Edgar Filing: PETROLEUM DEVELOPMENT CORP

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

S Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2007

£ Transition Report Pursuant to Section 13 of 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File Number 000-07246

PETROLEUM DEVELOPMENT CORPORATION

(Exact name of registrant as specified in its charter)


Nevada	95-2636730
(State of incorporation)	(I.R.S. Employer Identification No.)

120 Genesis Boulevard

Bridgeport, West Virginia 26330

(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code: (304) 842-3597

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 S No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large accelerated filer £

Accelerated filer S

Non-accelerated filer £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No S

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

14,902,762 shares of the Company's Common Stock ($.01 par value) were outstanding as of October 31, 2007.

PETROLEUM DEVELOPMENT CORPORATION

INDEX

PART 1 – FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Income	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	45



PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Submission of Matters to a Vote of Security Holders	47
Item 5.	Other Information	47
Item 6.	Exhibits	48


	SIGNATURES	49

Index

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PETROLEUM DEVELOPMENT CORPORATION

Condensed Consolidated Balance Sheets

(in thousands, except share data)

	September 30,			December 31,
	2007			2006*
Assets
Current assets:
Cash and cash equivalents	$	28,612		$	194,326
Restricted cash - current		14,810			519
Accounts receivable, net		45,199			42,600
Accounts receivable - affiliates		10,288			9,235
Inventories		5,794			3,345
Fair value of derivatives		16,403			15,012
Other current assets		20,440			5,977
Total current assets		141,546			271,014
Properties and equipment, net		782,667			394,217
Restricted cash - long term		1,272			192,451
Other assets		8,266			26,605
Total assets	$	933,751		$	884,287

Liabilities and shareholders' equity
Current liabilities:
Accounts payable	$	99,663		$	67,675
Short term debt		-			20,000
Production tax liability		12,224			11,497
Other accrued expenses		7,725			9,685
Accounts payable - affiliates		28,035			7,595
Deferred gain on sale of leaseholds		-			8,000
Federal and state income taxes payable		2,512			28,698
Fair value of derivatives		2,773			2,545
Advances for future drilling contracts		2,199			54,772
Funds held for future distribution		43,955			31,367
Total current liabilities		199,086			241,834
Long-term debt		172,000			117,000
Deferred gain on sale of leaseholds		-			17,600
Other liabilities		21,222			19,400
Deferred income taxes		135,680			116,393
Asset retirement obligation		18,148			11,916
Total liabilities		546,136			524,143

Commitments and contingencies
Minority interest in consolidated limited liability company		776			-

Shareholders' equity:
Common stock, shares issued: 14,908,656 in 2007 and 14,834,871 in 2006		149			148
Additional paid-in capital		2,052			64
Retained earnings		384,847			360,102
Treasury shares, at cost: 5,531 in 2007 and 4,706 in 2006		(209	)		(170	)
Total shareholders' equity		386,839			360,144
Total liabilities and shareholders' equity	$	933,751		$	884,287

______________

*Derived from audited 2006 balance sheet.

See accompanying notes to condensed consolidated financial statements.

Index

PETROLEUM DEVELOPMENT CORPORATION

Condensed Consolidated Statements of Income

(unaudited, in thousands except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
				Revised*						Revised*
Revenues:
Oil and gas sales	$	44,437		$	30,577		$	117,699		$	86,901
Sales from natural gas marketing activities		19,934			30,374			71,845			101,445
Oil and gas well drilling operations		1,573			2,659			7,342			11,682
Well operations and pipeline income		2,092			2,536			6,682			7,312
Oil and gas price risk management, net		6,345			2,707			4,442			9,002
Other		1,894			1,964			2,122			1,988
Total revenues		76,275			70,817			210,132			218,330

Costs and expenses:
Oil and gas production and well operations cost		12,645			8,584			33,308			22,363
Cost of natural gas marketing activities		19,810			29,988			70,102			100,239
Cost of oil and gas well drilling operations		749			3,838			1,559			11,328
Exploration expense		5,337			2,180			14,795			5,286
General and administrative expense		7,513			5,357			21,823			14,178
Depreciation, depletion and amortization		20,354			8,300			50,857			22,492
Total costs and expenses		66,408			58,247			192,444			175,886

Gain on sale of leaseholds		-			328,000			25,600			328,000

Income from operations		9,867			340,570			43,288			370,444
Interest income		462			3,475			2,059			4,216
Interest expense		(2,544	)		(366	)		(4,825	)		(1,154	)

Income before income taxes		7,785			343,679			40,522			373,506
Income taxes		3,326			132,795			15,511			143,697
Net income	$	4,459		$	210,884		$	25,011		$	229,809

Earnings per common share:
Basic	$	0.30		$	13.39		$	1.70		$	14.39
Diluted	$	0.30		$	13.33		$	1.68		$	14.32
Weighted average common shares outstanding:
Basic		14,757			15,750			14,739			15,973
Diluted		14,827			15,824			14,845			16,048

___________

*See Note 1.

See accompanying notes to condensed consolidated financial statements.

Index

PETROLEUM DEVELOPMENT CORPORATION

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

	Nine Months Ended September 30,
	2007			2006
				Revised*
Cash flows from operating activities:
Net income	$	25,011		$	229,809
Adjustments to net income to reconcile to cash used in operating activities
Deferred income taxes		14,833			112,407
Depreciation, depletion and amortization		50,857			22,491
Amortization of debt issuance costs		280			89
Accretion of asset retirement obligation		712			380
Exploratory dry hole costs		969			2,486
Gain from sale of assets		(1	)		(328,000	)
Gain from sale of leaseholds		(25,600	)		(64	)
Expired and abandoned leases		1,246			24
Stock-based compensation		1,652			1,101
Unrealized gain on derivative transactions		(1,256	)		(7,592	)
Excess tax benefits from stock-based compensation		(500	)		-
Changes in assets and liabilities related to operations:
Increase in current assets		(34,879	)		(2,906	)
Decrease (increase) in other assets		220			(179	)
Decrease in current liabilities		(68,302	)		(44,970	)
Increase in other liabilities		1,958			3,613

Net cash used in operating activities		(32,800	)		(11,311	)

Cash flows from investing activities:
Capital expenditures		(158,727	)		(133,612	)
Acquisitions		(201,594	)		-
Decrease (increase) in restricted cash for property acquisition		191,178			(300,000	)
Proceeds from sale of assets		2			353,617
Proceeds from sale of leases to partnerships		682			1,184

Net cash used in investing activities		(168,459	)		(78,811	)

Cash flows from financing activities:
Proceeds from debt		238,000			232,000
Repayment of debt		(203,000	)		(171,000	)
Payment of debt issuance costs		(591	)		(160	)
Proceeds from exercise of stock options		182			31
Excess tax benefits from stock-based compensation		500			-
Minority interest investment		800			-
Purchase of treasury stock		(346	)		(52,639	)

Net cash provided by financing activities		35,545			8,232

Net decrease in cash and cash equivalents		(165,714	)		(81,890	)

Cash and cash equivalents, beginning of period		194,326			90,110
Cash and cash equivalents, end of period	$	28,612		$	8,220

_____________

*See Note 1.

