CONFORMED COPY

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.

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 16,060,881 shares of the Company's Common Stock ($.01 par value) were outstanding as of July 31, 2006.

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

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.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Report of Independent Registered Public Accounting Firm

We have reviewed the accompanying condensed consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of June 30, 2006, the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2006 and 2005, the related condensed consolidated statement of stockholders' equity for the six-month period ended June 30, 2006, and the related condensed consolidated statements of cash flows for the six-month periods ended June 30, 2006 and 2005. These condensed consolidated financial statements are the responsibility of the Company's management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical review procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U. S. generally accepted accounting principles.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of December 31, 2005, and the related consolidated statements of income, stockholders' equity and cash flows for the year then ended (not presented herein); and in our report dated May 24, 2006, we expressed an unqualified opinion on those consolidated financial statements. As discussed in that report, the consolidated financial statements as of December 31, 2004 and 2003, and for each of the years in the two year period ended December 31, 2004, have been restated and the report also included an explanatory paragraph referring to a change in accounting for asset retirement obligations in 2003. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

As discussed in note 12 to the condensed consolidated financial statements, the Company has restated the condensed consolidated statement of income for the three and six-month periods ended June 30, 2005.

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Income

	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
		(Restated)(2)		(Restated)(2)
Revenues:
Oil and gas well drilling operations (1)	$ 3,745	$ 28,111	$ 9,023	$ 53,477
Gas sales from marketing activities	29,129	25,917	71,071	43,439
Oil and gas sales	27,267	21,542	56,476	40,206
Well operations and pipeline income	2,486	2,068	4,776	3,995
Other income	364	3,493	754	9,707
Total revenues	62,991	81,131	142,100	150,824

Costs and expenses:
Cost of oil and gas well drilling operations (1)	3,474	23,743	7,630	44,387
Cost of gas marketing activities	28,462	26,177	70,238	44,079
Oil and gas production and well operations cost	6,313	4,481	13,417	8,459
Exploration cost	1,657	4,864	2,795	4,864
General and administrative expense	4,667	1,266	8,647	2,884
Depreciation, depletion, and amortization	7,617	4,845	14,233	9,702
Total costs and expenses	52,190	65,376	116,960	114,375

Income from operations	10,801	15,755	25,140	36,449
Interest expense	(267)	(143)	(447)	(291)
Oil and gas price risk management gain (loss), net	1,367	858	5,802	(2,800)
Income before income taxes	11,901	16,470	30,495	33,358

Income taxes	4,351	6,091	11,147	12,339

Net income	$ 7,550	$ 10,379	$ 19,348	$ 21,019

Basic earnings per common share	$ 0.47	$ 0.63	$ 1.21	$ 1.27

Diluted earnings per common share	$ 0.47	$ 0.63	$ 1.20	$ 1.27



(1) See Note 11.
(2) See Note 12.

Condensed Consolidated Statement of Stockholders' Equity


	Common Stock Issued
			Additional		Treasury	Unamortized
	Number of		Paid-In	Retained	Stock	Stock
	Shares	Amount	Capital	Earnings	at Cost	Award	Total
Balance, December 31, 2005	16,281,923	$ 163	$ 30,423	$ 158,504	$ -	$ (825)	$ 188,265
Reclassification of unearned
compensation pursuant to
SFAS 123(R) adoption	-	-	(825)	-	-	825	-
Exercise of stock options	8,000	-	31	-	-	-	31
Issuance of stock awards	104,039	1	(1)	-	-	-	-
Forfeiture of stock awards	(4,736)	-	-	-	-	-	-
Amortization of stock award	-	-	666	-	-	-	666
Purchase of treasury stock	-	-	-	-	(10,153)	-	(10,153)
Treasury stock retirement	(258,169)	(3)	(10,150)	-	10,153	-	-
Net income	-	-	-	19,348	-	-	19,348
Balance, June 30, 2006	16,131,057	$ 161	$ 20,144	$ 177,852	$ -	$ -	$ 198,157

Condensed Consolidated Statements of Cash Flows

	Six Months Ended June 30,
	2006	2005
Cash flows from operating activities:
Net income	$ 19,348	$ 21,019
Adjustments to net income to reconcile to cash
(used in )provided by operating activities:
Deferred federal income taxes	1,671	4,630
Depreciation, depletion & amortization	14,233	9,702
Accretion of asset retirement obligation	249	229
Dry hole costs	1,617	4,864
Gain from sale of assets	(12)	(7,857)
Expired and abandoned leases	16	393
Amortization of stock award	666	257
Unrealized (gain) loss on derivative transactions	(4,096)	2,380
Decrease in current assets	9,645	1,921
(Increase) decrease in other assets	(7)	24
(Decrease) increase in current liabilities	(58,067)	19,593
Increase (decrease) in other liabilities	1,649	(257)

Net cash (used in) provided by operating activities	(13,088)	56,898

Cash flows from investing activities:
Capital expenditures	(57,896)	(42,215)
Proceeds from sale of leases to partnerships	782	1,406
Proceeds from sale of assets	14	9,575

Net cash used in investing activities	(57,100)	(31,234)

Cash flows from financing activities:
Proceeds from debt	136,000	40,000
Retirement of debt	(91,000)	(39,000)
Payment of debt issuance costs	(22)	-
Proceeds from stock option exercises	31	-
Purchase of treasury stock	(10,153)	(7,879)

Net cash provided by (used in) financing activities	34,856	(6,879)

Net (decrease) increase in cash and cash equivalents	(35,332)	18,785

Cash and cash equivalents, beginning of period	90,110	77,735
Cash and cash equivalents, end of period	$ 54,778	$ 96,520

Notes to Condensed Consolidated Financial Statements

Petroleum Development Corporation, together with its subsidiaries, (the Company) is an independent energy company engaged primarily in the exploration, development, production and marketing of natural gas and oil. Since it began oil and gas operations in 1969, the Company has grown primarily through exploration and development activities, the acquisition of producing natural gas and oil wells and the expansion of its natural gas marketing activities.

The accompanying 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 footnotes and other financial information included in audited financial statements were condensed or omitted. In the opinion of management, the condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Company's financial position, results of operations and cash flows for the interim periods presented. The interim results of operations for the six months ended June 30, 2006, 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 unaudited condensed consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2005, as filed with the SEC on May 31, 2006.

As described in the Company's Annual Report on Form 10-K for the year ended December 31, 2005, the Company restated its condensed consolidated statements of income for each of the quarterly periods ended March 31, 2005, June 30, 2005, and September 30, 2005. The restatement was to correct certain revenues and expenses to properly reflect the elimination of transactions between the Company and Company-sponsored limited partnerships. The corrections resulted in the reduction of revenues and expenses of equal amounts. The restatement had no effect on net income, earnings per share, cash flows, proved oil and gas reserves or the Company's financial position. No amounts labeled as restated have been changed subsequent to the Company filing its 2005 Annual Report on Form 10-K. See Note 12 for further disclosure.

Certain prior year amounts were reclassified to conform to the current year presentation. Such reclassification had no impact on reported net earnings, earnings per share or shareholders' equity.

The Company's drilling segment recognizes revenue from our drilling contracts with our sponsored drilling programs using the percentage of completion method based upon the percentage of contract costs incurred to date to the estimated total contract costs for each contract. The Company utilizes this method since reasonably dependable estimates of the total estimated costs can be made and recognized revenues are subject to revisions as a contract progresses, the term of which can range from three to twelve months. In addition, the Company offers its drilling services under two types of contractual arrangements, cost-plus or footage-based service contracts, which result in differing risk and reward relationships, and hence, different revenue recognition policies pursuant to EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent.

Cost-plus drilling service arrangements were initially entered into in late 2005 with drilling activity commencing in the first quarter of 2006. Although the Company acts as a principal in the transaction and takes title to products and services acquired necessary for drilling, the Company acts as an agent, with little risk of loss during the performance of the drilling activities. Consistent with the provisions of EITF 99-19, the Company's services provided under the cost-plus drilling agreements are recognized net of recovered costs.

Footage-based contracts provide for the drilling, completion and equipping of wells at footage rates and are completed within nine to twelve months after the commencement of drilling. The Company provides geological, engineering, and drilling supervision on the drilling and completion process and uses subcontractors to perform drilling and completion services and accordingly has risk of loss in performing services under these arrangements. As such, the Company recognizes revenue under these agreements gross of related expenses. Anticipated losses, if any, on uncompleted contracts are recorded at the time that our estimated costs exceed the estimated contract revenue. As of June 30, 2006, the Company has a loss contract reserve of $0.2 million.

Natural gas marketing is recorded on the gross accounting method. Riley Natural Gas (RNG), our marketing subsidiary, purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains or losses of the RNG commodity based derivative transactions for natural gas marketing activities are included in gas sales from marketing activities or cost of gas marketing activities, as applicable.

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company's contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry.

The Company currently uses the "net-back" method of accounting for transportation arrangements of our natural gas sales. The Company sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our customers and reflected in the wellhead price.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is sold to purchasers at or near the Company's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable. The Company is paid a monthly operating fee for each well it operates for outside owners including the limited partnerships sponsored by the Company. The fee covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions.

The Company accounts for stock based compensation pursuant to SFAS 123(R) - Share‑Based Payment. SFAS 123(R), which requires an entity to recognize at the grant date, the fair value of stock options and other equity‑based compensation issued to employees in the statement of income. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in the Company's consolidated statements of income. Compensation expense attributable to awards granted prior to the adoption of SFAS 123(R) is recognized over the requisite service period for each separately vesting portion and awards granted subsequent to the adoption are recognized using the straight-line method over the vesting period of the entire award.

The Company utilizes a Black-Scholes option pricing model to measure the fair value of stock options granted to employees. The Company's determination of fair value of share-based payment awards on the date of grant using the model is affected by the Company's stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to the Company's expected stock price volatility over the expected term of the awards, and actual and projected employee stock option exercise behaviors. In addition, forfeitures are required to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Although the fair value of employee stock options is determined in accordance with SFAS 123(R) and SAB 107 using a Black-Scholes option-pricing model, that value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. The Company is responsible for determining the assumptions used in estimating the fair value of its share-based payment awards.

