news08092007.htm

NEWS FROM

Petroleum Development Corporation

FOR IMMEDIATE RELEASE: August 9, 2007

CONTACT: Celesta Miracle - (304) 842-3597 http://www.petd.com

Petroleum Development Corporation Announces Second Quarter 2007 Results

Net Income, EPS Increase in Quarter and First-Half

Significant Growth Achieved in Drilling Activity and Production

Bridgeport, West Virginia... Petroleum Development Corporation (NASDAQ GSM:PETD) today reported net income of $18.1 million for the second quarter of 2007, compared to $7.3 million for the same period of 2006. Second quarter 2007 revenue of $75.9 million increased by 17% compared to the second quarter 2006 revenue of $64.7 million. Net income for the second quarter of 2007 includes a $25.6 million pre-tax gain related to the May 2007 amendment on the 2006 leasehold sale. Diluted earnings per share during the period were $1.21 compared to the year ago period of $0.45 earnings per share. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities, see pages 2 and 8 for more information) increased to $16.8 million from $15.2 million in the second quarter of 2006, despite lower natural gas prices.

The Company also reported that it had record drilling activity during the second quarter of 2007 and that the new wells helped generate record production during the second quarter and for the year to date periods. The Company drilled 108 wells during the second quarter of 2007, successfully completing 103 producing wells with only 5 dry holes. The new wells turned into production, in combination with production from acquisitions made during the fourth quarter of 2006 and the first quarter of 2007, helped increase Company production to approximately 6.4 billion cubic feet equivalent (Bcfe) (where 1 barrel of oil equals 6 thousand cubic feet equivalent). This represented a 54.3% increase from the 4.2 Bcfe produced in the second quarter of 2006, and a 21% increase sequentially from the 5.3 Bcfe produced in the first quarter of 2007.

Net income for the first six months of 2007 was $20.6 million compared to $18.9 million for the first six months of 2006. Diluted earnings per share for the first six months of 2007 were $1.38 compared to first six months of 2006 diluted earnings per share of $1.17. Adjusted cash flow from operations for the first six month period in 2007 was $36.6 million, compared to $33.0 million during the comparable period in 2006. The increase was achieved even though average energy prices for the six month period ending June 30, 2007 being $0.96 per Mcfe (thousand cubic feet equivalent) lower than the same period in 2006.

Comparative Results	Three Months Ended		Six Months Ended
(In thousands, except per share amounts)	June 30,		June 30,
	(unaudited)		(unaudited)
	2007	2006	2007	2006
Revenues	$75,945	$64,743	$133,857	$147,513
Net income	$18,051	$7,280	$20,552	$18,925
Basic earnings per common share	$1.22	$0.45	$1.40	$1.18
Diluted earnings per common share	$1.21	$0.45	$1.38	$1.17

“We are pleased with the record drilling and production during the second quarter, particularly from our new wells and acquired properties,” said Steven R. Williams, Chairman and CEO. “We are beginning to see the tangible benefits of these high quality producing properties. Importantly, we have significantly increased the prospects for our overall production program that we believe will lead to a record level of drilling for the year. PDC is also making important strides in creating an operating system commensurate with our growth strategy. Expenses related to our strategic initiatives are key investments in our future,” added Williams.

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Page 2

Financial Results

The Company experienced a 9% reduction in realized pricing for its oil and natural gas production from the second quarter 2006 to the second quarter 2007, which adversely impacted results. The 2007 second quarter net income includes a $25.6 million pretax gain on sale of leaseholds from a May 2007 release of commitments related to the lease sale in 2006, an unrealized derivative gain of $4.1 million compared to a gain of $1.7 million in the prior year second quarter, and a $3.9 million exploratory expense related to an expired exploratory agreement with an unaffiliated party. Depreciation, depletion and amortization increased to $17.4 million from $7.6 million in 2006 due to the higher production, increased investment, and increased leasehold acquisition costs. Adjusted cash flow from operations (defined as Cash flow from operations before changes in assets and liabilities, a non-GAAP measure) increased to $16.8 million from $15.2 million for the second quarter in 2006 despite a 9% decrease in energy prices. EBITDA (defined as net income, plus interest expense, income taxes and DD&A, a non-GAAP measure) increased from $19.5 million to $47.7 million in the second quarter of 2007 compared to the same period in 2006. The following table shows the calculation of Adjusted cash flow from operations for the second quarters of 2006 and 2007:

Reconciliation of Adjusted Cash Flow from Operations (a non-GAAP measure)

