PDC Energy 10Q 2005 Q2 Quarterly report

CONFORMED COPY

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

For the period ended June 30, 2005

[ ] Transition Report Pursuant to Section 13 of 15(d) of

the Securities Exchange Act of 1934

For the transition period from to

Commission file number 0-7246

I.R.S. Employer Identification Number 95-2636730

PETROLEUM DEVELOPMENT CORPORATION

(A Nevada Corporation)

103 East Main Street

Bridgeport, WV 26330

Telephone: (304) 842-6256

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 16,268,028 shares of the Company's Common Stock ($.01 par value) were outstanding as of July 29, 2005.

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

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

INDEX



		Page No.

Explanatory Note - 2005 Restatement PART I - FINANCIAL INFORMATION		1

Item 1. Financial Statements

	Report of Independent Registered Public Accounting Firm	2

	Condensed Consolidated Balance Sheets - June 30, 2005 (Unaudited) and December 31, 2004 (Restated)	3


	Condensed Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2005 and 2004 (Unaudited)	5


	Condensed Consolidated Statements of Cash Flows-Six Months Ended June 30, 2005 and 2004 (Unaudited)	6


	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	11

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	28

Item 4.	Controls and Procedures	30

PART II	OTHER INFORMATION	32

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Explanatory Note - 2005 Restatement

As described in our Amended Annual Report on Form 10-K/A for the year ended December 31, 2004 and our Amended Quarterly Report on Form 10-Q/A for the three months ended March 31, 2005, we restated certain financial statements and other information, including such statements and information for each of the quarters of 2004 and the quarter ended March 31, 2005. These restatements related to our accounting for derivative transactions, certain aspects of the Company's oil and gas property accounting, asset retirement obligations and accounting for income taxes.

PART I - FINANCIAL INFORMATION

Report of Independent Registered Public Accounting Firm

The Board of Directors

Petroleum Development Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of June 30, 2005, the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2005 and 2004, and the related condensed consolidated statements of cash flows for the six-month periods ended June 30, 2005 and 2004. 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 Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of December 31, 2004, 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 March 30, 2005, except as to the restatement discussed in Note 22 to the consolidated financial statements which is as of December 2, 2005, 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 three 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, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

As discussed in notes 21 and 22 to the Company's Form 10-K/A as of December 31, 2004 the Company has restated the condensed consolidated balance sheet as of December 31, 2004 and the condensed consolidated statements of income and cash flows for the three and six month periods ended June 30, 2004.

KPMG LLP

Pittsburgh, Pennsylvania

January 5, 2006

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

June 30, 2005 and December 31, 2004

ASSETS

	2005	2004
	(Unaudited)	(Restated)
Current assets:
Cash and cash equivalents	$ 96,519,900	$ 77,735,300
Accounts and notes receivable	35,311,900	36,065,300
Inventories	5,559,400	1,657,300
Prepaid expenses	7,210,900	9,878,900

Total current assets	144,602,100	125,336,800



Properties and equipment	330,955,700	299,748,700
Less accumulated depreciation, depletion
and amortization	100,423,300	92,165,400
	230,532,400	207,583,300

Other assets	2,549,800	2,108,200

	$ 377,684,300	$ 335,028,300

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets, Continued

June 30, 2005 and December 31, 2004

LIABILITIES AND STOCKHOLDERS' EQUITY

	2005	2004
	(Unaudited)	(Restated)

Current liabilities:
Accounts payable and accrued expenses	$ 69,415,900	$ 69,696,600
Advances for future drilling contracts	63,880,400	42,497,300
Funds held for future distribution	13,673,000	12,911,800

Total current liabilities	146,969,300	125,105,700


Long-term debt	22,000,000	21,000,000
Other liabilities	5,675,300	3,927,500
Deferred income taxes	27,606,100	22,976,300
Asset retirement obligations	8,015,800	7,998,200


Stockholders' equity:
Common stock par value $0.01 per share;
authorized 50,000,000 shares; issued and
outstanding 16,268,028 shares and 16,589,824 shares	162,700	165,800
Additional paid-in capital	30,064,500	37,684,300
Retained earnings	138,071,000	117,052,500
Unamortized stock award	(880,400)	(882,000)
Total stockholders' equity	167,417,800	154,020,600

	$ 377,684,300	$ 335,028,300

See accompanying notes to unaudited condensed consolidated financial statements.

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Income

Three Months and Six Months ended June 30, 2005 and 2004

(Unaudited)

	Three Months Ended June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
		(Restated)		(Restated)
Revenues:
Oil and gas well drilling operations	$ 36,056,500	$ 29,453,800	$ 68,407,700	$ 58,953,100
Gas sales from marketing activities	25,917,100	24,954,300	43,439,100	47,013,200
Oil and gas sales	21,542,800	16,209,000	40,206,500	32,525,200
Well operations and pipeline income	2,244,400	1,912,400	4,356,800	3,749,900
Other income	3,572,800	687,000	9,786,600	745,100
Total revenues	89,333,600	73,216,500	166,196,700	142,986,500

Costs and expenses:
Cost of oil and gas well drilling operations	31,688,700	24,967,300	59,317,700	50,323,000
Cost of gas marketing activities	26,177,300	24,605,800	44,078,900	46,495,500
Oil and gas production and well operations cost	4,737,900	4,036,000	8,901,300	7,942,100
Exploratory dry hole costs	4,864,000	-	4,864,000	-
General and administrative expenses	1,266,000	900,900	2,883,500	1,895,100
Depreciation, depletion, and amortization	4,845,100	4,451,300	9,702,000	8,995,700
Total costs and expenses	73,579,000	58,961,300	129,747,400	115,651,400

Income from operations	15,754,600	14,255,200	36,449,300	27,335,100
Interest expense	143,000	194,400	290,800	404,000
Oil and gas price risk management (gain) loss, net	(858,400)	868,700	2,800,700	1,698,700

Income before income taxes	16,470,000	13,192,100	33,357,800	25,232,400
Income taxes	6,091,400	4,755,400	12,339,300	9,089,800

Net income	$ 10,378,600	$ 8,436,700	$ 21,018,500	$ 16,142,600

Basic earnings per common share	$ 0.63	$ 0.52	$ 1.27	$ 1.01

Diluted earnings per common share	$ 0.63	$ 0.51	$ 1.27	$ 0.98

See accompanying notes to unaudited condensed consolidated financial statements.

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Six Months Ended June 30, 2005 and 2004

(Unaudited)

	2005	2004
		(Restated)(a)
Cash flows from operating activities:
Net income	$21,018,500	$16,142,600
Adjustments to net income to reconcile to cash
provided by operating activities:
Deferred income taxes	4,629,800	6,145,600
Depreciation, depletion & amortization	9,702,000	8,995,700
Unrealized loss on derivative transactions	2,379,900	373,800
Exploratory dry hole cost	4,864,000	-
Accretion of asset retirement obligations	228,600	213,200
(Gain) loss from sale of assets	(7,856,500)	13,200
Leasehold acreage expired or surrendered	392,900	171,000
Amoritization of stock award	257,500	1,800
Decrease (increase) in current assets	1,920,800	(9,488,000)
Decrease (increase) in other assets	24,300	(142,100)
Increase (decrease) in current liabilities	19,593,100	(20,744,000)
(Decrease) increase in other liabilities	(257,500)	425,700
Total adjustments	35,878,900	(14,034,100)
Net cash provided by operating activities	56,897,400	2,108,500

Cash flows from investing activities:
Capital expenditures	(42,215,200)	(10,945,600)
Proceeds from sale of leases	1,406,500	992,500
Proceeds from sale of fixed assets	9,574,700	51,400
Net cash used in investing activities	(31,234,000)	(9,901,700)

Cash flows from financing activities:
Net proceeds from/(retirement of) long-term debt	1,000,000	(23,000,000)
Proceeds from issuance of common stock	-	2,020,200
Repurchase and cancellation of treasury stock	(7,878,800)	(2,749,100)
Net cash used in financing activities	(6,878,800)	(23,728,900)

Net increase (decrease) in cash and cash equivalents	18,784,600	(31,522,100)
Cash and cash equivalents, beginning of period	77,735,300	80,379,300

Cash and cash equivalents, end of period	$96,519,900	$48,857,200

See accompanying notes to unaudited condensed consolidated financial statements.

(a) Only certain individual line items within cash provided from operating activities have been restated. Net cash provided by operating activities is the same as the original 10-Q filing.

