news11092007.htm

EX-99 2 news11092007.htm NEWS11092007 news11092007.htm

NEWS FROM Petroleum Development Corporation

FOR IMMEDIATE RELEASE: November 9, 2007

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

Petroleum Development Corporation Announces Third Quarter 2007 Results

Significant Growth Achieved in Cash Flow, Drilling Activity, and Production

Colorado Prices Impact Third Quarter Results

Bridgeport, West Virginia, November 9, 2007: Petroleum Development Corporation (NASDAQ GSM:PETD) today reported third quarter net income of $4.5 million or $0.30 per diluted share, and nine months net income of $25.0 million or $1.68 per diluted share. The comparable numbers for 2006, which included profits from the $354 million sale of lease rights in the Piceance Basin, were third quarter net income of $210.8 million or $13.33 per diluted share and nine month net income of $229.8 million or $14.32 per diluted 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 $31.6 million in the third quarter from $135,000 in 2006 ($68.2 million for the first 9 months of 2007 compared to $33.1 million for the same period in 2006.).

Third quarter and nine month results in 2007 reflect record oil and gas production and sales revenue. Production for the third quarter was 7.7 Bcfe, up 78.9% from the 4.3 Bcfe produced in the third quarter of 2006. Total production for the nine month period was 19.5 Bcfe compared to 12.2 Bcfe, a 60.2% increase. Each of the Company’s three operating areas contributed to the Company’s growth.

The Company also continued on its record-setting pace for new development in 2007 drilling by adding 94 development wells and one exploratory well during the third quarter. One development well and the exploratory well were dry holes. Totals for the year-to-date are 258 development and 6 gross exploratory wells including 8 gross development dry holes and 5 dry exploratory wells. This active drilling program, combined with production from acquisitions made with proceeds from the 2006 lease sale, are the driving force behind the dramatic production increases in 2007.

Comparative Results	Three Months Ended		Nine Months Ended
(In thousands, except per share amounts)	September 30,		September 30,
	(unaudited)		(unaudited)
	2007	2006	2007	2006
Revenues	$76,275	$70,817	$210,132	$218,330
Net income	$4,459	$210,884	$25,011	$229,809
Basic earnings per common share	$0.30	$13.39	$1.70	$14.39
Diluted earnings per common share	$0.30	$13.33	$1.68	$14.32

“Our plan to convert the proceeds of last year’s lease sale into increased reserves and production continues to progress on schedule,” said Steven R. Williams, Chairman and CEO. “We continue on pace to reach our 2007 guidance production of 28 Bcfe. With the recent acquisition of the Castle properties in Pennsylvania, we estimate our proved reserves to be in excess of 650 Bcfe, and we fully expect our high quality prospect inventory to allow us to continue to significantly exceed industry growth norms in 2008 and beyond.”

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Page 2

Financial Results

Net income for the three and nine months ended September 30, 2007, declined significantly compared to the respective year ago period results from operations due to the $328 million pretax gain associated with the July 2006 sale of leasehold to an unrelated party. The nine month income for 2007 includes a $25.6 million pretax gain on sale of leasehold recorded in May 2007. The Company experienced an 18.8% reduction in realized pricing for its oil and natural gas production from the third quarter 2006 to the third quarter 2007, which adversely impacted results. Net income for the quarter was $4.5 million which includes an unrealized derivative gain of $3.8 million compared to a unrealized derivative gain of $2.6 million in the prior year, and $5.3 million in exploratory expense. Depreciation, depletion and amortization for the third quarter increased to $20.4 million from $8.3 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 $31.6 million from $0.1 million for the third quarter in 2006 despite an 18.8% decrease in energy prices. The lower adjusted cash flow from operations in the third quarter of 2006 reflects increased costs related to exploring acquisition opportunities to utilize the funds received from the leasehold sale. EBITDA (defined as net income, plus interest (net), income taxes and DD&A, a non-GAAP measure) decreased from $348.9 million to $30.2 million in the third quarter of 2007 compared to the same period in 2006. This significant decline is again due to the gain from the leasehold sale included in the 2006 data. The following tables show the calculation of adjusted cash flow from operations and EBITDA for the third quarters and first nine months of 2007 and 2006:

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

See Page 8 for explanation.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	(unaudited)		(unaudited)
	2007	2006	2007	2006

