e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2005


o		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: 001-31899

WHITING PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		20-0098515

(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

1700 Broadway, Suite 2300
Denver, Colorado		80290-2300

(Address of principal executive offices)		(Zip code)

(303) 837-1661

(Registrant’s telephone number, including area code)

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 þ No o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Number of shares of the registrant’s common stock outstanding at October 17, 2005: 36,842,723 shares.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)


	September 30,			December 31,
	2005			2004
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	7,542		$	1,660
Accounts receivable trade, net		83,845			63,489
Deferred income taxes		28,308			2,368
Prepaid expenses and other		7,407			7,603


Total current assets		127,102			75,120

PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		1,775,915			1,225,676
Unproved properties		18,553			6,038
Deposit on North Ward Estes acquisition		45,900			—
Other property and equipment		13,911			7,517


Total property and equipment		1,854,279			1,239,231

Less accumulated depreciation, depletion and amortization		(306,911	)		(244,246	)


Total property and equipment-net		1,547,368			994,985


DEBT ISSUANCE COSTS		19,124			11,823

OTHER LONG-TERM ASSETS		11,781			10,278


TOTAL	$	1,705,375		$	1,092,206

See condensed notes to consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)


	September 30,			December 31,
	2005			2004
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	39,596		$	19,815
Accrued interest		11,378			2,050
Oil and gas sales payable		9,527			4,987
Accrued employee compensation and benefits		8,673			7,808
Production taxes payable		13,533			8,254
Current portion of tax sharing liability		4,214			4,214
Current portion of long-term debt		3,280			3,167
Current portion of derivative liability		68,874			1,670
Income taxes payable and other liabilities		—			129


Total current liabilities		159,075			52,094

NON-CURRENT LIABILITIES:
Asset retirement obligations		36,891			31,639
Production Participation Plan liability		11,457			9,579
Tax sharing liability		28,826			26,966
Long-term debt		735,623			325,261
Deferred income taxes		63,452			34,281
Long-term derivative liability		34,053			—


Total non-current liabilities		910,302			427,726

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Common stock, $.001 par value; 75,000,000 shares authorized, 29,788,723 and 29,717,808 shares issued and outstanding as of September 30, 2005 and December 31, 2004, respectively		30			30
Additional paid-in capital		458,837			455,635
Accumulated other comprehensive loss		(63,198	)		(1,025	)
Deferred compensation		(2,707	)		(1,715	)
Retained earnings		243,036			159,461


Total stockholders’ equity		635,998			612,386


TOTAL	$	1,705,375		$	1,092,206

See condensed notes to consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
REVENUES:
Oil and gas sales	$	153,386		$	65,898		$	374,829		$	166,408
Loss on oil and gas hedging activities		(13,744	)		(2,040	)		(20,689	)		(3,615	)
Gain on sale of marketable securities		—			2,380			—			4,762
Gain on sale of oil and gas properties		—			1,000			—			1,000
Interest income and other		153			52			319			186

Total		139,795			67,290			354,459			168,741


COSTS AND EXPENSES:
Lease operating		27,792			12,957			70,732			34,650
Production taxes		10,103			3,950			24,558			10,168
Depreciation, depletion and amortization		23,318			13,010			64,400			34,500
Exploration and impairment		4,596			3,766			11,999			4,686
General and administrative		8,141			6,117			21,636			14,191
Interest expense		11,640			4,172			25,018			9,591

Total costs and expenses		85,590			43,972			218,343			107,786


INCOME BEFORE INCOME TAXES		54,205			23,318			136,116			60,955

INCOME TAX EXPENSE:
Current		4,440			400			9,177			400
Deferred		16,483			8,601			43,364			23,129

Total income tax expense		20,923			9,001			52,541			23,529


NET INCOME	$	33,282		$	14,317		$	83,575		$	37,426


NET INCOME PER COMMON SHARE, BASIC	$	1.12		$	0.70		$	2.82		$	1.93


NET INCOME PER COMMON SHARE DILUTED	$	1.12		$	0.70		$	2.81		$	1.93


WEIGHTED AVERAGE SHARES OUTSTANDING, BASIC		29,707			20,516			29,688			19,341


WEIGHTED AVERAGE SHARES OUTSTANDING, DILUTED		29,725			20,554			29,705			19,370

See condensed notes to consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (Unaudited)
(In thousands)


									Accumulated
						Additional			Other								Total
	Common Stock					Paid-in			Comprehensive			Deferred			Retained		Stockholders’			Comprehensive
	Shares			Amount		Capital			Income (Loss)			Compensation			Earnings		Equity			Income
BALANCES—January 1, 2004		18,750		$	19	$	170,367		$	(223	)	$	—		$	89,415	$	259,578		$	19,612

Net income		—			—		—			—			—			70,046		70,046			70,046
Change in fair value of marketable securities for sale		—			—		—			3,741			—			—		3,741			3,741
Realized gain on marketable securities for sale		—			—		—			(4,835	)		—			—		(4,835	)		(4,835	)
Change in derivative instrument fair value		—			—		—			(2,701	)		—			—		(2,701	)		(2,701	)
Realized loss on settled derivative contracts, net of related taxes		—			—		—			2,993			—			—		2,993			2,993
Issuance of stock – Equity Oil Company merger		2,237			2		43,296			—			—			—		43,298			—
Issuance of stock – secondary offering		8,625			9		239,677			—			—			—		239,686			—
Deferred compensation stock issued		106			—		2,295			—			(2,295	)		—		—			—
Amortization of deferred compensation		—			—		—			—			580			—		580			—


BALANCES—December 31, 2004		29,718			30		455,635			(1,025	)		(1,715	)		159,461		612,386		$	69,244

Net income		—			—		—			—			—			83,575		83,575			83,575
Change in derivative instrument fair value		—			—		—			(74,876	)		—			—		(74,876	)		(74,876	)
Realized loss on settled derivative contracts, net of related taxes		—			—		—			12,703			—			—		12,703			12,703
Restricted stock issued		85			—		3,407			—			(3,407	)		—		—			—
Restricted stock forfeited		(8	)		—		(193	)		—			193			—		—			—
Restricted stock used for tax withholdings		(6	)		—		(241	)		—			—			—		(241	)		—
Net tax effect arising from restricted stock activity		—			—		229			—			—			—		229			—
Amortization of deferred compensation		—			—		—			—			2,222			—		2,222			—


BALANCES—September 30, 2005		29,789		$	30	$	458,837		$	(63,198	)	$	(2,707	)	$	243,036	$	635,998		$	21,402

See condensed notes to consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands)


	Nine Months Ended
	September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	83,575		$	37,426
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		64,400			34,500
Deferred income taxes		43,364			23,129
Amortization of debt issuance costs and debt discount		2,754			1,025
Accretion of tax sharing agreement		1,860			1,800
Amortization of deferred compensation		2,222			422
Gain on sale of marketable securities		—			(4,835	)
Gain on sale of oil and gas properties		—			(1,000	)
Impairment on oil and gas properties		1,928			2,152
Changes in assets and liabilities:
Accounts receivable		(17,791	)		(6,466	)
Other assets		(1,284	)		(883	)
Asset retirement obligations		(188	)		(321	)
Production participation plan liability		2,520			542
Accounts payable		8,580			4,351
Accrued interest		9,328			(814	)
Other current liabilities		10,155			5,257

Net cash provided by operating activities		211,423			96,285


CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures		(427,331	)		(445,340	)
Drilling capital expenditures		(103,896	)		(52,201	)
Deposit on North Ward Estes acquisition		(45,900	)		—
Proceeds from sale of marketable securities		—			5,420
Proceeds from sale of oil and gas properties		—			1,000
Acquisition of partnership interests, net of cash acquired of $26		(30,433	)		—
Equity Oil Company cash paid in excess of cash received		—			(256	)

Net cash used in investing activities		(607,560	)		(491,377	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of 7¹/4% Senior Subordinated debt due 2013		216,715			—
Issuance of long-term debt under credit agreement		395,000			583,890
Payment on long-term debt under credit agreement		(200,000	)		(214,000	)
Debt issuance costs		(9,684	)		(11,022	)
Restricted stock used for tax withholdings		(241	)		—
Net tax effect arising from restricted stock activity		229			—

Net cash provided by financing activities		402,019			358,868


NET CHANGE IN CASH AND CASH EQUIVALENTS		5,882			(36,224	)

CASH AND CASH EQUIVALENTS:
Beginning of period		1,660			53,585

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS (Unaudited)
(In thousands, except per share data)

1.		BASIS OF PRESENTATION

		*Description of Operations*—Whiting Petroleum Corporation (“Whiting” or the “Company”) is a Delaware corporation that prior to its initial public offering in November 2003 was a wholly owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), a holding company whose primary businesses are utility companies. Whiting acquires, develops and explores for producing oil and gas properties primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States.

		*Consolidated Financial Statements*—The unaudited consolidated financial statements include the accounts of Whiting and its subsidiaries, all of which are wholly owned. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Except as disclosed herein, there has been no material change to the information disclosed in the notes to consolidated financial statements included in Whiting’s Annual Report on Form 10-K for the year ended December 31, 2004. It is recommended that these unaudited consolidated financial statements be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Form 10-K.

		*Earnings Per Share*—Basic net income per common share of stock is calculated by dividing net income by the weighted average number of common shares outstanding during each period. Diluted net income per common share of stock is calculated by dividing net income by the weighted average number of common shares outstanding and other dilutive securities. The only securities considered dilutive are the Company’s unvested restricted stock awards.

