjunction with the Le Norman acquisition. This amount was recorded in oil and gas properties in conjunction with the acquisition of the remaining 70% interest in LNP. At September 30, 2003, the balance primarily represented $8.1 million in assets held in a deferred compensation plan and $671,000 in unamortized loan origination costs. See Notes (3) and (7).

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, 2002 and September 30, 2003 were insignificant.

Accumulated Other Comprehensive Income (Loss)

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 (loss) and related tax effects for the nine months ended September 30, 2003 were as follows (in thousands):

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income – 12/31/02	$	9,064		$	(3,263	)	$	5,801
Change in fair value of hedges		(86,719	)		32,772			(53,947	)
Contract settlements during the nine months		36,631			(13,920	)		22,711

Accumulated other comprehensive loss – 09/30/03	$	(41,024	)	$	15,589		$	(25,435	)

Comprehensive income for the three months ended September 30, 2002 and 2003 totaled $14.4 million and $37.8 million, respectively. Comprehensive income for the nine months ended September 30, 2002 and 2003 totaled $15.9 million and $38.1 million, respectively.

Financial Instruments

The book value and estimated fair value of cash and equivalents was $1.9 million and $278,000 at December 31, 2002 and September 30, 2003, respectively. The book value and estimated fair value of the bank debt was $200.0 million and $220.0 million at December 31, 2002 and September 30, 2003, respectively. The book value of these assets and liabilities approximates fair value due to their short maturity or floating rate structure.

Derivative Instruments and Hedging Activities

The Company regularly enters into commodity derivative contracts and fixed-price physical contracts to help 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 for the first nine months of 2002 and 2003, recognizing losses of $1.4 million and $17.5 million, respectively, related to these contracts. The Company entered into various swap contracts for natural gas based on the Colorado Interstate Gas (“CIG”) and ANR Pipeline Oklahoma (“ANR”) indexes during the first nine months of 2002 and 2003, recognizing a gain of $21.2 million and a loss of $22.2 million, respectively, related to these contracts.

At September 30, 2003, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 13,100 barrels of oil per day for the remainder of 2003 at fixed prices ranging from $22.31 to $31.10 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.91 per barrel for the remainder of 2003. The Company also entered into swap contracts for oil for 2004 and 2005 as of September 30, 2003, which are summarized in the table below. The net unrealized losses on these contracts totaled $17.6 million based on NYMEX futures prices at September 30, 2003.

At September 30, 2003, the Company was a party to swap contracts for natural gas based on CIG, El Paso San Juan (“EPSJ”), ANR and Panhandle Eastern Pipeline (“PEPL”) index prices covering approximately 115,200 MMBtu’s per day for the remainder of 2003 at fixed prices ranging from $2.87 to $5.49 per MMBtu. The overall weighted average hedged price for the swap contracts is $3.83 per MMBtu for the remainder of 2003. The Company also entered into natural gas swap contracts for 2004 and 2005 as of September 30, 2003, which are summarized in the tables below. The net unrealized losses on these contracts totaled $23.4 million based on futures prices at September 30, 2003.

At September 30, 2003, the Company was a party to the fixed price swaps summarized below:

	Oil Swaps (NYMEX)				Natural Gas Swaps (CIG Index)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
10/01/03 - 12/31/03	13,100	24.91	(4,525	)	86,700	3.60	(5,455	)

01/01/04 - 03/31/04	13,450	25.44	(2,666	)	95,000	4.23	(3,713	)
04/01/04 - 06/30/04	14,350	24.93	(2,449	)	85,000	3.56	(2,724	)
07/01/04 - 09/30/04	12,750	24.33	(2,244	)	75,000	3.49	(3,164	)
10/01/04 - 12/31/04	12,850	24.12	(2,013	)	65,000	3.83	(2,111	)

2005	8,000	23.95	(3,702	)	55,000	3.65	(4,826	)

	Natural Gas Swaps (ANR/PEPL Indexes)				Natural Gas Swaps (EPSJ Index)
Time Period	Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
10/01/03 - 12/31/03	24,500	4.48	(295	)	4,000	4.65	136

01/01/04 - 03/31/04	27,700	4.84	(373	)	5,400	4.87	94
04/01/04 - 06/30/04	28,800	4.31	(545	)	6,300	4.18	49
07/01/04 - 09/30/04	30,000	4.28	(648	)	7,400	4.15	43
10/01/04 - 12/31/04	30,100	4.49	(462	)	7,900	4.34	67

2005	20,000	4.51	469		3,500	4.06	32

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.

During the first nine months of 2003, net hedging losses of $36.6 million ($22.7 million after tax) were reclassified from Accumulated other comprehensive loss to earnings and the changes in the fair value of outstanding derivative net liabilities increased by $86.7 million ($53.9 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 the first nine months of 2003.

As of September 30, 2003, the Company had net unrealized hedging losses of $41.0 million ($25.4 million after tax), comprised of $2.8 million of current assets, $3.7 million of non-current assets, $31.3 million of current liabilities and $16.2 million of non-current liabilities. Based on estimated futures prices as of September 30, 2003, the Company would reclassify as a decrease to earnings during the next twelve months $28.5 million ($17.7 million after tax) of net unrealized hedging losses from Accumulated other comprehensive loss.

Stock Options and Deferred Compensation Plans

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. See Note (7). The Company accounts for assets held in a deferred compensation plan in accordance with EITF 97-14. See Note (7).

Per Share Data

In June 2002, the Company declared a 5-for-4 stock split which was effected in the form of a 25% stock dividend to common stockholders. In June 2003, the Company declared another 5-for-4 stock split which was effected in the form of a 25% stock dividend to common stockholders. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock splits.

The Company uses weighted average shares outstanding in calculating earnings per share. When dilutive, options 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.

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 prior to the purchase of the remaining 50% interest in Elysium in January 2003, 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 United 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. In the opinion of management, those adjustments to the financial statements (all of which are of a normal and recurring nature) necessary to present fairly the Company’s financial position and results of operations have been made. These interim financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

Recent Accounting Pronouncements

In July 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 146, “Accounting for Costs Associated With Exit or Disposal Activities,” which provides guidance for financial accounting and reporting of costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This statement requires the recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. The statement was effective for the Company in 2003. The adoption of SFAS No. 146 did not have a material effect on the Company’s financial position or results of operations.