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 48 provides that the tax effects from an uncertain tax position can be recognized in our financial statements, only if the position is more likely than not of being sustained on audit by the Internal Revenue Service, based on the technical merits of the position. The provisions of FIN 48 will become effective for the Company as of January 1, 2007. The cumulative effect, if any, of applying the provisions of FIN 48 will be accounted for as an adjustment to retained earnings. The Company is currently evaluating the impact of adopting FIN 48 on its consolidated financial statements.

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3, which replaces Accounting Principles Board Opinion (APB) No. 20, "Accounting Changes", and SFAS 3, "Reporting Accounting Changes in Interim Financial Statements", and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application for voluntary changes in accounting principle unless it is impracticable to do so, and it applies to all voluntary changes in accounting principle in addition to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of the provisions of SFAS 154 in the first quarter of 2006 did not have a material impact on the Company's condensed consolidated financial statements.

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, to account for stock-based employee compensation. See Note 5 to condensed consolidated financial statements for a discussion of the adoption of SFAS 123(R) and its impact on the Company's condensed consolidated financial statements.

Computation of earnings per common and common equivalent share is as follows for the three and six months ended June 30, 2006 and 2005: (In thousands, except for per share data)

	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
Weighted average common shares outstanding	15,998	16,444	16,026	16,516
Dilutive effect of share-based compensation:
Unamortized portion of restricted stock	13	1	13	1
Stock options	63	47	65	50
Weighted average common and common
equivalent shares outstanding	16,074	16,492	16,104	16,567

Net income	$ 7,550	$ 10,379	$ 19,348	$ 21,019
Basic earnings per common share	$ 0.47	$ 0.63	$ 1.21	$ 1.27
Diluted earnings per common share	$ 0.47	$ 0.63	$ 1.20	$ 1.27

For the three and six months ended June 30, 2006, the effects of stock options and restricted stock representing 6,721 and 5,887 common shares, respectively, were excluded from the calculation of diluted earnings per share as their inclusion would have been antidilutive. Similarly, for the three and six months ended June 30, 2005, the effects of 4,207 and 359 shares, respectively, were excluded from the calculation of diluted earnings per share.

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, (SFAS 123(R)) to account for stock-based employee compensation. Among other items, SFAS 123(R) eliminates the use of APB Opinion No. 25 (APB 25) and the intrinsic value method of accounting for equity compensation and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards in their financial statements. We elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, will be recognized in our financial statements over the remaining requisite service period for each separately vesting portion. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant or modification, will be recognized in our financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in oil and natural gas acquisition, exploration and development activities, such amounts are capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the appropriate cost and expense line item in the statements of income. Prior to the adoption of SFAS 123(R), we followed the intrinsic value method in accordance with APB 25 to account for employee stock-based compensation. Prior period financial statements have not been restated for the adoption of SFAS 123(R) under the modified prospective method.

The adoption of SFAS 123(R) required the unearned compensation recorded under APB 25 related to stock-based compensation awards as of January 1, 2006, in the amount of $0.8 million to be eliminated against additional paid-in-capital.

Total compensation cost charged against income for the Company's plans was $0.5 million and $0.5 million for the three and six months ended June 30, 2006, and $0.1 million and $0.2 million for the three and six months ended June 30, 2005, respectively. Compensation capitalized as part of properties and equipment for the three and six months ended June 30, 2006, was immaterial.

Prior to January 1, 2006, we accounted for our employee stock options using the intrinsic value method prescribed by APB 25. The table below provides the effect on net income and earnings per share as if the Company had applied the fair value based method recognition provisions of SFAS 123 to record stock-based compensation for the three and six months ended June 30, 2005:

	Three Months		Six Months
		Ended		Ended
		June 30, 2005		June 30, 2005
Net Income:
As reported		$ 10,379		$ 21,019
Add: Stock-based compensation expense
included in reported net income, net of tax		88		162
Deduct: Total stock-based compensation
expense determined under fair value based
method for all awards, net of tax		(112)		(210)
Pro forma net income		$ 10,355		$ 20,971
Basic earnings per common share:
As reported		$ 0.63		$ 1.27

Pro forma		$ 0.63		$ 1.27
Diluted earnings per common share:
As reported		$ 0.63		$ 1.27

Pro forma		$ 0.63		$ 1.27

The fair value of options awarded is estimated using the Black-Scholes option pricing model using the assumptions noted in the following table. Expected volatility is based on the Company's 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. The Company does not expect to pay dividends and is restricted from doing so based on its current credit facility. The Company did not grant any option awards in 2005.

The Company began issuing shares of restricted common stock to employees in 2004. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, ratably over four years from the date of grant for employees and three years for directors.

The following table provides a summary of restricted stock activity for the six months ended June 30, 2006:

As of June 30, 2006, there was $4.3 million of total unrecognized compensation cost related to non-vested restricted stock. The cost is expected to be recognized over a weighted average period of 3.7 years.

The Company 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.

The following table provides information related to stock option activity for the six months ended June 30, 2006.


		Weighted
	Number of	Average	Weighted	Aggregate
	Shares	Exercise	Average	Intrinsic
	Underlying	Price	Contract Life	Value (a)
	Options	Per Share	(years)	( thousands)

Outstanding at December 31, 2005	73,880	$ 11.96
Granted	20,354	43.74
Exercised	(8,000)	3.88
Forfeited or expired	-	-

Outstanding June 30, 2006	86,234	$ 20.21	5.9	$ 2,169

Exercisable at June 30, 2006	53,220	$ 7.18	5.9	$ 2,032


(a) The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.

The aggregate intrinsic value of stock options exercised during the six months ended June 30, 2006, was $0.3 million. There were no options exercised during the six months ended June 30, 2005.

As of June 30, 2006, there was $0.5 million of total unrecognized compensation cost related to non-vested stock options. The cost is expected to be recognized over a weighted average period of 3.2 years.

Interest related to the construction of qualifying assets is capitalized as part of the construction cost, which totaled $0.4 million for the three and six months ended June 30, 2006. No interest was capitalized in 2005.

The nature of the independent oil and gas industry involves a dependence on outside investor drilling capital and involves a concentration of gas and oil sales to a few customers. The Company sells natural gas to various public utilities, natural gas marketers, industrial and commercial customers.

The Company is exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's derivative instruments or the counterparties to the Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in the six months ended June 30, 2006 or in 2005.

Substantially all of the Company's drilling programs contain a repurchase provision where investors may request the Company to repurchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is 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 month's cash distributions), only if investors request the Company to repurchase such units, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if requested by investors, is currently approximately $13.1 million. The Company believes it has adequate liquidity to meet this obligation should it arise. During 2005 and the first six months of 2006, the Company paid $0.4 million and $0.2 million, respectively, under this provision for the repurchase of partnership units.

The Company's drilling programs dating back to 1996 contain a performance supplement that requires the Company to remit a payment equal to one-half of its share of net revenue from the partnership to the investing partners if certain levels of performance are not met. During the six months ended June 30, 2006 and 2005, the Company paid the partnerships a total of $0.4 million and $0.2 million, respectively in accordance with the provision. As of June 30, 2006, based upon current oil and gas reserve reports of the partnerships with this provision, the maximum amount of this contingency is $4.2 million.

As managing general partner of 75 partnerships, the Company is liable for any potential casualty losses in excess of the partnership assets and insurance. The Company's management believes the casualty insurance coverage carried by the Company and its subcontractors is adequate to meet this potential liability.

In order to secure the services for drilling rigs, the Company made commitments to the drilling contractors which call for a minimum commitment of $24,000 daily for a specified period of time if the Company ceases to use the drilling rigs, an event that is not anticipated to occur, and a maximum commitment of $55,400 daily for a specified period of time for daily use of the drilling rigs. As of June 30, 2006, commitments for these three separate contracts expire in May 2008, July 2009 and May 2010. As of June 30, 2006, the Company has an outstanding minimum commitment for $21.1 million and an outstanding maximum commitment for $55.9 million.

From time to time, the Company is a party to various legal proceedings in the ordinary course of business. The Company is not currently a party to any litigation that it believes would have a materially adverse effect on the Company's business, financial condition, results of operations, or liquidity.

On January 13, 2006, the Company publicly announced that its Board of Directors authorized the purchase of up to 10% (1,627,500 shares) of the Company's common stock during 2006. Stock purchases under this program may be made in the open market or in private transactions, at times and in amounts that management deems appropriate. The Company may terminate or limit the stock purchase program at any time. For the six months ended June 30, 2006, the Company purchased 258,169 shares at a cost of $10.2 million ($39.33 average price paid per share). In July 2006, the Company purchased an additional 70,176 shares at a cost of $2.8 million ($40.48 average price paid per share). An additional 1,299,155 shares are authorized for purchase through December 31, 2006.

The following provides a summary of the activity that has occurred since inception of the plan on January 13, 2006, through July 31, 2006.

The Company's operating activities are divided into four major segments: drilling and development, natural gas marketing, oil and gas sales, and well operations and pipeline income. The Company drills natural gas wells for Company-sponsored drilling partnerships and retains an interest in each well. A wholly-owned subsidiary, Riley Natural Gas, engages in the marketing of natural gas to commercial and industrial end-users. The Company owns an interest in approximately 2,800 wells from which it derives oil and gas working interests. The Company charges Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. All material inter-company accounts and transactions between segments have been eliminated. Segment information for the three and six months ended June 30, 2006 and 2005, is as follows (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006		2005
		(Restated)(4)			(Restated)(4)
REVENUES
Drilling and development	$ 3,745	$ 28,111	$ 9,023		$ 53,477
Natural gas marketing	29,273	25,993	71,380		43,575
Oil and gas sales	27,267	21,542	56,476		40,206
Well operations and pipeline income	2,486	2,068	4,776		3,995
Unallocated amounts (1)(2)	220	3,417	445		9,571
Total	$ 62,991	$ 81,131	$ 142,100	#	$ 150,824

SEGMENT INCOME (LOSS)
BEFORE INCOME TAXES
Drilling and development	$ 271	$ 4,368	$ 1,393	$ 9,090
Natural gas marketing	809	(188)	1,138	(509)
Oil and gas sales (3)	15,015	9,348	35,765	16,367
Well operations and pipeline income	612	1,082	1,031	2,312
Unallocated amounts (2)
General and administrative expense	(4,667)	(1,266)	(8,647)	(2,884)
Interest expense	(267)	(143)	(447)	(291)
Other (1)	128	3,269	262	9,273
Total	$ 11,901	$ 16,470	$ 30,495	$ 33,358

(1) Includes gain on sale of assets, interest on investments and partnership management fees.