		*Reclassifications*—Certain prior period balances were reclassified to conform to the current year presentation. As of December 31, 2004, tubular goods in the amount of $2,963 were reclassed from prepaid expenses and other current assets to other property and equipment. These reclassifications had no impact on net income or stockholders’ equity as previously reported. During the period ended September 30, 2005, the Company determined that drilling capital expenditures on account, which were previously reported as a component of changes in operating assets and liabilities and drilling capital expenditures, should not have been reported in the statements of cash flows, and that changes in tubular goods and field supplies, which were previously reported as a component of changes in operating assets and liabilities, should have been reported as drilling capital expenditures in the investing activity section of the statements of cash flows. As a result, the Company restated certain amounts in the statement of cash flows for the nine months ended September 30, 2004 from amounts previously reported, which had the effect of reducing drilling capital expenditures by $581 and decreasing net cash provided by operating activities by the same amount, with no impact on net income or stockholders’ equity.

2.		DERIVATIVE FINANCIAL INSTRUMENTS

		Whiting is exposed to market risk in the pricing of its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Whiting

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		utilizes traditional collar arrangements to mitigate the impact of oil and gas price fluctuations related to its sales of oil and gas. The Company has qualified all of these instruments as cash flow hedges for accounting purposes.

		During the first nine months of 2005 and 2004, the Company recognized losses of $20,689 and $3,615, respectively, related to its hedging activities. In addition, at September 30, 2005, Whiting’s remaining cash flow hedge positions resulted in a current pre-tax liability of $68,874 of which $42,289 was recorded as a component of accumulated other comprehensive income and $26,585 was recorded as a current deferred tax asset, and a long-term pre-tax liability of $34,053 of which $20,909 was recorded as a component of accumulated other comprehensive income and $13,144 was recorded as a long-term deferred tax asset. See Note 5 for restrictions in the Company’s credit agreement relating to hedging activities.

3.		MARKETABLE SECURITIES

		As of December 31, 2003, the Company held an investment in a publicly traded security classified as available-for-sale (included in other long-term assets). The original cost to the Company was $585. During the nine months ended September 30, 2004, the Company sold its holdings for $5,420 realizing a gain on sale of $4,835. The Company did not hold any publicly traded securities as of September 30, 2005.

4.		ASSET RETIREMENT OBLIGATIONS

		The Company recognizes the fair value of its liability for plugging and abandoning its oil and natural gas wells in the financial statements by capitalizing that cost as a part of the cost of the related asset. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and includes the abandonment obligation for certain onshore and offshore facilities located in California. The discounted obligation is accreted at the end of each accounting period through charges to depreciation, depletion and amortization expense. If the obligation is settled for other than the carrying amount, then a gain or loss is recognized upon settlement.

		The following table provides a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2005 and 2004, respectively.


	Nine Months Ended			Nine Months Ended
	September 30, 2005			September 30, 2004
Beginning asset retirement obligation	$	31,639		$	23,021
Additional liability incurred		3,705			6,588
Accretion expense		1,735			1,214
Liabilities settled		(188	)		(321	)


Ending asset retirement obligation	$	36,891		$	30,502

No revisions have been made to the timing or the amount of the original estimate of undiscounted cash flows during the first nine months of 2005 or 2004.

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5.		LONG-TERM DEBT

		Long-term debt consisted of the following at September 30, 2005 and December 31, 2004:


	September 30,			December 31,
	2005			2004
Credit Agreement	$	370,000		$	175,000
7¹/4% Senior Subordinated Notes due 2012		148,668			150,261
7¹/4% Senior Subordinated Notes due 2013		216,955			—
Alliant Energy		3,280			3,167

Total debt		738,903			328,428
Current portion of long-term debt		(3,280	)		(3,167	)

Long-term debt	$	735,623		$	325,261

		*Credit Agreement*—On August 31, 2005, the Company’s wholly-owned subsidiary, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”) entered into an amended and restated $1.2 billion credit agreement with a syndicate of banks. The new credit agreement increased the Company’s borrowing base to $675.0 million from $480.0 million under the prior credit agreement. The borrowing base under the credit agreement increased to $850.0 million after the closing of the Company’s acquisition of the North Ward Estes properties from Celero Energy, LP (“Celero”) on October 4, 2005, which was offset by a reduction in the borrowing base of $62.5 million upon the closing of the Company’s private placement of $250.0 million aggregate principal amount of 7% Senior Subordinated Notes due 2014 on October 4, 2005, resulting in a borrowing base of $787.5 million. See Note 13 for a further discussion of these transactions. The borrowing base under the credit agreement is determined in the discretion of the lenders based on the collateral value of the proved reserves, and is subject to regular redeterminations on May 1 and November 1 of each year as well as special redeterminations described in the credit agreement. On August 31, 2005, Whiting Oil and Gas borrowed $391.2 million under the credit agreement to refinance the entire outstanding balance under the prior credit agreement. As of September 30, 2005, the outstanding principal balance under the credit agreement was $370.0 million. On October 4, the Company repaid $100.0 million of the outstanding principal balance with the net proceeds from the private placement of 7% Senior Subordinated Notes due 2014, resulting in an outstanding principal balance of $270.0 million under the credit agreement. See Note 13 for a further discussion of these transactions.

		The credit agreement provides for interest only payments until August 31, 2010, when the entire amount borrowed is due. Whiting Oil and Gas may, throughout the five-year term of the credit agreement, borrow, repay and reborrow up to the borrowing base in effect from time to time. The lenders under the credit agreement have also committed to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company from time to time in an aggregate amount not to exceed $50 million. As of September 30, 2005, letters of credit totaling $300 were outstanding under the credit agreement.

		Interest accrues, at Whiting Oil and Gas’ option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the prime rate or the federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.00% to 1.75% depending on the utilization percentage of the borrowing base. Whiting Oil and Gas has consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on the utilization

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		percentage and are included as a component of interest expense. At October 4, 2005, the effective weighted average interest rate on the entire outstanding principal balance under the credit agreement was 5.3%.

		The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, change material agreements, incur liens and engage in certain other transactions without the prior consent of the lenders and requires the Company to maintain a debt to EBITDAX (as defined in the credit agreement) ratio of less than 3.5 to 1 and a working capital ratio (as defined in the credit agreement) of greater than 1 to 1. Except for limited exceptions, including the payment of interest on the senior notes, the credit agreement restricts the ability of Whiting Oil and Gas and Equity Oil Company to make any dividends, distributions or other payments to the Company. The restrictions apply to all of the net assets of these subsidiaries. The Company was in compliance with its covenants under the credit agreement as of September 30, 2005. The credit agreement is secured by a first lien on all of Whiting Oil and Gas’ properties included in the borrowing base for the credit agreement. Whiting Petroleum Corporation and its wholly-owned subsidiary, Equity Oil Company, have guaranteed the obligations of Whiting Oil and Gas under the credit agreement. Whiting Petroleum Corporation has pledged the stock of Whiting Oil and Gas and Equity Oil Company as security for its guarantee and Equity Oil Company has mortgaged all of its properties included in the borrowing base for the credit agreement as security for its guarantee.

		*7¹/4% Senior Subordinated Notes*—On April 19, 2005, the Company issued $220.0 million aggregate principal amount of its 7-1/4% Senior Subordinated Notes due 2013. The net proceeds of the offering were used to repay debt outstanding under Whiting Oil and Gas’s credit agreement. The 7-1/4% Senior Subordinated Notes due 2013 were issued at 98.507% of par and the associated discount is being amortized to interest expense over the term of the notes. Based on the market price of the 7-1/4% Senior Subordinated Notes due 2013, their estimated fair value was $220.6 million as of September 30, 2005.

		In May 2004, the Company issued $150.0 million aggregate principal amount of its 7-1/4% Senior Subordinated Notes due 2012. The 7-1/4% Senior Subordinated Notes due 2012 were issued at 99.26% of par and the associated discount is being amortized to interest expense over the term of the notes. Based on the market price of the 7-1/4 % Senior Subordinated Notes due 2012, their estimated fair value was $150.4 million as of September 30, 2005.

		The notes are unsecured obligations of the Company and are subordinated to all of the Company’s senior debt. The indentures governing the notes contain various restrictive covenants that are substantially identical and may limit the Company’s and its subsidiaries’ ability to, among other things, pay cash dividends, redeem or repurchase the Company’s capital stock or the Company’s subordinated debt, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries taken as a whole, and enter into hedging contracts. These covenants may limit the discretion of the Company’s management in operating the Company’s business. In addition, Whiting Oil and Gas’ credit agreement restricts the ability of the Company’s subsidiaries to make certain payments, including principal on the notes, to the Company. The Company was in compliance with these covenants as of September 30, 2005. Both of the Company’s operating subsidiaries, Whiting Oil and Gas and Equity Oil Company (the “Guarantors”), have fully, unconditionally, jointly and severally guaranteed the Company’s obligations under the notes. All of the Company’s subsidiaries other than the Guarantors are minor within the meaning of Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange Commission, and the Company has no independent assets or operations.

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		*Interest Rate Swap*—In August 2004, the Company entered into an interest rate swap contract to hedge the fair value of $75 million of its 7-1/4% Senior Subordinated Notes due 2012. Because this swap meets the conditions to qualify for the “short cut” method of assessing effectiveness under the provisions of Statement of Financial Accounting Standards No. 133, the change in fair value of the debt is assumed to equal the change in the fair value of the interest rate swap. As such, there is no ineffectiveness assumed to exist between the interest rate swap and the notes.

		The interest rate swap is a fixed for floating swap in that the Company receives the fixed rate of 7.25% and pays the floating rate. The floating rate is redetermined every six months based on the LIBOR rate in effect at the contractual reset date. When LIBOR plus the Company’s margin of 2.345% is less than 7.25%, the Company receives a payment from the counterparty equal to the difference in rate times $75 million for the six month period. When LIBOR plus the Company’s margin of 2.345% is greater than 7.25%, the Company pays the counterparty an amount equal to the difference in rate times $75 million for the six month period. The LIBOR rate at September 30, 2005 was 4.27%. As of September 30, 2005, the Company has recorded a long term derivative liability of $442 related to the interest rate swap, which has been designated as a fair value hedge, with a corresponding debt decrease to the 7-1/4% Senior Subordinated Notes due 2012.