In November 2002, the FASB issued Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this Statement did not have a material impact on the Company’s financial position or results of operations.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of SFAS No. 123.” SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. SFAS No. 148 was effective for the Company’s year ended December 31, 2002. The adoption of this pronouncement did not have an impact on the Company’s financial condition or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of this pronouncement did not have an impact on the Company’s financial condition or results of operations.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer measures certain financial instruments with characteristics of both liabilities and equity and requires that an issuer classify a financial instrument within its scope as a liability (or asset in some circumstances). SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003 and otherwise was effective and adopted by the Company on July 1, 2003. As the Company has no such instruments, the adoption of this statement did not have an impact on the Company’s financial condition or results of operations.

The FASB is currently evaluating the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No.142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other oil and gas property costs, and provide specific footnote disclosures.

Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, approximately $291.5 million of the Company’s oil and gas property acquisition costs may be required to be separately classified on its balance sheets as intangible assets. However, the Company currently believes that its results of operations and financial condition would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company does not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on the Company’s compliance with covenants under its debt agreements.

(3) ACQUISITIONS

On November 5, 2002, Patina acquired the stock of Le Norman Energy Corporation (“Le Norman” or the “Le Norman Acquisition”) for $62.0 million and the issuance of 256,600 shares of common stock. Le Norman’s properties are located primarily in the Anadarko and Ardmore-Marietta Basins of Oklahoma. The Le Norman properties primarily produce oil.

On December 6, 2002, Patina acquired the stock of Bravo Natural Resources, Inc. (“Bravo” or the “Bravo Acquisition”), for $119.0 million. Bravo’s properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western Oklahoma, within the Anadarko Basin. The Bravo properties primarily produce gas.

As these acquisitions were recorded using the purchase method of accounting, the results of operations from the acquisitions are included in the results of the Company from the respective acquisition dates. The table below summarizes the preliminary allocation of the purchase price of each transaction based upon the acquisition date fair values of the assets acquired and the liabilities assumed (in thousands):

	Le Norman			Bravo
Purchase Price:
Cash paid	$	62,023		$	118,974
Stock issued		5,779			—

Total	$	67,802		$	118,974

Allocation of Purchase Price:
Working capital	$	215		$	(1,784	)
Oil and gas properties		66,805			159,913
Other non-current assets		5,271			2,622
Deferred income taxes		(4,489	)		(40,653	)
Other non-current liabilities		—			(1,124	)

Total	$	67,802		$	118,974

The following table reflects the unaudited pro forma results of operations for the three and nine-month periods ended September 30, 2002 as though the acquisitions had occurred on January 1, 2002 (in thousands, except per share amounts):

Three months ended September 30, 2002	Historical Patina		Pro Forma			Pro Forma Consolidated
Three months ended September 30, 2002	Historical Patina		Le Norman	Bravo		Pro Forma Consolidated
Revenues	$	51,646	$5,647	$	4,130	$	61,423
Net income		13,973	642		531		15,146
Net income per share – basic		0.42					0.45
Net income per share – diluted		0.40					0.43

	Historical Patina		Pro Forma			Pro Forma Consolidated
Nine months ended September 30, 2002	Historical Patina		Le Norman		Bravo	Pro Forma Consolidated
Revenues	$	154,225	$	13,300	13,128	$	180,653
Net income		39,437		88	1,056		40,581
Net income per share – basic		1.21					1.23
Net income per share – diluted		1.14					1.17

The pro forma amounts above are presented for information purposes only and are not necessarily indicative of the results that would have occurred had the acquisitions been consummated on January 1, 2002, nor are the pro forma amounts necessarily indicative of future results.

(4) OIL AND GAS PROPERTIES

The cost of oil and gas properties at December 31, 2002 and September 30, 2003 included $10.3 million and $4.3 million, respectively, in net unevaluated leasehold and property costs to which proved reserves have not been assigned. These amounts have been excluded from amortization during the respective period. The following table sets forth costs incurred related to oil and gas properties:

	Year Ended December 31, 2002			Nine Months Ended September 30, 2003
	(In thousands)
Development	$	97,428		$	118,688
Acquisition - evaluated		182,008			66,331
Acquisition - unevaluated		500			1,064
Exploration and other		2,171			2,788

	$	282,107		$	188,871

Disposition	$	(2,303	)	$	(1,719	)

Depletion rate (per Mcfe)	$	0.93		$	0.93

In conjunction with the Le Norman and Bravo acquisitions, the Company recorded additions to oil and gas properties of $4.5 million and $40.7 million, respectively, as a result of the deferred tax liability for the difference between the tax basis of the properties acquired and the book basis attributed to the properties under the purchase method of accounting. See Note (3). In conjunction with the acquisition of the remaining 70% interest in LNP, $4.6 million representing the value assigned for the 30% reversionary interest in LNP which the Company acquired in conjunction with the Le Norman acquisition was recorded in oil and gas properties. During the third quarter of 2003, the Company exchanged its interests in the Wyoming grassroots project for certain oil and gas properties in Wattenberg. No gain or loss was recognized on the exchange.

During the first quarter of 2003, the Company recorded an addition to oil and gas properties of approximately $17.2 million for the asset retirement costs related to the adoption of SFAS No. 143. During the second and third quarters of 2003, additions to oil and gas properties of approximately $252,000 were recorded for the estimated asset retirement costs related to new wells drilled.

(5) INDEBTEDNESS

The following indebtedness was outstanding on the respective dates:

	December 31, 2002		September 30, 2003
	(In thousands)
Bank facility - Patina	$	193,000	$	220,000
Bank facility – Elysium, net		7,000		—
Less current portion		—		—

Bank debt, net	$	200,000	$	220,000

In January 2003, the Company entered into an Amended Bank Credit Agreement (the “Credit Agreement”). The Credit Agreement is a revolving credit facility for up to $500.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $300.0 million at September 30, 2003. Patina had $80.0 million available under the Credit Agreement at September 30, 2003. On October 1, 2003, in conjunction with the Cordillera Acquisition (see Note 12), the Credit Agreement was amended, increasing the amount available under the facility to $500.0 million. Subsequent to the closing of the Cordillera transaction, the Company had $456.0 million outstanding on October 1, 2003 under the facility.

The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the LIBOR rate for one, two, three or six months plus a margin which fluctuates from 1.25% to 1.90%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility was 2.6% during the first nine months of 2003 and 2.4% at September 30, 2003.