Net Cash used in Operating Activities	$43,585	$2,632	$(32,800)	$(11,311)
Changes in Assets and Liabilities Related to Operations	(11,947)	(2,497)	101,003	44,442
Adjusted Cash Flow from Operations	$31,638	$135	$68,203	$33,131

Reconciliation of EBITDA (a non-GAAP measure) (In thousands)

See Page 8 for explanation.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	(unaudited)		(unaudited)
	2007	2006	2007	2006
Net Income	$4,459	$210,884	$25,011	$229,809
Interest, net	2,082	(3,109)	2,766	(3,062)
Income Taxes	3,326	132,795	15,511	143,697
Depreciation	20,354	8,300	50,857	22,492
EBITDA	$30,221	$348,870	$94,145	$392,936

Operations

Third 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.

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Page 3

Early in the fourth quarter, the Company purchased from an unrelated party a majority working interest in 762 natural gas wells located in Southwestern Pennsylvania for approximately $53 million. The acquisition includes approximately 47 Bcfe net proved reserves.

Drilling Activity

The Company’s drilling activities continue to be focused in its Rocky Mountain Region. The 95 wells drilled in the third quarter bring the total for the year to 264, with a total of 13 dry holes and are shown by area in the table below. The two dry holes in the third quarter were located in the NECO field area. The total number of wells drilled during the quarter represents an increase of 92% year over year. In addition to the drilling of the new wells, the Company re-fraced 44 wells in the Wattenberg Field area during the third quarter of 2007.

Gross Wells Drilled

	Three Months Ended				Nine Months Ended
	September 30, 2007				September 30, 2007
Area	In Process	Productive	Dry	Total	In Process	Productive	Dry	Total
Wattenberg	31	10	-	41	40	65	4	109
Grand Valley/Piceance	8	3	-	11	14	27	-	41
NECO	35	2	2	39	47	51	8	106
Michigan	-	-	-	-	-	2	-	2
Appalachian	2	2	-	4	2	2		4
North Dakota	-	-	-	-	-	1	1	2
Total	76	17	2	95	103	148	13	264

Net Wells Drilled

	Three Months Ended				Nine Months Ended
	September 30, 2007				September 30, 2007
Area	In Process	Productive	Dry	Total	In Process	Productive	Dry	Total
Wattenberg	20.5	8.9	-	29.4	30.0	48.0	1.5	79.5
Grand Valley/Piceance	5.5	3.0	-	8.5	11.5	25.1	-	36.6
NECO	34.9	2.0	2.0	38.9	46.9	43.0	8.0	97.9
Michigan	-	-	-	-	-	1.8	-	1.8
Appalachian	2.0	2.0	-	4.0	2.0	2.0	-	4.0
North Dakota	-	-	-	-	-	0.2	0.4	0.6
Total	62.9	15.9	2.0	80.8	90.4	120.1	9.9	220.4

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Page 4

Other Information

PETROLEUM DEVELOPMENT CORPORATION

Condensed Consolidated Statements of Income

(Unaudited; in thousands except per share data)

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

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

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

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

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

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

^*As Revised in the Company’s Annual Report on Form 10-K.

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Page 5

Oil and Gas Sales and Production

Production for the quarter increased 78.9% above volumes for the third quarter of 2006. Oil and natural gas sales from the Company's producing properties for the three months ended September 30, 2007, were up 45.3% to $44.4 million compared to $30.6 million for the same prior year period, an increase of $13.8 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 third quarter of 2007 and 2006, excluding derivative gains or losses.

	Three Months Ended September 30,			Change
	2007		2006	Amount		Percent
Natural Gas (Mcf)
Appalachian Basin	606,165		327,499	278,666		85.1%
Michigan Basin	421,909		355,624	66,285		18.6%
Rocky Mountains	5,284,103		2,620,421	2,663,682		101.7%
Total	6,312,177		3,303,544	3,008,633		91.1%

Average Sales Price	$ 4.67		$ 6.15	$ (1.48)		-24.1%

Oil (Bbls)
Appalachian Basin	602		441	161		36.5%
Michigan Basin	1,003		1,281	(278)		-21.7%
Rocky Mountains	233,130		166,821	66,309		39.7%
Total	234,735		168,543	66,192		39.3%