See accompanying notes to condensed consolidated financial statements.

Index

Petroleum Development Corporation

Notes to Condensed Consolidated Financial Statements

September 30, 2007

(unaudited)

1. GENERAL

Petroleum Development Corporation ("PDC"), together with our consolidated entities (the "Company"), is an independent energy company engaged primarily in the exploration, development, production and marketing of oil and natural gas. Since we began oil and natural gas operations in 1969, we have grown primarily through exploration and development activities, the acquisition of producing oil and natural gas wells and the expansion of our natural gas marketing activities.

The accompanying interim condensed consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries and WWWV, LLC, an entity in which we have a controlling financial interest (see Note 6). All material intercompany accounts and transactions have been eliminated in consolidation. Minority interest in earnings and ownership has been recorded for the percentage of the LLC we do not own for each of the applicable periods. We account for our investment in interests in oil and natural gas limited partnerships under the proportionate consolidation method. Accordingly, our condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the limited partnerships in which we participate. Our proportionate share of all significant transactions between us and the limited partnerships is eliminated.

The accompanying interim condensed consolidated financial statements have been prepared without audit in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission ("SEC"). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. In our opinion, the accompanying interim condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly our financial position, results of operations and cash flows for the periods presented. The interim results of operations for the nine months ended September 30, 2007, and the interim cash flows for the same interim period, are not necessarily indicative of the results to be expected for the full year or any other future period.

The accompanying interim condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on May 23, 2007 ("2006 Form 10-K").

Items Affecting Comparability

Reclassifications have been made to the income statement data presented for the three and nine months ended September 30, 2006, both to conform to the current year presentation and to correct the prior period presentation. These reclassifications had no impact on reported net earnings, earnings per share, shareholders’ equity or total net cash flows for the related periods. Oil and gas price risk management gains of $2.7 million and $9 million for the three and nine months ended September 30, 2006, respectively, have been reclassified from non-operating gains to a component of revenues. These reclassifications and all other reclassifications are reflected in the revised amounts for the three and nine months ended September 30, 2006.

Index

As described in Note 1 to the Consolidated Financial Statements included in our 2006 Form 10-K, during the fourth quarter of 2006, we adopted SEC Staff Accounting Bulletin ("SAB") No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. In accordance with SAB No. 108, we adjusted our opening financial position for 2006 by the cumulative effect of immaterial prior period misstatements. In connection with the adoption of SAB No. 108, we determined that certain similar immaterial errors were included in the results of operations for each of the first three quarters of 2006, and as a result, the data presented in Note 19, Quarterly Financial Data, to the Consolidated Financial Statements of the 2006 Form 10-K and included herein, reflect the correction of those immaterial misstatements.

The following table presents our unaudited income statements for the three month and nine month periods ended September 30, 2006, as previously presented in our Form 10-Q for the related period, adjusted to reflect reclassifications to conform to current presentation and to correct previous presentation, and as revised to reflect the correction of immaterial prior period misstatements.

	Three Months Ended September 30, 2006									Nine Months Ended September 30, 2006
	Originally									Originally
	Reported			Reclassified⁽¹⁾			Revised ⁽²⁾			Reported			Reclassified⁽¹⁾			Revised ⁽²⁾
	(in thousands, except per share data)
Revenues:
Oil and gas sales	$	29,663		$	29,663		$	30,577		$	86,139		$	86,138		$	86,901
Sales from natural gas marketing activities		30,374			30,374			30,374			101,445			101,445			101,445
Oil and gas well drilling operations		2,659			2,659			2,659			11,682			11,682			11,682
Well operations and pipeline income		2,530			2,530			2,536			7,306			7,306			7,312
Oil and gas price risk management, net		-			2,912			2,707			-			8,714			9,002
Other		1,964			1,964			1,964			1,986			1,988			1,988
Total revenues		67,190			70,102			70,817			208,558			217,273			218,330

Costs and expenses:
Oil and gas production and well operations cost		9,961			8,762			8,584			23,627			22,793			22,363
Cost of natural gas marketing activities		29,883			29,883			29,988			100,121			100,120			100,239
Cost of oil and gas well drilling operations		4,257			4,311			3,838			11,888			11,551			11,328
Exploration expense		940			1,749			2,180			3,735			4,569			5,286
General and administrative expense		4,423			4,759			5,357			13,070			13,407			14,178
Depreciation, depletion and amortization		8,322			8,322			8,300			22,554			22,555			22,492
Total costs and expenses		57,786			57,786			58,247			174,995			174,995			175,886

Gain on sale of leaseholds		328,000			328,000			328,000			328,000			328,000			328,000

Income from operations		337,404			340,316			340,570			361,563			370,278			370,444
Interest income		3,427			3,427			3,475			4,159			4,158			4,216
Interest expense		(34	)		(34	)		(366	)		(232	)		(232	)		(1,154	)
Oil and gas price risk management, net		2,912			-			-			8,714			-			-

Income before income taxes		343,709			343,709			343,679			374,204			374,204			373,506
Income taxes		132,795			132,795			132,795			143,943			143,943			143,697
Net income	$	210,914		$	210,914		$	210,884		$	230,261		$	230,261		$	229,809

Basic earnings per common share	$	13.44		$	13.44		$	13.39		$	14.47		$	14.47		$	14.39
Diluted earnings per share	$	13.38		$	13.38		$	13.33		$	14.40		$	14.40		$	14.32

_______________

⁽¹⁾

As previously reported in the corresponding Form 10-Q, reclassified to conform to current year presentation and to correct previous presentation.