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. At December 31, 2002 and September 30, 2003, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in January 2007, but may be prepaid at anytime. The Company had a restricted payment basket under the Credit Agreement of $50.0 million as of September 30, 2003, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

In May 2001, Elysium entered into a bank credit agreement. In January 2003, the Elysium facility was terminated in conjunction with the closing of the acquisition by the Company of the remaining 50% interest in Elysium.

In October 2003, the Company entered into interest rate swaps effective November 1, 2003 for one-year and two-year periods. Each contract is for $100.0 million principal with a fixed interest rate of 1.26% on the one-year term and 1.83% on the two-year term, respectively, payable by the Company and the variable interest rate, the three-month LIBOR, payable by the third party. The difference between the Company’s fixed rates of 1.26% and 1.83% and the three-month LIBOR rate, which is reset every 90 days, is received or paid every 90 days in arrears.

Scheduled maturities of indebtedness for the next five years are zero in 2003, 2004, 2005, 2006 and $220.0 million in 2007. 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 $1.5 million and $4.4 million during the first nine months of 2002 and 2003, respectively.

(6) STOCKHOLDERS’ EQUITY

A total of 156.3 million common shares, $0.01 par value, are authorized of which 35.3 million were issued at September 30, 2003. The common stock is listed on the New York Stock Exchange. In June 2002, a 5-for-4 stock split was effected in the form of a 25% stock dividend to common stockholders. In June 2003, another 5-for-4 stock split was affected in the form of a 25% stock dividend to common stockholders. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock splits. 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 outstanding shares of common stock since January 1, 2002:

	Year Ended December 31, 2002		Nine Months Ended September 30, 2003
Beginning shares	33,190,500		35,162,200

Exercise of stock options	1,262,500		701,500
Issued under Stock Purchase Plan	278,800		—
Issued in lieu of salaries and bonuses	123,000		71,100
Issued for directors fees	2,900		2,300
Issued for Le Norman acquisition	256,600		—
Issued to deferred comp plan (salary match)	18,000		—
Contributed to 401(k) plan	30,200		—

Total shares issued	1,972,000		774,900

Repurchases	(300	)	(590,800	)

Ending shares	35,162,200		35,346,300

Treasury shares held in rabbi trust (Note 7)	(1,295,300	)	(1,358,200	)

Adjusted shares outstanding	33,866,900		33,988,100

Adjusted for the stock dividends, following is a schedule of quarterly cash dividends paid on the common stock since the dividend was initiated in December 1997:

	Quarter
	First		Second		Third		Fourth		Total
1997	$	—	$	—	$	—	$	0.0064	$	0.0064
1998		0.0064		0.0064		0.0064		0.0064		0.0256
1999		0.0064		0.0064		0.0064		0.0128		0.0320
2000		0.0128		0.0128		0.0128		0.0256		0.0640
2001		0.0256		0.0256		0.0256		0.0320		0.1088
2002		0.0320		0.0400		0.0400		0.0480		0.1600
2003 YTD		0.0480		0.0600		0.0600		—		0.1680

During the first nine months of 2003, the Company repurchased and retired 590,800 shares of common stock for $17.2 million.

A total of 5,000,000 preferred shares, $0.01 par value, are authorized with no shares issued or outstanding at December 31, 2002 and September 30, 2003.

In September 2003, the Compensation Committee of the Board of Directors awarded a restricted stock grant of 23,750 shares of common stock to the officers and directors of the Company in lieu of the suspended Stock Purchase Plan (see Note 7). The shares vest 30% in May 2004, 30% in May 2005 and 40% in May 2006. The non-vested shares have been recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets.

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):

	Three Months Ended September 30,
	2002					2003
	Net Income		Common Shares	Per Share		Net Income		Common Shares	Per Share
Basic net income attributable to common stock	$	13,973	33,136	$	0.42	$	25,019	33,907	$	0.74


Effect of dilutive securities:
Stock options		—	1,713				—	1,779

Diluted net income attributable to common stock	$	13,973	34,849	$	0.40	$	25,019	35,686	$	0.70

	Nine Months Ended September 30,
	2002					2003
	Net Income		Common Shares	Per Share		Net Income		Common Shares	Per Share
Basic net income attributable to common stock	$	39,437	32,750	$	1.21	$	69,288	34,003	$	2.04


Effect of dilutive securities:
Stock options		—	1,659				—	1,554

Diluted net income attributable to common stock	$	39,437	34,409	$	1.14	$	69,288	35,557	$	1.95

At September 30, 2003, all stock options were included in the computation of diluted earnings per share because they were all dilutive.

(7) EMPLOYEE BENEFIT PLANS

401(k) Plan

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 $647,000 and $801,000 for 2001 and 2002, respectively. The contributions were made in common stock. A total of 37,800 and 30,200 common shares were contributed in 2001 and 2002, 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 were granted the right 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 781,250 shares of common stock are reserved for possible purchase under 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 781,250 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 2002, the Board of Directors approved 221,000 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, 2002, participants had purchased 279,000 shares of common stock at an average price of $23.85 per share ($17.89 net price per share), resulting in cash proceeds to the Company of $5.0 million. The Company recorded non-cash general and administrative expenses of $1.7 million associated with these purchases for 2002. The Stock Purchase Plan was suspended as of December 31, 2002.

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, may be 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 September 30, 2003, the value of the assets in the Trust totaled $57.3 million, including 1,358,200 shares of common stock of the Company valued at $49.2 million. The Company accounts for the Deferred Compensation Plan in accordance with Emerging Issues Task Force (“EITF”) Abstract 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 sheets. 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, 2002 and September 30, 2003 was $5.3 million and $8.1 million, respectively, and is classified as Other Assets in the accompanying balance sheets. The amounts payable to the plan participants at December 31, 2002 and September 30, 2003, including the market value of the shares of the Company’s common stock that are reflected as treasury stock, was $38.1 million and $57.3 million, respectively, and is classified as Deferred Compensation Liability in the accompanying balance sheets. Approximately 1,139,700 shares or 84% of the Company common stock held in the Plan are attributable to the Chief Executive Officer at September 30, 2003.

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 statements. In response to the changes in total market value of the Trust, the Company recorded deferred compensation adjustments of $6.4 million and $15.9 million in the first nine months of 2002 and 2003, respectively.