		*Short-Term Debt*—In conjunction with the Company’s initial public offering in November 2003, the Company issued a promissory note payable to Alliant Energy in the aggregate principal amount of $3.0 million. The promissory note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005.

6.		EQUITY INCENTIVE PLAN

		The Company maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan, pursuant to which two million shares of the Company’s common stock have been reserved for issuance. No participating employee may be granted options for more than 300,000 shares of common stock, stock appreciation rights with respect to more than 300,000 shares of common stock or more than 150,000 shares of restricted stock during any calendar year. This plan prohibits the repricing of outstanding stock options without stockholder approval. During the first nine months of 2005, the Company granted 84,652 shares of restricted stock under this plan and 8,365 shares were forfeited. The new shares of restricted stock were recorded at fair value of $3.4 million and are being amortized to general and administrative expense over their three year vesting period.

7.		PRODUCTION PARTICIPATION PLAN

		The Company has a Production Participation Plan for all employees. On an annual basis, economic interests in oil and gas properties acquired or developed during the year are allocated to the plan on a discretionary basis. Once allocated, the interests (not legally conveyed) are fixed. Allocations prior to 1995 consisted of 2% — 3% overriding royalty interests. Allocations since 1995 have been 2% — 5% net revenue interests. Prior to plan year 2004, plan participants generally vested ratably over their initial five years of employment in all income allocated to the plan on their behalf and forfeitures were re-allocated among other Plan participants. The Production Participation Plan was modified in 2004 to provide that (1) for years 2004 and beyond, employees will vest at a rate of 20% per year with respect to the income allocated to the plan for such year; (2) employees will become fully vested at age 65, regardless of when their interests would otherwise vest; and (3) for years 2004 and beyond, if there are forfeitures, the interests will inure to the benefit of the Company. At September 30, 2005 and 2004, the current

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		portion of the Production Participation Plan liability was $7,757 and $4,013, respectively which is recorded as a component of accrued employee compensation and benefits.

		Since 2001, the Company has used average historical NYMEX prices to estimate the vested long-term production participation plan liability. At September 30, 2005, the average historical NYMEX prices used to estimate this liability were $27.41 for crude oil and $2.82 for natural gas. Although on average, employees are approximately 66% vested in the Plan’s interests at September 30, 2005, if the Company were to terminate the Plan, all Plan participants would fully vest immediately in the Plan. In that event, the Company would have three options to distribute to each Plan participant their respective value: 1) in a lump sum payment; 2) in five annual installments; or 3) by continuing to make distributions in accordance with the Plan for the existing plan assets. As of September 30, 2005, if the Company elected to terminate the Plan and purchase the participant interests based on current prices, it is estimated that the fully vested lump sum cash payment to employees would approximate $81.0 million. The Company has no intention to terminate the Plan.

8.		TAX SEPARATION AND INDEMNIFICATION AGREEMENT WITH ALLIANT ENERGY

		In connection with Whiting’s initial public offering in November 2003, the Company entered into a tax separation and indemnification agreement with Alliant Energy. Pursuant to this agreement, the Company and Alliant Energy made a tax election with the effect that the tax basis of the assets of Whiting and its subsidiaries were increased to the deemed purchase price of their assets immediately prior to such initial public offering. Whiting has adjusted deferred taxes on its balance sheet to reflect the new tax basis of the Company’s assets. This additional basis is expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by Whiting.

		Under this agreement, the Company has agreed to pay to Alliant Energy 90% of the future tax benefits the Company realizes annually as a result of this step-up in tax basis for the years ending on or prior to December 31, 2013. Such tax benefits will generally be calculated by comparing the Company’s actual taxes to the taxes that would have been owed by the Company had the increase in basis not occurred. In 2014, Whiting will be obligated to pay Alliant Energy 90% of the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. Future tax benefits in total will approximate $62.0 million. The Company has estimated total payments to Alliant Energy will approximate $49.0 million given the discounting affect of the final payment in 2014. The Company has discounted all cash payments to Alliant Energy at the date of the Tax Separation Agreement.

		The initial recording of this transaction in November 2003 resulted in a $57.2 million increase in deferred tax assets, a $28.6 million discounted payable to Alliant Energy and a $28.6 million increase to stockholders’ equity. The Company will monitor the estimate of when payments will be made and adjust the accretion of this liability on a prospective basis. During the first nine months of 2005, the Company did not make any payments under this agreement but did recognize $1.9 million of accretion expense which is included as a component of interest expense. The Company’s estimate of payments to be made in the fourth quarter of 2005 under this agreement of $4.2 million is reflected as a current liability at September 30, 2005.

		The Tax Separation Agreement provides that if tax rates were to change (increase or decrease), the tax benefit or detriment would result in a corresponding adjustment of the Alliant Energy liability. For purposes of this calculation, the Company’s management has assumed that no such change will occur during the term of this agreement.

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COMMITMENTS AND CONTINGENCIES

The Company leases 87,000 square feet of administrative office space under an operating lease arrangement through October 31, 2010. Rental expense for the first nine months of 2005 and 2004 was $1,144 and $688, respectively. Future minimum lease payments under this non-cancelable operating lease as of September 30, 2005 are as follows (in thousands):


Year Ending December 31, 2005	$	367
Year Ending December 31, 2006		1,469
Year Ending December 31, 2007		1,469
Year Ending December 31, 2008		1,469
Year Ending December 31, 2009		1,469
Year Ending December 31, 2010		1,224

Total	$	7,467

On October 4, 2005, the Company assumed two office leases in Midland, Texas totaling approximately 23,100 square feet. Future minimum lease payments under these non-cancelable operating leases as of October 4, 2005 were $56, $232, $213 and $12 for 2005, 2006, 2007 and 2008, respectively.

The Company is subject to litigation claims and governmental and regulatory controls arising in the ordinary course of business. The Company believes that all claims and litigation involving the Company are not likely to have a material adverse effect on its financial position or results of operations.

10.

ACQUISITIONS

Postle Field—On August 4, 2005, Whiting Oil and Gas acquired the operated interest in producing oil and natural gas fields located in the Postle Field in the Oklahoma Panhandle from Celero. The purchase price was $343.0 million for estimated proved reserves of approximately 241.5 Bcfe as of the acquisition effective date of July 1, 2005, resulting in a cost of approximately $1.42 per Mcfe of estimated proved reserves. Future development costs of the proved undeveloped reserves are estimated at approximately $111.0 million. The average daily production from the properties was approximately 25.8 MMcfe per day as of the acquisition effective date. The Company funded the acquisition through borrowings under Whiting Oil and Gas’ credit agreement.

Other Properties

Limited Partnership Interests—On June 23, 2005, Whiting Oil and Gas acquired all of the limited partnership interests in three institutional partnerships managed by its wholly-owned subsidiary, Whiting Programs, Inc. The partnership properties are located in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The purchase price was $30.5 million for estimated proved reserves of approximately 17.4 Bcfe as of the acquisition effective date of January 1, 2005, resulting in a cost of approximately $1.75 per Mcfe of estimated proved reserves. The average daily production from the properties was 4.0 MMcfe per day as of the acquisition effective date. The Company funded the acquisition with cash on hand.

Green River Basin—On March 31, 2005, Whiting Oil and Gas acquired operated interests in five producing gas fields in the Green River Basin of Wyoming. The purchase price was $65.0 million for estimated proved reserves of approximately 50.5 Bcfe as of the acquisition effective date of March 1, 2005, resulting in a cost of $1.29 per Mcfe of

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estimated proved reserves. Future development costs of the proved undeveloped reserves are estimated at approximately $14.0 million. The average daily production from the properties was approximately 6.3 MMcfe per day as of the acquisition effective date. The Company funded the acquisition through borrowings under Whiting Oil and Gas’ credit agreement and with cash on hand.

As these acquisitions were recorded using the purchase method of accounting, the results of operations from the acquisitions are included with our results from the respective acquisition dates noted above. The table below summarizes the preliminary allocation of the purchase price of each transaction based on the acquisition date fair values of the assets acquired and the liabilities assumed. See Note 13 for additional discussions of the North Ward Estes acquisition that occurred subsequent to September 30, 2005 (in thousands):


	Postle
	Properties			Other Properties			North Ward Estes
Purchase Price:
Cash paid, net of cash acquired	$	343,000		$	95,433		$	442,000
Common stock issued		—			—			17,176

Total	$	343,000		$	95,433		$	459,176


Allocation of Purchase Price:
Working capital	$	—		$	2,096		$	—
Oil and gas properties		343,513			95,832			463,340
Other long-term assets		243			—			—
Other non-current liabilities		(756	)		(2,495	)		(4,164	)

Total	$	343,000		$	95,433		$	459,176

The following table reflects the unaudited pro forma results of operations for the three and nine month periods ended September 30, 2005 and 2004 as though the above acquisitions had occurred on the first day of each period presented. The pro forma amounts for the three and nine month periods ended September 30, 2005 and 2004 include only the activity from the beginning of the period to the closing date of the acquisitions. See Note 13 for additional discussions of the North Ward Estes acquisition that occurred subsequent to September 30, 2005 (in thousands, except per share amounts):

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			Pro Forma
										North Ward
										Estes and		Pro
										Ancillary		Forma
	Historical Whiting		Postle Properties			Other Properties		Sub Total		Properties		Consolidated
Three months ended September 30, 2005
Total revenues	$	139,795	$	7,944		$	—	$	147,739	$	26,129	$	173,868
Net income		33,282		1,687			—		34,969		7,943		42,912
Net income per common share-basic and diluted		1.12		0.06			—		1.18		0.22		1.17

Three months ended September 30, 2004
Total revenues	$	67,290	$	16,086		$	5,691	$	89,067	$	10,244	$	99,311
Net income		14,317		1,776			371		16,464		853		17,317
Net income per common share-basic and diluted		0.70		0.09			0.02		0.81		0.03		0.63

Nine months ended September 30, 2005
Total revenues	$	354,459	$	46,075		$	8,721	$	409,255	$	56,061	$	465,316
Net income		83,575		6,815			1,016		91,406		12,131		103,537
Net income per common share-basic and diluted		2.82		0.23			0.03		3.08		0.33		2.82

Nine months ended September 30, 2004
Total revenues	$	168,741	$	43,431		$	17,001	$	229,173	$	25,972	$	255,145
Net income		37,426		(691	)		1,216		37,951		708		38,659
Net income per common share-basic and diluted		1.93		(0.04	)		0.06		1.95		0.03		1.46

11.