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

June 30, 2005

(Unaudited)

1. Accounting Policies

Reference is hereby made to Petroleum Development Corporation and Subsidiaries (the Company) Annual Report on Form 10-K/A for 2004, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the quarterly report included herein.

2. Stock Compensation

The Company applies the intrinsic-value based method of accounting prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees", and related interpretations including FASB Interpretation No. 44, "Accounting for Certain Transactions involving Stock Compensation, an interpretation of APB Opinion No. 25", to account for its fixed-plan stock options. Under this method, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. FASB Statement No. 123, "Accounting for Stock-Based Compensation" and FASB Statement No. 148, "Accounting for Stock Based Compensation- Transition and Disclosure, an amendment of FASB Statement No. 123", established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As permitted by existing accounting standards, the Company has elected to continue to apply the intrinsic-value-based method of accounting described above, and has adopted only the disclosure requirements of Statement 123, as amended and Statement 148. If the fair-value-based method had been applied to all outstanding and unvested awards in each period, the impact in 2005 would have been $47,600. There would have been no impact on reported net income in 2004.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
		(Restated)		(Restated)
Net income, as reported	$ 10,378,600	$ 8,436,700	$ 21,018,500	$ 6,142,600
Stock-based employee compensation expense
included in reported net income, net of
related tax effects	88,400	600	162,200	1,200
Deduct total stock-based employee
compensation expense determined under
fair-value based method for all awards, net of tax	(112,200)	(600)	(209,800)	(1,200)

Pro forma net income	$ 10,354,800	$ 8,436,700	$ 20,970,900	$6,142,600

Basic earnings per share as reported	$ 0.63	$ 0.52	$ 1.27	$ 1.01

Pro forma basic earnings per share	$ 0.63	$ 0.52	$ 1.27	$ 1.01

Diluted earnings per share as reported	$ 0.63	$ 0.51	$ 1.27	$ 0.98

Pro forma diluted earnings per share	$ 0.63	$ 0.51	$ 1.27	$ 0.98

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123R (revised 2004), "Share-Based Payment" which is a revision of FASB Statement No. 123, "Accounting for Stock-Based Compensation". Statement 123R supersedes APB opinion No. 25, "Accounting for Stock Issued to Employees", and amends FASB Statement No. 95, "Statement of Cash Flows". Generally, the approach in Statement 123R is similar to the approach described in Statement 123. However, Statement 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. On April 14, 2005, the SEC amended the effective date of the provisions of this statement. The effect of this amendment by the SEC is that we will have to comply with Statement 123R and use the Fair Value based method of accounting no later than the first quarter of 2006. Management has not determined the impact that this statement will have on our consolidated financial statements.

3. Basis of Presentation

The Management of the Company believes that all adjustments (consisting of only normal recurring accruals) necessary to a fair statement of the results of such periods have been made. The results of operations for the six months ended June 30, 2005 are not necessarily indicative of the results to be expected for the full year.

4. Oil and Gas Properties

Oil and Gas Properties are reported on the successful efforts method.

5. Earnings Per Share

Computation of earnings per common and common equivalent share is as follows for the three months and six months ended June 30, 2005 and 2004.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
Weighted average common shares outstanding	16,443,657	16,272,763	16,516,337	16,067,300
Weighted average common and
common equivalent shares outstanding	16,492,174	16,679,382	16,567,128	16,471,709
		(Restated)		(Restated)
Net income	$ 10,378,600	$ 8,436,700	$ 21,018,500	$ 16,142,600

Basic earnings per share	$ 0.63	$ 0.52	$ 1.27	$ 1.01
Diluted earnings per share	$ 0.63	$ 0.51	$ 1.27	$ 0.98

6. Business Segments

PDC's operating activities can be 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 over 2,700 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 transaction between segments have been eliminated. Segment information for the three and six months ended June 30, 2005 and 2004 is as follows: (All amounts presented below are in thousands)

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2005	2004		2005		2004
REVENUES		(Restated)				(Restated)
Drilling and Development	$ 36,057		$ 29,454		$ 68,408		$ 58,953
Natural Gas Marketing	25,993		24,960		43,575		47,028
Oil and Gas Sales	21,542		16,209		40,206		32,525
Well Operations and Pipeline Income	2,244		1,912		4,357		3,750
Unallocated Amounts (1)	3,498		682		9,651		731
Total	$ 89,334		$ 73,217		$ 166,197		$ 142,987

SEGMENT INCOME BEFORE
INCOME TAXES
Drilling and Development	$ 4,368		$ 4,487		$ 9,090		$ 8,630
Natural Gas Marketing	(188)		353		(509)		529
Oil and Gas Sales(3)	9,348		7,911		16,367		15,966
Well Operations and pipeline income	1,003		961		2,233		1,881
Unallocated amounts (2)
General and Administrative expenses	(1,266)		(901)		(2,883)		(1,895)
Interest expense	(143)		(194)		(291)		(404)
Other (1)	3,348		576		9,351		526
Total	$ 16,470		$ 13,192		$ 33,358		$ 25,233

	June 30, 2005	December 31, 2004
SEGMENT ASSETS		(Restated)
Drilling and Development	$ 89,229	$ 64,348
Natural Gas Marketing	31,345	31,234
Oil and Gas Sales	226,529	211,255
Well Operations and pipeline income	22,818	16,518
Unallocated amounts(2)
Cash	267	112
Other	7,492	11,561
Total	$ 377,680	$ 335,028

(1) Includes gains on sales of assets, interest on investments and partnership management fees which are not

allocated in assessing segment performance.

(2) Items which are not allocated in assessing segment performance.

(3) Includes $4,864 in exploratory dry hole cost in the three and six months ended June 30, 2005.

7. Sale of Undeveloped Acreage

During the first quarter of 2005, the Company sold a portion of one of its undeveloped Garfield County, Colorado leases to an unaffiliated entity. The proceeds of the sale were $6.2 million and the Company's carrying value of the property was zero. The Company was required to remit $1.0 million to the original lessor, unless it commenced construction of certain facilities adjacent to this undeveloped property subject to certain timing conditions. The gain of $5.2 million was recognized during the first quarter of 2005 and is included in "Other Income" in the accompanying condensed consolidated statements of income. During the second quarter of 2005, the Company commenced construction of the facilities and recorded income of $1.0 million which is included in "Other Income" in the accompanying condensed consolidated statements of income.

8. Sale of Producing Wells

During the second quarter of 2005, the Company completed the sale to an unaffiliated entity of 111 Pennsylvania wells it purchased from Pemco Gas, Inc. in 1998. The Company received proceeds of $3.4 million and recorded a gain of approximately $1.5 million which is included in "Other Income" in the accompanying condensed consolidated statements of income. In addition during the second quarter of 2005, the Company recorded an additional gain of approximately $234,000 because the asset retirement obligation liability related to the Pemco sale was no longer necessary after the sale.

9. Exploratory Dry Hole

During the second quarter of 2005, the exploratory Fox Federal #1-13 well was deemed to be non-commercial after well tests were completed and will be plugged and abandoned. Under the successful efforts method of accounting, this cost is required to be expensed in the period when such determination is made. This amounted to a $4.9 million expense which is included in the accompanying condensed consolidated statements of income under Exploratory Dry Hole Costs. Due to the dry hole, the Company reevaluated the Company's adjacent leases and wrote-off acreage of approximately $383,000 which is included in the condensed consolidated statements of income as an expense under Cost of oil and gas well drilling operations.

10. Commitments and Contingencies

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

The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's derivative instruments not perform. Such nonperformance is not anticipated. There were no counterparty default losses in the first six months of 2005 or the year 2004.

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), 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 $8.4 million. The Company believes it has adequate liquidity to meet this obligation should it arise.

The Company's drilling programs formed since 1996 contain a performance standard which states that if certain performance levels are not met, the Company must remit a payment equal to one-half of its share of revenue from such partnership to the investing partners. For the six months ended June 30, 2005 and 2004, the Company paid partnerships a total of $237,900 and $198,300 respectively in accordance with the provision.

As Managing General Partner of 10 private limited partnerships and 64 public limited partnerships, the Company has liability for any potential casualty losses in excess of the partnership assets and insurance. The Company is the sole general partner of each of these various limited partnerships. The Company believes its casualty insurance coverage is adequate to meet this potential liability.

In order to secure the services for drilling rigs, the Company makes commitments to the drilling contractor that call for penalties for a specified amount of time if the Company ceases to use such drilling rigs, an event that is not anticipated to occur. As of June 30, 2005, the Company has an outstanding commitment for $26.9 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 affect on the Company's business, financial condition, results of operations, or liquidity.