See Page 9 for explanation.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	(unaudited)		(unaudited)
	2007	2006	2007	2006

Net Cash used in Operating Activities	$(43,647)	$(16,698)	$(76,385)	$(13,943)
Changes in Assets and Liabilities Related to Operations	60,418	31,905	112,950	46,939
Adjusted Cash Flow from Operations	$16,771	$15,207	$36,565	$32,996

Reconciliation of EBITDA (a non-GAAP measure)

See Page 9 for explanation.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	(unaudited)		(unaudited)
	2007	2006	2007	2006
Net Income	$18,051	$7,280	$20,552	$18,925
Interest	1,450	436	2,281	788
Income Taxes	10,749	4,192	12,185	10,902
Depreciation	17,428	7,605	30,503	14,192
EBITDA	$47,678	$19,513	$65,521	$44,807

Operations

Second quarter operations focused on integrating and exploiting the acquisitions made with the proceeds from the 2006 lease sale, and continuing exploitation of the Company’s lease position in its Rocky Mountain Region. These operations included the very active drilling program, recompletions of Codell wells and completion of behind pipe Niobrara zones in Wattenberg Field, and work on the infrastructure to support further development.

Late in the second quarter of 2007, the Company placed into service its upgraded Garden Gulch pipeline and compressor facilities. These facilities, which serve a majority of the Company’s Piceance Basin wells, are expected to significantly increase the Company’s take away capacity from the basin, allowing additional drilling in the area and better deliverability from the existing wells. The access road to the top of the mesa in the Piceance Basin was also completed and placed in service in the second quarter. The new road will provide improved access to the mesa and may allow year round development.

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Page 3

Drilling Activity

The Company’s drilling activities continue to be focused in its Rocky Mountain Region. The 108 wells drilled in the second quarter bring the total for the year to 169, with a total of 9 dry holes and are shown by area in the table below. The five dry holes in the second quarter were all located in the NECO field area. The total number of wells drilled during the quarter represents an increase of 170% year over year and an increase of 77% from the first quarter. In addition to the drilling of the new wells, the Company re-fraced 46 wells in the Wattenberg Field area.

Gross Wells Drilled

	Three Months Ended			Six Months Ended
	June 30,			June 30,
Area	Drilled	Productive	Dry	Drilled	Productive	Dry
Wattenberg	38	38	-	68	66	2
Grand Valley/Piceance	14	14	-	30	30	-
NECO	54	49	5	67	61	6
Michigan	2	2	-	2	2	-
North Dakota	-	-	-	2	1	1
Total	108	103	5	169	160	9

Net Wells Drilled

	Three Months Ended			Six Months Ended
	June 30,			June 30,
Area	Drilled	Productive	Dry	Drilled	Productive	Dry
Wattenberg	36.38	36.38	-	50.13	49.39	0.74
Grand Valley/Piceance	14.00	14.00	-	28.11	28.11	-
NECO	46.00	41.00	5.00	59.00	53.00	6.00
Michigan	1.80	1.80	-	1.80	1.80	-
North Dakota	-	-	-	0.59	0.23	0.36
Total	98.18	93.18	5.00	139.63	132.53	7.10

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Page 4

Production

Production for the quarter increased 21% above volumes for the first quarter of 2007 and 54% from the same quarter in 2006. Total year to date production through June 30, 2007 is 11.8 Bcfe. Approximately half of the increase was due to the production generated from acquisitions (including new wells drilled on the acquired properties) that were made during the fourth quarter of 2006 and first quarter of 2007. The remaining increase in production occurred from other new wells drilled by the Company.

Company Production by Region

	2007				2006
		Percent		Percent
	2Q Sales	of 1Q	1Q Sales	of 2Q		2Q Sales
Region	Mmcfe	2007	Mmcfe	2006		Mmcfe
Rocky Mountains	5,322	124%	4,290	155%		3,435
Appalachian	687	111%	617	184%		374
Michigan	427	100%	426	118%		361
Company Total	6,436	121%	5,333	154%		4,170

Rocky Mountain Production by Area

	2007			2006
		Percent		Percent
	2Q Sales	of 1Q	1Q Sales	of 2Q	2Q Sales
Region	Mmcfe	2007	Mmcfe	2006	Mmcfe
Wattenberg	2,623	119%	2,209	146%	1,802
Grand Valley/Piceance	1,590	128%	1,246	231%	689
NECO	942	139%	678	117%	808
North Dakota	167	106%	157	123%	136
Total	5,322	124%	4,290	154%	3,435