ACCOUNTING FOR SUSPENDED EXPLORATORY WELLS

In April 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No. FAS 19-1, Accounting for Suspended Well Costs (“FSP 19-1”), which amends FAS 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. Under the provisions of FSP 19-1, exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. The FSP provides a number of indicators that can assist an entity to demonstrate sufficient progress is being made in assessing the reserves and economic viability of the project.

During the quarter ended September 30, 2005, the Company adopted the requirements of FSP 19-1. Upon adoption, the Company evaluated all existing capitalized well costs under the provisions of FSP 19-1 and determined there was no impact to the Company’s consolidated financial statements. The following table reflects the net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2005 and for the year ended December 31, 2004 (in thousands):

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	Nine Months
	Ended			Year Ended
	September 30,			December 31,
	2005			2004
Balance at beginning of period	$	2,937		$	—
Capitalized exploratory well costs charged to expense upon the adoption of FSP FAS 19-1		—			—
Additions to capitalized exploratory well costs pending the determination of proved reserves		1,752			5,562	*
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(3,523	)		(2,625	)
Capitalized exploratory well costs charged to expense		(214	)		—	*


Balance at end of period	$	952		$	2,937


	*	Amounts revised by $641 from that reported in the Company’s 2004 Annual Report on Form 10-K due to changes between the draft FSP 19-a and the final FSP19-1. The final FSP directs that costs suspended and expensed in the same annual period not be included in this analysis. Amounts for the year ended December 31, 2003 have not been presented as all exploratory well costs were suspended and expensed during 2003.

At September 30, 2005, the Company had no exploratory well costs capitalized for a period of greater than one year after the completion of drilling.

12.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The FASB recently issued the following standards which were reviewed by Whiting to determine the potential impact on our financial statements upon adoption.

In December 2004, the FASB issued Statement of Financial Accounting Standard No. 123R, Share-Based Payment (“FAS 123R”), which is a revision of FAS 123, Accounting for Stock-Based Compensation. FAS 123R, supersedes APB Opinion No 25, Accounting for Stock Issued to Employee, and amends FAS 95, Statement of Cash Flows. FAS 123R requires all share-based payments to employees, including restricted stock grants, to be recognized in the financial statements based on their fair values, beginning with the first interim or annual period of the registrant’s first fiscal year beginning on or after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123R also requires the tax benefits in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as currently required. The impact of adoption is anticipated to have a minimal impact on the Company’s results of operations, financial position and liquidity.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of

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these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of FIN 47 is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

13.

SUBSEQUENT EVENTS

Acquisition of North Ward Estes and Ancillary Properties—On October 4, 2005, Whiting Oil and Gas acquired the operated interest in the North Ward Estes field in Ward and Winkler counties, Texas, and certain smaller fields located in the Permian Basin from Celero. The purchase price was approximately $459.2 million, consisting of $442.0 million in cash and 441,500 shares of the Company’s common stock, for estimated proved reserves of approximately 492.5 Bcfe as of the acquisition effective date of July 1, 2005, resulting in a cost of approximately $0.93 per Mcfe of estimated proved reserves. Future development costs of the proved undeveloped reserves are estimated at approximately $422.0 million. The average daily production from the properties was approximately 29.6 MMcfe per day as of the acquisition effective date. The Company funded the cash portion of the purchase price with the net proceeds from the Company’s public offering of common stock and private placement of 7% Senior Subordinated Notes due 2014, both of which closed on October 4, 2005 and are further discussed below. The shares of common stock the Company issued to Celero were previously registered with the Securities and Exchange Commission pursuant to an acquisition shelf registration statement.

Common Stock Offering—On October 4, 2005, the Company completed its public offering of 6,612,500 shares of its common stock. The offering was priced at $43.60 per share to the public. The number of shares includes the sale of 862,500 shares pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds to the Company were approximately $277.0 million.

7% Senior Subordinated Notes Private Placement—On October 4, 2005, the Company completed the private placement of $250 million aggregate principal amount of 7% Senior Subordinated Notes due 2014 pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The notes are unsecured and subordinated to the Company’s senior debt. The notes rank equally with the Company’s outstanding 7¹/4% Senior Subordinated Notes due 2012 and 7¹/4% Senior Subordinated Notes due 2013 and any senior subordinated debt the Company incurs in the future. The notes will rank senior to any subordinated debt the Company may incur in the future.

The notes were issued at par, the indenture governing the notes contains restrictive covenants that may limit the Company’s and its subsidiaries’ ability to, among other things pay cash dividends, redeem or repurchase capital stock or subordinated debt, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer substantially all of the Company’s or the Restricted Subsidiaries’ assets taken as a whole and enter into hedging contracts. These covenants may limit the discretion of the Company’s management in operating the Company’s business. In addition, Whiting Oil and Gas’ credit agreement restricts the ability of the Company’s operating subsidiaries to make certain payments, including principal on the notes, to the Company. Three of the Company’s subsidiaries, Whiting Oil and Gas, Equity Oil Company and Whiting Programs, Inc. (the “Guarantors”), have fully, unconditionally, jointly and severally guaranteed the Company’s obligations under the notes. All of the Company’s subsidiaries other than the Guarantors are minor within the meaning of Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange Commission, and the Company has no independent assets or operations.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its operating subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company. When the context requires, we refer to these entities separately.

Forward-Looking Statements

This report contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Some, but not all, of the risks and uncertainties include: declines in oil or natural gas prices; our level of success in exploitation, exploration, development and production activities; the timing of our exploration and development expenditures, including our ability to obtain drilling rigs; our ability to obtain external capital to finance acquisitions; our ability to identify and complete acquisitions and to successfully integrate acquired businesses and properties, including our ability to realize cost savings from completed acquisitions, including the properties acquired from Celero Energy, LP (“Celero”); unforeseen underperformance of or liabilities associated with acquired properties, including the properties acquired from Celero; inaccuracies of our reserve estimates or our assumptions underlying them; failure of our properties to yield oil or natural gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and natural gas operations; our inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and natural gas operations; risks related to our level of indebtedness and periodic redeterminations of our borrowing base under our credit facility; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and natural gas industry; and risks arising out of our hedging transactions. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

Overview

We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. Over the last four years, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development. Our drilling activity is directed at this development; specifically on projects that we believe provide repeatable successes in particular fields.

Our combination of acquisitions and development allows us to direct our capital resources to what we believe to be the most advantageous investments. We have historically acquired operated as well as non-operated properties that meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending. In some instances, we have been able to acquire non-operated property interests at attractive rates of return that provided a foothold in a new area of interest or complemented our existing

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operations. We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria. In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis. We sell properties when management is of the opinion that the sale price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.

On October 4, 2005, we acquired the operated interest in the North Ward Estes field and certain other smaller fields located in the Permian Basin from Celero Energy, LP (“Celero”), acquiring total estimated proved reserves as of the effective date of the acquisition of approximately 492.5 Bcfe for a purchase price of $459.2 million, consisting of $442.0 million in cash and 441,500 shares of our common stock. On August 4, 2005, we acquired the operated interest contained in producing oil and gas fields located in the Postle Field in the Oklahoma Panhandle from Celero, acquiring total estimated proved reserves as of the effective date of the acquisition of approximately 241.5 Bcfe for a purchase price of $343.0 million. On June 23, 2005, we acquired all of the limited partnership interests in three institutional partnership managed by our wholly-owned subsidiary, Whiting Programs, Inc., acquiring total estimated proved reserves as of the effective date of the acquisition of approximately 17.4 Bcfe for a purchase price of $30.5 million. On March 31, 2005, we acquired operated interests in five producing gas fields in the Green River Basin of Wyoming, acquiring total estimated proved reserves as of the effective date of the acquisition of approximately 50.5 Bcfe for a purchase price of $65.0 million. During 2004, we completed seven separate acquisitions of producing properties with a combined purchase price of $535.1 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 436.1 Bcfe. Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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Results of Operations

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Selected Operating Data:


	Nine Months Ended
	September 30,
	2005			2004
Net production:
Natural gas (MMcf)		22,377			17,098
Oil (MBbls)		4,666			2,158
MMcfe		50,373			30,046
Oil and gas sales (in thousands)
Natural gas	$	139,810		$	90,603
Oil	$	235,019		$	75,805
Average sales prices:
Natural gas (per Mcf)	$	6.25		$	5.30
Effect of natural gas hedges on average price (per Mcf)	$	(0.08	)	$	—

Natural gas net of hedging (per Mcf)	$	6.17		$	5.30


Oil (per Bbl)	$	50.37		$	35.13
Effect of oil hedges on average price (per Bbl)	$	(4.05	)	$	(1.68	)

Oil net of hedging (per Bbl)	$	46.32		$	33.45


Additional data (per Mcfe):
Sales price, net of hedging	$	7.03		$	5.42
Lease operating expenses	$	1.40		$	1.15
Production taxes	$	0.49		$	0.34
Depreciation, depletion and amortization expense	$	1.28		$	1.15
General and administrative expenses	$	0.43		$	0.47

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $208.4 million to $374.8 million in the first nine months of 2005 compared to the first nine months of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 67.7% between periods on an Mcfe basis. The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset natural decline. Our production volumes in the first nine months of 2005 were less than anticipated due in part to delays in rig availability that have caused delays in our development drilling program and temporary pipeline shut downs and workover activity in the first quarter of 2005, as well as reductions related to Hurricanes Katrina and Rita. During the third quarter of 2005, a total of approximately 100 MMcfe of production was shut-in due to the hurricanes. Our average price for natural gas sales increased 17.9% and our average price for crude oil increased 43.4% between periods.