Stock Option 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 4.7 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	Range of Exercise Prices		Weighted Average Exercise Price
2001	990,000	$	14.47 – $21.14	$	14.66
2002	1,153,000	$	16.50 – $25.33	$	16.82
2003	1,061,000	$	27.18 – $34.25	$	27.23

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 an annual retainer of $20,000, an attendance fee of $5,000 for each meeting of the Board of Directors, and a $1,000 fee for attendance of each meeting of a committee of the Board of Directors. The total quarterly director fee, including retainer, attendance and committees fees is payable quarterly with common shares having a market value equal to one-half of their quarterly fee and the remainder in cash. A total of 2,900 shares were issued in 2002 and 2,300 in the first nine months of 2003. It also provides for 7,800 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	Range of Exercise Prices		Weighted Average Exercise Price
2001	39,000	$	15.74 – $21.02	$	19.97
2002	39,000	$	22.60 – $25.60	$	23.20
2003	39,000		$30.78	$	30.78

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 for the three and nine month periods ended September 30, 2002 and 2003, respectively:

		Three Months Ended September 30,				Nine Months Ended September 30,
		2002		2003		2002		2003
Net income	As Reported	$	13,973	$	25,019	$	39,437	$	69,288
	Pro forma		13,159		23,895		37,186		66,255
Basic net income per common share	As Reported	$	0.42	$	0.74	$	1.21	$	2.04
	Pro forma		0.40		0.70		1.14		1.95
Diluted net income per common share	As Reported	$	0.40	$	0.70	$	1.14	$	1.95
	Pro forma		0.38		0.67		1.08		1.86

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 for the three months ended September 30, 2002 and 2003: dividend yield of 0.8% and 0.8%; expected volatility of 46% and 44%; risk-free interest rate of 4.2% and 3.5%; and expected life of 3.8 years and 4.0 years, respectively. The following weighted-average assumptions were used for grants for the first nine months of 2002 and 2003: dividend yield of 0.8% and 0.7%; expected volatility of 46% and 45%; risk-free interest rate of 4.2% and 2.7%; and expected life of 3.8 years and 3.7 years, respectively.

(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 nine months ended September 30, 2002 and 2003 follows:

	2002		2003
Federal statutory rate	35	%	35	%
State income tax rate, net of federal benefit	3	%	3	%
Section 29 tax credits and other	(3	)%	—

Effective income tax rate	35	%	38	%

Current income tax expense in the nine months ended September 30, 2002 and 2003 totaled $6.3 million and $16.5 million, respectively. The Company utilized approximately $13.6 million of net operating loss carryforwards to reduce its 2002 tax liability.

For tax purposes, the Company had net operating loss carryforwards of approximately $66.1 million at December 31, 2002. Utilization of these losses will be limited to a maximum of approximately $9.8 million per year as a result of the Le Norman, Bravo and earlier acquisitions. These carryforwards expire from 2005 through 2021. The Company has provided a valuation allowance of $3.6 million against the loss carryforwards that could expire unutilized. At December 31, 2002, the Company had AMT credit carryforwards of approximately $14.1 million that are available indefinitely. In addition, at December 31, 2002, the Company had depletion deduction carryforwards of approximately $10.1 million that are available indefinitely. The Company paid $2.7 million and $12.0 million in federal and state income taxes during the nine months ended September 30, 2002 and 2003, respectively.

Net cash provided by operations in the first nine months of 2002 and 2003 were increased by $3.5 million and $6.9 million, respectively, related to the tax deduction generated from the exercise and same day sale of stock options. Generally accepted accounting principles do not allow for this deduction to be offset against the tax provision on the income statement. This deduction is recorded as an addition to additional paid in capital and as a reduction to the tax liability on the balance sheet.

(9) MAJOR CUSTOMERS

During the nine months ended, September 30, 2002 and 2003, Duke Energy Field Services, Inc. accounted for 37% and 23%, BP Amoco Production Company accounted for 8% and 15%, and Conoco accounted for 9% and 10%, of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2002 totaled $15.2 million. 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

Patina provided certain administrative services to Elysium under an operating agreement. The Company was paid $2.2 million for these services in the first nine months of 2002. As the Company purchased the remaining 50% interest in Elysium in January 2003, there were no indirect monthly reimbursements during the nine months ended September 30, 2003.

(11) COMMITMENTS AND CONTINGENCIES

The Company leases office space and certain equipment under non-cancelable operating leases. In the third quarter of 2003, the Company entered into a firm transportation agreement for 4,773 MMBtu’s per day on a pipeline from central Wyoming to the Oklahoma panhandle. The term of the agreement is through February 2024, with a fixed fee of $0.334 per MMBtu. Future minimum lease payments under such leases and agreements approximate $1.7 million per year from 2003 through 2007 and approximately $600,000 per year from 2008 to 2023.

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 limiting the deductibility of certain post-production costs to be borne by royalty interest owners has resulted in uncertainty of these deductions insofar as they relate to the Company’s Colorado operations. The Company has been named as a party to a related lawsuit which plaintiff seeks to certify as a class action. The Company filed a response to the lawsuit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued for this matter in the Company’s financial statements.

(12) SUBSEQUENT EVENTS

On August 25, 2003, the Company executed a purchase and sale agreement to acquire Cordillera Energy Partners, L.L.C. (the “Cordillera Acquisition”) for $244.5 million, comprised of $240.5 million of cash funded with borrowings under the Company’s bank facility and the issuance of five year warrants to purchase 500,000 shares of Patina common stock for $45.00 per share. The transaction closed on October 1, 2003. The Cordillera properties are primarily located in the Mid Continent, the San Juan Basin, and the Permian Basin and primarily produce gas.

In conjunction with the closing of the Cordillera Acquisition, the Company’s credit facility was amended to increase the borrowing base from $300.0 million to $500.0 million effective October 1, 2003. Subsequent to the closing of the Cordillera Acquisition, the outstanding balance under the credit facility rose to $456.0 million on October 1, 2003.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 help 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, all of the Company’s oil and gas swap contracts are designated as cash flow hedges.