11. Common Stock Repurchase

On March 18, 2005 the Company publicly announced the authorization by its Board of Directors to repurchase up to 2% of the Company's outstanding common stock (331,796 shares) at fair market value at the date of purchase. At a meeting held June 10, 2005, the Board of Directors of Petroleum Development Corporation approved an amendment of the size of the stock repurchase from 2% to 10% (1,658,980 shares) of the Company's then outstanding common stock. Under the program, the Board has discretion as to the dates of purchase and amounts of stock to be purchased and whether or not to make purchases. This program is scheduled to expire on December 31, 2005. The following activity has occurred since inception of the plan on March 18, 2005 until June 30, 2005.

Month of Purchase	May, 2005
Average Price paid per share	$23.75
Broker/Dealer	McDonald Investments
Number of Shares Purchased	331,796
Remaining Number of Shares to purchase	1,327,184

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

2005 Restatement

The Company has recorded historically strong revenues, income and cash flow for the first two quarters of 2005. High oil and natural gas prices in combination with record Company production have been the largest contributors to both income and cash flow. The high energy prices have also increased the Company's revenues for sales of Company-owned production. Management also believes that high energy prices have increased the attractiveness of its partnership investment programs to investors resulting in a significant increase in the sale of program interests and as a result increased drilling activity, revenues and profits for the Drilling and Development segment. The new wells drilled for the partnerships also led to an increase in revenues for operating wells for the partnerships and others.

The increased level of activities also increased the costs associated with the drilling and development and well operations activities since more goods, services and other costs were incurred as a result of the higher levels of activities. Similarly, higher oil and natural gas prices also increased the cost of purchasing gas for resale in the Company's gas marketing unit.

The increased profitability and cash flow from operations allowed the company to continue to invest in capital projects. The majority of the capital investment was for oil and gas drilling and development activities. In addition the Company repurchased common stock for approximately $7.9 million.

A more detailed explanation of the various components for the most recent quarter and first two quarters of 2005 follows:

Results of Operations

Three Months Ended June 30, 2005 Compared with June 30, 2004

Revenues

Total revenues for the three months ended June 30, 2005 were $89.3 million compared to a restated $73.2 million for the three months ended June 30, 2004, an increase of approximately $16.1 million or 22.0 percent. Such increase was a result of increased drilling revenues, gas sales from marketing activities, oil and gas sales, well operations and pipeline income along with other income.

Costs and Expenses

Costs and expenses for the three months ended June 30, 2005 were $73.6 million compared to a restated $59.0 million for the three months ended June 30, 2004, an increase of approximately $14.6 million or 24.7 percent. Such increase was primarily the result of exploratory dry hole costs of $4.9 million in 2005 compared to zero in 2004 and increased cost of oil and gas well drilling operations, cost of gas marketing activities, oil and gas production and well operations costs, general and administrative costs, and depreciation, depletion and amortization.

Drilling Operations

Drilling revenues for the three months ended June 30, 2005 were $36.1 million compared to $29.5 million for the three months ended June 30, 2004, an increase of approximately $6.6 million or 22.4 percent. Such increase was due to the increased drilling funds raised through the Company's Public Drilling Programs. The Company started the second quarter of 2005 with advances for future drilling from March 31, 2005 of $54.4 million. The Company funded its second drilling partnership of the year in the second quarter with $40 million in subscriptions and commenced drilling of the partnership wells late in the second quarter. We believe in part that this increase in drilling program partnership subscriptions is fueled by the increase in oil and natural gas prices which has improved the performance of our prior programs which in turn has helped to increase our current drilling program sales.

Oil and gas well drilling operations costs for the three months ended June 30, 2005 were $31.7 million compared to a restated $25.0 million for the three months ended June 30, 2004, an increase of approximately $6.7 million or 26.8 percent. Such increase was due to the higher levels of drilling activity from our Public Drilling Programs referred to above. The gross margin on the drilling activities for the three months ended June 30, 2005 was 12.1% compared with 15.2% for the three months ended June 30, 2004, a decrease in gross margin of 3.1% as a result of the rising well fracturing and steel costs for casing and other well equipment. For the first two partnerships in 2005, the Company has raised the footage-based drilling rates it charges to its Public Drilling Partnerships.

Natural Gas Marketing Activities

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, 2005 were $25.9 million compared to a restated $25.0 million for the three months ended June 30, 2004, an increase of approximately $900,000 or 3.6 percent. Such increase was due to unrealized gains (losses) on derivative transactions which amounted to a $2.0 million gain and a $1.1 million loss for the three months ended June 30, 2005 and 2004, respectively and higher average sales prices of natural gas sold, offset in part by lower volumes.

The costs of gas marketing activities for the three months ended June 30, 2005 were $26.2 million compared to a restated $24.6 million for the three months ended June 30, 2004, an increase of $1.6 million or 6.5 percent. Such increase was due to higher average purchase prices and unrealized gains (losses) on derivative transactions, which amounted to a loss of $2.2 million and a gain of $1.0 million for the three months ended June 30, 20 05 and 2004, respectively, offset in part by lower volumes of natural gas purchased for resale. Income before income taxes for the Company's natural gas marketing subsidiary decreased from a restated income of $353,000 for the three months ended June 30, 2004 to a $188,000 loss for the three months ended June 30, 2005.

Oil and Gas Sales

Oil and gas sales from the Company's producing properties for the three months ended June 30, 2005 were $21.5 million compared to a restated $16.2 million for the three months ended June 30, 2004 an increase of $5.3 million or 32.7 percent. The increase was due to increased volumes sold at higher average sales prices of oil and natural gas. The volume of natural gas sold for the three months ended June 30, 2005 was 2.7 million Mcf at an average sales price of $6.04 per Mcf compared to 2.5 million Mcf at an average restated sales price of $5.05 per Mcf for the three months ended June 30, 2004. Oil sales were 111,000 barrels at an average sales price of $47.26 per barrel for the three months ended June 30, 2005 compared to 96,000 barrels at an average restated sales price of $34.81 per barrel for the three months ended June 30, 2004. 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 NECO, Colorado area of operation, and the investment in oil and gas properties we own in our public drilling program partnerships.

Oil and Gas Production

The Company's oil and natural gas production by area of operations along with average sales price is presented below:

	Three Months Ended June 30, 2005			Three Months Ended June 30, 2004
		Natural	Natural Gas		Natural	Natural Gas
	Oil	Gas	Equivalents	Oil	Gas	Equivalents
	(Bbl)	(Mcf)	(Mcfe)*	(Bbl)	(Mcf)	(Mcfe)*
Appalachian Basin	756	392,690	397,226	1,138	431,040	437,868
Michigan Basin	1,232	380,266	387,658	1,853	425,854	436,972
Rocky Mountains	109,370	1,924,150	2,580,370	93,113	1,689,576	2,248,254
Total	111,358	2,697,106	3,365,254	96,104	2,546,470	3,123,094

				(Restated)	(Restated)	(Restated)
Average Price	$47.26	$6.04	$6.40	$34.81	$5.05	$5.19

* One barrel of oil is equal to the energy equivalent of six Mcf of natural gas.

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, leading to improved natural gas prices in the region, which reduced local supplies. 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.

Oil and Gas Derivative Activities

Because of uncertainty surrounding natural gas prices we have used various derivative instruments to manage some of the impact of fluctuations in prices. Through March of 2007 we have in place a series of floors and ceilings on part of our natural gas and oil 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, 2005 the Company averaged natural gas volumes sold of 899,000 Mcf per month and oil sales of 37,000 barrels per month. The positions in effect as of July 31, 2005 on the Company's share of production are shown in the following table.