The following table provides a summary of capitalized exploratory well costs, included in properties and equipment, for the six months ended June 30, 2006. (dollars in thousands)

		Number of
	Amount	Wells
Beginning balance at December 31, 2005	$ 1,918	2

Additions to capitalized exploratory well costs
pending the determination of proved reserves	9,878	10

Reclassifications to wells, facilities and equipment
based on the determination of proved reserves	(11,504)	(9)

Capitalized exploratory well costs charged to
expense	-	-

Ending balance at June 30, 2006	$ 292	3

At June 30, 2006, none of the wells awaiting the determination of proved reserves have been capitalized for a period greater than three months.

As described in Note 2, the Company changed the type of drilling arrangement it has with its sponsored partnerships. The Company changed, effective with the last partnership of 2005, which started drilling in the first quarter of 2006, from footage-based contracts to cost-plus contracts. The elimination of risk of loss with the new cost-plus contracts does not allow the Company to record revenue for the total contract price of the arrangement but rather only the gross profit from the contract. The new cost-plus contract impacted the three and six months ended June 30, 2006, by reducing drilling revenues and drilling costs by $9.0 million and $26.5 million, respectively.

As described in the Company's Annual Report on Form 10-K for the year ended December 31, 2005, we restated our condensed consolidated statements of income for each of the quarterly periods ended March 31, 2005, June 30, 2005, and September 30, 2005. The restatement was to correct certain revenues and expenses to properly reflect the elimination of transactions between the Company and Company-sponsored limited partnerships. The corrections resulted in the reduction of revenues and expenses of equal amounts. The restatement had no effect on net income, earnings per share, cash flows, proved oil and gas reserves or the Company's financial position. No amounts labeled as restated have been changed subsequent to the Company filing its 2005 Annual Report on Form 10-K.

The following table sets forth the effect of the restatement on the affected line items within the Company's previously reported condensed consolidated statement of income for the three-month and six-month periods ended June 30, 2005 (unaudited, in thousands).


	Three Months Ended June 30, 2005		Six Months Ended June 30, 2005
	As		As
Condensed Consolidated Statements	previously	As	previously	As
of Income Data:	reported	restated	reported	restated
Revenues:
Oil and gas well drilling operations	$ 36,057	$ 28,111	$ 68,408	$ 53,477
Well operations and pipeline income	2,244	2,068	4,357	3,995
Other income	3,573	3,493	9,787	9,707
Total revenues	89,334	81,131	166,197	150,824

Costs and expenses:
Cost of oil and gas well drilling
operations	$ 31,689	$ 23,743	$ 59,318	$ 44,387
Oil and gas production
and well operations costs	4,738	4,481	8,901	8,459
Total costs and expenses	73,579	65,376	129,747	114,375

Income from operations	$ 15,755	$ 15,755	$ 36,449	$ 36,449

On July 20, 2006, the Company sold to an unaffiliated company a portion of its undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado. The sale encompassed 100% of the working interest in approximately 8,700 acres, including approximately 6,400 acres of the Company's Chevron leasehold and 2,300 acres of the Company's Puckett Land Company leasehold. The Company retained approximately 475 undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in addition to all of its producing properties in the field. The proceeds from the sale were $353.6 million. The Company is currently evaluating the accounting for this transaction. The Company expects to recognize a minimum pre-tax gain of approximately $328 million in the third quarter of 2006 and a total gain of $353.6 million pre-tax sometime in the future if it is able to fulfill the following drilling obligations. The Company is obligated to either drill 16 wells on certain of the acreage over the next three years or pay liquidated damages of $1.6 million per well.

In conjunction with the sale, the Company entered into a "like-kind exchange" agreement, in accordance with Section 1031 of the Internal Revenue Code, with a "qualified intermediary", J.P. Morgan Property Exchange, Inc. Proceeds in the amount of $300 million were transferred directly to J.P. Morgan to be held in trust pursuant to the terms of the "like-kind exchange" agreement. The Company is currently searching for suitable like-kind property.

The remaining $53.6 million (proceeds of $353.6 million less $300 million in trust) is not subject to a like-kind exchange transaction. The Company intends to use these remaining sale proceeds primarily to pay down debt, purchase up to 10% of the Company's common stock in accordance with its 2006 common stock buyback program, initiate new drilling opportunities on the retained undeveloped locations, as well as on other properties, purchase producing properties, acquire acreage in other areas to support both development and exploratory drilling ventures and give consideration to other potential projects.

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

Net income for the three months ended June 30, 2006, was $7.6 million, compared to $10.4 million for the same prior year period, a decrease of $2.8 million or 26.9%. Diluted earnings per share for the three months ended June 30, 2006, decreased to $.47 per share from $0.63 per share, or 25.4%, for the same prior year period. The decrease is the result of decreased net income offset in part by a decrease in the number of common shares outstanding.

For the six months ended June 30, 2006, net income was $19.3 million compared to $21.0 million for the same prior year period, a decrease of $1.7 million or 8.1%. Diluted earnings per share for the current six-month period was $1.20, a decrease of $0.07 per share or 5.5% from the six-month period ended June 30, 2005. The decrease is the result of decreased net income offset in part by a decrease in the number of common shares outstanding.

Three Months Ended June 30, 2006, Compared to Three Months Ended June 30, 2005

Total revenues for the three months ended June 30, 2006, were $63.0 million compared to a restated $81.1 million for the same prior year period, a decrease of $18.1 million or 22.3%. The decrease was primarily attributable to a decline in drilling revenues and other income, offset partially by increased oil and gas sales from both gas marketing activities and the Company's share of production. See Note 11 to the condensed consolidated financial statements and the discussion below entitled "Drilling Operations" for the impact the new cost-plus drilling arrangements and related accounting had on our drilling revenues for second quarter 2006.

Costs and expenses for the three months ended June 30, 2006, were $52.2 million compared to a restated $65.4 million for the same prior year period, a decrease of $13.2 million or 20.2%. The decrease was primarily the result of decreased cost of oil and gas well drilling operations and exploration costs, offset in part by increases in cost of gas marketing activities, oil and gas production and well operations costs, general and administrative, and depreciation, depletion and amortization. See Note 11 to the condensed consolidated financial statements and the discussion below entitled "Drilling Operations" for the impact the new cost-plus drilling arrangements and related accounting had on our drilling expenses for second quarter 2006.

Beginning in first quarter 2006, the Company, in addition to its footage-based drilling arrangements, began recognizing revenues for its cost-plus drilling arrangements with its partnerships. The cost-plus drilling arrangements became effective with the private program partnership funded by the Company in late December 2005. Revenue from oil and gas well drilling operations for the three months ended June 30, 2006, were $3.7 million, net of $9.0 million of costs related to drilling arrangements accounted for on the cost-plus basis, compared to a restated $28.1 million for the same prior year period, a decrease of $24.4 million or 86.8%. The Company started second quarter 2006 with advances for future drilling from March 31, 2006, of $22.0 million and the Company did not fund any drilling partnership in the second quarter of 2006. The Company started second quarter 2005 with advances for future drilling from March 31, 2005, of $54.4 million and the Company funded its second drilling partnership of 2005 in second quarter 2005 with $40 million in subscriptions and commenced drilling of the partnership wells late in the same quarter.

The new cost-plus contract impacted the current year period by reducing drilling revenues and drilling costs by $9.0 million, as outlined in the table below (in millions):

	Three months ended June 30,
	2006			2005
	Drilling Service Revenue/Cost	Direct Reimbursed Cost	Revenue/Cost including reimburse- ment from Partnerships	Drilling Service Revenue/Cost
Oil and gas well drilling operations	$ 3.7	$ 9.0	$ 12.7	$ 28.1
Total revenues	$ 63.0	$ 9.0	$ 72.0	$ 81.1

Cost of oil and gas well drilling operations	$ 3.5	$ 9.0	$ 12.5	$ 23.7
Total costs and expenses	$ 52.2	$ 9.0	$ 61.2	$ 65.4

Income from operations	$ 10.8	$ -	$ 10.8	$ 15.8

Cost of oil and gas well drilling operations decreased $20.2 million or 85.2% to $3.5 million for the three months ended June 30, 2006, from a restated $23.7 million in the same prior year period. The decrease was primarily due to the Company's revenue recognition accounting for its new cost-plus drilling arrangements, which reduced drilling costs by $9.0 million for the current year period, and an overall reduction in drilling activities with the partnerships noted above. See Note 11 to condensed consolidated financial statements.

Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's gas marketing subsidiary, for the three months ended June 30, 2006, were $29.1 million compared to $25.9 million for the same prior year period, an increase of $3.2 million or 12.4%. The increase was due to higher volumes of natural gas sold, partially offset by lower average sales prices, for the three months ended June 30, 2006. The costs of gas marketing activities for the three months ended June 30, 2006, were $28.5 million compared to $26.2 million for the three months ended June 30, 2005, an increase of $2.3 million or 8.8%. The increase was due to higher volumes of natural gas purchased, partially offset by lower average purchase prices and unrealized losses on derivative transactions, which amounted to $1.6 million and $2.2 million for the three months ended June 30, 2006 and 2005, respectively. Income before income taxes for the Company's natural gas marketing subsidiary increased from a loss of $0.2 million for the three months ended June 30, 2005, to a $0.8 million profit for the three months ended June 30, 2006.