⁽²⁾

Reflects the impact of certain immaterial errors on the results originally reported in 2006.

Index

The reclassifications and revisions discussed above have no impact on the condensed consolidated balance sheets presented herein, nor do they result in changes to the net decrease in cash and cash equivalents previously presented in the Form 10-Q for the nine months ended September 30, 2006. However, certain line items within cash flows from operating activities and one line item within cash flow from investing activities for the nine months ended September 30, 2006, have been adjusted herein to reflect the impact of the income statement revisions. Revised line items are as follows:

	Nine Months Ended September 30, 2006
	Originally
	Reported			Revised ⁽¹⁾
Certain statement of cash flow line items:	(in thousands)

Net income	$	230,261		$	229,809
Deferred income taxes		112,486			112,407
Depreciation, depletion and amortization		22,554			22,491
Exploratory dry hole cost		1,769			2,486
Unrealized gain on derivative transactions		(7,305	)		(7,592	)
Increase in current assets		(3,038	)		(2,906	)
Decrease in other current liabilities		(43,396	)		(44,970	)
Increase in other liabilities		3,412			3,613

Net cash used in operating activities		(9,906	)		(11,311	)

Capital expenditures		(135,017	)		(133,612	)

Net cash used in investing activities		(80,216	)		(78,811	)

Net decrease in cash and cash equivalents		(81,890	)		(81,890	)

______________

⁽¹⁾

Reflects the impact of certain immaterial errors on the results originally reported in 2006.

2. RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

In June 2006, the Financial Accounting Standards Board ("FASB") issued Emerging Issues Task Force ("EITF") No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation). EITF 06-3 addresses the income statement presentation of any tax collected from customers and remitted to a government authority and concludes that the presentation of taxes on either a gross basis or a net basis is an accounting policy decision that should be disclosed pursuant to Accounting Principles Board ("APB") No. 22, Disclosures of Accounting Policies. For taxes that are reported on a gross basis (included in revenues and costs), EITF 06-3 requires disclosure of the amounts of those taxes in interim and annual financial statements, if those amounts are significant. EITF 06-3 became effective for interim and annual reporting periods beginning after December 15, 2006. The adoption of the standard, effective January 1, 2007, did not have a significant impact on the accompanying condensed consolidated financial statements. Our existing accounting policy, which was not changed upon the adoption of EITF 06-3, is to present taxes within the scope of EITF 06-3 on a net basis.

In July 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109, which prescribes a comprehensive model for accounting for uncertainty in tax positions. FIN No. 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements, only if the position is more likely than not of being sustained on audit by the Internal Revenue Service ("IRS"), based on the technical merits of the position. The provisions of FIN No. 48 became effective for us on January 1, 2007. The cumulative effect of applying the provisions of FIN No. 48 has been accounted for as an adjustment to retained earnings in the first quarter of 2007. The adoption of FIN No. 48 resulted in a $0.3 million cumulative effect adjustment (see Note 5 for further discussion).

Index

In May 2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN No. 48-1”). FIN No. 48-1 amends FIN No. 48 to provide guidance on how an entity should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The term “effectively settled” replaces the term “ultimately settled” when used to describe recognition, and the terms “settlement” or “settled” replace the terms “ultimate settlement” or “ultimately settled” when used to describe measurement of a tax position under FIN No. 48. FIN No. 48-1 clarifies that a tax position can be effectively settled upon the completion of an examination by a taxing authority without being legally extinguished. For tax positions considered effectively settled, an entity would recognize the full amount of tax benefit, even if the tax position is not considered more likely than not to be sustained based solely on the basis of its technical merits and the statute of limitations remains open. The adoption of FIN No. 48-1, effective January 1, 2007, did not have an incremental impact on the accompanying condensed consolidated financial statements.

Recently Issued Accounting Standards

In September 2006, the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 157, Accounting for Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value within generally accepted accounting principles and expands required disclosure about fair value measurements. SFAS No. 157 does not expand the use of fair value in any new circumstances. The provisions of SFAS No. 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are evaluating the impact that this new standard will have, if any, on our consolidated financial statements when adopted in 2008.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. We are evaluating the impact that SFAS No. 159 will have, if any, in our consolidated financial statements when it is adopted in 2008.

In April 2007, the FASB issued FSP FIN No. 39-1, Amendment of FASB Interpretation No. 39 (“FIN No. 39-1”), to amend certain portions of Interpretation 39. FIN No. 39-1 replaces the terms "conditional contracts" and "exchange contracts" in Interpretation 39 with the term "derivative instruments" as defined in Statement 133. FIN No. 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments. FIN No. 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted. We are evaluating the impact that FIN No. 39-1 will have, if any, on our consolidated financial statements when adopted in 2008.

3. ACQUISITIONS

Acquisition of Internal Revenue Code Section 1031 – Like-Kind Exchange Properties

During the first quarter of 2007, we completed the acquisition of suitable like-kind properties in accordance with the like-kind exchange ("LKE") agreement we entered into in connection with our sale of undeveloped leaseholds located in Grand Valley Field, Garfield County, Colorado in July 2006. We acquired, for cash, qualifying oil and gas properties totaling $188.9 million, including costs of acquisition, as described below.

Index

EXCO Properties. On January 5, 2007, we completed the purchase of producing properties and undeveloped drilling locations and acreage in the Wattenberg Field area of the DJ Basin, Colorado from EXCO Resources Inc., an unaffiliated party. The acquisition included substantially all of EXCO’s assets in the area and encompassed 144 oil and natural gas wells (approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and 8,160 acres of leasehold. The wells and leases acquired are located in Weld, Adams, Larimer, and Broomfield Counties, Colorado. We operate the assets and hold a majority working interest in the properties.

Company Sponsored Partnerships. On January 10, 2007, we completed the purchase of the remaining working interests in 44 of our sponsored partnerships. The transaction resulted in an increase in our ownership in 718 gross (423 net) wells that are currently operated by us. The wells are located primarily in the Appalachian Basin and Michigan.

The following table presents the adjusted purchase price for each of the acquisitions described above as of September 30, 2007.