		FLOORS		CEILINGS
		Monthly		Monthly
		Quantity	Contract	Quantity	Contract
Month Set	Month	Mmbtu	Price	Mmbtu	Price
Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)
Feb-04	Jul 2005 - Oct 2005	33,000	$3.10	16,000	$4.43
Mar-05	Jul 2005 - Oct 2005	38,000	$4.75	19,000	$8.12
Jan-05	Nov 2005 - Mar 2006	60,000	$4.50	30,000	$7.15
Jul-05	Nov 2005 - Mar 2006	27,500	$6.50	13,750	$8.27
Mar-05	Apr 2006 - Oct 2006	42,000	$4.50	21,000	$7.25
Jul-05	Apr 2006 - Oct 2006	27,500	$5.50	13,750	$7.63
Jul-05	Nov 2006 - Mar 2007	27,500	$6.00	13,750	$8.40

NYMEX Based Derivatives - (Appalachian and Michigan Basins)
Feb-04	Jul 2005 - Oct 2005	122,000	$4.28	61,000	$5.00
Mar-05	Jul 2005 - Oct 2005	39,000	$5.75	19,500	$8.37
Jan-05	Nov 2005 - Mar 2006	156,000	$5.00	78,000	$8.50
Mar-05	Apr 2006 - Oct 2006	78,000	$5.50	39,000	$7.40
Jul-05	Apr 2006 - Oct 2006	61,000	$6.25	30,000	$8.98
Jul-05	Nov 2006 - Mar 2007	68,000	$7.00	34,000	$9.27
NYMEX Based Derivatives (NECO Area)
Feb-04	Jul 2005 - Oct 2005	150,000	$4.26	75,000	$5.00
Jan-05	Nov 2005 - Mar 2006	150,000	$5.00	75,000	$8.45
Panhandle Based Derivatives (NECO Area)
Jul-05	Apr 2006 - Oct 2006	150,000	$5.00	75,000	$8.62
Jul-05	Nov 2006 - Mar 2007	150,000	$6.50	75,000	$8.56
Oil - NYMEX Based (Wattenberg)
		Bbls		Bbls
Aug-04	Jul 2005 - Dec 2005	15,000	$32.30	7,500	$40.00

Oil and Gas Production and Well Operations Costs

Oil and gas production and well operations costs from the Company's producing properties for the three months ended June 30, 2005 were $4.7 million compared to $4.0 million for the three months ended June 30, 2004, an increase of approximately $700,000 or 17.5 percent. Such increase was 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 $1.02 to $1.13 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.

Exploratory Dry Hole Cost

During the second quarter of 2005, the exploratory Fox Federal #1-13 well, was deemed to be non-commercial after well tests were completed and will be plugged and abandoned. Under the successful efforts method of accounting, this cost is required to be expensed in the period when such determination is made. This amounted to a $4.9 million expense which is included under Exploratory Dry Hole Costs. There were no exploratory dry hole costs in 2004.

Well Operations and Pipeline Income

Well operations and pipeline income for the three months ended June 30, 2005 was $2.2 million compared to $1.9 million for the three months ended June 30, 2004, an increase of approximately $300,000 or 15.8 percent. Such 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

Other income for the three months ended June 30, 2005 was $3.6 million compared to $687,000 other income for the three months ended June 30, 2004, an increase of $2.9 million. Such increase was due to the gain on sale of some Pennsylvania wells (See Note 8) in the amount of $1.5 million, a gain on sale of undeveloped acreage in Colorado of $1.0 million (see Note 7) and increased management fee income from the increased partnership subscriptions and increased interest income earned on higher average cash balances and higher interest rates.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2005 were $1.3 million compared to $901,000 for the three months ended June 30, 2004, an increase of approximately $399,000 or 44.3%. Such increase was due to the costs of complying with the various provisions of Sarbanes Oxley, in particular with Section 404 (Internal Controls) and increased administrative activity associated with an expanding Company.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for the three months ended June 30, 2005 increased to $4.8 million from a restated $4.5 million for the three months ended June 30, 2004, an increase of approximately $300,000 or 6.7 percent. Such increase was due to the increased production and investment in oil and gas properties by the Company.

Interest Expense

Interest expense for the three months ended June 30, 2005 was $143,000 compared to a restated $194,000 for the three months ended June 30, 2004, an decrease of $51,000. Such decrease was due to significantly lower average outstanding balances of our credit facility offset in part by an unrealized gain on an interest rate swap in 2004, higher interest rates and increased accretion related to asset retirement obligations. Interest expense for the three months ended June 30, 2004 included an unrealized gain from an interest rate swap of $159,000. There was no interest rate swap in 2005. 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, 2005 was $1.0 million compared to $12.1 million for the three months ended June 30, 2004.

Oil and Gas Price Risk Management (Gain) Loss, Net

For the three months ended June 30, 2005, the Company recorded unrealized gains of $1,933,100 and realized losses of $1,074,700 compared to the three months ended June 30, 2004 which is comprised of a restated unrealized loss of $518,900 and restated realized losses of $349,800. The 2005 change is the result of increasing 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).

Provision for Income Taxes

The effective income tax rate for the Company's provision for income taxes increased from approximately 36 percent to 37 percent primarily because of a reduction in the benefit from percentage depletion, offset in part by additional benefit to be realized for the tax deduction for domestic production activities.

Net Income and Earnings per Share

Net income for the three months ended June 30, 2005 was $10.4 million compared to a restated net income of $8.4 million for the three months ended June 30, 2004, an increase of approximately $2.0 million or 23.8 percent.

Diluted earnings per share for the three months ended June 30, 2005 was $0.63 per share compared to a restated $0.51 per share for the three months ended June 30, 2004, an increase of $0.12 per share or 23.5 percent.

Six Months Ended June 30, 2005 Compared with June 30, 2004

Revenues

Total revenues for the six months ended June 30, 2005 were $166.2 million compared to a restated $143.0 million for the six months ended June 30, 2004, an increase of approximately $23.2 million or 16.2 percent. Such increase was a result of increased drilling revenues, oil and gas sales, well operations and pipeline income, and other income, offset in part from lower gas sales from marketing activities.

Costs and Expenses

Costs and expenses for the six months ended June 30, 2005 were $129.7 million compared to a restated $115.7 million for the six months ended June 30, 2004, an increase of approximately $14.0 million or 12.1 percent. Such increase was primarily the result of exploratory dry hole costs of $4.9 million in 2005 as compared to zero in 2004 and increased cost of oil and gas well drilling operations, oil and gas production and well operations cost, general and administrative expenses, and depreciation, depletion and amortization, offset in part by lower cost of gas marketing activities.

Drilling Operations

Drilling revenues for the six months ended June 30, 2005 were $68.4 million compared to $59.0 million for the six months ended June 30, 2004, an increase of approximately $9.4 million or 15.9 percent. Such increase was due to the increased drilling funds raised through the Company's Public Drilling Programs. The Company started 2005 with advances for future drilling from December 31, 2004 of $23.4 million. The Company has funded two drilling partnerships during the year with $40 million in subscriptions each and has commenced drilling of the partnerships wells. We believe in part that this increase in drilling program partnership subscriptions is fueled by the increase in oil and natural gas prices which has improved the performance of our prior programs which in turn has helped to increase our current drilling program sales.

Oil and gas well drilling operations costs for the six months ended June 30, 2005 were $59.3 million compared to $50.3 million for the six months ended June 30, 2004, an increase of approximately $9.0 million or 17.9 percent. Such increase was due to the higher levels of drilling activity from our Public Drilling Programs referred to above. The gross margin on the drilling activities for the six months ended June 30, 2005 was 13.3% compared with 14.6% for the six months ended June 30, 2004, a decrease in gross margin of 1.3% as a result of the rising well fracturing and steel costs for casing and other well equipment. For the first two partnerships in 2005, the Company has raised its footage-based drilling rates it charges to its Public Drilling Partnerships.

Natural Gas Marketing Activities

Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's gas marketing subsidiary for the six months ended June 30, 2005 were $43.4 million compared to a restated $47.0 million for the six months ended June 30, 2004, a decrease of approximately $3.6 million or 7.7 percent. Such decrease was primarily due to unrealized losses on derivative transactions which amounted to $4.7 million and $2.5 million for the six months ended June 30, 2005 and 2004, respectively.

The costs of gas marketing activities for the six months ended June 30, 2005 were $44.1 million compared to a restated $46.5 million for the six months ended June 30, 2004, a decrease of $2.4 million or 5.2 percent. Such decrease was due to unrealized gains on derivative transactions which amounted to $3.9 million and $2.0 million for the six months ended June 30, 2005 and 2004, respectively and lower volumes of natural gas purchased for resale, offset in part by higher average purchase prices. Income before income taxes for the Company's natural gas marketing subsidiary decreased from a restated $529,000 income for the six months ended June 30, 2004 to a $509,000 loss for the six months ended June 30, 2005.