Oil and gas sales from the Company's producing properties for the three months ended June 30, 2006, were $27.3 million compared to $21.5 million for the same prior year period, an increase of $5.8 million or 27.0%. The increase was due to increased volumes sold at higher average sales prices of oil partially offset by lower average sales prices of natural gas. The volume of natural gas sold for the three months ended June 30, 2006, was 3.1 Bcf at an average sales price of $5.49 per Mcf compared to 2.7 Bcf at an average sales price of $6.04 per Mcf for the three months ended June 30, 2005. Oil sales were 179,000 barrels at an average sales price of $57.35 per barrel for the three months ended June 30, 2006, compared to 111,000 barrels at an average sales price of $47.26 per barrel for the three months ended June 30, 2005. The increase in natural gas and oil volumes was the result of the Company's increased investment in oil and gas properties, primarily recompletions of existing wells, wells drilled in our northeast Colorado area of operation, and the investment in oil and gas properties we own in our drilling program partnerships.

The Company's oil and natural gas production by area of operations along with average sales price (excluding derivative gains/losses) is presented below:

	Three Months Ended June 30, 2006			Three Months Ended June 30, 2005
		Natural	Natural Gas		Natural	Natural Gas
	Oil	Gas	Equivalents	Oil	Gas	Equivalents
	(Bbl)	(Mcf)	(Mcfe)*	(Bbl)	(Mcf)	(Mcfe)*
Appalachian Basin	300	372,476	374,276	756	392,690	397,226
Michigan Basin	904	355,244	360,668	1,232	380,266	387,658
Rocky Mountains	177,982	2,366,987	3,434,879	109,370	1,924,150	2,580,370
Total	179,186	3,094,707	4,169,823	111,358	2,697,106	3,365,254

Average Sales Price	$ 57.35	$ 5.49	$ 6.54	$ 47.26	$ 6.04	$ 6.40

Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production effectively. In recent years, natural gas and oil prices have been among the most volatile of all commodity prices. These price variations can have a material impact on our financial results. Natural gas prices in the Rocky Mountain Region continue to trail prices which we receive for our Appalachian and Michigan gas. The Company's management believes the lower prices in the Rocky Mountain Region, including Colorado, reflect the higher costs to move gas to major market areas compared to Michigan and the Appalachian Basin resulting in lower price compared to the eastern areas. In May 2003, a pipeline expansion project was completed, leading to improved natural gas prices in the region, which reduced local surplus. There is currently a substantial amount of drilling activity in the Rockies and, if future additions to the pipeline system are not made in a timely fashion, it is possible that pipeline constraints could create a local oversupply situation in the future which could mean lower natural gas prices. Like most other producers in the area, we rely on major interstate pipeline companies to construct these facilities, so their timing and construction is not within our control.

Because of uncertainty surrounding natural gas prices we have used various derivative instruments to manage some of the impact of fluctuations in prices. Through October 2007, we have in place a series of floors and ceilings on a portion of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor, the counterparty pays us. During the three months ended June 30, 2006, the Company averaged natural gas volumes sold of 1.0 Bcf per month and oil sales of 60,000 barrels per month. The positions in effect as of July 31, 2006, on the Company's share of production by area are shown in the following table.

		Floors		Ceilings
		Monthly		Monthly
		Quantity	Contract	Quantity	Contract
Month Set	Contract Term	Mmbtu	Price	Mmbtu	Price

Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)

Mar 2005	Jul 2006 - Oct 2006	42,000	$ 4.50	21,000	$ 7.25
Jul 2005	Jul 2006 - Oct 2006	27,500	5.50	13,750	7.63
Jul 2005	Nov 2006 - Mar 2007	27,500	6.00	13,750	8.40
Feb 2006	Nov 2006 - Mar 2007	60,000	6.50	-	-
Feb 2006	Apr 2007 - Oct 2007	44,000	5.50	-	-

NYMEX Based Derivatives - (Appalachian and Michigan Basins)

Mar 2005	Jul 2006 - Oct 2006	78,000	5.50	39,000	7.40
Jul 2005	Jul 2006 - Oct 2006	61,000	6.25	30,000	8.98
Jul 2005	Nov 2006 - Mar 2007	68,000	7.00	34,000	9.27
Feb 2006	Nov 2006 - Mar 2007	34,000	8.00	-	-
Feb 2006	Nov 2006 - Mar 2007	34,000	8.50	34,000	13.73
Feb 2006	Apr 2007 - Oct 2007	34,000	7.00	-	-
Feb 2006	Apr 2007 - Oct 2007	34,000	7.50	34,000	10.83

Panhandle Based Derivatives (NECO)

Mar 2005	Jul 2006 - Oct 2006	150,000	5.00	75,000	8.62
Jul 2005	Nov 2006 - Mar 2007	150,000	6.50	75,000	8.56
Feb 2006	Apr 2007 - Oct 2007	60,000	6.00	-	-
Feb 2006	Apr 2007 - Oct 2007	60,000	6.50	60,000	9.80

Oil and gas production and well operations costs from the Company's producing properties for the three months ended June 30, 2006, were $6.3 million compared to a restated $4.5 million for the three months ended June 30, 2005, an increase of $1.8 million or 40.0%. The increase was primarily attributable to increased production costs and severance and property taxes on the increased volumes and higher sales prices of oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting cost per Mcfe increased from $1.11 to $1.18 per Mcfe due to increased severance and property taxes on the significantly increased oil prices along with additional well workovers and production enhancements work performed.

For the three months ended June 30, 2006, exploration costs decreased to $1.7 million from $4.9 million for the same prior year period, a decrease of $3.2 million or 65.3%. The decrease is primarily attributable to decreased exploratory dry hole costs of $0.5 million compared to $4.9 million in the same prior year period. The current three-month period includes $1.1 million in geological and geophysical (G&G) costs, which relate to an exploratory seismic program initiated in the current three-month period on the Company's northeast Colorado properties. The Company expects to incur additional G&G costs in 2006. The exploratory dry hole costs of $0.5 million incurred in second quarter 2006 were related to exploratory wells determined to be dry in the first quarter of 2006 and the fourth quarter of 2005.

Well operations and pipeline income for the three months ended June 30, 2006, was $2.5 million compared to a restated $2.1 million for the same prior year period, an increase of $0.4 million or 19.0%. The increase was due to an increase in the number of wells and pipeline systems operated by the Company for our drilling program partnerships as well as third parties.

Other income for the three months ended June 30, 2006, was $0.4 million compared to $3.5 million for the same prior year period, a decrease of $3.1 million. The decrease was due to the gain on sale of certain Pennsylvania wells in the amount of $1.5 million, a gain on sale of undeveloped acreage in Colorado of $1.0 million and management fee income from partnership subscriptions, all of which occurred during the three months ended June 30, 2005.

General and administrative expenses for the three months ended June 30, 2006, were $4.7 million compared to $1.3 million for the same prior year period, an increase of $3.4 million. The increase was due to the costs of the Company's financial statement restatement, the restatement of the Company-sponsored partnerships' financial statements and increased payroll and payroll related costs. The Company expects these costs to remain at current period levels into 2007.

Depreciation, depletion, and amortization costs for the three months ended June 30, 2006, increased to $7.6 million from $4.8 million for the same prior year period, an increase of $2.8 million or 58.3 %. The increase was due to the increased production and investment in oil and gas properties by the Company.

Interest expense for the three months ended June 30, 2006, was $0.3 million compared to $0.1 million for the same prior year period. The increase was due to rising interest rates on significantly higher average outstanding balances of our credit facility and increased accretion related to asset retirement obligations, offset in part by $0.4 million of capitalized construction period interest in 2006. The Company utilizes its daily cash balances to reduce its line of credit to lower its costs of interest. The average daily outstanding debt balance for the three months ended June 30, 2006, was $25.9 million compared to $1.0 million for the three months ended June 30, 2005.

For the three months ended June 30, 2006, the Company recorded unrealized gains of $1.4 million compared to unrealized gains of $1.9 million and realized losses of $1.1 million for the same prior year period. The 2006 change is the result of declining natural gas prices. Oil and gas price risk management gain (loss), net is comprised of the change in fair value of oil and natural gas derivatives related to our oil and gas production (this line does not include commodity based derivative transactions related to transactions from marketing activities).

The effective income tax rate for the Company's provision for income taxes decreased from 37.0% to 36.6%, primarily due to certain one time income tax expenses during 2005.

Total revenues for the six months ended June 30, 2006, were $142.1 million compared to a restated $150.8 million for the same prior year period, a decrease of $8.7 million or 5.7%. The decrease was primarily attributable to a decline in drilling revenues and other income, offset partially by increased oil and gas sales from both gas marketing activities and the Company's share of production. See Note 11 to the condensed consolidated financial statements and the discussion below entitled "Drilling Operations" for the impact the new cost-plus drilling arrangements and related accounting had on our drilling revenues for the first six months of 2006.

Costs and expenses for the six months ended June 30, 2006, were $117.0 million compared to a restated $114.4 million for the same prior year period, an increase of $2.6 million or 2.3%. The increase was primarily the result of increased cost of gas marketing activities, oil and gas production and well operations cost, general and administrative expenses, and depreciation, depletion and amortization, partially offset by lower cost of oil and gas well drilling operations and exploration costs. See Note 11 to the condensed consolidated financial statements and the discussion below entitled "Drilling Operations" for the impact the new cost-plus drilling arrangements and related accounting had on our drilling expenses for the first six months of 2006.

During first quarter 2006, the Company, in addition to its footage-based drilling arrangements, began recognizing revenues for its cost-plus service arrangements with its partnerships. The cost-plus drilling arrangements became effective with the private program partnership funded by the Company in December 2005. Revenue from oil and gas well drilling operations for the six months ended June 30, 2006, was $9.0 million, net of $26.5 million of costs related to drilling arrangements accounted for on the cost-plus basis, compared to a restated $53.5 million for the same period in 2005, a decrease of $44.5 million or 83.2%.

The new cost-plus contract impacted the current year period by reducing drilling revenues and drilling costs by $26.5 million, as outlined in the table below (in millions):

	Six months ended June 30,
	2006			2005
	Drilling Service Revenue/Cost	Direct Reimbursed Cost	Revenue/Cost including reimburse- ment from Partnerships	Drilling Service Revenue/Cost
Oil and gas well drilling operations	$ 9.0	$ 26.5	$ 35.5	$ 53.5
Total revenues	$ 142.1	$ 26.5	$ 168.6	$ 150.8

Cost of oil and gas well drilling operations	$ 7.6	$ 26.5	$ 34.1	$ 44.4
Total costs and expenses	$ 117.0	$ 26.5	$ 143.5	$ 114.4

Income from operations	$ 25.1	$ -	$ 25.1	$ 36.5

The cost of oil and gas well drilling operations for the six months ended June 30, 2006, was $7.6 million compared to a restated $44.4 million for the six months ended June 30, 2005, a decrease of $36.8 million. The decrease in cost is primarily attributable to the Company's revenue recognition accounting for its new cost-plus drilling arrangements, which reduced drilling costs by $26.5 million for the six months ended June 30, 2006.