Loss on Oil and Natural Gas Hedging Activities. We hedged 60% of our natural gas volumes during the first nine months of 2005 incurring a hedging loss of $1.8 million and 22% of our natural gas volumes during the first nine months of 2004 incurring no hedging loss or gain. We hedged 61% of our oil volumes during the first nine months of 2005 incurring a hedging loss of $18.9 million, and 42% of our oil volumes during the first nine months of 2004 incurring a hedging loss of $3.6 million. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of October 17, 2005.

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Gain on Sale of Marketable Securities. During the initial nine months of 2004, we sold all of our holdings in Delta Petroleum, Inc., which trades publicly under the symbol “DPTR”. We realized gross proceeds of $5.4 million and recognized a gain on sale of $4.8 million. At September 30, 2005, we had no investments in marketable securities.

Gain on Sale of Oil and Gas Properties. During the third quarter of 2004, we sold certain undeveloped acreage held by production in Wyoming. No value had been assigned to the acreage when we acquired it over five years ago. As a result, the recognized gain on sale was equal to the gross proceeds of $1.0 million.

Lease Operating Expenses. Our lease operating expense increased approximately $36.1 million to $70.7 million in the first nine months of 2005 compared to the first nine months of 2004. The increase resulted primarily from costs associated with new property acquisitions over the past year. Our lease operating expense as a percentage of oil and gas sales decreased from 20.8% during the first nine months of 2004 to 18.9% during the first nine months of 2005 as lease operating costs increases did not keep pace with sales price increases. Our lease operating expenses per Mcfe increased from $1.15 during the first nine months of 2004 to $1.40 during the same period in 2005. The increase of 21.7% was primarily caused by higher cost for electric power, increases in the cost of oil field goods and services due to the increased demand in the industry and operating costs of approximately $2.00 per Mcfe related to the secondary and tertiary recovery methods at the Postle field.

Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in the various taxing jurisdictions. Our production taxes for the first nine months of 2005 and 2004 were 6.6% and 6.1% of oil and natural gas sales, respectively. The increase in tax rates between periods was related to product price increases that eliminate certain exemptions and move us into higher tax tiers in our various tax jurisdictions.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $29.9 million to $64.4 million during the first nine months of 2005 compared to $34.5 million for the same period in 2004. The increase resulted from increased production due to our recent acquisitions and an increase in the DD&A rate. On an Mcfe basis, the rate increased from $1.15 during 2004 to $1.28 in 2005. The increase in rate is primarily due to our 2004 all sources finding, development and acquisition cost which averaged $1.28 per Mcfe, which was higher than our historical average rate. Also contributing to the DD&A rate increase is the increase in the Company’s drilling expenditures as costs to develop proved undeveloped reserves are not considered for DD&A purposes until incurred. In addition, the acquisition cost of the Postle field was approximately $1.42 per Mcfe, causing an increase to the overall rate. Changes to the pricing environment can also impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):


	Nine Months Ended September 30,
	2005		2004
Depletion	$	61,745	$	32,736
Depreciation		920		550
Accretion of asset retirement obligations		1,735		1,214

Total	$	64,400	$	34,500

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Exploration and Impairment. Our exploration and impairment costs increased $7.3 million to $12.0 million in the first nine months of 2005 compared to the first nine months of 2004.


	Nine Months Ended September 30,
	2005		2004
Exploration	$	10,071	$	2,534
Impairment		1,928		2,152

Total	$	11,999	$	4,686

The higher exploratory costs resulted from five exploratory dry holes drilled during 2005 totaling $3.1 million, compared to two exploratory dry holes in first nine months of 2004 totaling $214. In addition, we incurred increased geological and geophysical costs to support the increase in our development drilling budget from $79.4 million in 2004 to approximately $180 million in 2005. The impairment charge in 2005 relates primarily to unrecoverable costs associated with our investment in the Cherokee Basin of Kansas. The impairment charge in 2004 represented the write down of cost associated with the High Island field located off the coast of Texas.

General and Administrative Expenses. We report general and administrative expense net of reimbursements. The components of our general and administrative expense were as follows (in thousands):


	Nine Months Ended September 30,
	2005			2004
General and administrative expenses	$	29,389		$	18,016
Reimbursements		(7,753	)		(3,825	)

General and administrative expense, net	$	21,636		$	14,191

General and administrative expense before reimbursements increased $11.4 million to $29.4 million during the first nine months of 2005 compared to $18.0 million during the same period in 2004. The largest components of the increase related to costs associated with salaries and related benefits and taxes of $5.2 million and our production participation plan of $4.7 million. The increase in salaries was due primarily to an increase in the employee base due to our continued growth. The increased cost of the production participation plan was caused primarily by increased production and increased average prices between the first nine months of each year. The increase in reimbursements was caused by an increase in operated properties due to acquisition and drilling activity during the last half of 2004 and the first nine months of 2005. Our net general and administrative expense decreased between periods from $0.47 to $0.43 per Mcfe due primarily to the efficiencies of spreading fixed costs over a larger production base. As a percentage of oil and gas sales, our general and administrative expense also decreased from 8.5% during the first nine months of 2004 to 5.8% during the same period in 2005 as general and administrative costs increased slower than oil and gas sales prices.

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Interest Expense. The components of our interest expense were as follows (in thousands):


	Nine Months Ended September 30,
	2005		2004
Credit Agreement	$	5,918	$	3,875
7¹/4% Senior Subordinated Notes due 2012		7,175		2,778
7¹/4% Senior Subordinated Notes due 2013		7,198		—
Alliant Energy		113		113
Amortization of debt issue costs and debt discount		2,754		1,025
Accretion of tax sharing liability		1,860		1,800

Total interest expense	$	25,018	$	9,591

The increase in interest expense is primarily due to the May 2004 issuance of $150.0 million of 7-1/4% Senior Subordinated Notes due 2012 and the April 2005 issuance of $220.0 million of 7-1/4% Senior Subordinated Noted due 2013. The additional cash interest cost and additional amortization of debt issue costs and debt discount in 2005 is due to the greater number of days that each instrument was outstanding versus the prior year. In August of 2004, $75.0 million of the face amount of the 7-1/4% Senior Subordinated Notes due 2012 notes were swapped to a floating rate. At May 1, 2005, the floating rate component was set at 5.76% through November 1, 2005.

Our weighted average debt outstanding during the initial nine months of 2005 was $441.6 million versus $180.9 million during the initial nine months of 2004. Our weighted average effective cash interest rate was 6.2% during the first nine months of 2005 versus 4.9% during the same period in 2004. After inclusion of noncash interest costs related to the amortization of debt issue costs and debt discount and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 7.0% during the first nine months of 2005 versus 6.1% during the same period in 2004.

Income Tax Expense. Income tax expense totaled $52.5 million for the first nine months of 2005 and $23.5 million for the same period in 2004, resulting in effective income tax rates of 38.6% for both periods. We reported current income tax expense of $0.4 million in the first nine months of 2004 since our net operating loss carryforward from 2003 was sufficient to offset the majority of taxable income generated during the first nine months of 2004. During the first nine months of 2005, we estimated that our 2005 cash tax liability would approximate 17% of the 2005 tax provision and have reflected this as current tax expense.

Net Income. Net income increased from $37.4 million during the first nine months of 2004 to $83.6 million during the first nine months of 2005. The primary reasons for this increase included 35.5% higher crude oil and natural gas prices net of hedging between periods and a 67.7% increase in equivalent volumes sold, offset by higher lease operating expense, production taxes, general and administrative, DD&A, interest and exploration and impairment costs in the first nine months of 2005 due primarily to our growth.

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Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

Selected Operating Data:


	Three Months Ended
	September 30,
	2005			2004
Net production:
Natural gas (MMcf)		7,400			6,128
Oil (MBbls)		1,713			857
MMcfe		17,678			11,270
Oil and gas sales (in thousands)
Natural gas	$	54,314		$	32,341
Oil	$	99,072		$	33,557
Average sales prices:
Natural gas (per Mcf)	$	7.34		$	5.28
Effect of natural gas hedges on average price (per Mcf)	$	(0.24	)	$	—

Natural gas net of hedging (per Mcf)	$	7.10		$	5.28


Oil (per Bbl)	$	57.84		$	39.16
Effect of oil hedges on average price (per Bbl)	$	(6.98	)	$	(2.38	)

Oil net of hedging (per Bbl)	$	50.86		$	36.78


Additional data (per Mcfe):
Sales price, net of hedging	$	7.90		$	5.67
Lease operating expenses	$	1.57		$	1.15
Production taxes	$	0.57		$	0.35
Depreciation, depletion and amortization expense	$	1.32		$	1.15
General and administrative expenses	$	0.46		$	0.54

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $87.5 million to $153.4 million in the third quarter of 2005 compared to the third quarter of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 56.9% between periods on an Mcfe basis. The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset natural decline. Our production volumes in the third quarter of 2005 were less than anticipated due in part to delays in rig availability that have caused delays in our development drilling program, in addition to reductions related to Hurricanes Katrina and Rita. Our average price for natural gas sales increased 39.0% and our average price for crude oil increased 47.7% between periods.