Oil and Gas Sales

Oil and gas sales from the Company's producing properties for the six months ended June 30, 2005 were $40.2 million compared to a restated $32.5 million for the six months ended June 30, 2004 an increase of $7.7 million or 23.7 percent. The increase was due to increased volumes sold at higher average sales prices of oil and natural gas. The volume of natural gas sold for the six months ended June 30, 2005 was 5.4 million Mcf at an average sales price of $5.65 per Mcf compared to 5.2 million Mcf at an average restated sales price of $4.99 per Mcf for the six months ended June 30, 2004. Oil sales were 212,200 barrels at an average sales price of $45.80 per barrel for the six months ended June 30, 2005 compared to 200,200 barrels at an average restated sales price of $33.51 per barrel for the six months ended June 30, 2004. 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 NECO, Colorado area of operation, and the investment in oil and gas properties we own in our public drilling program partnerships.

Oil and Gas Production

The Company's oil and natural gas production by area of operations along with average sales price is presented below:

	Six Months Ended June 30, 2005			Six Months Ended June 30, 2004
		Natural	Natural Gas		Natural	Natural Gas
	Oil	Gas	Equivalents	Oil	Gas	Equivalents
	(Bbl)	(Mcf)	(Mcfe)*	(Bbl)	(Mcf)	(Mcfe)*
Appalachian Basin	1,855	843,742	854,872	2,342	888,258	902,310
Michigan Basin	2,214	792,814	806,098	3,004	869,816	887,840
Rocky Mountains	208,185	3,756,785	5,005,895	194,894	3,411,388	4,580,752
Total	212,254	5,393,341	6,666,865	200,240	5,169,462	6,370,902

				(Restated)	(Restated)	(Restated)
Average Price	$45.80	$5.65	$6.03	$33.51	$4.99	$5.11

* One barrel of oil is equal to the energy equivalent of six Mcf of natural gas.

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, 2005 compared with restated June 30, 2004 for a complete schedule of derivative positions.

Oil and Gas Production and Well Operations Costs

Oil and gas production and well operations costs from the Company's producing properties for the six months ended June 30, 2005 were $8.9 million compared to $7.9 million for the six months ended June 30, 2004, an increase of approximately $1.0 million or 12.7 percent. Such increase was 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 $1.00 to $1.11 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.

Exploratory Dry Hole Cost

Well Operations and Pipeline Income

Well operations and pipeline income for the six months ended June 30, 2005 was $4.4 million compared to $3.7 million for the six months ended June 30, 2004, an increase of approximately $700,000 or 18.9 percent. Such 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

Other income for the six months ended June 30, 2005 was $9.8 million compared to $745,000 for the six months ended June 30, 2004, an increase of $9.1 million. The increase is a result of a sale of a portion of one of our undeveloped leases in Garfield County, Colorado, which we sold in the first quarter of 2005 (See Note 7) for a pre-tax gain of $6.2 million, a second quarter gain on sale of some Pennsylvania wells (See Note 8) in the amount of $1.5 million, management fees collected from the funding of two drilling partnerships, and interest earned on higher average cash balances and higher interest rates.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2005 were $2.9 million compared to $1.9 million for the six months ended June 30, 2004, an increase of approximately $1.0 million or 52.6%. Such increase was due to the costs of complying with the various provisions of Sarbanes Oxley, in particular with Section 404 (Internal Controls) and increased administrative activity associated with an expanding Company.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for the six months ended June 30, 2005 increased to $9.7 million from a restated $9.0 million for the six months ended June 30, 2004, an increase of approximately $700,000 or 7.8 percent. Such increase was due to the increased production and investment in oil and gas properties by the Company.

Interest Expense

Interest expense for the six months ended June 30, 2005 was $291,000 compared to a restated $404,000 for the six months ended June 30, 2004, a decrease of $113,000 or 28.0 percent. Such decrease was due to significantly lower average outstanding balances of our credit facility offset in part by an unrealized gain on an interest rate swap in 2004, higher interest rates and increased accretion related to asset retirement obligations. Interest expense for the six months ended June 30, 2004 included an unrealized gain from an interest rate swap of $290,000. There was no interest rate swap in 2005. 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, 2005 was $950,000 compared to $12.1 million for the six months ended June 30, 2004.

Oil and Gas Price Risk Management (Gain) Loss, Net

For the six months ended June 30, 2005, the Company recorded unrealized losses of $1,525,500 and realized losses of $1,275,200 compared to the six months ended June 30, 2004 balance which is comprised of restated unrealized losses of $1,228,900 and restated realized losses of $469,800. The 2005 change is the result of increasing 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 item does not include commodity based derivative transactions related to transactions from marketing activities).

Provision for Income Taxes

Net income and Earnings per share

Net income for the six months ended June 30, 2005 was $21.0 million compared to a restated net income of $16.1 million for the six months ended June 30, 2004, an increase of approximately $4.9 million or 30.4 percent.

Diluted earnings per share for the six months ended June 30, 2005 was $1.27 per share compared to a restated $0.98 per share for the six months ended June 30, 2004, an increase of $0.29 share or 29.6 percent.

Liquidity and Capital Resources

The Company funds its operations through a combination of cash flow from operations and use of the Company's credit facility. Operational 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 for the Company's public 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 payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities.

Oil and Gas Derivative Activities

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 March, 2007 we have in place a series of floors and ceilings on part of our natural gas and oil 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 previous pages in this Management's Discussion and Analysis for a schedule of open derivative positions.

The Company also enters into derivative instruments 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.

Natural Gas Pricing and Pipeline Capacity

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 two quarters prices for natural gas were close to or above record levels, and future expectations as reflected in the NYMEX futures market are for continuing high price levels for the balance of 2005 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 tend to be fairly closely related after allowing for differences in the quality and energy content of the gas, the location and distance to market, and other factors. Sometimes prices in a particular area may vary from historical relationships. This can 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. However future delivery constraints could result in lower than anticipated prices or production in any of the Company's producing areas.

Oil Pricing

Oil prices were near or above record levels for most of the first two quarters of 2005. 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.

Public Drilling Programs

During January, 2005, the Company commenced sales and funded its first 2005 Partnership (PDC 2005-A) at its maximum subscriptions of $40 million. The Company commenced the drilling operations of the partnership late in the first quarter and will continue to drill for the partnership into the second and third quarters of 2005.

In April, 2005, the Company commenced sales and funded its second 2005 Partnership (PDC 2005-B) at its maximum allowable subscriptions of $40 million. The Company commenced drilling operations of this partnership late in the second quarter and will continue to drill for the partnership during the third and fourth quarters of 2005.

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 will commence in the first quarter of 2006.

Substantially all of the Company's drilling programs contain a repurchase provision allowing Investors to request that the Company repurchase their partnership units at any time beginning with the third anniversary after 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), only if investors request the Company to repurchase such 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 $8.4 million. The Company has adequate liquidity to meet this obligation. During the first six months of 2005, the Company purchased $151,275 under this provision.

Drilling Activity

During the first six months 2005, the Company drilled along with its public drilling fund partnerships a total of 84 successful wells. The Company drilled 66 successful wells in its Wattenberg field in the Denver-Julesburg Basin and 18 successful wells in the Piceance Basin in western Colorado, all of the wells that the Company drills in these two areas are in conjunction with its public drilling fund partnerships. The Company plans to conduct the remainder of its 2005 partnership drilling activity in these two areas.

Through the second quarter of 2005, the Company has drilled for its own account a 46 gross and 31.5 net wells on its northeast Colorado properties (NECO). The wells are being drilled on locations created by the regulatory approval of the reduction in well spacing from 80 to 40 acres on the properties the Company acquired in Yuma County in 2003.

Exploratory Wells

During the second quarter of 2005, the exploratory Fox Federal #1-13 well, was deemed to be non-commercial after well tests were completed and will be plugged and abandoned. Under the successful efforts method of accounting, this cost is required to be expensed in the period when such determination is made. This amounted to a $4.9 million expense which is included in the Income Statement under Exploratory Dry Hole Costs.

The Company's second exploratory well, the Coffeepot Springs #24-34 has been drilled to total depth, completed in three zones, tested and has been deemed to be productive under the successful efforts method of accounting. The Company has a 100% working interest in this well. The cost of this well, which is approximately $5.2 million as of November 30, 2005 will be capitalized and depreciated over the life of the well using the units of production depreciation method.

Early in the third quarter the Company commenced the drilling of a horizontal Bakken exploratory well, the Fedora #34-22H in Dunn County, North Dakota which has been drilled to total depth, completed and placed in production in late September, 2005. The Company has a 100% working interest in this well. The cost of this well, which is approximately $4.1 million as of November 30, 2005, will be capitalized and depreciated over the life of the well using units of production depreciation method.