	EXCO			Partnerships
	(in thousands)

Cash consideration paid	$	128,672		$	57,776
Plus: direct costs of acquisition		1,662			1,664
Less: acquisition cost adjustments		(119	)		(2,792	)
Total acquisition cost	$	130,215		$	56,648

The following table presents, as of the respective date of acquisition, the current preliminary allocations of the purchase prices based on estimates of fair value.

	EXCO			Partnerships
	(in thousands)

Current assets acquired	$	91		$	-
Proved oil and gas properties		117,425			46,870
Unproved oil and gas properties		14,960			13,273
Asset retirement obligation		(748	)		(3,495	)
Other liabilities assumed		(1,513	)		-
Preliminary acquisition cost	$	130,215		$	56,648

The assessment of fair value of proved oil and gas properties acquired was based primarily on projections of expected discounted future cash flows of acquired oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable reserves were reduced by additional risk-weighting factors in that valuation. The purchase price allocations are preliminary, subject to fair value appraisals and evaluations of the assets acquired. These amounts are subject to change prior to the completion of the final purchase price allocation as additional information becomes available and is assessed by us.

Other. In January 2007, we acquired from unaffiliated parties other like-kind undeveloped leaseholds in Erath County, Texas for $2.1 million, including costs of acquisition. Acreage in this area is prospective for development of oil and natural gas reserves in the Barnett Shale.

Other Acquisitions

Unioil. On December 6, 2006, we completed a cash tender offer and purchased approximately 95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an independent energy company with properties in northern Colorado and southern Wyoming. The acquisition of more than 90% of the outstanding shares of common stock allowed us to effect a short-form merger of Unioil and our wholly owned subsidiary, resulting in the acquisition of the remaining 428,719 shares of Unioil. Each share of Unioil common stock not tendered through the offer was converted into the right to receive $1.91 in cash, the same consideration paid for shares in the tender offer. We paid $18.6 million, including $0.4 million of direct acquisition costs, for 100% of Unioil’s outstanding common stock.

Index

The assessment of the fair values of oil and gas properties acquired was based primarily on projections of expected future net cash flows, discounted to present value. The preliminary allocation of acquisition cost included $6.8 million in goodwill, which was re-allocated to properties and equipment in the first quarter of 2007 as part of our ongoing process of finalizing the preliminary allocation of the purchase price. As a result of this reclassification, the deferred tax liabilities increased and property and equipment increased. This increase was approximately $4.2 million. The purchase price allocation is preliminary, subject to completing the evaluation of proved and unproved oil and gas properties. These amounts are subject to change prior to the completion of the final purchase price allocation as additional information becomes available and is assessed by us.

Other. On February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells and associated undeveloped acreage located in Colorado (Wattenberg Field) for a purchase price of $12 million, which was allocated to oil and gas properties. The purchase price allocation is preliminary, subject to completing the evaluation of proved and unproved oil and gas properties. These amounts are subject to change prior to the completion of the final purchase price allocation as additional information becomes available and is assessed by us.

Pro Forma Financial Information

The results of operations for all of the above acquisitions have been included in the condensed consolidated financial statements from the dates of acquisition. The pro forma effect of the inclusion of the results of operations for all of the above acquisitions, individually and in the aggregate, in our condensed consolidated statement of income for the nine months ended September 30, 2007, was not material.

The following unaudited pro forma financial information presents a summary of our consolidated results of operations for the three and nine months ended September 30, 2006, assuming the acquisitions of the EXCO properties and our sponsored partnerships had been completed as of January 1, 2006, including adjustments to reflect the allocation of the purchase price to the acquired net assets. The pro forma effect of the inclusion of the results of operations for all of the other acquisitions described above, individually and in the aggregate, was not material.

	September 30, 2006
	Three Months		Nine Months
	Ended		Ended
	(in thousands, except per share data)

Total revenues	$	77,130	$	238,750
Net income		211,691		234,058
Earnings per common share:
Basic	$	13.44	$	14.65
Diluted	$	13.38	$	14.58

The pro forma results of operations are not necessarily indicative of what our results of operations would have been had the EXCO properties and our sponsored partnerships been acquired at the beginning of the periods indicated, nor does it purport to represent results of operations for any future periods.

4. RESTRICTED CASH

In July 2006, we established a trust in the amount of $300 million with a qualified intermediary in conjunction with the sale of undeveloped leaseholds and corresponding LKE agreement. As of December 31, 2006, $300 million remained in the trust, with $109 million reflected in cash and cash equivalents as a current asset in the condensed consolidated balance sheet and the remaining $191.5 million reflected as restricted cash - long term. In January 2007, $188.9 million of the $191.5 million was utilized in the acquisition of oil and gas properties qualifying for LKE treatment, which are included in oil and gas properties at September 30, 2007, with the unused amount being used in general operating activities.

In June 2007, we funded an escrow account in the amount of $14.1 million for amounts due to the limited partners of our sponsored drilling partnerships as a result of us over withholding estimated production taxes in years prior to 2007, which is included, along with interest earned of $0.2 million, in restricted cash, current, in the condensed consolidated balance sheet as of September 30, 2007.

Index

5. INCOME TAXES

Effective January 1, 2007, we adopted FIN No. 48, which clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement 109, Accounting for Income Taxes, by prescribing the minimum recognition threshold and measurement attribute a tax position taken or expected to be taken on a tax return is required to meet before being recognized in the financial statements. We recorded a $0.3 million reduction in retained earnings at January 1, 2007, to recognize the cumulative effect of the adoption of FIN No. 48. This amount represents the total amount of interest on unrecognized tax benefits as of the date of adoption. As of January 1, 2007, unrecognized tax benefits amounted to $1 million and are included in federal and state income taxes payable in the condensed consolidated balance sheet. None of the unrecognized tax benefits relate to a position that, if recognized, will impact our effective tax rate. While the income or expense to which the uncertain tax position relates is variable in nature, as of September 30, 2007, we do not expect the unrecognized tax position to significantly increase or decrease in the next twelve months.

As a matter of accounting policy, we recognize interest and penalties related to unrecognized tax benefits, if applicable, in income tax expense in the condensed consolidated statements of income. During the three and nine months ended September 30, 2007, there was no material change to the amount of interest recorded on unrecognized tax benefits. Accruals for interest on unrecognized tax benefits totaled $0.3 million at September 30, 2007, which are included in federal and state income taxes payable in the condensed consolidated balance sheet. There were no accruals for penalties on unrecognized tax benefits at January 1, 2007, or during the three and nine months ended September 30, 2007.