Natural gas sales from the marketing activities of RNG for the six months ended June 30, 2006, were $71.1 million compared to $43.4 million for the same prior year period, an increase of $27.7 million or 63.8%. The increase was primarily due to unrealized gains on derivative transactions totaling $10.6 million in the current period compared to an unrealized loss of $4.7 million for the prior year period along with higher volumes of natural gas sold at higher average sales prices.

The costs of gas marketing activities for the six months ended June 30, 2006, were $70.2 million compared to $44.1 million for the same prior year period, an increase of $26.1 million or 59.2%. The increase was primarily due to unrealized losses on derivative transactions of $10.9 million for the six months ended June 30, 2006, compared to an unrealized gain of $3.9 million for the six months ended June 30, 2005, along with higher volumes of natural gas purchased for resale at higher average purchase prices. Income before income taxes for the Company's natural gas marketing subsidiary increased from a $0.5 million loss for the prior six months ended June 30, 2005, to a $1.1 million profit for the six months ended June 30, 2006.

Oil and gas sales from the Company's producing properties for the six months ended June 30, 2006, were $56.5 million compared to $40.2 million for the same prior year period, an increase of $16.3 million or 40.5%. The increase was primarily due to increased volumes sold at higher average sales prices of oil and natural gas. The volume of natural gas sold for the current six-month period was 6.0 Bcf at an average sales price of $6.34 per Mcf compared to 5.4 Bcf at an average price of $5.65 per Mcf for the same prior year period. Oil sales were 307,000 barrels at an average sales price of $59.93 per barrel for the six months ended June 30, 2006, compared to 212,000 barrels at an average sales price of $45.80 per barrel for the same prior year period. The increase in natural gas and oil volumes was the result of the Company's increased investment in oil and gas properties, primarily recompletions of existing wells, wells drilled in our northeast Colorado area of operation, and the investment in oil and gas properties we own in our drilling program partnerships.

The Company's oil and natural gas production by area of operations along with average sales price (excluding derivative gains/losses) is presented below:

	Six Months Ended June 30, 2006			Six Months Ended June 30, 2005
		Natural	Natural Gas		Natural	Natural Gas
	Oil	Gas	Equivalents	Oil	Gas	Equivalents
	(Bbl)	(Mcf)	(Mcfe)*	(Bbl)	(Mcf)	(Mcfe)*
Appalachian Basin	789	780,901	785,635	1,855	843,742	854,872
Michigan Basin	1,993	711,536	723,494	2,214	792,814	806,098
Rocky Mountains	304,117	4,514,950	6,339,652	208,185	3,756,785	5,005,895
Total	306,899	6,007,387	7,848,781	212,254	5,393,341	6,666,865

Average Sales Price	$ 59.93	$ 6.34	$ 7.20	$ 45.80	$ 5.65	$ 6.03

Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production effectively. In recent years, natural gas and oil prices have been among the most volatile of all commodity prices. These price variations can have a material impact on our financial results. Natural gas prices in Colorado continue to trail prices which we receive for our Appalachian and Michigan gas which are based upon NYMEX. The Company's management believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. In 2003, a pipeline expansion project was completed reducing the local surplus and leading to improved natural gas prices in the region. There is currently a substantial amount of drilling activity in the Rockies and, if future additions to the pipeline system are not made in a timely fashion, it is possible that pipeline constraints could create a local oversupply situation in the future which could mean lower natural gas prices. Like most other producers in the area we rely on major interstate pipeline companies to construct these facilities, so their timing and construction is not within our control. See Management's Discussion and Analysis for the three months ended June 30, 2006, compared to the three months ended June 30, 2005, for a complete schedule of derivative positions.

Oil and gas production and well operations costs from the Company's producing properties for the six months ended June 30, 2006, were $13.4 million compared to a restated $8.5 million for the same prior year period, an increase of $4.9 million or 57.6%. The increase was primarily due to increased production costs and severance and property taxes on the increased volumes and higher sales prices of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting cost per Mcfe increased from $1.07 to $1.35 per Mcfe due to increased severance and property taxes on the significantly increased oil and gas prices along with additional well workovers and production enhancements work performed.

During the first six months of 2006, exploration costs decreased $2.1 million to $2.8 million from $4.9 million for the same prior year period. The prior year period included $4.9 million in dry hole costs compared to $1.6 million for the current year period. The current six-month period includes one dry hole identified and reported in the first quarter of 2006 totaling $1.3 million and an additional $0.3 million related to the dry holes identified in 2005. The Company does not expect to recognize any material additional cost related to these dry wells in future periods. The current six-month period also includes geological and geophysical (G&G) costs of $1.1 million related to a seismic program initiated on the Company's northeast Colorado properties in second quarter 2006. The Company expects to incur additional G&G costs throughout the remainder of 2006.

Well operations and pipeline income for the six months ended June 30, 2006, was $4.8 million compared to a restated $4.0 million for the same prior year period, an increase of $0.8 million or 20.0%. The increase was primarily due to an increase in the number of wells and pipeline systems operated by the Company for our drilling program partnerships as well as third parties.

Other income for the six months ended June 30, 2006, was $0.8 million compared to a restated $9.7 million for the same prior year period, a decrease of $8.9 million. The prior year period included a pre-tax gain of $6.2 million for the sale of a portion of one of the Company's undeveloped leases in Garfield County, Colorado, the sale of certain Pennsylvania wells for a gain of $1.5 million and management fees collected from the funding of two drilling partnerships.

General and administrative expenses for the six months ended June 30, 2006, were $8.6 million compared to $2.9 million for the same prior year period, an increase of $5.7 million. The increase was due to the cost of the Company's financial statement restatement, the restatement of the Company-sponsored partnerships' financial statements and increased payroll and payroll related costs. The Company expects these costs to remain at current period levels into 2007.

For the six months ended June 30, 2006, depreciation, depletion, and amortization expense increased to $14.2 million from $9.7 million in the same prior year period, an increase of $4.5 million or 46.4%. The increase was due to the increased production and investment in oil and gas properties by the Company.

Interest expense for the six months ended June 30, 2006, was $0.4 million compared to $0.3 million for the same prior year period. The increase was due to rising interest rates on significantly higher average outstanding balances of our credit facility and increased accretion related to asset retirement obligations, offset in part by $0.4 million of capitalized construction period interest in the second quarter of 2006. The Company utilizes its daily cash balances to reduce its line of credit to lower its costs of interest. The average daily outstanding debt balance for the six months ended June 30, 2006, was $14.3 million compared to $1.0 million for the same prior year period.

For the six months ended June 30, 2006, our recognized oil and gas price management gain, net was comprised of $4.4 million unrealized gains and $1.4 million realized gains compared to a net loss of $2.8 million, consisting of realized losses of $1.3 million and unrealized losses of $1.5 million for the same prior year period. The 2006 change is the result of declining natural gas prices. Oil and gas price risk management gain (loss), net is comprised of the change in fair value of oil and natural gas derivatives related to our oil and gas production (this line does not include commodity based derivative transactions related to transactions from marketing activities).

The effective income tax rate for the Company's provision for income taxes decreased from 37.0% to 36.6%, primarily due to certain one time income tax expenses during 2005.

The Company funds its operations through a combination of cash flow from operations and use of the Company's credit facility. Operating cash flow is generated by sales of natural gas and oil from the Company's well interests, natural gas marketing, profits from well drilling and operating activities from the Company's drilling programs and others, and natural gas gathering and transportation. Cash payments from Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent revenues exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities. Such credit arrangements were adequate to meet all cash and liquidity requirements.

The Company sells natural gas under contracts that are priced based on spot prices or price indexes that reflect current market prices for the commodity. As a result, variations in the market are reflected in the revenue we receive. The price of natural gas has varied substantially over short periods of time in the past, and there is every reason to expect a continuation of that variability in the future. During the first six months of 2006 prices for natural gas decreased slightly from the last part of 2005 but were still close to or above record levels, and future expectations as reflected in the New York Mercantile Exchange (NYMEX) futures market are for continuing high price levels for the remainder of 2006 and beyond. Strong domestic and international demand for energy and inadequate short term supplies are believed to be key causes of the strong prices. High prices could encourage the development of new energy sources and reduced consumption as users find more efficient ways to use energy or substitute other energy forms. High energy prices could also slow global economic growth, further reducing demand. As a result the energy price outlook could change rapidly from current expectations. Reduced natural gas prices would reduce the profitability and cash flow from the Company's gas production operations.

Natural gas prices throughout the country are generally closely related allowing for differences in the quality and energy content of the gas, the location and distance to market, and other factors. However, it is not uncommon for prices in a particular area to vary from historical relationships. This may occur when a local condition restricts the marketability of the natural gas. For example, limits on pipeline delivery capacity for natural gas can result in lower than normal prices for wells that use the system to deliver gas to market. This situation occurred in 2002 to 2003 in the Rocky Mountains, when the productive capacity of wells in the region exceeded the amount of gas that could be used by local markets or shipped out of the area. In order to access the available capacity, producers were forced to sell their gas at lower than normal prices with the alternative being to shut wells in. Since that time, additional pipeline capacity has been added, and further additions are planned in the future, so prices have returned to the historical relationship to other producing regions. Thus, future delivery constraints could result in lower than anticipated prices or production in any of the Company's producing areas.

Oil prices were near or above record levels for most of 2005 and continue through the first six months of 2006. The Company's oil prices are largely determined by oil prices in the world market. Global supply and demand and geopolitical factors are the key determinants of oil prices. The rapid growth of energy use in developing countries, most notably China, is driving a rapid increase in worldwide oil consumption. Higher prices could result in reduced consumption and/or increasing supplies that could moderate the current high price levels. Over the past several years, oil has been an increasing part of the Company's production mix. As a result, higher oil prices have contributed to the Company's increased revenue from oil and gas sales more than in the past, and the Company would suffer a greater impact if oil prices were to decrease.