All the costs of the above three exploratory wells were incurred 100% by the Company as no costs were incurred by the drilling fund partnerships.

Purchase of Oil and Gas Properties

Although the Company made several offers to purchase producing oil and gas properties from other companies during the first six months of 2005, it was not successful in purchasing any of those properties. The Company did purchase a number of small interests in its partnerships from investors wishing to liquidate their holdings under the repurchase provision of the partnerships.

Costs incurred by the Company in oil and gas acquisitions, exploration and development for the six months ended June 30, 2005 are presented below:

Property acquisition cost:
Proved undeveloped properties		$4,979,982
Producing properties		178,775
Development costs		29,572,159
Exploration costs		4,570,210
		$39,301,126

Common Stock Repurchase Program

On March 18, 2005 the Company publicly announced the authorization by its Board of Directors to purchase up to 2% of the Company's outstanding common stock (331,796) at fair market value at the date of purchase. At a meeting held June 10, 2005, the Board of Directors of Petroleum Development Corporation approved an amendment of the size of the stock repurchase from 2% to 10% (1,658,980 shares) of the Company's outstanding common stock. Under the program, the Board has discretion as to the dates of purchase and amounts of stock to be purchased and whether or not to make purchases. This program is scheduled to expire on December 31, 2005. The following activity has occurred since inception of the plan on March 18, 2005 until June 30, 2005.

Month of Purchase		May, 2005
Average Price Paid per Share		$23.75
Broker/Dealer		McDonald Investments
Number of Shares Purchased		1,327,184

Working Capital

Although the Working Capital of the Company as of June 30, 2005 is a negative $2.4 million this amount included a net liability of $3.2 million related to the fair value of derivatives. Such amount may or may not be realized depending on the change in the fair value of derivatives between June 30, 2005 and settlement and will not require additional expenditures of cash since it will be funded with proceeds from future oil and gas sales.

Long-Term Debt

The Company has a $200 million credit facility agented by JP Morgan Securities, Inc. and BNP Paribas subject to and secured by adequate levels of oil and gas reserves. The maximum available borrowing base is $125.0 million as of April 1, 2005, of which the Company has activated $80 million of the facility. The Company is required to pay a commitment fee of ¼ percent annually 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 and subject to a pricing grid which defines the spread over LIBOR. No principal payments are required until the credit agreement expires on November 4, 2010.

As of June 30, 2005, the outstanding balance was $22,000,000. 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 and maintenance of certain financial and negative covenants customary for a facility of this size. At June 30, 2005, the outstanding balance was subject to a prime rate of 6.25%. As of this filing the Company was in compliance with all financial covenants in the credit agreement except for timely filing of the September 30, 2005, Form 10-Q. The Company has been granted a waiver through January 12, 2006, for the delivery of its quarterly reporting requirements for the quarter ended September 30, 2005.

Contractual Obligations

Contractual obligations and due dates are as follows:

		Less than			More than
Contractual Obligations	Total	1 year	1-3 Years	3-5 Years	5 years
Long-Term Debt	$ 22,000,000	$ -	$ -	$ 22,000,000	$ -
Operating Leases	737,600	281,300	309,100	107,200	40,000
Asset Retirement Obligations	8,015,800	50,000	100,000	100,000	7,765,800
Drilling Rig Commitment	26,950,000	5,621,000	11,242,000	10,087,000	-
Derivative Agreements	12,450,900	10,133,800	2,317,100	-	-
Other Liabilities	3,326,200	40,000	250,000	250,000	2,786,200
Total	$ 73,480,500	$ 16,126,100	$ 14,218,200	$ 32,544,200	$ 10,592,000

Long-term debt in the above table does not include interest as 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. Management believes that the Company has adequate capital to meet its operating requirements.

Commitments and Contingencies

As Managing General Partner of 10 private limited partnerships and 64 public limited partnerships, the Company has liability for any potential casualty losses in excess of the partnership assets and insurance. The Company is generally the sole general partner of each of these various limited partnerships. The Company believes its casualty insurance coverage is adequate to meet this potential liability.

Factors That May Affect Future Results and Financial Conditions

In the course of its normal business the Company is subject to a number of risks that could potentially adversely impact its revenues, expenses and financial condition. The following is a discussion of some of the more significant risks.

Drilling of oil and natural gas wells is highly speculative and may be unprofitable or result in the loss of the entire investment in a well and the lease on which it is located. To the extent the Company drills unsuccessful developmental wells its future profitability will be reduced on production from the field where the well is located, since the investment in the well will be included in the investment in the field and depreciated on the unit-of-production method. Recently the Company has begun drilling several planned exploratory wells that could lead to significant future development opportunities. Under the Successful Efforts method used by the Company, the costs of exploratory dry holes are taken as an expense in the period when it is determined that they are non-productive. As a result exploratory dry holes, if any additional are drilled, will result in an immediate reduction in net income for that period.

Reductions in prices of oil and natural gas reduce the profitability of the Company's production operations. Revenue from the sale of oil and gas increases when prices increase and declines when prices decrease. These price changes can occur rapidly and are not predictable nor within the control of the Company.

Changes in prices of oil and natural gas may also affect sales of drilling programs. Recent energy price increases have coincided with increased sales of the Company's partnership investments, and increased profitability from those operations. It is likely that declining prices could have the opposite effect, reducing partnership sales and profitability. Because the Company has not been able to meet the demand for oil and gas investments from its Broker/Dealer network, those Broker/Dealers have been seeking investments from other oil and gas program sponsors. These new competitors could potentially take business from the Company, particularly in a declining price market for oil and gas.

Increases in prices of oil and natural gas have increased the cost of drilling, the cost of potential acquisitions and other factors affecting the performance of the Company in both the short and long term. In the current high price environment most oil and gas companies have increased their expenditures for drilling new wells. This has resulted in increased demand and higher prices for leases, oilfield services and well equipment. Similarly higher energy prices have increased the price purchasers are willing to pay for producing properties and increased competition for the properties that are available. These factors make it more difficult to add to the Company's production, and increase the cost of additions. To the extent that new reserves and production are added at these higher prices in addition to the increased drilling costs, the risk to the Company of decreased profitability from future decreases in oil and gas prices is increased.

The Company's derivative activities could result in reduced revenue compared to the level the Company would experience if no derivatives were in place. The Company uses derivatives to reduce the impact of price movements on revenue. While these derivatives protect the Company against the impact of declining prices, they also may limit the positive impact of price increases. As a result the Company may have lower revenues when prices are increasing than might otherwise be the case.

The high level of drilling activity could result in an oversupply of natural gas on a regional or national level resulting in much lower commodity prices. Recently the natural gas market been characterized by excess demand compared to the supplies available. The high level of drilling, combined with reduction in demand resulting from high prices could result in an oversupply of natural gas. On a local level increasing supplies could exceed available pipeline capacity. In both cases the result would probably be lower prices for the natural gas the Company produces and reduced profitability for the Company.

The Company owns interests in and operates more than 2,700 wells and drills many new wells each year. Environmental hazards and unpredictable costs associated with those wells could have a negative impact on the performance of the Company. While many of the wells the Company drills are relatively low risk development wells, the Company also plans to drill exploratory wells to test new areas in coming months. Under the terms of the Company's drilling agreements with its partnerships the Company also bears the risk for the investor partners interests in new wells through an indemnification agreement. The costs associated with problems encountered in drilling, completing and operating wells can be significant, and could adversely affect the profitability of the Company if such problems are encountered.

Changes in the Tax Code could reduce the attractiveness of the Company's partnership investments and reduce the revenues and profitability of those operations. The partnership interests sold by the Company offer investors significant tax benefits under current tax regulations. If the Congress changes the Code and eliminates or reduces those benefits investments in the partnerships would be less attractive to investors and fewer investors might invest.

Increasing interest rates could increase the cost of the Company's borrowing. Higher interest rates would increase the interest costs of the Company's borrowing, and would make additional borrowing less attractive. This could also make potential acquisitions and other activities funded with borrowed money less profitable, potentially reducing the rate of growth of production and reserves. Consequently, the Company's profitability could be reduced.