Loss on Oil and Natural Gas Hedging Activities. We hedged 61% of our natural gas volumes during the third quarter of 2005 incurring a hedging loss of $1.8 million. During the third quarter of 2004 we hedged 19.6% our natural gas volumes but did not incur any hedging gain or loss. We hedged 62% of our oil volumes during the third quarter of 2005 incurring a hedging loss of $11.9 million, and 35.0% of our oil volumes during the third quarter of 2004 incurring a loss of $2.1 million. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of October 17, 2005.

Lease Operating Expenses. Our lease operating expense increased approximately $14.8 million to $27.8 million in the third quarter of 2005 compared to the same period in 2004. The increase resulted primarily from costs associated with new property acquisitions over the past year. Our lease operating expense as a percentage of oil and gas sales decreased from 19.7% during the third quarter

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of 2004 to 18.1% during the third quarter of 2005 as lease operating costs increases did not keep pace with sales price increases. Our lease operating expenses per Mcfe increased from $1.15 during the third quarter of 2004 to $1.57 during the third quarter of 2005. The increase of 36.5% was primarily caused by higher cost for electric power, increases in the cost of oil field goods and services due to the increased demand in the industry and operating costs of approximately $2.00 per Mcfe related to the secondary and tertiary recovery methods at the Postle field.

Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in the various taxing jurisdictions. Our production taxes for the third quarters of 2005 and 2004 were 6.6% and 6.0% of oil and natural gas sales, respectively. The increase in tax rates between periods was related to product price increases that eliminate certain exemptions and move us into higher tax tiers in our various tax jurisdictions.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $10.3 million to $23.3 million during the third quarter of 2005 compared to $13.0 million for the same period in 2004. The increase resulted from increased production due to our recent acquisitions and an increase in the DD&A rate. On an Mcfe basis, the rate increased from $1.15 during 2004 to $1.32 in 2005. The increase in rate is primarily due to our 2004 all sources finding, development and acquisition cost which averaged $1.28 per Mcfe, which was higher than our historical average rate. Also contributing to the DD&A rate increase is the increase in the Company’s drilling expenditures as costs to develop proved undeveloped reserves are not considered for DD&A purposes until incurred. In addition, the acquisition cost of the Postle field was approximately $1.42 per Mcfe, causing an increase to the overall rate. Changes to the pricing environment can also impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):


	Three Months Ended September 30,
	2005		2004
Depletion	$	22,337	$	12,366
Depreciation		360		190
Accretion of asset retirement obligations		621		454

Total	$	23,318	$	13,010

Exploration and Impairment. Our exploration costs increased $830 to $4.6 million in the third quarter of 2005 compared to the same quarter of 2004.


	Three Months Ended September 30,
	2005		2004
Exploration	$	4,596	$	1,614
Impairment		—		2,152

Total	$	4,596	$	3,766

The higher exploratory costs resulted from two exploratory dry holes drilled during the third quarter of 2005 totaling $1.3 million, compared to no exploratory dry holes in the third quarter of 2004. In addition, we increased purchases of seismic and increased geological and geophysical costs to support the increase in our development drilling budget from $79.4 million in 2004 to approximately $180 million in 2005. The 2004 impairment charge represented the write down of costs associated with the High Island field located off the coast of Texas.

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General and Administrative Expenses. We report general and administrative expense net of reimbursements. The components of our general and administrative expense were as follows (in thousands):


	Three Months Ended September 30,
	2005			2004
General and administrative expenses	$	10,750		$	7,386
Reimbursements		(2,609	)		(1,269	)

General and administrative expense, net	$	8,141		$	6,117

General and administrative expense before reimbursements increased $3.4 million to $10.8 million during the third quarter of 2005 compared to $7.4 million during the same quarter of 2004. The largest components of the increase related to increased salaries with related benefits and taxes of $1.7 million and costs associated with our production participation plan of $1.5 million. The increase in salaries was due primarily to an increase in the employee base due to our continued growth. The increased cost of the production participation plan was caused primarily by increased production and increased average prices between the third quarters of each year. The increase in reimbursements was caused by an increase in operated properties due to acquisition and drilling activity during the last half of 2004 and the first nine months of 2005. Our general and administrative expense decreased between periods from $0.54 to $0.46 per Mcfe due primarily to the efficiencies of spreading fixed costs over a larger production base. As a percentage of oil and gas sales, our general and administrative expense also decreased from 9.3% during the third quarter of 2004 to 5.3% during the third quarter of 2005 as general and administrative costs increased slower than oil and gas sales prices.

Interest Expense. The components of our interest expense were as follows (in thousands):


	Three Months Ended September 30,
	2005		2004
Credit Agreement	$	3,485	$	803
7¹/4% Senior Subordinated Notes due 2012		2,451		2,365
7¹/4% Senior Subordinated Notes due 2013		3,988		—
Alliant Energy		38		38
Amortization of debt issue costs and debt discount		1,058		366
Accretion of tax sharing liability		620		600

Total interest expense	$	11,640	$	4,172

The increase in cash interest expense and additional amortization of debt issue costs and debt discount in 2005 is primarily due to the April 2005 issuance of $220.0 million of 7-1/4% Senior Subordinated Noted due 2013 and higher weighted average amounts outstanding under our credit agreement. In August of 2004, $75.0 million of the face amount of the 7-1/4% Senior Subordinated Notes due 2012 notes were swapped to a floating rate. At May 1, 2005, the floating rate component was set at 5.76% through November 1, 2005.

Our weighted average debt outstanding during the third quarter of 2005 was $627.6 million versus $222.3 million during the third quarter of 2004. Our weighted average effective cash interest rate was 6.3% during the third quarter of 2005 versus 5.8% during the third quarter of 2004. After inclusion of noncash interest costs related to the amortization of debt issue costs and debt discount and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 7.0% during the third quarter of 2005 versus 6.6% during the third quarter of 2004.

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Income Tax Expense. Income tax expense totaled $20.9 million for the third quarter of 2005 and $9.0 million for the same quarter in 2004, resulting in effective income tax rates of 38.6% for both periods. We reported current income tax expense of $0.4 million in the third quarter of 2004 since our net operating loss carryforward from 2003 was sufficient to offset the majority of taxable income generated during the third quarter of 2004. During the third quarter of 2005, we estimated that our full year cash tax liability will approximate 17% of the tax provision and have reflected the required adjustment as current tax expense.

Net Income. Net income increased from $14.3 million during the third quarter of 2004 to $33.3 million during the third quarter of 2005. The primary reasons for this increase included 37.8% higher crude oil and natural gas prices net of hedging between periods and a 56.9% increase in equivalent volumes sold, offset by higher lease operating expense, production taxes, general and administrative, DD&A, exploration and interest costs in the third quarter of 2005 due to our growth.

Liquidity and Capital Resources

Overview. At December 31, 2004, our debt to total capitalization ratio was 34.9%, we had $1.7 million of cash on hand and $612.4 million of stockholders’ equity. Through the first nine months of 2005, we generated $211.4 million from operating activities. Cash flows from operating activities were up from prior year levels primarily due to higher realized natural gas and oil prices and volumes. Through the first nine months of 2005, we generated $402.0 million from financing activities primarily due to the 7-1/4% Senior Subordinated Notes due 2013 issued in April 2005 and borrowings under our credit agreement. We used these sources of cash in the first nine months of 2005 to finance acquisitions of $457.8 million and drilling capital expenditures of $114.6 million. At September 30, 2005, our debt to total capitalization ratio was 53.7%, we had $7.5 million of cash on hand and $636.0 million of stockholders’ equity.

We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures for the further development of our property base are approximately $180.0 million during 2005, of which we incurred $114.6 million in the first nine months of 2005. Our 2005 budget is an increase from the $79.4 million incurred on capitalized development during 2004 and the $40.3 incurred in 2003. We also spent $457.8 million on acquisitions in the first nine months of 2005 and $445.6 million on acquisitions in the same period of 2004, funded primarily by borrowings under Whiting Oil and Gas’s credit agreement. A portion of the borrowings for the 2004 acquisitions were repaid in the fourth quarter of 2004 using approximately $240 million of proceeds from our secondary offering of 8.6 million shares of common stock. Although we have no specific budget for property acquisitions, we will continue to seek property acquisition opportunities that complement our existing core property base. We expect to fund our 2005 development expenditures from internally generated cash flow and cash on hand. If attractive acquisition opportunities arise or development expenditures exceed $180.0 million, then we believe that we could finance the additional capital expenditures with cash on hand, operating cash flow, borrowings under our credit agreement, issuances of additional equity or debt securities, or development with industry partners. Our level of capital expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.