Factors Affecting Financial Condition and Liquidity

Liquidity and Capital Resources

During the nine months ended September 30, 2003, $118.7 was spent million on the further development of properties and $67.4 million on acquisitions. Acquisition expenditures included $23.1 million and $39.7 million on the Elysium and the Le Norman Partners purchases, respectively. Development expenditures included $65.8 million in Wattenberg for the drilling or deepening of 37 J-Sand wells, the drilling of 25 Codell wells, and performing 322 Codell refracs, 28 Codell trifracs and 12 recompletions, $36.2 million on the further development of the Mid Continent (Le Norman, Le Norman Partners and Bravo properties) for the drilling or deepening of 143 wells, and performing four refracs and four recompletions, and $16.7 million on other properties (primarily in Illinois and Kansas), primarily for drilling or deepening 60 wells and performing 71 recompletions. These acquisitions and projects, and the continued success in production enhancement allowed production to increase 43% over the prior year period. On October 1, 2003, the Company expended $244.5 million on the Cordillera Acquisition. The Cordillera properties are primarily located in the Mid Continent, the San Juan Basin, and the Permian Basin and primarily produce gas. The Company anticipates incurring approximately $165.0 million on the further development of its properties during 2003. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.

At September 30, 2003, the Company had $869.1 million of assets. Total capitalization was $545.4 million, of which 60% was represented by stockholders’ equity and 40% by bank debt. During the first nine months of 2003, net cash provided by operations totaled $186.5 million, as compared to $104.9 million in 2002 ($193.2 million and $111.2 million prior to changes in working capital, respectively). At September 30, 2003, there were no significant commitments for capital expenditures other than the Cordillera Acquisition which closed in October 2003. Based upon a $165.0 million capital budget for 2003 and the Cordillera Acquisition, the Company expects production to continue to increase for the remainder of the 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.

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 September 30, 2003 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	$	—	$	—	$	220,000	$	220,000
Firm transportation agreement		582		1,164		10,085		11,831
Non-cancelable operating leases		1,100		2,295		683		4,078

Total contractual cash obligations	$	1,682	$	3,459	$	230,768	$	235,909

Banking

The following summarizes the Company’s borrowings and availability under its revolving credit facility (in thousands):

	September 30, 2003
	Borrowing Base		Outstanding		Available
Revolving Credit Facility	$	300,000	$	220,000	$	80,000

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 hedging agreements for the remainder of 2003, 2004 and 2005. The $118.7 million of development expenditures for the first nine months of 2003 was funded entirely with internal cash flow. The 2003 development capital budget of $165.0 million is comprised primarily of $89.0 million of development expenditures in Wattenberg, $56.0 million in the Mid Continent region, and $18.0 million on the other properties (primarily Illinois and Kansas), and is expected to increase production by over 40%. The budgeted capital and production growth estimates include capital for the Elysium properties acquired in January 2003, the LNP properties acquired in March 2003 and the Cordillera properties acquired in October 2003. The purchase price for the Elysium acquisition was $23.1 million and the purchase price for the LNP properties was $39.7 million. On October 1, 2003, the Company acquired the Cordillera properties for $244.5 million, comprised of $240.5 million of cash funded with borrowings under the Company’s bank facility and the issuance of five year warrants to purchase 500,000 shares of Patina common stock for $45.00 per share. On October 1, 2003, the Company had $456.0 million outstanding under its bank facility. As such, exclusive of any other acquisitions or significant equity repurchases and after the Cordillera Acquisition on October 1, 2003, management expects to reduce long-term debt and fund the remaining 2003 development program with internal cash flow. Based upon a preliminary capital development budget of approximately $200.0 million, production is expected to increase over 15% in 2004.

Net cash provided by operating activities in the nine months ended September 30, 2002 and 2003 was $104.9 million and $186.5 million, respectively. Cash flow from operations increased in 2003 due to the 43% increase in oil and gas equivalent production and the 31% increase in average oil and gas prices. Lease operating expenses, production taxes, general and administrative expenses and interest expense all increased as a result of the acquisitions made in the fourth quarter of 2002 (Le Norman and Bravo) and the first quarter of 2003 (Elysium and Le Norman Partners). Operating cash flows in the first nine months of 2002 and 2003 were benefited by $3.5 million and $6.9 million, respectively, related to the tax deduction generated from the exercise and same day sale of stock options.

Net cash used in investing activities in the nine months ended September 30, 2002 and 2003 totaled $67.6 million and $190.7 million, respectively. Acquisition, development and exploration expenditures totaled $188.9 million in the first nine months of 2003 compared to $67.9 million in 2002. The increase in expenditures in the first nine months of 2003 was primarily due to incurring $62.8 million of acquisition costs related to Elysium and Le Norman Partners acquisitions and the $36.2 million of development expenditures spent on the Mid Continent properties acquired in the fourth quarter of 2002. Development expenditures in Wattenberg increased to $65.8 million in the first nine months of 2003 as compared to $59.6 million in the first nine months of 2002.

Net cash used in financing activities in the nine months ended September 30, 2002 totaled $37.0 million, while net cash provided by financing activities in the nine months ended September 30, 2003 totaled $2.5 million. Sources of financing have been primarily bank borrowings. During the first nine months of 2002, the combination of operating cash flow and $9.8 million in proceeds from the exercise of stock options, allowed the Company to repay $43.0 million of bank debt, fund net capital development and acquisition expenditures of $65.6 million and pay common stock dividends of $3.8 million. During the first nine months of 2003, the combination of operating cash flow, bank borrowings of $20.0 million and $6.7 million in proceeds from the exercise of stock options, allowed the Company to fund net capital development and acquisition expenditures of $187.2 million, buy back $17.2 million in common stock and pay common stock dividends of $6.0 million.

Capital Requirements

During the first nine months of 2003, $190.7 million of capital was expended, including $118.7 million on development projects and $67.4 million on acquisitions. Development expenditures represented approximately 62% of internal cash flow (defined as net cash provided by operations before changes in working capital). The Company manages its capital budget with the goal of funding it with internal cash flow. The 2003 development capital budget of $165.0 million combined with the benefits of the acquisitions made in the fourth quarter of 2002 (LEC and Bravo), the first quarter of 2003 (Elysium and LNP) and the Cordillera Acquisition in fourth quarter of 2003, is expected to increase production by over 40%. The purchase price for the Elysium acquisition was $23.1 million and the purchase price for the LNP properties was $39.7 million. On October 1, 2003, the Company acquired the Cordillera properties for $244.5 million, comprised of $240.5 million of cash funded with borrowings under the Company’s bank facility and the issuance of five year warrants to purchase 500,000 shares of Patina common stock for $45.00 per share. As such, exclusive of any other acquisitions or significant equity repurchases and after the Cordillera Acquisition on October 1, 2003, management expects to reduce long-term debt and fund the remaining 2003 development program with internal cash flow. 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. Based upon a preliminary capital development budget of approximately $200.0 million, production is expected to increase over 15% in 2004.