Critical Accounting Policies and Estimates

We have identified the following policies as critical to our business operations and the understanding of our results of operations. This listing 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 observance 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 financial statements and related notes on Form 10-K/A. Our critical accounting policies and estimates are as follows:

Revenue Recognition

The Company's drilling segment recognizes revenue from our drilling contracts with our publicly registered drilling programs using the percentage of completion method. These contracts are footage rate based and 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. The percentage of completion method measures 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 continually during the term of the contract, recognized revenues are subject to revisions as the contract progresses. Anticipated losses, if any, on uncompleted contracts would be recorded at the time that our estimated costs exceeded the contract revenue. The Company has not experienced any contract losses in 2005 or 2004.

Natural gas marketing is recorded on the gross accounting method. Riley Natural Gas ("Riley"), 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. Riley 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 Riley takes title to the gas it purchases from the various producers and bears the risks and enjoys the benefits of that ownership. Both the realized and unrealized portions of the Riley 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 is competitive with rates charged by other operators in the area. 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.

Valuation of Accounts Receivable

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.

Accounting for Derivatives Contracts at Fair Value

The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives are complex; interpretation of these requirements by standard-setting bodies is ongoing. The Company currently does not use hedge accounting treatment for its derivatives.

Derivatives are reported on the Consolidated Balance Sheets at fair value. Changes in fair value of derivatives are recorded in earnings in the consolidated statements of income as none of the Company's derivatives qualified for hedge accounting under the provisions of FAS No. 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.

Use of Estimates in Long-Lived Asset Impairment Testing

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Company estimates the future cash flows associated with individual assets or groups of assets. Impairment must be 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.

Oil and Gas Properties

Exploration and development costs are accounted for by the successful efforts method.

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 expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. 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.

Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes are capitalized.

Unproved properties or leases are written-off to expense when it is determined that they will expire or be abandoned.

Costs of proved developed properties, exploration and development costs and equipment, 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 an independent petroleum engineer annually as of December 31^st of each year. The Company adjusts for any major acquisitions, new drilling and divestures during the year as needed.

Upon sale or retirement of 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 a partial unit of property, the proceeds are credited to accumulated depreciation and depletion.

Deferred Tax Asset Valuation Allowance

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 cannot be recognized under the preceding criteria, a valuation allowance has been 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.

New Accounting Standards

The FASB issued FIN 46, "Consolidation of Variable Interest Entities", in January 2003 and amended the interpretation in December 2003. A variable interest entity (VIE) is an entity in which its voting equity investors lack the characteristics of having a controlling financial interest or where the existing capital at risk is insufficient to permit the entity to finance its activities without receiving additional financial support from other parties. FIN 46 requires the consolidation of entities which are determined to be VIEs when the reporting company determines itself to be the primary beneficiary (the entity that will absorb a majority of the VIE's expected losses, receive a majority of the VIE's residual returns, or both). The amended interpretation was effective for the first interim or annual reporting period ending after March 15, 2004, with the exception of special purpose entities for which the statement was effective for periods ending after December 15, 2003. We have completed a review of our partnership investments and have determined that those entities do not qualify as VIEs.

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123R (revised 2004), "Share-Based Payment" which is a revision of FASB Statement No. 123, "Accounting for Stock-Based Compensation". Statement 123R supersedes APB opinion No. 25, "Accounting for Stock Issued to Employees", and amends FASB Statement No. 95, "Statement of Cash Flows". Generally, the approach in Statement 123R is similar to the approach described in Statement 123. However, Statement 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. The provisions of this statement become effective for our first quarter 2006. Management has not determined the impact that this statement will have on our consolidated financial statements.

Recently Issued Accounting Pronouncements

On March 30, 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN No. 47). This interpretation clarifies that the term "conditional asset retirement obligation" as used in Statement No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exits. FIN No. 47 will be effective for the Company no later than the end of the fiscal year ended December 31, 2005. The Company does not expect any impact on the Company's financial position or results of operations upon adoption of FIN No. 47.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 "Accounting for Suspended Well Costs." This staff position amends FASB Statement No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies" and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well's economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in the FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The Company does not expect the application of this FSP to have a significant impact on the Company's financial position or results of operations.

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 No. 20, Accounting Changes, and SFAS No. 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 No. 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. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Consequently, we will adopt the provisions of SFAS No. 154 for our fiscal year beginning January 1, 2006. We currently believe that adoption of the provisions of SFAS No. 154 will not have a material impact on our consolidated financial statements.

In June 2005, the EITF reached a consensus on EITF Issue No. 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. This consensus applies to voting right entities not within the scope of FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities in which the investor is the general partner in a limited partnership or functional equivalent. The EITF consensus is that the general partner in a limited partnership is presumed to control that limited partnership regardless of the extent of the general partner's ownership interest, and therefore, should include the limited partnership in its consolidated financial statements. The general partner may overcome this presumption of control and not consolidate the entity if the limited partners have either: (a) the substantive ability to dissolve (liquate) the limited partnership or otherwise remove the general partner through substantive kick-out rights that can be exercised without having to show cause; or (b) substantive participating rights in managing the partnership. This guidance became immediately effective upon ratification by the FASB on June 29, 2005, for all newly formed limited partnerships and for

existing limited partnerships for which the partnership agreements have been modified. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

Disclosure Regarding Forward Looking 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 prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, 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 and in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.

When used in the Form 10-Q, the words, "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Management's Discussions and Analysis of Financial Condition and Results of Operations" and elsewhere in this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Interest Rate Risk

There have been no material changes in the reported market risks faced by the Company since December 31, 2004.

Commodity Price Risk

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 and CIG-based contracts traded by JP Morgan for Colorado production and purchase and sales contracts with customers deemed to be derivatives used by its gas marketing company, Riley Natural Gas. 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 derivative instruments are structured to reduce the Company's exposure to changes in price associated with the commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the commodity. 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 purchase and sale contracts for Riley Natural Gas and PDC as of June 30, 2005 and 2004.

Riley Natural Gas
Open Derivatives Contracts
Commodity	Type	Quantity	Weighted	Total	Fair
		Gas-Mmbtu	Average	Contract	Market
		Oil-Barrels	Price	Amount	Value
Total Contracts as of June 30, 2005
Natural Gas	Cash Settled Sale	4,064,000	$6.46	$ 26,257,050	$ (4,942,194)
Natural Gas	Cash Settled Purchase	1,345,000	$6.95	9,353,030	850,113
Natural Gas	Cash Settled Sale Option	200,000	$5.45		5,029
Natural Gas	Cash Settled Purchase Option	100,000	$7.06		(50,567)
Natural Gas	Physical Contract Sale	657,800	$7.79	5,122,908	(392,300)
Natural Gas	Physical Contract Purchase	3,543,200	$6.68	$ 23,655,200	$ 4,406,500

Contracts maturing in 12 months following June 30, 2005
Natural Gas	Cash Settled Sale	3,024,000	$6.60	$ 19,965,270	$ (3,162,634)
Natural Gas	Cash Settled Purchase	1,115,000	$6.86	7,650,680	752,508
Natural Gas	Cash Settled Sale Option	200,000	$5.45		5,029
Natural Gas	Cash Settled Purchase Option	100,000	$7.06		(50,567)
Natural Gas	Physical Contract Sale	602,900	$8.24	4,697,691	(360,300)
Natural Gas	Physical Contract Purchase	2,683,200	$6.87	$ 18,421,000	$ 2,752,100

Prior Year Total Contracts as of June 30, 2004
Natural Gas	Cash Settled Sale	3,660,000	$5.10	$ 18,681,050	$ (3,742,180)
Natural Gas	Cash Settled Purchase	430,000	$5.53	2,378,320	369,300
Natural Gas	Cash Settled Sale Option	270,000	$4.75		0
Natural Gas	Cash Settled Purchase Option	135,000	$6.74		(1,440)
Natural Gas	Physical Contract Sale	223,000	$6.24	1,391,870	(116,500)
Natural Gas	Physical Contract Purchase	3,654,300	$5.37	$ 19,609,900	$ 3,462,900
The maximum term over which RNG is hedging exposure to the variability of cash flows for commodity price risk is
40 months.