Because of the uncertainty surrounding natural gas and oil prices we have used various derivative instruments to manage some of the impact of fluctuations in prices. Through October 2007, we have in place a series of floors and ceilings on part of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor, the counterparty pays us. See the section titled "Oil and Gas Derivative Activities" as discussed in our three-month results of operations for a more detailed analysis of the Company's current derivative positions.

The Company uses derivative investments to protect prices for its partners' share of production as well as its own production. Actual wellhead prices will vary based on local contract conditions, gathering and other costs and factors. The Company records the fair value of its partners' share of outstanding derivatives and the partners corresponding obligation or benefit in accounts receivable or other liabilities as appropriate.

In December, 2005, the Company commenced sales and funded its third 2005 partnership, a private limited partnership, Rockies Region Private Limited Partnership with subscriptions of approximately $36 million. Drilling operations commenced in the first quarter and continued into the second quarter of 2006. This is the first partnership under the "cost-plus" arrangement (see Note 11). Although the Company offered and funded two drilling programs in the first six months of 2005, the Company has not yet done so in 2006, resulting in a decreased drilling revenues and cash flow from operations for 2006. The next drilling program is currently being offered and is scheduled to be funded in the third quarter of 2006. We are offering a maximum of $100 million in subscriptions.

The Company invests, as its equity contribution to each drilling partnership, a sum equal to approximately 43% of the aggregate subscriptions received in the current drilling partnership being offered. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. No assurance can be made that the Company will continue to receive this level of funding from these or future programs.

Substantially all of the Company's drilling programs contain a repurchase provision allowing investors to request that the Company repurchase their partnership units. This repurchase provision is in effect any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is 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 investors request that the Company repurchase the units and subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if requested by the investors, is currently approximately $13.1 million. The Company has adequate liquidity to meet this obligation. During the first six months of 2006, the Company paid $0.2 million under this provision for the repurchase of partnership units.

During the six months ended June 30, 2006, the Company and its drilling fund partnerships drilled a total of 49 wells with one developmental dry hole. The Company drilled 37 successful wells and one dry hole in Wattenberg Field in the Denver-Julesburg Basin and 10 successful wells in the Piceance Basin in western Colorado. An exploratory dry hole was drilled in the Red Desert Basin in Wyoming.

Additionally, the Company drilled several development wells outside of the drilling fund partnerships. The Company participated in nine wells on its northeast Colorado property, which were drilled by a joint venture partner. The Company drilled 21 successful wells and 1 dry hole in the Wattenberg Field, 10 Piceance Basin wells and one well in Michigan for its own account. The Company drilled one exploratory well on its North Dakota Bakken acreage as well as participated in three exploratory wells on its North Dakota Nesson acreage.

Costs incurred by the Company in oil and gas property acquisition, exploration and development for the six months ended June 30, 2006, are presented below: (in thousand)

On January 13, 2006, the Company publicly announced that its Board of Directors has authorized the purchase of up to 10% (1,627,500 shares) of the Company's outstanding common stock during 2006. Stock purchases under in accordance with the program may be made in the open market or in private transactions, at times and in amounts that management deems appropriate. The Company may terminate or limit the stock purchase program at any time. For the six months ended June 30, 2006, the Company purchased 258,169 shares at a cost of $10.2 million ($39.33 average price per share). In July 2006, the Company purchased an additional 70,176 shares at a cost of $2.8 million ($40.48 average price per share). An additional 1,299,155 shares are authorized for purchase through December 31, 2006. The following provides a summary of the activity that has occurred since inception of the plan on January 13, 2006, through July 31, 2006.

The Company's working capital as of June 30, 2006, is a negative $7.6 million. The Company manages its working capital needs by only drawing from its credit facility of $200 million as liabilities come due and cash is required. The decrease in cash flows from operating activities from a positive $56.9 million for the six months ended June 30, 2005, to a negative $13.1 million for the six months ended June 30, 2006, is a result of the decrease in current liabilities for the current six-month period. The decrease in current liabilities is primarily due to a decrease in advances for future drilling contracts of $43.6 million in 2006. The Company has not funded a drilling program partnership to date in 2006 and has drilled the majority of the funds from the program funded in December 2005.

During the six months ended June 30, 2005, the Company funded two drilling partnerships for a total of $80 million in subscriptions. The Company is currently offering a drilling program, which is scheduled to be funded by end of third quarter 2006, with a maximum of $100 million in subscriptions being offered. At June 30, 2006, the Company has adequate liquidity with the credit facility to meet both its working capital requirements and plans for continued investment in oil and gas well drilling over the next year.

The Company has a credit facility with J. P. Morgan Chase Bank, NA (formerly Bank One, NA) and BNP Paribas of $200 million subject to and secured by required levels of oil and gas reserves. The current borrowing base, based upon current oil and gas reserves, is $125 million of which the Company has activated $80 million of the facility. The Company is required to pay a commitment fee of 0.25 to 0.375 percent per annum on the unused portion of the activated credit facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on November 4, 2010. There were no significant changes to the credit facility during the six months ended June 30, 2006.

As of June 30, 2006, the outstanding balance was $69 million compared to $24 million as of December 31, 2005. The increase of approximately $45 million was related to capital expenditures of approximately $57.9 million in the first six months of 2006. Any amounts outstanding under the credit facility are secured by substantially all properties of the Company. The credit agreement requires, among other things, the existence of satisfactory levels of natural gas reserves, maintenance of specified working capital and tangible net worth ratios along with a restriction on the payment of dividends. At June 30, 2006, the outstanding balance was subject to a prime rate of 8.25%. The Company is currently in compliance with all covenants in the credit agreement.

Contractual obligations and contingent commitments and due dates are as follows (in thousands):

	Payments due by period
Contractual Obligations		Less than	1-3	3-5	More than
and Contingent Commitments	Total	1 year	years	years	5 years
Long-Term Debt	$ 69,000	$ -	$ -	$ 69,000	$ -
Operating Leases	1,226	299	586	325	16
Asset Retirement Obligations	8,945	50	100	100	8,695
Drilling Rig Commitment	55,874	20,221	30,956	4,697	-
Derivative Agreements (1)	5,081	4,442	639	-	-
Partnership Performance Supplement (2)	4,212	660	2,608	902	42
Other Liabilities	3,703	40	250	250	3,163
Total	$ 148,041	$ 25,712	$ 35,139	$ 75,274	$ 11,916

(1) Amount represents gross liability related to fair value of derivatives. Includes fair value of derivatives for Riley Natural Gas, Petroleum Development Corporation's share of oil and gas production and derivatives contracts entered into by the Company on behalf of the affiliate partnerships as the managing general partner. The Company has a corresponding receivable from the partnerships of $0.2 million as of June 30, 2006.

(2) Represents maximum amount the Company would be required to pay to investing partners if certain levels of partnership performance are not met as of June 30, 2006 (see Note 7).

Long-term debt in the above table does not include interest because interest rates are variable and principal balances fluctuate significantly from period to period. The Company continues to pursue capital investment opportunities in producing natural gas properties as well as its plan to participate in its sponsored natural gas drilling partnerships, while pursuing opportunities for operating improvements and cost efficiencies. Management believes that the Company has adequate capital to meet its operating requirements.

As managing general partner of 75 partnerships the Company has liability for any potential casualty losses in excess of the partnership assets and insurance. The Company's management believes its and its subcontractors' casualty insurance coverage is adequate to meet this potential liability.

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under "Risks Related to the Oil and Natural Gas Industry and the Company" in Item 1A of our annual report on Form 10-K for the year ended December 31, 2005, as filed with the Securities and Exchange Commission on May 31, 2006. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

We have identified the following policies as critical to our business operations and the understanding of our results of operations. This is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and may require the application of significant judgment by our management; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 1 - Summary of Significant Accounting Policies" in our annual financial statements and related notes on Form 10-K. Our critical accounting policies and estimates are as follows:

The accompanying condensed consolidated financial statements include the accounts of Petroleum Development Corporation (PDC) and its wholly owned subsidiaries, Riley Natural Gas and PDC Securities Incorporated. All material intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its investment in interests in oil and gas limited partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its pro rata share of assets, liabilities and revenues and expenses respectively of the Company sponsored limited partnerships in which it participates. The Company's proportionate share of all significant transactions between the Company and the Company-sponsored limited partnerships are eliminated.

The Company's drilling segment recognizes revenue from drilling contracts with its sponsored drilling programs using the percentage of completion method. These contracts range in term from three to twelve months after the commencement of drilling. The Company provides geological, engineering, and drilling supervision for the drilling and completion process and uses subcontractors to perform drilling and completion services. Revenues are recognized under the percentage of completion method based upon the percentage of contract costs incurred to date to the estimated total contract costs for each contract. The Company utilizes this method because reasonably dependable estimates of the total estimated costs can be made. Because the revenue recognized depends on estimates of the final contract costs, which are assessed periodically during the term of the contract, recognized revenues are subject to revisions as the contract progresses. Anticipated losses, if any, on uncompleted contracts are recorded at the time that our estimated costs exceed the estimated contract revenue. As of June 30, 2006, the Company has a loss contract reserve of $0.2 million.

The Company offers its drilling services under two types of contractual arrangements, cost-plus fee or footage-based drilling contracts, which result in differing risk and reward relationships and, hence, differing revenue recognition polices.

Our cost-plus drilling service arrangements were initially entered into in late 2005 with drilling activity commencing in early 2006. Although the Company acts as a principal in the transaction and takes title to products and services acquired necessary for drilling, the Company acts as an agent, with little risk of loss during the performance of the drilling activities. Consistent with the provisions of EITF 99-19, the Company's services provided under the cost-plus drilling agreements are recognized net of recovered costs.