At September 30, 2007, our federal income tax returns were closed through the 2002 tax year and there are no outstanding tax controversies with any taxing authorities regarding these prior tax years. Subsequently, during the third quarter of 2007, we reached a final settlement with the IRS regarding the examination of our 2003 and 2004 tax years. The examination was officially concluded and the revenue agent’s report was signed on July 31, 2007, resulting in no material impact to the current year financial statements or to any of our uncertain tax positions.

State and other income tax returns are generally subject to examination for a period of three to five years after the filing of the respective returns. The state impact of any amended federal returns, whether or not pursuant to IRS examination changes or pursuant to our voluntary changes, remains subject to examination by various states for a period of up to one year after formal notification of such amendments to the states. We currently have no state income tax returns in the process of examination or administrative appeal. We are currently preparing amended 2003 and 2004 state income tax returns to reflect the IRS examination changes.

We filed our 2004 state income tax returns in June 2007 and our 2005 federal and state income tax returns in September 2007. These filing dates begin the applicable statute of limitations for examination and adjustment. Our 2006 federal and state income tax returns were filed timely, by the extended due dates, in September 2007 and October 2007, respectively.

6. MINORITY INTEREST IN CONSOLIDATED LIMITED LIABILITY COMPANY

In May 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (“LLC”), a limited liability company for which we serve as the managing member. One-sixth of the entity is owned by the Chief Executive Officer of the Company, who paid the same unit price for his interest as was paid by us and unrelated third parties for such interests in the LLC. The LLC's only asset is an aircraft and the LLC was formed for the purpose of owning and operating the aircraft.

The minority interest portion of pre-tax expense incurred by and belonging to the minority interest holders of the consolidated limited liability company is not material and included in the accompanying condensed consolidated statement of income as an offset to depreciation, depletion and amortization expense.

Index

7. EARNINGS PER SHARE

A reconciliation of basic and diluted earnings per common share is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(in thousands, except per share data)

Weighted average common shares outstanding		14,757		15,750		14,739		15,973
Dilutive effect of share-based compensation: ⁽¹⁾
Unamortized portion of restricted stock		35		20		41		16
Stock options		30		54		60		59
Non employee director deferred compensation		5		-		5		-
Weighted average common and common equivalent shares outstanding		14,827		15,824		14,845		16,048

Net income	$	4,459	$	210,884	$	25,011	$	229,809
Basic earnings per common share	$	0.30	$	13.39	$	1.70	$	14.39
Diluted earnings per common share	$	0.30	$	13.33	$	1.68	$	14.32

⁽¹⁾Excludes the effect of average anti-dilutive common share equivalents related to out-of-the-money options and unvested restricted shares of 48,500 and 9,673 for the three and nine months ended September 30, 2007, respectively, and 22,180 and 12,003 for the three and nine months ended September 30, 2006.

8. STOCK-BASED COMPENSATION

We maintain long-term equity compensation plans for our directors, officers and certain key employees. In accordance with the plans, awards have been granted in the form of stock options, restricted stock and market based shares.

The following table provides a summary of the impact of our stock based compensation plans on the results of operations for the periods presented.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)

Total share-based compensation expense	$	628		$	435		$	1,652		$	1,101
Income tax benefit		(242	)		(168	)		(637	)		(424	)

Net income impact	$	386		$	267		$	1,015		$	677

Stock Option Awards. We granted stock options in previous years under several stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We did not grant any stock option awards for the nine months ended September 30, 2007. The weighted average fair value per share of the options granted during the nine months ended September 30, 2006, as computed using the Black-Scholes pricing model, was $19.65. The weighted average assumptions used to estimate these fair values were as follows:

	Nine Months Ended September 30, 2006
Expected Volatility	39.5%
Expected term (in years)	5.9
Risk-free interest rate	4.3%

Expected volatilities are based on our historical volatility. The expected life of an award is estimated using historical exercise behavior data. The risk-free interest rate is based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the expected life of the award. We do not expect to declare or pay cash dividends in the foreseeable future.

Index

The following table provides a summary of our stock option award activity for the nine months ended September 30, 2007:

						Weighted
				Weighted		Average
	Number of			Average		Remaining		Aggregate
	Shares			Exercise		Contractual		Intrinsic
	Underlying			Price		Term		Value
	Options			Per Share		(in years)		(in millions)

Outstanding at December 31, 2006		89,567		$	21.36		5.6	$	2.0
Exercised		(38,000	)		4.81				1.7

Outstanding at September 30, 2007		51,567			33.55		6.6		0.6

Vested and expected to vest at September 30, 2007		47,808			32.65		6.5		0.6

Exercisable at September 30, 2007		24,529			23.85		4.9		0.5

Total unrecognized stock-based compensation cost related to stock options, net of estimated forfeitures, was $0.3 million as of September 30, 2007. This cost is expected to be recognized over a weighted average period of 2.1 years.

Restricted and Market Based Awards. During the nine months ended September 30, 2007, we awarded 61,609 restricted shares with a weighted average grant date fair value of $47.69 per share and 31,972 market based shares of restricted stock with a weighted average grant date fair value of $36.07 per share. The fair value of the restricted awards and market based shares is amortized ratably over the requisite service period, primarily over four years for restricted awards and three years for market based awards. The market based shares vest only upon the achievement of certain per share price thresholds and continuous employment during the vesting period. All compensation cost related to the market based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The weighted average grant date fair value of each market based share was computed using the Monte Carlo pricing model and the following weighted average assumptions:

Expected term of award	3 years
Risk-free interest rate	4.7%
Volatility	44.0%

The following table provides a summary of our restricted and market based share awards activity for the nine months ended September 30, 2007:

				Weighted Average
				Grant-Date
	Shares			Fair Value
Non-vested at December 31, 2006		131,730		$	39.87
Granted		93,581			43.72
Vested		(28,934	)		38.10
Forfeited		(2,139	)		40.07

Non-vested at September 30, 2007		194,238			41.98

The total compensation cost related to non-vested and expected to vest restricted awards not yet recognized as of September 30, 2007, for both restricted and market based awards was $5.6 million. The cost is expected to be recognized over a weighted-average period of 2.8 years.