Hedging

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 twenty-four month basis. At September 30, 2003, hedges were in place covering 81.7 Bcf at prices averaging $3.94 per MMBtu and 9.0 million barrels of oil averaging $24.49 per barrel. The estimated fair value of the Company’s hedge contracts that would be realized on termination, approximated a net unrealized pre-tax loss of $41.0 million ($25.4 million loss net of $15.6 million of deferred taxes) at September 30, 2003, which is presented on the balance sheet as a current asset of $2.8 million, a non-current asset of $3.7 million, a current liability of $31.3 million, and a non-current liability of $16.2 million based on contract expiration. The oil and gas contracts expire monthly through December 2005. 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, ANR Pipeline Oklahoma (“ANR”) index, Panhandle Eastern Pipeline (“PEPL”) index and El Paso San Juan (“EPSJ”) 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 realized pre-tax gains relating to these derivatives were $19.8 million in the nine months ended September 30, 2002 and net realized pre-tax hedging losses were $39.7 million in the nine months ended September 30, 2003. 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, CIG, ANR, PEPL or EPSJ 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 2002 and 2003. 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
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
2002		25.71		2.23		2.81

Quarterly

2002
First	$	21.02	$	2.06	$	2.45
Second		25.72		2.25		2.81
Third		27.74		1.74		2.53
Fourth		27.51		2.80		3.34

2003
First	$	33.33	$	4.26	$	4.69
Second		28.18		4.02		4.27
Third		29.40		4.27		4.49

Results of Operations

Three months ended September 30, 2003 compared to the three months ended September 30, 2002.

Revenues for the third quarter of 2003 totaled $99.2 million, a 92% increase from the prior year period. Net income for the third quarter of 2003 totaled $25.0 million compared to $14.0 million in 2002. The increases in revenue and net income were due to higher oil and gas prices and production.

Average daily oil and gas production in the third quarter of 2003 totaled 15,777 barrels and 179.9 MMcf (274.5 MMcfe), an increase of 45% on an equivalent basis from the same period in 2002. The rise in production was due to the continued development activity in Wattenberg, the benefits of the Le Norman and Bravo acquisitions made in the fourth quarter of 2002, and the Elysium and LNP acquisitions made in the first quarter of 2003, respectively. During the third quarter of 2003, the Company drilled or deepened 20 wells, performed 84 refracs, 14 trifracs and four recompletions in Wattenberg, compared to 20 new wells or deepenings, 112 refracs and four recompletions in Wattenberg in 2002. During the third quarter of 2003, the Company drilled or deepened 61 wells and performed 30 recompletions on its Mid Continent and other properties, compared to 24 new drills or deepenings and 17 recompletions in 2002. Based upon a $165.0 million development budget for 2003 combined with the benefits of the acquisitions made in the fourth quarter of 2002 and the first quarter of 2003 and the recent Cordillera Acquisition in the fourth quarter of 2003, the Company expects production to increase over 40% from 2002. The following table sets forth summary information with respect to oil and natural gas production for the three months ended September 30, 2002 and 2003:

	Oil (Bbls per day)			Gas (Mcfs per day)			Total (Mcfe per day)
	2002	2003	Change	2002	2003	Change	2002	2003	Change
Wattenberg	6,378	7,659	1,281	135,046	147,199	12,153	173,316	193,150	19,834
Mid Continent	—	4,311	4,311	—	29,093	29,093	—	54,958	54,958
Other	2,266	3,807	1,541	2,313	3,588	1,275	15,905	26,433	10,528

Total	8,644	15,777	7,133	137,359	179,880	42,521	189,221	274,541	85,320

Average oil prices increased 3% from $24.69 per barrel in the third quarter of 2002 to $25.45 in 2003. Average gas prices increased 51% from $2.43 per Mcf in the third quarter of 2002 to $3.68 in 2003. Average oil prices include hedging losses of $2.4 million or $3.05 per barrel and $5.7 million or $3.95 per barrel in the third quarters of 2002 and 2003, respectively. Average gas prices included hedging gains of $8.7 million or $0.69 per Mcf in the third quarter of 2002 and hedging losses of $9.7 million or $0.59 per Mcf in 2003. The following table sets forth summary information with respect to oil and natural gas prices for the three months ended September 30, 2002 and 2003:

	Oil $/Bbls									Gas $/Mcf								Total $/Mcfe
	2002			2003			Change			2002		2003			Change			2002		2003			Change
Wattenberg	$	28.31		$	30.63		$	2.32		$	1.73	$	4.11		$	2.38		$	2.39	$	4.35		$	1.96
Mid Continent		—			27.71			27.71			—		5.09			5.09			—		4.87			4.87
Other		26.13			28.86			2.73			2.33		4.15			1.82			4.06		4.72			0.66

Subtotal		27.74			29.40			1.66			1.74		4.27			2.53			2.53		4.49			1.96
Hedging		(3.05	)		(3.95	)		(0.90	)		0.69		(0.59	)		(1.28	)		0.36		(0.62	)		(0.98	)

Total	$	24.69		$	25.45		$	0.76		$	2.43	$	3.68		$	1.25		$	2.89	$	3.87		$	0.98

Lease operating expenses totaled $14.4 million or $0.57 per Mcfe for the third quarter of 2003 compared to $6.4 million or $0.37 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to additional operating expenses incurred as a result of increasing oil production associated with the recent acquisitions. Production taxes totaled $7.2 million or $0.28 per Mcfe in the third quarter of 2003 compared to $2.7 million in 2002 or $0.16 per Mcfe. The $4.4 million increase was a result of higher oil and gas prices and production.

General and administrative expenses for the third quarter of 2003 totaled $4.4 million, an increase of $1.8 million or 74% over the same period in 2002. The increase was largely attributable to additional employees hired in conjunction with the recent acquisitions.

Interest and other expenses increased to $1.7 million in the third quarter of 2003, an increase of 232% from the prior year period. Interest expense increased as a result of higher average debt balances in conjunction with the acquisitions made in late 2002 and early 2003, somewhat offset by lower average interest rates. The Company’s average interest rate during the third quarter of 2003 was 2.5% compared to 3.1% in 2002.

Deferred compensation adjustment totaled $6.0 million in the third quarter of 2003, an increase of $5.6 million from the prior year period. The increase relates to the increase in value of the Company’s common shares and other investments held in a deferred compensation plan over 2002. The Company’s common stock price appreciated by 13% or $4.09 per share in the third quarter of 2003 versus an increase of 4% or $0.86 per share in the third quarter of 2002.