Our footage-based contracts provide for the drilling, completion and equipping of wells at footage rates and are completed within nine to twelve months after the commencement of drilling. The Company provides geological, engineering, and drilling supervision on the drilling and completion process and uses subcontractors to perform drilling and completion services and accordingly has risk of loss in performing services under these arrangements. As such, the Company recognizes revenue under these agreements gross of related expenses.

Natural gas marketing is recorded on the gross accounting method. RNG purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains or losses of the RNG commodity based derivative transactions for natural gas marketing activities are included in gas sales from marketing activities or cost of gas marketing activities, as applicable.

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company's contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry.

The Company currently uses the ''net-back" method of accounting for transportation arrangements of our natural gas sales. The Company sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our customers and reflected in the wellhead price.

Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable. The Company is paid a monthly operating fee for each well it operates for outside owners, including the limited partnerships sponsored by the Company. The fee covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions.

Management reviews accounts receivable to determine which are doubtful of collection. In making the determination of the appropriate allowance for doubtful accounts, management considers the Company's history of write-offs, relationships and overall credit worthiness of its customers, and well production data for receivables related to well operations.

The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.

Derivatives are reported on the Condensed Consolidated Balance Sheets at fair value. Changes in fair value of derivatives are recorded in earnings in the condensed consolidated statements of income as none of the Company's derivatives qualified for hedge accounting under the provisions of SFAS 133.

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Company's management. For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value.

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing an impairment test, the Company estimates the future cash flows associated with individual assets or groups of assets. Impairment is recognized when the undiscounted estimated future cash flows are less than the related asset's carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

The Company accounts for its oil and gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves. The Company obtains new reserve reports from independent petroleum engineers annually as of December 31st of each year. The Company adjusts oil and gas reserves for any major acquisitions, new drilling and divestitures during the year as needed.

Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing its reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of our financial statements, the costs are expensed to exploratory dry hole costs, which is included in "exploration cost" in the statements of income. If we are unable to make a final determination about the productive

status of a well prior to issuance of our financial statements, the well is classified as "Suspended Well Costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well's productive status, the well is removed from the suspended well status and the proper accounting treatment is recorded. The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.

The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved oil and gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to expense. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on the Company's historical experience, acquisition dates and average lease terms. Amortization of remaining lease costs for all other insignificant properties is recorded over the average remaining lives of the leases. The valuation of unproved properties is subjective and requires management of the Company to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value, is credited or charged to income. Upon sale of individual wells, the proceeds are credited to property costs.

The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products to be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management's estimates of future production or product prices could result in an impairment of the Company's oil and gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

Deferred tax assets are recognized for deductible temporary differences, net operating loss carry-forwards, and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, a valuation allowance will be established.

The judgments used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates.

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 48 provides that the tax effects from an uncertain tax position can be recognized in our financial statements, only if the position is more likely than not of being sustained on audit by the Internal Revenue Service, based on the technical merits of the position. The provisions of FIN 48 will become effective for the Company as of January 1, 2007. The cumulative effect of applying the provisions of FIN 48 will be, if any, accounted for as an adjustment to retained earnings. The Company is currently evaluating the impact of adopting FIN 48 on its consolidated financial statements.

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, to account for stock-based employee compensation. Among other items, SFAS 123(R) eliminates the use of APB 25 and the intrinsic value method of accounting for equity compensation and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards in their financial statements. We elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. Prior to the adoption of SFAS 123(R), we followed the intrinsic value method in accordance with APB 25 to account for employee stock-based compensation. Prior period financial statements have not been restated for the adoption of SFAS 123(R) under the modified prospective method. See Note 5 to condensed consolidated financial statements for a discussion of the adoption of SFAS 123(R) and its impact on the Company's condensed consolidated financial statements.

This Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are the Company's estimate of the sufficiency of its existing capital sources, its ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in successfully drilling productive wells and in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, its ability to sell its produced natural gas and oil and the prices it receives for its production, its ability to comply with changes in federal, state, local, and other laws and regulations, including environmental policies, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in this Form 10-Q, the Company's Annual Report on Form 10-K for the year ended December 31, 2005, and the Company's other SEC filings and public disclosures. The Company undertakes no duty to update or revise these forward-looking statements.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

There have been no material changes in the reported market risks faced by the Company since December 31, 2005.

The Company utilizes commodity based derivative instruments to manage a portion of its exposure to price risk from its oil and natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures contracts and option contracts for Appalachian and Michigan production, Panhandle-based contracts traded by BNP Paribas for NECO production and CIG-based contracts traded by JP Morgan for other Colorado production. These derivative instruments have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the derivative relates and, in the case of RNG, the cost of gas supplies purchased for marketing activities. As a result, while these derivatives are structured to reduce the Company's exposure to changes in price associated with the derivative commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the derivative commodity. RNG also enters into fixed-price physical purchase and sale agreements that are derivative contracts. The Company's policy prohibits the use of oil and natural gas future and option contracts for speculative purposes.

The following tables summarize the open derivative and fixed-price purchase and sale positions for Riley Natural Gas and Petroleum Development Corporation as of June 30, 2006 and 2005.

Riley Natural Gas
Open Derivative Positions
(in thousands, except average price data)

		Quantity	Weighted	Total Contract
Commodity	Type	Gas-Mmbtu	Average Price	Amount	Fair Value
Total Contracts as of June 30, 2006
Natural Gas	Cash Settled Futures / Swaps Purchases	561	$ 9.31	$ 5,222	$ (553)
Natural Gas	Cash Settled Futures / Swaps Sales	2,327	8.31	19,338	656
Natural Gas	Cash Settled Basis Swap Sales	140	0.50	70	32
Natural Gas	Physical Purchases	2,177	8.70	18,932	(598)
Natural Gas	Physical Sales	336	10.17	3,416	738
Natural Gas	Physical Basis Purchases	140	0.45	63	(25)

Contracts Maturing in 12 months following June 30, 2006
Natural Gas	Cash Settled Futures / Swaps Purchases	561	$ 9.31	$ 5,222	$ (553)
Natural Gas	Cash Settled Futures / Swaps Sales	1,837	8.12	14,924	668
Natural Gas	Cash Settled Basis Swap Sales	140	0.50	70	32
Natural Gas	Physical Purchases	1,687	8.72	14,713	(966)
Natural Gas	Physical Sales	336	10.17	3,416	738
Natural Gas	Physical Basis Purchases	140	0.45	63	(25)

Prior Year Total Contracts as of June 30, 2005
Natural Gas	Cash Settled Sale	4,064	$ 6.46	$ 26,257	$ (4,942)
Natural Gas	Cash Settled Purchase	1,345	6.95	9,353	850
Natural Gas	Cash Settled Sale Option	200	5.45	-	5
Natural Gas	Cash Settled Purchase Option	100	7.06	-	(51)
Natural Gas	Physical Contract Sale	658	7.79	5,123	(392)
Natural Gas	Physical Contract Purchase	3,543	6.68	23,655	4,406

The maximum term for the derivative contracts listed above is 31 months.

Petroleum Development Corporation
Open Derivative Positions
(in thousands, except average price data)

		Quantity
		Gas-Mmbtu	Weighted	Total Contract
Commodity	Type	Oil-Barrels	Average Price	Amount	Fair Value
Total Contracts as of June 30, 2006
Natural Gas	Cash Settled Option Sales	4,585	$ 9.41	$ 43,162	$ (2,931)
Natural Gas	Cash Settled Option Purchases	12,210	6.27	76,525	2,578

Contracts maturing in 12 months following June 30, 2006
Natural Gas	Cash Settled Option Sales	3,945	$ 9.25	$ 36,478	$ (2,563)
Natural Gas	Cash Settled Option Purchases	10,050	6.26	62,885	2,441

Prior Year Total Contracts as of June 30, 2005
Natural Gas	Purchase	23,472	$ 6.65	$ 156	$ 16
Natural Gas	Sale Option	5,166	4.81	-	152
Natural Gas	Purchase Option	2,583	7.41	-	(2,490)
Crude Oil	Sale Option	79	32.30	-	-
Crude Oil	Purchase Option	40	40.00	-	(724)

The maximum term for the derivative contracts listed above is 16 months.

In addition to including the gross assets and liabilities related to the Company's 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 entered into by the Company on behalf of the affiliate partnerships as the managing general partner. The accompanying condensed consolidated balance sheets include the negative fair value of derivatives and a corresponding receivable from the partnerships of $0.2 million as of June 30, 2006, and $5.4 million as of December 31, 2005. In addition to the short-term fair value of derivatives shown on the accompanying condensed consolidated balance sheets there is a long-term asset of $0.1 million as of June 30, 2006, and long-term liability of $1.3 million as of December 31, 2005, related to the fair value of derivatives.

The average NYMEX closing price for natural gas for the first half of 2006 and the year 2005 was $7.88 per Mmbtu and $8.62 per Mmbtu, respectively. The average NYMEX closing price for oil for the first half of 2006 and the year 2005 was $64.65 per Bbl and $55.34 per Bbl, respectively. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulation and new drilling activities within the industry.

Item 4. Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company's reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including the Company's Chief Executive Officer and Chief Financial Officer, and the Company's Audit Committee and Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

In connection with the preparation of the Company's Annual Report on Form 10-K for the year ended December 31, 2005 ("2005 10-K"), an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act). The Company concluded that control deficiencies in its internal control over financial reporting as of December 31, 2005, constituted material weaknesses within the meaning of the Public Company Accounting Oversight Board's Auditing Standard No. 2.

Material weaknesses were identified by the Company and disclosed in its 2005 10-K and its March 31, 2006, Form 10-Q. Based on the identification of material weaknesses and subsequent evaluations, the Chief Executive Officer and Chief Financial Officer have concluded that, as of June 30, 2006, the Company's disclosure controls and procedures were not effective as a result of the previously-identified material weaknesses in internal control over financial reporting.

(b) Changes and Remediation in the Company's Internal Control over Financial Reporting

There has been no change in the Company's internal control over financial reporting during the fiscal quarter ended June 30, 2006, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. See continued remediation effects discussed below.