Credit Agreement. On August 31, 2005, our wholly-owned subsidiary, Whiting Oil and Gas, entered into an amended and restated $1.2 billion credit agreement with a syndicate of banks. The new credit agreement increased our borrowing base to $675.0 million from $480.0 million under the prior credit agreement. The borrowing base under the credit agreement increased to $850.0 million after the closing of our acquisition of the North Ward Estes properties from Celero on October 4, 2005, which was offset by a reduction in the borrowing base of $62.5 million upon the closing of our private placement of

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$250.0 million aggregate principal amount of 7% Senior Subordinated Notes due 2014 on October 4, 2005, resulting in a borrowing base of $787.5 million. See “7% Senior Subordinated Notes Private Placement”, “Acquisition of Postle Properties” and “Acquisition of North Ward Estes and Ancillary Properties” below for a further discussion of these transactions. The borrowing base under the credit agreement is determined in the discretion of the lenders based on the collateral value of the proved reserves and is subject to regular redeterminations on May 1 and November 1 of each year as well as special redeterminations described in the credit agreement. On August 31, 2005, we borrowed $391.2 million under the credit agreement to refinance the entire outstanding balance under the prior credit agreement. As of September 30, 2005, the outstanding principal balance under the credit agreement was $370.0 million. On October 4, we repaid $100.0 million of the outstanding principal balance with the net proceeds from our public offering of common stock and the private placement of 7% Senior Subordinated Notes due 2014, resulting in an outstanding principal balance of $270.0 million under the credit agreement. See “Common Stock Offering”, “7% Senior Subordinated Notes Private Placement” and “Use of Proceeds” below for a further discussion of these transactions.

The credit agreement provides for interest only payments until August 31, 2010, when the entire amount borrowed is due. We may, throughout the five-year term of the credit agreement, borrow, repay and reborrow up to the borrowing base in effect from time to time. The lenders under the credit agreement have also committed to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of ours from time to time in an aggregate amount not to exceed $50 million. As of September 30, 2005, letters of credit totaling $0.3 million were outstanding under the credit agreement.

Interest accrues, at our option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the prime rate or the federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.00% to 1.75% depending on the utilization percentage of the borrowing base. We have consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on the utilization percentage and are included as a component of interest expense. At October 4, 2005, the effective weighted average interest rate on the entire outstanding principal balance under the credit agreement was 5.3%.

The credit agreement contains restrictive covenants that may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, change material agreements, incur liens and engage in certain other transactions without the prior consent of the lenders and requires us to maintain a debt to EBITDAX (as defined in the credit agreement) ratio of less than 3.5 to 1 and a working capital ratio (as defined in the credit agreement) of greater than 1 to 1. Except for limited exceptions, including the payment of interest on the senior notes, the credit agreement restricts the ability of Whiting Oil and Gas and Equity Oil Company to make any dividends, distributions or other payments to the Company. The restrictions apply to all of the net assets of these subsidiaries. We were in compliance with our covenants under the credit agreement as of September 30, 2005. The credit agreement is secured by a first lien on all of Whiting Oil and Gas’ properties included in the borrowing base for the credit agreement. We and our wholly-owned subsidiary, Equity Oil Company, have guaranteed the obligations of Whiting Oil and Gas under the credit agreement. We have pledged the stock of Whiting Oil and Gas and Equity Oil Company as security for our guarantee, and Equity Oil Company has mortgaged all of its properties included in the borrowing base for the credit agreement as security for its guarantee.

7-1/4% Senior Subordinated Notes. On April 19, 2005, we issued $220.0 million aggregate principal amount of our 7-1/4% Senior Subordinated Notes due 2013. The net proceeds of the offering were used to repay debt outstanding under Whiting Oil and Gas Corporation’s credit agreement.

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The 7-1/4% Senior Subordinated Notes due 2013 were issued at 98.507% of par and the associated discount is being amortized to interest expense over the term of the notes.

In May 2004, we issued $150.0 million aggregate principal amount of our 7-1/4% Senior Subordinated Notes due 2012. The 7-1/4% Senior Subordinated Notes due 2012 were issued at 99.26% of par and the associated discount is being amortized to interest expense over the term of the notes.

The notes are unsecured obligations of ours and are subordinated to all of our senior debt. The indentures governing the notes contain restrictive covenants that are substantially identical and may limit our and our subsidiaries’ ability to, among other things, pay cash dividends, redeem or repurchase our capital stock or our subordinated debt, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of ours and our restricted subsidiaries taken as a whole and enter into hedging contracts. These covenants may limit the discretion of our management in operating our business. We were in compliance with these covenants as of September 30, 2005. Three of our subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity Oil Company, have fully, unconditionally, jointly and severally guaranteed our obligations under the notes.

Common Stock Offering. On October 4, 2005, we completed a public offering of 6,612,500 shares of our common stock. The offering was priced at $43.60 per share to the public. The number of shares includes the sale of 862,500 shares pursuant to the exercise of the underwriters’ over-allotment option.

7% Senior Subordinated Notes Private Placement. On October 4, 2005, we completed the private placement of $250 million aggregate principal amount of 7% Senior Subordinated Notes due 2014 pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The notes are unsecured and subordinated to our senior debt. The notes rank equally with our outstanding 7¹/4% Senior Subordinated Notes due 2012 and 7¹/4% Senior Subordinated Notes due 2013 and any senior subordinated debt that we incur in the future. The notes will rank senior to any subordinated debt that we may incur in the future.

The notes were issued at par, the indenture governing the notes contains restrictive covenants that may limit our and our subsidiaries’ ability to, among other things pay cash dividends, redeem or repurchase capital stock or subordinated debt, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer substantially all of our or the restricted subsidiaries’ assets taken as a whole and enter into hedging contracts. These covenants may limit the discretion of our management in operating our business. In addition, Whiting Oil and Gas’ credit agreement restricts the ability of our subsidiaries to make certain payments, including principal on the notes, to us. Three of our subsidiaries, Whiting Oil and Gas, Equity Oil Company and Whiting Programs, Inc., have fully, unconditionally, jointly and severally guaranteed our obligations under the notes.

Use of Proceeds. We received net proceeds of approximately $277.0 million from the common stock offering and approximately $244.5 million from the private placement of the notes, in each case after deducting underwriting discounts and commissions and estimated expenses of the offering. We used the net proceeds from the offerings to pay the cash portion of the purchase price for the acquisition of the North Ward Estes and ancillary properties and to repay $100.0 million of the debt currently outstanding under Whiting Oil and Gas’ credit agreement that was incurred in connection with the acquisition of the Postle properties from Celero. After such transactions, our debt to capitalization ratio was 49%.

Alliant Energy Promissory Note. In conjunction with our initial public offering in November 2003, we issued a promissory note payable to Alliant Energy Corporation, our former parent

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company, in the aggregate principal amount of $3.0 million. The note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005.

Tax Separation and Indemnification Agreement with Alliant Energy. In connection with our initial public offering in November 2003, we entered into a tax separation and indemnification agreement with Alliant Energy. Pursuant to this agreement, we and Alliant Energy made a tax election with the effect that the tax basis of the assets of Whiting Oil and Gas Corporation and its subsidiaries were increased to the deemed purchase price of their assets immediately prior to such initial public offering. We have adjusted deferred taxes on our balance sheet to reflect the new tax basis of our assets. This additional basis is expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by us. Under this agreement, we have agreed to pay to Alliant Energy 90% of the future tax benefits we realize annually as a result of this step up in tax basis for the years ending on or prior to December 31, 2013. Such tax benefits will generally be calculated by comparing our actual taxes to the taxes that would have been owed by us had the increase in basis not occurred. In 2014, we will be obligated to pay Alliant Energy the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. The initial recording of this transaction in November 2003 resulted in a $57.2 million increase in deferred tax assets, a $28.6 million discounted payable to Alliant Energy and a $28.6 million increase to stockholders’ equity. During 2004 and the first nine months of 2005, we did not make any payments under this agreement but did recognize $2.4 million and $1.9 million, respectively, of accretion expense, which is included as a component of interest expense. Our estimate of payments to be made under this agreement of $4.2 million in 2005 is reflected as a current liability at September 30, 2005.

Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of September 30, 2005 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods. This table does not include asset retirement obligations or production participation plan liabilities since we cannot determine with accuracy the timing of future payments. The table also does not include cash interest expense related to our credit agreement since we cannot determine with accuracy the timing of future loan advances, repayments or interest rates. Cash interest expense on the 7-1/4% Senior Subordinated Notes due 2012 and 2013 is estimated assuming no principal repayment until the due date. The interest rate swap on the $75.0 million of our $150.0 million 7-1/4% Senior Subordinated Note due 2012 is assumed to equal 5.76% until the note is paid.


	Payments due by period
			Less than 1						More than
Contractual Obligations	Total		year		2-3 years		4-5 years		5 years
Long-Term Debt	$	738,903	$	3,280	$	—	$	370,000	$	365,623
Cash Interest Expense on Notes		193,760		25,708		51,416		51,416		65,220
Operating Lease		7,467		1,469		2,938		2,938		122
Tax Separation and Indemnification Agreement with Alliant Energy⁽¹⁾		33,040		4,214		8,273		6,961		13,592

Total	$	973,170	$	34,671	$	62,627	$	431,315	$	444,557


(1)		Amounts shown are estimates based on estimated future income tax benefits from the increase in tax basis described under “Tax Separation and Indemnification Agreement with Alliant Energy” above.

Price-sharing Arrangement. As part of a 2002 purchase transaction, we agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2005 increased to 50% of the actual price received in excess of $20.16 per barrel. As of September 30, 2005, approximately 41,000 net barrels of crude oil per month

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(6.8% of September 2005 estimated net crude oil production) are subject to this sharing agreement. The terms of the agreement do not provide for a maximum amount to be paid. During the first nine months of 2005, we paid $5.1 million under this agreement. As of September 30, 2005, we have accrued an additional $0.9 million as currently payable.

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 123R, Share-Based Payment (“FAS 123R”), which is a revision of FAS 123, Accounting for Stock-Based Compensation. FAS 123R supersedes APB Opinion No 25, Accounting for Stock Issued to Employees, and amends FAS 95, Statement of Cash Flows. FAS 123R requires all share-based payments to employees, including restricted stock grants, to be recognized in the financial statements based on their fair values, beginning with the first interim or annual period of the registrant’s first fiscal year beginning on or after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123R also requires the tax benefits in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as currently required. The impact of adoption is anticipated to have a minimal impact on the Company’s results of operations, financial position and liquidity.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of FIN 47 is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2004. No material changes to such information have occurred during the nine months ended September 30, 2005.