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Page 5

Other Information

PETROLEUM DEVELOPMENT CORPORATION

Condensed Consolidated Statements of Income

(Unaudited; in thousands except per share data)

	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
		Revised*		Revised*
Revenues:
Oil and gas sales	$ 39,246	$ 27,992	$ 73,262	$ 56,324
Sales from natural gas marketing activities	29,924	29,129	51,911	71,071
Oil and gas well drilling operations	1,739	3,745	5,769	9,023
Well operations and pipeline income	1,292	2,486	4,590	4,776
Oil and gas price risk management, net	3,742	1,370	(1,903)	6,295
Other	2	21	228	24
Total revenues	75,945	64,743	133,857	147,513

Costs and expenses:
Oil and gas production and well operations cost	11,628	6,830	20,663	13,779
Cost of natural gas marketing activities	28,780	28,471	50,292	70,251
Cost of oil and gas well drilling operations	246	3,278	810	7,490
Exploration expense	6,780	1,898	9,458	3,106
General and administrative expense	6,886	5,102	14,310	8,821
Depreciation, depletion and amortization	17,429	7,605	30,503	14,192
Total costs and expenses	71,749	53,184	126,036	117,639

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

Income from operations	29,796	11,559	33,421	29,874
Interest income	454	349	1,597	741
Interest expense	(1,450)	(436)	(2,281)	(788)

Income before income taxes	28,800	11,472	32,737	29,827
Income taxes	10,749	4,192	12,185	10,902
Net income	$ 18,051	$ 7,280	$ 20,552	$ 18,925

Earnings per common share:
Basic	$ 1.22	$ 0.45	$ 1.40	$ 1.18
Diluted	$ 1.21	$ 0.45	$ 1.38	$ 1.17
Weighted average common shares outstanding:
Basic	14,740	16,058	14,730	16,086
Diluted	14,860	16,134	14,851	16,164

*As revised in the Company's Annual Report on Form 10-K

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Page 6

Oil and Gas Sales and Production

Oil and natural gas sales from the Company's producing properties for the three months ended June 30, 2007, were up 40.0% to $39.2 million compared to $28.0 million for the same prior year period, an increase of $11.2 million. The sales increase was related to increased volumes, primarily due to the Company’s acquisitions from the fourth quarter 2006 and first quarter 2007, and was partially offset by lower average natural gas and oil sales prices. The following table shows the production by area of operations as well as the average sales price for the second quarters of 2007 and 2006, excluding derivative gains or losses.

	Three Months Ended June 30,		Change
	2007	2006	Amount	Percent
Natural Gas (Mcf)
Appalachian Basin	675,591	372,476	303,115	81.4%
Michigan Basin	420,390	355,244	65,146	18.3%
Rocky Mountains	3,945,077	2,366,987	1,578,090	66.7%
Total	5,041,058	3,094,707	1,946,351	62.9%

Average Sales Price	$ 5.16	$ 5.54	$ (0.38)	-6.9%

Oil (Bbls)
Appalachian Basin	1,840	300	1,540	513.3%
Michigan Basin	1,167	904	263	29.1%
Rocky Mountains	229,471	177,982	51,489	28.9%
Total	232,478	179,186	53,292	29.7%

Average Sales Price	$ 57.02	$ 60.55	$ (3.53)	-5.8%

Natural Gas Equivalents (Mcfe)*
Appalachian Basin	686,631	374,276	312,355	83.5%
Michigan Basin	427,392	360,668	66,724	18.5%
Rocky Mountains	5,321,903	3,434,879	1,887,024	54.9%
Total	6,435,926	4,169,823	2,266,103	54.3%

Average Sales Price	$ 6.10	$ 6.71	$ (0.61)	-9.1%

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

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Page 7

Oil and natural gas sales from the Company's producing properties for the six months ended June 30, 2007, were up 30.1% to $73.3 million compared to $56.3 million for the same prior year period, an increase of $16.9 million. The sales increase was related to increased volumes, primarily due to the Company’s acquisitions from the fourth quarter 2006 and first quarter 2007, and was partially offset by lower average natural gas and oil sales prices. The following table summaries the production by area of operation as well as the average sales price for the first six months of 2007 and 2006, excluding derivative gains or losses.