Petroleum Development Corporation
Open Derivatives Contracts
Commodity	Type	Quantity	Weighted	Total	Fair
		Gas-Mmbtu	Average	Contract	Market
		Oil-Barrels	Price	Amount	Value
Total Contracts as of June 30, 2005
Natural Gas	Purchase	23,472	$6.65	$ 156,187	$ 16,380
Natural Gas	Sale Option	5,166,404	$4.81		152,072
Natural Gas	Purchase Option	2,583,202	$7.41		(2,490,039)
Crude Oil	Sale Option	79,488	$32.30		333
Crude Oil	Purchase Option	39,744	$40.00		(723,515)

Contracts maturing in 12 months following June 30, 2005
Natural Gas	Purchase	23,472	$6.65	$ 156,187	$ 16,380
Natural Gas	Sale Option	4,096,084	$4.74		74,710
Natural Gas	Purchase Option	2,048,042	$7.24		(2,198,717)
Crude Oil	Sale Option	79,488	$32.30		333
Crude Oil	Purchase Option	39,744	$40.00		(723,515)

Prior Year Total Contracts as of June 30, 2004
Natural Gas	Purchase	21,552	$4.73	$ 101,941	$ 33,976
Natural Gas	Sale Option	5,114,680	$4.48		557,708
Natural Gas	Purchase Option	2,035,500	$5.45		(1,837,458)
Crude Oil	Sale Option	68,868	$31.63	2,178,294	$ 26,420
The maximum term over which PDC is managing exposure to the variability of cash flows for commodity price risk is
16 months.

See "Working Capital" in Management's Discussions of Liquidity and Capital Resources for the effect of these contracts on the Company's Consolidated Balance Sheet.

The average NYMEX closing price for natural gas for the six months of 2005 and the year 2004 was $6.50 Mmbtu and $6.14 Mmbtu. The average NYMEX closing price for oil for the six months of 2005 and the year 2004 was $49.93 bbl and $41.44 bbl. 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

(a) Evaluation of disclosure 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. The Company's management, with participation of the Company's Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q.

Remediation of Material Weaknesses in Internal Control

As previously disclosed in the Company's Amended Annual Report on Form 10-K/A for the year ended December 31, 2004, and in its amended quarterly report on Form 10-Q/A for the quarter ended March 31, 2005, the Company determined that, as of the end of the fiscal 2004, there were material weaknesses in its internal control over financial reporting relating to improper accounting of (1) derivatives transactions, (2) oil and gas property, (3) asset retirement obligations, and (4) provision for income taxes. The Company's management and Audit Committee have dedicated significant resources to assessing the underlying issues giving rise to the aforementioned accounting errors and to ensure that proper steps have been and are being taken to improve our internal controls. We have assigned the highest priority to the correction of the related control deficiencies and have taken and will continue to take action to fully correct them. Management is committed to instilling strong control policies and procedures and ensuring that the 'tone at the top' is committed to accuracy and completeness in all financial reporting. The Company's Audit Committee will continually be updated as to the progress and status of the remediation initiatives to ensure they are adequately implemented. As of the date of this filing, while we have corrected the financial statements, we have not completed the remediation of these material weaknesses; however, we believe that the remediation initiatives outlined below, when completed, will be sufficient to eliminate the material weaknesses in internal control over financial reporting as discussed above.

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

The Company is implementing a training initiative to increase the Company's technical expertise. The programs offered through this training initiative will include basic and advanced oil and natural gas accounting training programs, as well as general accounting, financial reporting (including SEC reporting), and income tax training programs. Also, related to this initiative, the Company has purchased licenses for accounting research software. Additionally, the CFO or a qualified designee will be responsible for the periodic review of the documentation and calculations related to oil and gas properties.
The Company currently does not use hedge accounting treatment; however, in the future when using hedge accounting, the Company will implement additional controls with respect to accounting for derivative transactions in accordance with SFAS No. 133. These controls include thorough and formal documentation of all potential derivative transactions prior to initiation of the transaction. This documentation will include the hedging relationship, the entity's risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item, the nature of the risk being hedged, and the method of assessing the hedging instrument's effectiveness. The Company is in the process of evaluating derivative accounting software to be implemented to calculate the impact of derivative contracts on the financial statements. The Company will also seek the input of its independent derivative expert to assist with the selection of the derivative accounting software. Additionally, the CFO or a qualified designee will be responsible for the periodic review of the documentation and calculations of derivative transactions. The Company also has utilized a derivative expert to assist the Company in evaluating its current derivative transactions to ensure that they have been properly reported and will utilize derivative experts in the future as needed.
The Company has re-evaluated and corrected its documentation, policies and procedures, and templates with respect to accounting for its oil and gas properties in compliance with generally accepted accounting principles. The design and effective operation of proper policies and procedures as well as the correction of these documents will ensure the accuracy of oil and gas property valuation in accordance with generally accepted accounting principles. This includes documented procedures to identify significant components of oil and gas property calculations including field designation, reserves and applicable set-up costs. This documentation also includes correcting the carry-forward schedules utilized to calculate the depreciation, depletion and amortization with the correct information and identification of the components of the calculation. Additionally, the CFO or a qualified designee will be responsible for the periodic review of the documentation and accounting for oil and gas properties, including related calculations. Also, the Company plans to utilize an independent specialist to review the Company's accounting for oil and natural gas properties, including the Company's documentation as well as templates. The specialist will be an accounting firm with significant oil and natural gas accounting and income tax experience and SEC experience and will also be utilized in identifying and implementing new accounting standards and review of our income tax reporting procedures.

The Company has reevaluated and corrected its documentation, policies and procedures, and templates with respect to its accounting for asset retirement obligations. The specialist discussed in the previous paragraph will also be utilized to help verify these practices and implement any new requirements.
The Company has reevaluated and corrected its documentation, policies and procedures, and templates with respect to its accounting for income taxes and the related disclosures in its financial statements. The Company will utilize a qualified independent tax expert to periodically review the calculation of income taxes and the related disclosures for reporting purposes and to identify and help implement any new rules or regulations.

{b} Changes in Internal Control Over Financial Reporting

As previously reported, there was no change in our internal control over financial reporting during the quarter ended June 30, 2005, that materially affects, or is reasonably likely to materially affect, our internal control over financial reporting. However, subsequent to June 30, 2005, we are in the process of implementing the remedial actions described above.

Although we have taken steps as referred to above to correct the material weaknesses, they were not remediated as of December 31, 2005.

Effective January 1, 2006 the Company reorganized the structure of its accounting department to provide a better distribution of responsibilities and the work load associated with the Company's accounting and financial reporting. As a part of the reorganization, several additional positions were created in the accounting department. The Controller's position was eliminated and new positions for a Director of Accounting Operations and a Director of Financial Reporting were created. The Company's controller was slated to become the Director of Financial Reporting, however, she chose to resign her position with the Company but is continuing to act as a consultant and will continue to perform the same duties until appropriate replacements are trained. The CFO will oversee the responsibilities of the Director of Financial Reporting until a qualified candidate has been hired to fill the position. The Company is currently seeking qualified accountants to fill certain of the new positions. The Company believes that the reorganization, when completed, will allow it to better meet its current financial and accounting obligations and to grow to fill future needs.

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
				(d)
			(c)	Maximum Number
			Total Number	(or Approximate
			of Shares	Dollar Value) of
	(a)		Purchased as	Shares that May
	Total Number	(b)	Part of Publicly	Yet Be Purchased
	Of Shares	Average Price	Announced Plans	Under the Plans
Period	Purchased	Paid per Share	or Programs	or Programs
May 1 - May 31, 2005	331,796	$23.75	331,796	1,327,184
Total	331,796	$23.75	331,796	1,327,184

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

(a) The Annual Meeting of Shareholders was held on June 10, 2005 in Bridgeport, WV.

(b) Brief description of matters voted upon.

1. Elected the named directors to serve three-year terms expiring 2008 as follows:

Shares For

Withheld

Jeffrey C. Swoveland

14,456,293

652,611

David C. Parke

14,625,404

483,500

The following Directors terms continued after the Annual Meeting of Shareholders.

Steven R. Williams

Thomas E. Riley

Vincent F. D'Annunzio

Donald B. Nestor

Kimberly Luff Wakim

2. Ratification of KPMG LLP as the Company's Independent Registered Public Accounting Firm.

Shares For	Shares Against	Shares Abstain
15,011,597	89,115	8,193

3. Approval of the Company's 2005 Non-Employee Director Restricted Stock Plan.

Shares For	Shares Against	Shares Abstain
10,725,151	989,393	27,159

Item 6. Exhibits

(a) Exhibits

Exhibit Name	Exhibit Number	Location
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.

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.

	Petroleum Development Corporation (Registrant)


Date: January 6, 2006	/s/ Steven R. Williams Steven R. Williams Chief Executive Officer and President

Date: January 6, 2006	/s/ Darwin L. Stump Darwin L. Stump Chief Financial Officer

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PDC Energy (PDCE) 10-Q2005 Q2 Quarterly report

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