As reported in Item 9A(c) of the 2005 10-K, the Company determined that material weaknesses in internal control over financial reporting existed as of December 31, 2005. These material weaknesses also existed as of June 30, 2006, and therefore are reported in this Form 10-Q as follows:

• The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to properly account for derivative transactions in accordance with generally accepted accounting principles. Specifically, the Company's policies and procedures relating to derivatives transactions were not designed effectively to ensure that each of the requirements for hedge accounting was evaluated appropriately with respect to the Company's commodity based derivatives. Additionally, the Company's policies and procedures relating to the derivative transactions entered into on behalf of affiliated partnerships were not adequate to ensure these transactions were recorded properly in the financial statements. As a result, a misstatement was identified in the fair value of derivatives and the oil and gas price risk management loss accounts that was corrected prior to the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.

• The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure compliance with appropriate accounting principles for its oil and gas properties. Specifically, the Company's policies and procedures were not designed effectively to ensure that the calculation of depreciation, depletion and amortization and the determination of impairments were performed in accordance with the applicable authoritative accounting guidance. As a result, misstatements were identified in the accumulated depreciation, depletion and amortization and the depreciation, depletion and amortization expense accounts that were corrected prior to the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.

• The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure proper accounting and disclosure for income taxes. Specifically, the Company's policies and procedures did not provide for appropriate control documentation or supervisory review of permanent and temporary differences, or assessment of tax reserves to ensure that they were properly reflected and disclosed in the Company's financial statements. As a result, misstatements were identified in the deferred income tax liability and income tax expense accounts that were corrected prior to the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.

• The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure that its accounting for asset retirement obligations complied with generally accepted accounting principles. Specifically, the Company's policies and procedures regarding the estimate of the fair value of the asset retirement obligations were not designed effectively to ensure that it was estimated in accordance with SFAS No. 143, Asset Retirement Obligations. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.

• The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to provide for adequate monitoring and assessment of the application of accounting principles, standards or rules as it relates to proportionate consolidation in a timely manner. As a result of this control deficiency, the Company did not appropriately eliminate its proportionate share of transactions with the Company sponsored limited partnerships, which resulted in the restatement of the Company's financial statements for the first three quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in 2004 and 2003.

Management, with oversight from the Audit Committee of the Board of Directors, has been addressing the material weakness disclosed in its 2005 Annual Report on Form 10-K and is committed to effectively remediating known weaknesses as expeditiously as possible. Due to the fact that these remedial steps have not been completed, the Company performed additional analysis and procedures in order to ensure that the consolidated financial statements contained in this Form 10-Q were prepared in accordance with generally accepted accounting principles in the United States of America. Although the Company's remediation efforts are well underway, control weaknesses will not be considered remediated until new internal controls over financial reporting are implemented and operational for a sufficient period of time to allow for effective testing and such controls are tested, and management and its independent registered certified public accounting firm conclude that these controls are operating effectively.

As of the date of this filing, the remediation initiatives management has and will continue to implement include:

§ The Company continued to enhance its financial accounting and reporting team. An additional Certified Public Accountant was hired in the first quarter of 2006 and two additional Certified Public Accountants were hired during the second quarter of 2006, which included a corporate financial reporting director and a partnership reporting director. As previously reported during 2005, the Company enhanced training for its financial accounting and reporting team; additional training has been attended and additional training is being planned for later in 2006.

§ The Company engaged a team of highly experienced advisors in the first and second quarters of 2006 to assist with various accounting research, projects and monitoring activities. They assist the Company with accounting and reporting issues including, but not limited to, derivatives, oil and gas activities, new accounting standards or rules, SEC reporting and on-going monitoring of changes that may impact the Company's application of accounting principles.

§ During 2005 and continuing in the first and second quarters of 2006, the Company reevaluated and corrected its documentation, policies and procedures, and templates with respect to its accounting for derivatives, depreciation, depletion and amortization, and income taxes and the related disclosures in its financial statements. The Company plans to make additional improvements during third quarter 2006.

§ The Company has evaluated, selected and begun planning for the implementation of a third-party integrated oil and gas accounting software system during first quarter 2006. Implementation of the system began in the second quarter of 2006. Full implementation is expected by the end of 2006.

Even though there have been no changes in the Company's internal control over financial reporting during any individual quarter since the fourth quarter of 2005, that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting, the Company believes the significant cumulative measures taken to date and the additional remediation planned for the future will address the reported material weaknesses and the Company intends to complete and test the remediation efforts by December 31, 2006. In addition, the Company will continue to develop and implement other initiatives during 2006 that will further improve both the effectiveness and efficiency of the Company's internal control over financial reporting. However, until the Company has tested the remediated internal controls, the Company can not make a complete assessment of its internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The Company is not a party to any legal actions that would materially affect the Company's operations or financial statements.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

ISSUER PURCHASES OF EQUITY SECURITIES



			Total Number of Shares	Maximum Number of
			Purchased as	Shares that May
	Total Number		Part of Publicly	Yet Be Purchased
	Of Shares	Average Price	Announced Plans	Under the Plans
Period	Purchased	Paid per Share	or Programs	or Programs
April 1-30, 2006	-	-	-	1,369,331
May 1-31, 2006	-	-	-	1,369,331
June 1-30, 2006	-	-	-	1,369,331
Total	-	-	-	1,369,331

In January 2006, the Company publicly announced that its Board of Directors authorized the Company to purchase of up to 10% (1,627,500 shares) of its outstanding common stock during 2006. Stock purchases under this program may be made in the open market or in private transactions, at time and in amounts that management deems appropriate. The Company may terminate or limit the stock purchase program at any time. For the six months ended June 30, 2006, the Company purchased 258,169 shares at a cost of $10.2 million ($39.33 average price per share). In July 2006, the Company purchased an additional 70,176 shares at a cost of $2.8 million ($40.48 average price per share). An additional 1,299,155 shares are authorized for purchase through December 31, 2006.

Item 5. Other Information

The Company, by press release dated July 20, 2006, announced that it sold a portion of its undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado to Marathon Oil Corporation. With this Report, the Company is filing a copy of the sales agreement as an exhibit.

Item 6. Exhibits

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934 the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	June 30, 2006	December 31, 2005
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$ 54,778	$ 90,110
Restricted cash	1,064	1,501
Accounts receivable	37,530	49,779
Accounts receivable - affiliates	3,162	7,234
Inventories	3,805	5,055
Fair value of derivatives	4,214	10,382
Other current assets	7,581	4,640
Total current assets	112,134	168,701
Properties and equipment, net	316,393	277,158
Other assets	1,636	3,226
Total Assets	$ 430,163	$ 449,085

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and accrued expenses	$ 93,686	$ 107,762
Fair value of derivatives	4,442	18,425
Advances for future drilling contracts	6,449	49,999
Funds held for future distribution	15,196	18,346
Total current liabilities	119,773	194,532
Long-term debt	69,000	24,000
Other liabilities	5,778	7,116
Deferred income taxes	28,560	26,889
Asset retirement obligation	8,895	8,283
Total liabilities	232,006	260,820

Commitments and contingent liabilities

Stockholders' equity:
Common stock, par value $.01 per share;
authorized 50,000,000 shares; issued and
outstanding 16,131,057 and 16,281,923 shares	161	163
Additional paid-in capital	20,144	30,423
Retained earnings	177,852	158,504
Unamortized stock award	-	(825)
Total stockholders' equity	198,157	188,265
Total Liabilities and Stockholders' Equity	$ 430,163	$ 449,085


See accompanying notes to condensed consolidated financial statements.

		Six Months
		Ended
		June 30, 2006
Expected volatility		39.5%
Expected life (in years)		5.9
Risk-free interest rate		4.3%
Dividend yield		0%

Weighted-average grant date fair value per share		$18.92


		Weighted Average
	Restricted	Grant-Date
	Shares	Fair Value
Non-vested restricted stock at December 31, 2005	38,430	$ 32.68
Granted	104,039	40.54
Vested	(12,758)	27.05
Forfeited	(4,736)	40.05

Non-vested restricted stock at June 30, 2006	124,975	$ 39.52

	June 30, 2006	December 31, 2005
Properties and Equipment:
Oil and gas properties (successful efforts method of accounting)	$ 412,121	$ 365,379
Pipelines	12,077	11,512
Transportation and other equipment	7,852	6,383
Land and buildings	4,029	3,981
Construction in progress	5,980	1,509
	442,059	388,764
Less accumulated depreciation, depletion and amortization	125,666	111,606
Properties and equipment, net of accumulated depreciation,
depletion and amortization	$ 316,393	$ 277,158

Broker/Dealer	McDonald Investments
Average price paid per share	$39.57
Number of shares purchased	328,345
Remaining number of shares subject to purchase	1,299,155

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Report of Independent Registered Public Accounting Firm

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Income

Condensed Consolidated Statement of Stockholders' Equity

Condensed Consolidated Statements of Cash Flows

Notes to Condensed Consolidated Financial Statements

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

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

Item 4. Controls and Procedures

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Item 5. Other Information

Item 6. Exhibits

SIGNATURES

SEGMENT ASSETS	June 30, 2006	December 31, 2005
Drilling and development	$ 45,914	$ 89,030
Natural gas marketing	34,943	56,518
Oil & gas sales	297,759	256,621
Well operations and pipeline income	29,415	31,407
Unallocated amounts (2)
Cash	232	3,383
Other	21,900	12,126
Total	$ 430,163	$ 449,085

Acquisition of properties:
Unproved properties	$ 7,905
Proved properties	241
Development costs	29,691
Exploration costs	12,885
Total costs incurred	$50,722

Exhibit Name	Exhibit Number	Location
By-laws	3. 2	Filed herewith.
Sales Agreement between the Company and Marathon Oil Corporation	10. 1	Filed herewith.
Acknowledgement of Independent Registered Public Accounting Firm	23. 1	Filed herewith.
Rule 13a-14(a)/15d-14(a) Certification by Chief Executive Officer	31. 1	Filed herewith.
Rule 13a-14(a)/15d-14(a) Certification by Chief Financial Officer	31. 2	Filed herewith.
Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation	32	Filed herewith.

	Petroleum Development Corporation (Registrant)


Date: August 9, 2006	/s/ Steven R. Williams Steven R. Williams Chief Executive Officer

Date: August 9, 2006	/s/ Darwin L. Stump Darwin L. Stump Chief Financial Officer