Index

9. PROPERTIES AND EQUIPMENT

	September 30,			December 31,
	2007			2006
	(in thousands)
Properties and equipment, net:
Oil and gas properties (successful efforts method of accounting)
Proved	$	869,700		$	473,451
Unproved		53,200			27,055
Total oil and gas properties		922,900			500,506
Pipelines and related facilities⁽¹⁾		20,605			12,673
Transportation and other equipment⁽²⁾		18,928			7,870
Land and buildings		11,915			11,620
Construction in progress⁽³⁾		2,449			4,801
		976,797			537,470
Accumulated depreciation, depletion and amortization ("DD&A")		(194,130	)		(143,253	)

	$	782,667		$	394,217

_______________

⁽¹⁾

At September 30, 2007, includes $3.2 million related to additional compressors and upgraded pipeline facilities in the Piceance Basin production operations, which was placed in service in second and third quarter of 2007.

⁽²⁾

At September 30, 2007, includes $5.1 million related to the Garden Gulch road, which was placed in service in May 2007. At December 31, 2006, construction in progress included $3.6 million related to the Garden Gulch road.

⁽³⁾

At September 30, 2007, includes costs primarily related to a new integrated oil and gas financial software system.

Suspended Well Costs

As of December 31, 2006, we had capitalized one exploratory well awaiting the determination of proved reserves with costs of $0.8 million. During the quarter ended June 30, 2007, the well was determined to be dry and expensed in the same quarter. As of September 30, 2007, there were no exploratory wells awaiting the determination of proved reserves.

10. ASSET RETIREMENT OBLIGATION

Changes in carrying amounts of the asset retirement obligation associated with our working interest in oil and gas properties are as follows:

	Amount
	(in thousands)

Beginning balance at December 31, 2006	$	11,966
Obligations assumed with development activities and acquisitions		5,541
Accretion expense		712
Obligations discharged with disposed properties and asset retirements		(21	)
Ending balance at September 30, 2007	$	18,198

Approximately $0.1 million of our asset retirement obligation is classified as short term and included in other accrued expenses as of September 30, 2007, and December 31, 2006.

Index

11. LONG-TERM DEBT

We entered into a credit facility with JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas with a maximum commitment of $200 million, dated as of November 4, 2005, subject to and secured by required levels of natural gas and oil reserves. We are required to pay a commitment fee of 0.25% to 0.375% per annum on the unused portion of the activated credit facility. Interest accrues at an alternative base rate ("ABR") or adjusted LIBOR at our discretion. The ABR is the greater of JPMorgan's prime rate, an adjusted secondary market rate for a three-month certificate of deposit plus 1% or the federal funds effective rate plus 0.5%. ABR borrowings are assessed an additional margin spread up to 0.375% and adjusted LIBOR borrowings are assessed an additional margin spread of 1.125% to 1.875%. The margin spread charges are based upon the outstanding balance under the credit facility. The credit agreement requires, among other things, the maintenance of certain working capital and tangible net worth ratios. No principal payments are required until the credit agreement expires on November 4, 2010.

Effective August 9, 2007, we entered into the first amendment to our credit facility adding a new bank, Wachovia Bank, N.A., and increasing our aggregate commitments from $150 million to $200 million, all of which is fully activated. The amendment also waived our working capital covenant until the earlier of (i) a debt or equity transaction resulting in net proceeds to us of at least $200 million or (ii) July 1, 2008. Under the amended agreement the ABR rate was increased by 0.375% as long as the waiver of the working capital covenant is in effect.

As of September 30, 2007, the outstanding balance under the credit facility was $172 million compared to $117 million, excluding the overline note discussed below, as of December 31, 2006. Any amounts outstanding under the credit facility are secured by substantially all of our properties. The outstanding balance at September 30, 2007, was subject to an adjusted LIBOR of 7.5625%. We were in compliance with all covenants as of September 30, 2007.

See Note 18 regarding a second amendment to our credit facility and the subsequent addition of two new banks.

On December 19, 2006, we executed, pursuant to our credit facility, an overline note in the amount of $20 million to be repaid on January 31, 2007. Interest on the overline note accrued at a per annum rate equal to the alternate base rate plus 0.8% until December 22, 2006, at which time the rate converted to a Eurodollar borrowing for a one month period and at a per annum rate equal to an adjusted LIBOR rate plus 2.30%. The overline note was paid in full in accordance with its terms in January 2007.

12. SUPPLEMENTAL CASH FLOW DISCLOSURE

	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Cash paid for:
Interest	$	6,991	$	1,398
Income taxes		43,615		46,478
Non-cash investing activities:
Change in deferred tax liability resulting from reallocation of acquisition purchase price		4,188		-
Changes in accounts payable - affiliates related to acquisition of partnerships		668		-
Changes in accounts payable related to purchases of properties and equipment		34,150		2,412
Changes in accounts payable-affiliates related to investment in drilling partnership		18,712		-

13. COMMITMENTS AND CONTINGENCIES

We are a party to a pipeline expansion agreement with an unrelated third party, which is also currently the purchaser of the majority of our Wattenberg Field natural gas production. Pursuant to the agreement, we have agreed to invest a minimum of $65 million, for our own benefit, to develop specified acreage in the Wattenberg Field area during a three-year period ending December 31, 2009. Such capital spending will include costs to drill new wells and the cost to recomplete existing wells in this area. Should we not meet the minimum commitment by December 31, 2009, we will be required to pay liquidated damages of $2 million, prorated based on our actual capital investment made to date. As of September 30, 2007, our total capital expenditures pursuant to the agreement were $26.1 million, resulting in a maximum potential obligation of $1.2 million.

Index

In August 2007, we completed the 2007 drilling partnership offering, Rockies Region 2007 Limited Partnership, and received subscriptions of approximately $90 million. At closing, we, as managing general partner, were obligated to make a cash capital contribution to the program of $38.7 million for our general partner interest, representing approximately 43% of the aggregate subscriptions received for the program. We funded $20 million of the total $38.7 million commitment at closing and recorded the remaining $18.7 million liability as a component of accounts payable - affiliates, a current liability, on the accompanying condensed consolidated balance sheet as of September 30, 2007. We subsequently paid the $18.7 million capital contribution to the partnership on October 31, 2007. Drilling for the new program commenced during the third quarter of 2007, with drilling and completion operations scheduled to continue through the first and second quarters of 2008. No assurance can be made that we will continue to receive this level of funding from any future programs.