	Six Months Ended June 30,		Change
	2007	2006	Amount	Percent
Natural Gas (Mcf)
Appalachian Basin	1,284,988	780,901	504,087	64.6%
Michigan Basin	841,277	711,536	129,741	18.2%
Rocky Mountains	7,050,746	4,514,950	2,535,796	56.2%
Total	9,177,011	6,007,387	3,169,624	52.8%

Average Sales Price	$ 5.56	$ 6.33	$ (0.77)	-12.2%

Oil (Bbls)
Appalachian Basin	3,214	789	2,425	307.4%
Michigan Basin	1,982	1,993	(11)	-0.6%
Rocky Mountains	426,821	304,117	122,704	40.3%
Total	432,017	306,899	125,118	40.8%

Average Sales Price	$ 51.49	$ 59.61	$ (8.12)	-13.6%

Natural Gas Equivalents (Mcfe)*
Appalachian Basin	1,304,272	785,635	518,637	66.0%
Michigan Basin	853,169	723,494	129,675	17.9%
Rocky Mountains	9,611,672	6,339,652	3,272,020	51.6%
Total	11,769,113	7,848,781	3,920,332	49.9%

Average Sales Price	$ 6.22	$ 7.18	$ (0.96)	-13.4%

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

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Page 8

Current Hedging of Commodity Transactions

The Company has entered into commodity-based derivative transactions to manage a portion of the exposure to price risk associated with its sales of oil and natural gas. During the three months ended June 30, 2007, the Company averaged natural gas volumes sold of 1.7 Bcf per month and oil sales of 77,000 barrels per month. The positions in effect as of August 9, 2007, on the Company's share of production by area are shown in the following table.

		Floors		Ceilings
		Monthly		Monthly
		Quantity		Quantity
		Gas-Mmbtu	Contract	Gas-Mmbtu	Contract
Month Set	Contract Term	Oil-Barrels	Price	Oil-Barrels	Price

Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)
Feb-06	Jul 2007 - Oct 2007	44,000	$ 5.50	-	$ -
Sep-06	Jul 2007 - Oct 2007	194,500	4.50	-	-
Dec-06	Nov 2007 - Mar 2008	100,000	5.25	-	-
Jan-07	Nov 2007 - Mar 2008	100,000	5.25	100,000	9.80
May-07	Apr 2008 - Oct 2008	197,250	5.50	197,250	10.35

NYMEX Based Derivatives - (Appalachian and Michigan Basins)
Feb-06	Jul 2007- Oct 2007	85,000	7.00	-	-
Feb-06	Jul 2007- Oct 2007	85,000	7.50	85,000	10.83
Sep-06	Jul 2007- Oct 2007	85,000	6.25	-	-
Jan-07	Jul 2007- Oct 2007	85,000	5.25	-	-
Dec-06	Nov 2007 - Mar 2008	144,500	7.00	-	-
Jan-07	Nov 2007 - Mar 2008	144,500	7.00	144,500	13.70
Jan-07	Apr 2008 - Oct 2008	144,500	6.50	144,500	10.80
May-07	Apr 2008 - Oct 2008	120,000	7.00	120,000	13.00

Panhandle Based Derivatives (NECO)
Feb-06	Jul 2007 - Oct 2007	60,000	6.00	-	-
Feb-06	Jul 2007 - Oct 2007	60,000	6.50	60,000	9.80
Jan-07	Jul 2007 - Oct 2007	90,000	4.50	-	-
Dec-06	Nov 2007 - Mar 2008	70,000	5.75	-	-
Jan-07	Nov 2007 - Mar 2008	90,000	6.00	90,000	11.25
Jan-07	Apr 2008 - Oct 2008	90,000	5.50	90,000	9.85
Jun-07	Apr 2008 - Oct 2008	90,000	6.00	90,000	11.25

Colorado Interstate Gas (CIG) Based Derivatives (DJ Basin)
Jan-07	Jul 2007 - Oct 2007	221,000	4.00	-	-
Jan-07	Nov 2007 - Mar 2008	120,000	5.25	120,000	9.80
May-07	Apr 2008 - Oct 2008	306,000	5.50	306,000	10.35

Oil - NYMEX Based (Wattenberg/ND)
Sep-06	Jul 2007 - Oct 2007	12,350	50.00	-	-

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Page 9

Non-GAAP Financial Measures (unaudited)

This release refers to "Adjusted cash flow from operations" and “EBITDA” both of which are non-GAAP financial measures. Adjusted cash flow from operations is the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. The Company believes it is important to consider Adjusted cash flow from operations separately, as the Company believes it can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during that year. The Company also uses this measure because the collection of its receivables or payment of its obligations has not been a significant issue for the Company's business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices. EBITDA is a non-GAAP measure calculated by adding net income, interest expense, income taxes, and depreciation, depletion and amortization for the period. Management believes EBITDA is relevant because it is a measure of cash available to fund the Company’s capital expenditures and service its debt and is a widely used industry metric which allows comparability of our results with our peers. Adjusted cash flow from operations and EBITDA are not measures of financial performance under GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP.