Effects of Inflation and Pricing

We experienced increased costs during 2004 and the first nine months of 2005 due to increased demand for oil field products and services. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. When prices decline, associated costs do not necessarily decline at the same rate. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, continued high prices for oil and natural gas could result in increases in the cost of electricity, material, services and personnel.

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Acquisition of Postle Properties

On August 4, 2005, Whiting Oil and Gas acquired the operated interest in producing oil and natural gas fields located in the Postle Field in the Oklahoma Panhandle from Celero. The purchase price was $343.0 million for estimated proved reserves of approximately 241.5 Bcfe as of the acquisition effective date, resulting in a cost of approximately $1.42 per Mcfe of estimated proved reserves. Future development costs of the proved undeveloped reserves are estimated at approximately $111.0 million. We funded the acquisition through borrowings under Whiting Oil and Gas’ credit agreement.

Acquisition of North Ward Estes and Ancillary Properties

On October 4, 2005, Whiting Oil and Gas acquired the operated interest in the North Ward Estes Field in Ward and Winkler counties, Texas, and certain smaller fields located in the Permian Basin from Celero. The purchase price was approximately $459.2 million, consisting of $442.0 million in cash and 441,500 shares of our common stock, for estimated proved reserves of approximately 492.5 Bcfe as of the acquisition effective date, resulting in a cost of approximately $0.93 per Mcfe of estimated proved reserves. Future development costs of the proved undeveloped reserves are estimated at approximately $422.0 million. The average daily production from the properties was approximately 29.6 MMcfe per day as of the acquisition effective date. We funded the cash portion of the purchase price with the net proceeds from our public offering of common stock and private placement of 7% Senior Subordinated Notes due 2014, both of which closed on October 4, 2005. The shares of common stock we issued to Celero were previously registered with the Securities and Exchange Commission pursuant to an acquisition shelf registration statement.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Our quantitative and qualitative disclosures about market risk for changes in commodity prices and interest rates are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2004 and have not materially changed since that report was filed.

Our outstanding hedges at October 17, 2005 are summarized below:

Monthly Volume

NYMEX

Commodity

Period

(MMBtu)/(Bbl)

Floor/Ceiling

Natural Gas

10/2005 to 12/2005

1,500,000

4.50/$10.00

Natural Gas

01/2006 to 03/2006

750,000

5.90/$10.30

Natural Gas

01/2006 to 03/2006

450,000

6.00/$16.00

Natural Gas

01/2006 to 03/2006

300,000

6.00/$17.00

Natural Gas

04/2006 to 06/2006

600,000

6.00/$10.10

Natural Gas

04/2006 to 06/2006

1,000,000

6.00/$10.12

Natural Gas

07/2006 to 09/2006

600,000

6.00/$10.28

Natural Gas

07/2006 to 09/2006

1,000,000

6.00/$10.38

Natural Gas

10/2006 to 12/2006

600,000

6.00/$12.28

Natural Gas

10/2006 to 12/2006

1,000,000

6.00/$12.18

Natural Gas

01/2007 to 03/2007

600,000

6.00/$15.20

Natural Gas

01/2007 to 03/2007

1,000,000

6.00/$15.52

Crude Oil

10/2005 to 12/2005

125,000

35.00/$60.55

Crude Oil

10/2005 to 12/2005

125,000

35.00/$65.75

Crude Oil

10/2005 to 12/2005

110,000

50.00/$75.00

Crude Oil

10/2005 to 12/2005

50,000

50.00/$80.50

Crude Oil

01/2006 to 03/2006

250,000

40.00/$51.50

Crude Oil

01/2006 to 03/2006

110,000

50.00/$76.55

Crude Oil

01/2006 to 03/2006

50,000

50.00/$82.25

Crude Oil

04/2006 to 06/2006

125,000

45.00/$82.80

Crude Oil

04/2060 to 06/2006

215,000

50.00/$73.80

Crude Oil

04/2006 to 06/2006

110,000

50.00/$76.20

Crude Oil

07/2006 to 09/2006

125,000

45.00/$81.90

Crude Oil

07/2006 to 09/2006

215,000

50.00/$72.90

Crude Oil

07/2006 to 09/2006

110,000

50.00/$75.25

Crude Oil

10/2006 to 12/2006

125,000

45.00/$81.10

Crude Oil

10/2006 to 12/2006

215,000

50.00/$72.05

Crude Oil

10/2006 to 12/2006

110,000

50.00/$74.30

Crude Oil

01/2007 to 03/2007

125,000

45.00/$81.00

Crude Oil

01/2007 to 03/2007

215,000

50.00/$70.90

Crude Oil

01/2007 to 03/2007

110,000

50.00/$73.15

Crude Oil

04/2007 to 06/2007

110,000

50.00/$72.00

Crude Oil

04/2007 to 06/2007

300,000

50.00/$78.50

Crude Oil

07/2007 to 09/2007

110,000

50.00/$70.90

Crude Oil

07/2007 to 09/2007

300,000

50.00/$77.55

Crude Oil

10/2007 to 12/2007

110,000

49.00/$71.50

Crude Oil

10/2007 to 12/2007

300,000

50.00/$76.50

Crude Oil

01/2008 to 03/2008

110,000

49.00/$70.65

Crude Oil

04/2008 to 06/2008

110,000

48.00/$71.60

Crude Oil

07/2008 to 09/2008

110,000

48.00/$70.85

Crude Oil

10/2008 to 12/2008

110,000

48.00/$70.20

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The collared hedges shown above have the effect of providing a protective floor while allowing us to share in upward pricing movements. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the 2005 natural gas contracts listed above, a hypothetical $0.10 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause a change in the gain (loss) on hedging activities in the fourth quarter of $150,000. For the 2005 crude oil contracts listed above, a hypothetical $1.00 change in the NYMEX price would cause a change in the gain (loss) on hedging activities in the fourth quarter of $410,000.

We have also entered into fixed price marketing contracts directly with end users for a portion of the natural gas we produce in Michigan. All of those contracts have built-in pricing escalators of 4% per year. Our outstanding fixed price marketing contracts at October 17, 2005 are summarized below:

Monthly

Volume

2005 Price

Commodity

Period

(Mmbtu)

Per Mmbtu

Natural Gas

01/2002 to 12/2011

51,000

4.39

Natural Gas

01/2002 to 12/2012

60,000

3.89

-35-

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our Vice President—Finance and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the quarter ended September 30, 2005. Based upon their evaluation of these disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Vice President—Finance and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the quarter ended September 30, 2005.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

-36-

EXHIBIT INDEX


Exhibit
Number		Exhibit Description
(2.1)		Purchase and Sale Agreement (Postle Field, Texas County, Oklahoma), dated effective as of July 1, 2005, by and between Whiting Oil and Gas Corporation and Celero Energy, LP [Incorporated by reference to Exhibit 2.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated July 26, 2005 (File No. 001-31899)].

(2.2)		Purchase and Sale Agreement (North Ward Estes Field/Wickett Area, Texas and New Mexico), dated effective as of July 1, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and Celero Energy, LP [Incorporated by reference to Exhibit 2.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated July 26, 2005 (File No. 001-31899)].

(4.1)		Third Amended and Restated Credit Agreement, dated August 31, 2005, among Whiting Oil and Gas Corporation, Whiting Petroleum Corporation, the financial institutions listed therein and JPMorgan Chase Bank, N.A., as Administrative Agent [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated August 31, 2005 (File No. 001-31899)].

(4.2)		Indenture, dated as of October 4, 2005, among Whiting Petroleum Corporation, Whiting Oil and Gas Company, Whiting Programs, Inc., Equity Oil Company and JP Morgan Trust Company, National Association, as Trustee, relating to $250 million aggregate principal amount of 7% Senior Subordinated Notes due 2015 [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 4, 2005 (File No. 001-31899)].

(4.3)		Registration Rights Agreement, dated as of October 4, 2005, Whiting Petroleum Corporation, Whiting Oil and Gas Company, Whiting Programs, Inc., Equity Oil Company, and the several initial purchasers named therein, relating to $250 million aggregate principal amount of 7% Senior Subordinated Notes due 2015 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 4, 2005 (File No. 001-31899)].

(31.1)		Certification by Chairman, President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(31.2)		Certification by the Vice President—Finance and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(32.1)		Certification of the Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

(32.2)		Certification of the Vice President—Finance and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.


Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004	1
	Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2005 and 2004	3
	Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Year Ended December 31, 2004 and the Nine Months Ended September 30, 2005	4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004	5
	Condensed Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	36

PART II—OTHER INFORMATION

Item 6.	Exhibits	37
Certification by Chairman, President and CEO Pursuant to Section 302
Certification by the VP-Finance and CFO Pursuant to Section 302
Certification by Chairman, President and CEO Pursuant to 18 U.S.C. Section 1350
Certification by the VP-Finance and CFO Pursuant to 18 U.S.C. Section 1350


	Nine Months Ended
	September 30,
	2005		2004
End of period	$	7,542	$	17,361


SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for income taxes	$	10,676	$	885

Cash paid for interest	$	10,465	$	3,592


NONCASH INVESTING ACTIVITIES:

Changes in working capital related to acquisition of property and equipment	$	10,733	$	3,350


		WHITING PETROLEUM CORPORATION

		By		/s/ James J. Volker
				James J. Volker Chairman, President and Chief Executive Officer

		By		/s/ Michael J. Stevens
				Michael J. Stevens Vice President — Finance and Chief Financial Officer

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