In order to secure the services for two drilling rigs, we made commitments to the drilling contractor, which call for a minimum commitment of $12,500 per day for a specified amount of time if we do not use the drilling rigs, an event that is not anticipated to occur, and a maximum commitment of $40,680 per day for a specified amount of time for daily use of the drilling rigs. Commitments for these two separate contracts expire in July 2009 and May 2010. As of September 30, 2007, we had an outstanding minimum commitment for $6.7 million and an outstanding maximum commitment for $26.4 million.

We would be exposed to oil and natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to our derivative instruments or the counterparties to our natural gas marketing contracts not perform. Nonperformance is not anticipated. There were no counterparty default losses in 2006 or through the third quarter of 2007.

Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), if repurchase is requested by investors, and subject to our financial ability to do so. The maximum annual potential repurchase obligation as of September 30, 2007, was approximately $6.6 million. During the first nine months of 2007, we paid $0.9 million for the repurchase of partnership units.

As managing general partner of 33 partnerships, we are liable for any potential casualty losses in excess of the partnership assets and insurance. Our management believes that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability.

In connection with the sale of undeveloped leaseholds in July 2006, we, pursuant to the purchase and sale agreement, were obligated to either drill 16 wells on specifically identified acreage over the next three years or pay liquidated damages of $1.6 million per undrilled well for a total contingent obligation of $25.6 million, which was reflected as a deferred gain on sale of leaseholds in the accompanying condensed consolidated balance sheet at December 31, 2006. On May 31, 2007, we entered into a letter agreement amending the original purchase and sale agreement. The letter agreement relieved us of the obligation, in its entirety, to either drill 16 wells or pay liquidated damages, resulting in the recognition of the remaining $25.6 million deferred gain on sale of leaseholds in the quarter ended June 30, 2007.

Pursuant to the above letter agreement, we are obligated to drill six wells on specifically identified acreage. These wells will be drilled on the unaffiliated party's leasehold for its benefit and at its cost. In addition, the unaffiliated party will return 160 acres of leasehold property acquired from us pursuant to the purchase and sale agreement. As of the date of this report, we have drilled four of the six wells; we anticipate drilling the remaining two wells during the fourth quarter of 2007.

Index

We were party to an exploration agreement with an unaffiliated party. The agreement required us to drill a minimum of 25 exploratory wells through June 30, 2007. For each well we failed to drill prior to June 30, 2007, we were required to pay liquidated damages equal to $125,000 per undrilled well. After drilling three exploratory wells, we determined, based on drilling results, not to drill the remaining 22 exploratory wells. During the quarter ended June 30, 2007, we recorded charges to exploration expense for the liquidated damages of $2.7 million related to the 22 undrilled wells and $1.1 million related to the write-off of the carrying value of the acreage resulting from the abandonment of the project. The accrued liquidated damages were paid in full in September 2007.

14. SHAREHOLDERS' RIGHTS AGREEMENT

On September 11, 2007, we entered into a Rights Agreement (the “Rights Agreement”), with Transfer Online, Inc., as rights agent. The Rights Agreement is designed to improve the ability of our Board of Directors ("Board") to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right ("Right") for each outstanding share of our common stock. The Right dividend was paid to shareholders of record on September 14, 2007. A “distribution date,” as defined in the Rights Agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. After the occurrence of a "distribution date," the Right entitles each registered holder (other than the acquiring shareholder who triggered the "distribution date"), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities of the Company) having a then-current value equal to two times the exercise price of the Right (i.e., for the $240 exercise price, the Rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The Rights Agreement and all Rights will expire on September 11, 2017.

15. LEGAL PROCEEDINGS

We are involved in various legal proceedings that we consider normal to our business. Although the results cannot be known with certainty, we believe that we have properly accrued reserves and that the ultimate results of such proceedings will not have a material adverse effect on our financial position or results of operations.

Royalty Payments. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against us in the District Court, Weld County, Colorado alleging that we underpaid royalties on natural gas produced from wells we operated in the State of Colorado (the "Droegemueller Action"). The plaintiff seeks declaratory relief and to recover an unspecified amount of compensation for the alleged underpayment of royalties we made to the plaintiff pursuant to leases. We moved the case to Federal Court on June 28, 2007, and on July 10, 2007, we filed our answer and affirmative defenses. A scheduling order has not been issued at this time and no discovery has taken place. Given the preliminary stage of this proceeding and the inherent uncertainty in litigation, we are unable to predict the ultimate outcome of this suit at this time.

16. BUSINESS SEGMENTS

Our operating activities are divided into four major segments: oil and gas sales, natural gas marketing, drilling and development, and well operations and pipeline income. We own an interest in approximately 3,500 wells from which we sell the oil and natural gas production from our working interests in the wells. Included in the oil and gas sales segment are the operating results of the acquisitions described in Note 3. A wholly-owned subsidiary, Riley Natural Gas ("RNG"), engages in the marketing of natural gas to commercial and industrial end-users. We drill natural gas wells for our sponsored drilling partnerships and retain an interest in each well. We charge our sponsored partnerships and other third parties competitive industry rates for well operations and natural gas gathering. All material inter-company accounts and transactions between segments have been eliminated.

Index

Segment information for the three and nine months ended September 30, 2007 and 2006, is presented below.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007		2006
				*Revised					*Revised
	(in thousands)
Revenues:
Oil and gas sales ⁽¹⁾	$	50,782		$	33,284		$	122,141	$	95,903
Natural gas marketing		19,934			30,374			71,845		101,445
Drilling and development		1,573			2,659			7,342		11,682
Well operations and pipeline income		2,092			2,536			6,682		7,312
Unallocated amounts		1,894			1,964			2,122		1,988
Total	$	76,275		$	70,817		$	210,132	$	218,330

Segment income (loss) before income taxes:
Oil and gas sales ⁽²⁾	$	14,367		$	15,878		$	28,727	$	51,352
Natural gas marketing		333			558			2,357		1,682
Drilling and development		824			(1,179	)		5,783		355
Well operations and pipeline income ⁽³⁾		486			776			1,900		1,807
Unallocated amounts ⁽⁴⁾		(8,225	)		327,646			1,755		318,310
Total	$	7,785		$	343,679		$	40,522	$	373,506


							September 30,		December 31,
							2007		2006
							(in thousands)
Segment assets:
Oil and gas sales							$	728,101	$	394,952
Natural gas marketing								31,705		39,899
Drilling and development ⁽⁵⁾								53,499		87,746
Well operations and pipeline income								36,954		28,895
Unallocated amounts ⁽⁶⁾								83,492		332,795
Total							$	933,751	$	884,287

_______________

* See Note 1.