2007 Second Half Outlook

Increasing shareholder value through increased reserves, production and cash flow is a primary focus of the Company’s operating efforts. Through the first six months of 2007 the Company believes it is on track to achieve its 2007 production guidance of 28 Bcfe, and to end the year with more than 500 Bcfe of proved reserves. The quality of the Company’s low risk prospect inventory supports these objectives and is reflected in the close match between the projected and actual production for the year-to-date. Softer energy prices, particularly in the Rocky Mountain Region, have negatively impacted cash flow from operations. However, even with this adverse factor the Company has achieved increased Adjusted cash flow from operations in each quarter and year to date in 2007.

Third quarter operations are continuing the trend of increasing production with an active drilling operation for the Company’s interest and new wells adding to production. Near the end of June the Company completed and placed in service an upgrade of the Company’s compression facility in Grand Valley Field in the Piceance Basin. The station, with daily capacity of 50 million cubic feet (Mmcf) (an increase of approximately 35 Mmcf from the current facility) is important to achieving the annual production goal. The facility expansion allows the Company to increase production from wells curtailed due to capacity restrictions, and to continue its development drilling in the area. The Company also completed construction of and initiated operations on a road accessing higher elevation mesa leasehold in the Grand Valley Field, facilitating operations through improved access and possibly allowing an extension of the drilling “season”, which has been limited by winter conditions on the mesa.

Rocky Mountain area natural gas prices have been substantially lower than other regions of the country in recent months. This resulted from local oversupply in the region, and insufficient pipeline capacity to move natural gas to other markets. This pricing situation, which affects about 37% of the Company’s production on an energy equivalent basis (Mcfe), is expected to continue until the winter of 2007-2008. Additional pipeline capacity is anticipated in January 2008 when portions of the Rockies Express Pipeline are scheduled to be placed into service. This new pipeline is planned to move 1.8 Bcfe per day from the Rocky Mountain area to the Midwest United States, providing additional market access for Rocky Mountain producers. The Company expects this to result in improved prices relative to other market areas.

The Company anticipates continuing a very active development drilling schedule in the third quarter and beyond. The new wells, many of which are being drilled on property obtained through the like-kind exchange purchases made in 2006 and earlier this year, are expected to provide the additional production required to reach the production target.

Continuing development of the technical capabilities and accounting processes, including a new information system, will result in a continuation of the higher level of G&A expense in 2007. These improved systems, processes and a strengthened staff will help the Company meet its reporting obligations in a timely and accurate fashion.

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Page 10

10-Q and Quarterly Conference Call

The Company filed its Quarterly Report on Form 10-Q on August 9, 2007. You can access the report at the Company’s website (www.petd.com), or contact the Company for a paper copy. The Company invites you to join Steven Williams, Chief Executive Officer and Richard McCullough, Chief Financial Officer and Treasurer, for a conference call on Friday, August 10, 2007 for a discussion of the results.

What: Petroleum Development Second Quarter Earnings Conference Call

When: Friday, August 10, 2007, at 10:00 a.m. Eastern Standard Time

Where: www.petd.com

How: Log on to the web address above or call (877) 407-8031

Replay Number: 877-660-6853 Account #: 286 Conference ID #: 211525

(Replay will be available approximately one hour after the conclusion of the call)

Contact: Celesta Miracle, Petroleum Development Corporation, (800) 624-3821 E-mail: petd@petd.com

About Petroleum Development Corporation

Petroleum Development Corporation (www.petd.com) is an independent energy company engaged in the development, production and marketing of natural gas and oil. The Company operations are focused in the Rocky Mountains with additional operations in the Appalachian Basin and Michigan. During the third quarter of 2004, the Company was added to the S&P SmallCap 600 Index. Additionally, PDC was added to the Russell 3000 Index of companies in 2003.

Certain matters discussed within this press release are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Although PDC believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Factors that could cause actual results to differ materially from expectations include financial performance, oil and gas prices, drilling program results, drilling results, regulatory changes, changes in federal or state tax policy, changes in local or national economic conditions and other risks detailed from time to time in the Company's reports filed with the SEC, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K.

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120 Genesis Boulevard• P. O. Box 26 • Bridgeport, West Virginia • Phone: (304) 842-3597