Depletion, depreciation and amortization expense for the third quarter of 2003 totaled $24.6 million, an increase of $7.9 million or 48% from 2002. Depletion expense totaled $23.6 million or $0.93 per Mcfe for the third quarter of 2003 compared to $16.3 million or $0.93 per Mcfe for 2002. The increase in depletion expense resulted from the 45% increase in oil and gas production in the third quarter of 2003. Depreciation and amortization expense for the three months ended September 30, 2003 totaled $686,000 or $0.03 per Mcfe, compared to $352,000 or $0.02 per Mcfe in the third quarter of 2002. Accretion expense related to SFAS No. 143 totaled $314,000 in the third quarter of 2003 compared to zero in the third quarter of 2002, as the statement was not effective until January 1, 2003.

Provision for income taxes for the third quarter of 2003 totaled $15.3 million, an increase of $7.8 million from the same period in 2002. The increase was due to higher earnings and an increase in the effective tax rate. The Company recorded a 38% tax provision for the third quarter of 2003 compared to a 35% tax provision in 2002. The increase in the effective tax rate was due to the expiration of Section 29 tax credits as of December 31, 2002.

Nine months ended September 30, 2003 compared to the nine months ended September 30, 2002.

Revenues for the first nine months of 2003 totaled $281.6 million, an 83% increase from the prior year period. Net income for the first nine months of 2003 totaled $69.3 million compared to $39.4 million in 2002. The increases in revenue and net income were due to higher oil and gas prices and production.

Average daily oil and gas production in the first nine months of 2003 totaled 15,118 barrels and 169.6 MMcf (260.3 MMcfe), an increase of 43% on an equivalent basis from the same period in 2002. The rise in production was due to the continued development activity in Wattenberg, the benefits of the Le Norman and Bravo acquisitions made in the fourth quarter of 2002, and the Elysium and LNP acquisitions made in the first quarter of 2003, respectively. During the first nine months of 2003, the Company drilled or deepened 62 wells, performed 322 refracs, 28 trifracs and 12 recompletions in Wattenberg, compared to 42 new wells or deepenings and 341 refracs and seven recompletions in Wattenberg in 2002. During the first nine months of 2003, the Company drilled or deepened 203 wells and performed 75 recompletions on its Mid Continent and other properties, compared to 35 new drills or deepenings and 37 recompletions for the same period in 2002. Based upon a $165.0 million development budget for 2003 combined with the benefits of the acquisitions made in the fourth quarter of 2002 and the first quarter of 2003 and the recent Cordillera Acquisition in the fourth quarter of 2003, the Company expects production to increase over 40% from 2002. The following table sets forth summary information with respect to oil and natural gas production for the nine months ended September 30, 2002 and 2003:

	Oil (Bbls per day)			Gas (Mcfs per day)			Total (Mcfe per day)
	2002	2003	Change	2002	2003	Change	2002	2003	Change
Wattenberg	6,177	7,664	1,487	129,725	143,506	13,781	166,784	189,487	22,703
Mid Continent	—	3,742	3,742	—	22,945	22,945	—	45,397	45,397
Other	2,193	3,712	1,519	2,366	3,177	811	15,527	25,449	9,922

Total	8,370	15,118	6,748	132,091	169,628	37,537	182,311	260,333	78,022

Average oil prices increased 6% from $24.33 per barrel in the first nine months of 2002 to $25.88 in 2003. Average gas prices increased 42% from $2.60 per Mcf in the first nine months of 2002 to $3.70 in 2003. Average oil prices include hedging losses of $1.4 million or $0.61 per barrel and $17.5 million or $4.24 per barrel in the first nine months of 2002 and 2003, respectively. Average gas prices included hedging gains of $21.2 million or $0.59 per Mcf in the first nine months of 2002 and hedging losses of $22.2 million or $0.48 per Mcf in 2003. The following table sets forth summary information with respect to oil and natural gas prices for the nine months ended September 30, 2002 and 2003:

	Oil $/Bbls									Gas $/Mcf								Total $/Mcfe
	2002			2003			Change			2002		2003			Change			2002		2003			Change
Wattenberg	$	25.54		$	31.35		$	5.81		$	2.00	$	3.97		$	1.97		$	2.50	$	4.28		$	1.78
Mid Continent		—			28.05			28.05			—		5.48			5.48			—		5.08			5.08
Other		23.24			29.66			6.42			2.33		4.36			2.03			3.64		4.87			1.23

Subtotal		24.94			30.12			5.18			2.01		4.18			2.17			2.60		4.48			1.88
Hedging		(0.61	)		(4.24	)		(3.63	)		0.59		(0.48	)		(1.07	)		0.40		(0.56	)		(0.96	)

Total	$	24.33		$	25.88		$	1.55		$	2.60	$	3.70		$	1.10		$	3.00	$	3.92		$	0.92

Lease operating expenses totaled $39.1 million or $0.55 per Mcfe for the first nine months of 2003 compared to $20.1 million or $0.40 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to additional operating expenses incurred as a result of increasing oil production associated with the recent acquisitions. Production taxes totaled $20.0 million or $0.28 per Mcfe in the first nine months of 2003 compared to $7.6 million in 2002 or $0.15 per Mcfe. The $12.4 million increase was a result of higher oil and gas prices and production.

General and administrative expenses for the first nine months of 2003 totaled $13.0 million, an increase of $4.5 million or 52% over the same period in 2002. The increase was largely attributed to additional employees hired in conjunction with the recent acquisitions.

Interest and other expenses increased to $5.8 million in the first nine months of 2003, an increase of 229% from the prior year period. Interest expense increased as a result of higher average debt balances in conjunction with the acquisitions made in late 2002 and early 2003, somewhat offset by lower average interest rates. The Company’s average interest rate during the first nine months of 2003 was 2.6% compared to 3.1% in 2002.

Deferred compensation adjustment totaled $15.9 million in the first nine months of 2003, an increase of $9.5 million from the prior year period. The increase relates to the increase in value of the Company’s common shares and other investments held in a deferred compensation plan over 2002. The Company’s common stock price appreciated by 43% or $10.92 per share in the first nine months of 2003 versus an increase of 30% or $5.20 per share during the first nine months of 2002.