(1)

Includes oil and gas price risk management, net.

(2)

Includes exploration expense; DD&A expense of $19.3 million and $48.2 million for the three and nine months ended September 30, 2007, and $7.7 million and $20.8 million for the three and nine months ended September 30, 2006, respectively.

(3)

Includes DD&A expense of $0.7 million and $1.9 million for the three and nine months ended September 30, 2007 and $0.5 and $1.4 million as of September 30, 2006, respectively.

(4)

Includes general and administrative expense; interest income; interest expense; DD&A expense of $0.3 million and $0.8 million for the three and nine months ended September 30, 2007, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2006, respectively; the nine months ended September 30, 2007, and the three and nine months ended September 30, 2006, include gains on sale of leasehold of $25.6 million and $328 million, respectively.

(5)

The December 31, 2006, amount includes cash of $50.7 million for partnership drilling activities, which was substantially utilized by September 30, 2007.

(6)

The December 31, 2006, amount includes designated cash of $191.5 million, which was utilized in LKE property transactions during the first quarter of 2007 and included in the oil and gas sales segment as of September 30, 2007.

Index

17. DERIVATIVE FINANCIAL INSTRUMENTS

We utilize commodity based derivative instruments to manage a portion of our exposure to price risk from oil and natural gas sales and marketing activities. Our policy prohibits the use of oil and natural gas future and option contracts for speculative purposes. These instruments consist of New York Mercantile Exchange ("NYMEX") traded natural gas futures contracts and option contracts for Appalachian and Michigan production, Panhandle-based contracts and NYMEX-traded contracts for Northeast Colorado ("NECO") production and Colorado Interstate Gas Index ("CIG") based contracts for other Colorado production. We purchase puts and participating collars for our production and affiliate partnerships’ production to protect against possible price instability in future periods while retaining much of the benefit of price increases. RNG enters into fixed-price physical purchase and sale agreements that are derivative contracts. In order to offset these fixed-price physical derivatives, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. As a result, while these derivatives are structured to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price changes in the physical market.

The following tables summarize the open derivative option and purchase and sales contracts for PDC and RNG as of September 30, 2007.

Petroleum Development Corporation

Open Derivative Positions

(dollars in thousands, except average price data)

		Quantity		Weighted		Total
		Gas-MMbtu		Average		Contract
Commodity	Type	Oil-Barrels		Price		Amount		Fair Value

Total Positions as of September 30, 2007
Natural Gas	Cash Settled Option Sales		16,300,000	$	10.70	$	174,373	$	(2,287	)
Natural Gas	Cash Settled Option Purchases		21,160,000		5.69		120,497		16,005
Oil	Cash Settled Option Purchases		30,000		50.00		1,500		(32	)
								$	13,686

Positions maturing in 12 months following September 30, 2007
Natural Gas	Cash Settled Option Sales		14,580,000	$	10.70	$	156,008	$	(1,728	)
Natural Gas	Cash Settled Option Purchases		19,440,000		5.69		110,567		14,652
Oil	Cash Settled Option Purchases		30,000		50.00		1,500		(32	)
								$	12,892

The maximum term for the derivative contracts listed above is 13 months.

Index

Riley Natural Gas

Open Derivative Positions

(dollars in thousands, except average price data)

				Weighted		Total
		Quantity		Average		Contract
Commodity	Type	Gas-MMbtu		Price		Amount		Fair Value

Total Positions as of September 30, 2007
Natural Gas	Cash Settled Futures/Swaps Purchases		243,525	$	7.36	$	1,793	$	(97	)
Natural Gas	Cash Settled Futures/Swaps Sales		1,567,000		8.71		13,642		1,699
Natural Gas	Cash Settled Option Purchases		60,000		5.50		330		1
Natural Gas	Cash Settled Option Sales		30,000		10.10		303		(1	)
Natural Gas	Physical Purchases		1,567,000		8.58		13,437		(966	)
Natural Gas	Physical Sales		123,583		9.36		1,157		151
								$	787

Positions maturing in 12 months following September 30, 2007
Natural Gas	Cash Settled Futures/Swaps Purchases		240,825	$	7.36	$	1,772	$	(97	)
Natural Gas	Cash Settled Futures/Swaps Sales		1,344,000		8.70		11,691		1,631
Natural Gas	Cash Settled Option Purchases		60,000		5.50		330		1
Natural Gas	Cash Settled Option Sales		30,000		10.10		303		(1	)
Natural Gas	Physical Purchases		1,344,000		8.52		11,452		(945	)
Natural Gas	Physical Sales		120,883		9.38		1,133		150
								$	739

The maximum term for the derivative contracts listed above is 26 months.

In addition to including the gross assets and liabilities related to our share of oil and natural gas production, the above tables and the accompanying condensed consolidated balance sheets include the gross assets and liabilities related to derivative contracts we entered into on behalf of the affiliate partnerships as the managing general partner. The accompanying condensed consolidated balance sheets include the fair value of derivatives and a corresponding net payable to the partnerships of $5.8 million as of September 30, 2007, and $7.5 million as of December 31, 2006.

We are required to maintain margin deposits with brokers for outstanding futures contracts. Restricted cash, current, of $0.5 million was on deposit as of September 30, 2007, and December 31, 2006.

By using derivative financial instruments to manage exposures to changes in interest rates and commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. There were no counterparty defaults in 2006 or during the nine months ended September 30, 2007.

The following table identifies the fair value of commodity based derivatives as classified in the condensed consolidated balance sheets.

	September 30,		December 31,
	2007		2006
	(in thousands)
Classification in the Condensed Consolidated Balance Sheets:
Fair value of derivatives - current asset	$	16,403	$	15,012