Depletion, depreciation and amortization expense for the first nine months of 2003 totaled $68.9 million, an increase of $21.3 million or 45% from 2003. Depletion expense totaled $66.1 million or $0.93 per Mcfe for the first nine months of 2003 compared to $46.6 million or $0.94 per Mcfe for 2002. The increase in depletion expense resulted from the 43% increase in oil and gas production in the first nine months of 2003, somewhat offset by a lower depletion rate. Depreciation and amortization expense for the nine months ended September 30, 2003 totaled $1.9 million or $0.03 per Mcfe compared to $985,000 or $0.02 per Mcfe in the first nine months of 2002. Accretion expense related to SFAS No. 143 totaled $942,000 in the first nine months of 2003 compared to zero in the first nine months of 2002, as the statement was not effective until January 1, 2003.

Provision for income taxes for the first nine months of 2003 totaled $44.1 million, an increase of $22.8 million from the same period in 2002. The increase was due to higher earnings and an increase in the effective tax rate. The Company recorded a 38% tax provision for the first nine months of 2003 compared to a 35% tax provision in 2002. The increase in the effective tax rate was due to the expiration of Section 29 tax credits as of December 31, 2002.

The Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” on January 1, 2003. The cumulative effect of change in accounting principle of $2.6 million (net of $1.6 million deferred taxes) in the first nine months of 2003 reflects accretion that would have been recorded if the Company had always been under the requirements of SFAS No. 143.

Recent Accounting Pronouncements

ITEM 3. 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 2002 and the first nine months of 2003, exclusive of any hedges, ranged from a monthly low of $1.59 per Mcf to a monthly high of $5.37 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $18.74 per barrel to a monthly high of $35.15 per barrel during 2002 and the first nine months of 2003. 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 the first nine months of 2003, a 10% reduction in oil and gas prices, excluding oil and gas quantities that were fixed through hedging transactions, would have reduced revenues by $10.7 million. If oil and gas future prices at September 30, 2003 had declined by 10%, the net unrealized hedging losses at that date would have decreased by $58.3 million (from a $41.0 million loss to a $17.3 million gain).

At September 30, 2003, the Company was a party to the fixed price swaps summarized below:

	Oil Swaps (NYMEX)				Natural Gas Swaps (CIG Index)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
10/01/03 - 12/31/03	13,100	24.91	(4,525	)	86,700	3.60	(5,455	)

01/01/04 - 03/31/04	13,450	25.44	(2,666	)	95,000	4.23	(3,713	)
04/01/04 - 06/30/04	14,350	24.93	(2,449	)	85,000	3.56	(2,724	)
07/01/04 - 09/30/04	12,750	24.33	(2,244	)	75,000	3.49	(3,164	)
10/01/04 - 12/31/04	12,850	24.12	(2,013	)	65,000	3.83	(2,111	)

2005	8,000	23.95	(3,702	)	55,000	3.65	(4,826	)

	Natural Gas Swaps (ANR/PEPL Indexes)				Natural Gas Swaps (EPSJ Index)
Time Period	Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
10/01/03 - 12/31/03	24,500	4.48	(295	)	4,000	4.65	136

01/01/04 - 03/31/04	27,700	4.84	(373	)	5,400	4.87	94
04/01/04 - 06/30/04	28,800	4.31	(545	)	6,300	4.18	49
07/01/04 - 09/30/04	30,000	4.28	(648	)	7,400	4.15	43
10/01/04 - 12/31/04	30,100	4.49	(462	)	7,900	4.34	67

2005	20,000	4.51	469		3,500	4.06	32

Interest Rate Risk

At September 30, 2003, the Company had $220.0 million outstanding under its credit facility at an average interest rate of 2.4%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the LIBOR for one, two, three or six months plus a margin which fluctuates from 1.25% to 1.90% or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The weighted average interest rate under the facility approximated 2.6% during the first nine months of 2003. Assuming no change in the amount outstanding at September 30, 2003, the annual impact on interest expense of a ten percent change in the average interest rate for the third quarter of 2003 would be approximately $343,000, net of tax. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.

Forward-Looking Statements

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 or present 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.

All statements, other than statements of historical or present facts, that address activities, events, outcomes or developments that the Company plans, expects, believes, assumes, budgets, predicts, forecasts, estimates, projects, intends or anticipates (and other similar expressions) will or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-Q and presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002. Such forward-looking statements appear in a number of places and include statements with respect to, among other things, such matters as: future capital, development and exploration expenditures (including the amount and nature thereof), drilling, deepening or refracing of wells, oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), estimates of future production of oil and natural gas, expected results or benefits associated with recent acquisitions, business strategies, expansion and growth of the Company’s operations, cash flow and anticipated liquidity, grassroots prospects and development and property acquisitions, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include but are not limited to: 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, regulatory developments and the other risks described in this Form 10-Q and presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions could change the schedule of any further production and/or development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q or presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

The Company’s principal executive officer and principal financial officer have evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report (the “Evaluation Date”). Based upon their evaluation, the principal executive officer and principal financial officer concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective. During the Company’s most recent fiscal quarter, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item is incorporated by reference from Notes to Consolidated Financial Statements in Part 1 of this report.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 6. Exhibits and Reports on Form 8-K

(a)	Exhibits – The following documents are filed as exhibits to this Quarterly Report on Form 10-Q:


2.1		Purchase and Sale Agreement between Cordillera Energy Partners, LLC and Patina Oil & Gas Corporation dated August 25, 2003 (Incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K filed on October 2, 2003).

10.1.3		Second Amendment to the Third Amended and Restated Credit Agreement by and among the Company, as borrower, Bank One, NA, as Administrative Agent, and certain other financial institutions dated October 1, 2003 (Incorporated herein by reference to Exhibit 10.1.3 to the Company’s Form 8-K filed on October 2, 2003).

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1		Certification of Chief Executive Officer, dated October 30, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

32.2		Certification of Chief Financial Officer, dated October 30, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

*	Filed herewith

(b)	The following reports on Form 8-K were filed by Registrant during the quarter ended September 30, 2003:

The Company filed a current report on Form 8-K on July 31, 2003 to furnish the information required under Item 12 related to the Company’s July 30, 2003 press release announcing the Company’s financial results for the three months ended June 30, 2003.

SIGNATURES

Pursuant to the requirements 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.

		PATINA OIL & GAS CORPORATION

BY		/s/ David J. Kornder
		David J. Kornder, Executive Vice President and
		Chief Financial Officer

October 30, 2003