Average Sales Price	$ 63.67		$ 60.93	$ 2.74		4.5%

Natural Gas Equivalents (Mcfe)*
Appalachian Basin	609,777		330,145	279,632		84.7%
Michigan Basin	427,927		363,310	64,617		17.8%
Rocky Mountains	6,682,883		3,621,347	3,061,536		84.5%
Total	7,720,587		4,314,802	3,405,785		78.9%

Average Sales Price	$ 5.76	$ 7.09		$ (1.33)	-18.8%

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

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Page 6

Production for the nine months ended September 30, 2007, increased 60.2% above volumes for the same period in 2006. Oil and natural gas sales from the Company's producing properties for the nine months ended September 30, 2007, were up 35.4% to $117.7 million compared to $86.9 million for the same prior year period, an increase of $30.8 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 nine months of 2007 and 2006, excluding derivative gains or losses.

	Nine Months Ended September 30,		Change
	2007	2006		Amount	Percent
Natural Gas (Mcf)
Appalachian Basin	1,891,153	1,108,400		782,753	70.6%
Michigan Basin	1,263,186	1,067,160		196,026	18.4%
Rocky Mountains	12,334,849	7,135,371		5,199,478	72.9%
Total	15,489,188	9,310,931		6,178,257	66.4%

Average Sales Price	$ 5.20	$ 6.27		$ (1.07)	-17.1%

Oil (Bbls)
Appalachian Basin	3,816	1,230		2,586	210.2%
Michigan Basin	2,985	3,274		(289)	-8.8%
Rocky Mountains	659,951	470,938		189,013	40.1%
Total	666,752	475,442		191,310	40.2%

Average Sales Price	$ 55.78	$ 60.08		$ (4.30)	-7.2%

Natural Gas Equivalents (Mcfe)*
Appalachian Basin	1,914,049	1,115,780		798,269	71.5%
Michigan Basin	1,281,096	1,086,804		194,292	17.9%
Rocky Mountains	16,294,555	9,960,999		6,333,556	63.6%
Total	19,489,700	12,163,583		7,326,117	60.2%

Average Sales Price	$ 6.04	$ 7.14		$ (1.10)	-15.4%

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

With the drop in October 2007 Rocky Mountain natural gas prices, we curtailed our production in the Piceance and NECO areas of operations for October 2007. Total net curtailment was approximately 350,000 Mcf for the month of October 2007. We ceased the curtailment and returned production to normal levels in November 2007 due to an increase in the November 2007 prices.

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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 September 30, 2007, the Company averaged natural gas volumes sold of 2.1 Bcf per month and oil sales of 78,000 barrels per month. The positions in effect as of November 6, 2007, on the Company's share of production by area are shown in the following table.

		Floors		Ceilings
		Monthly		Monthly
		Quantity	Contract	Quantity	Contract
Month Set	Month	Mmbtu	Price	Mmbtu	Price
Colorado Interstate Gas (CIG) Based Hedges (Piceance Basin)
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 Hedges - (Appalachian and Michigan Basins)
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 Hedges (NECO)
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 Hedges (Wattenberg Basin)
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

Monthly Quantity Swap Month Set Month Bbls Price
Oil – NYMEX Based (Wattenberg Basin)
Oct-07	Jan 2008 – Dec 2008	29,070*	$84.20

*This represents approximately 44% of our current Wattenberg oil production per month.

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Page 8

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 (net), 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 Fourth Quarter Outlook

Increasing shareholder value through increased reserves, production and cash flow is the primary focus of the Company’s operating efforts. For the first nine months of 2007 the Company has closely tracked its 2007 production guidance of 28 Bcfe. In January we predicted 2007 year-end proved reserves of more than 500 Bcfe, and we now expect that number to be in excess of 600 Bcfe. Production and reserve additions from acquisitions and from the Company’s low risk prospect inventory have supported these efforts and are 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 and will continue to do so in the fourth quarter of 2007. However, even with this adverse factor the Company has achieved increased Adjusted cash flow from operations in each quarter in 2007.

We expect the fourth quarter to continue the trend of increasing production with additional new wells adding to production. In addition to new drilling, in October we completed the acquisition of 760 producing wells, many undeveloped locations and other assets in Pennsylvania that add immediately to production and will add to our inventory of opportunities for future development. Of the 47 Bcfe of proved reserves acquired in this acquisition, nearly two thirds are undeveloped. Even before the acquisition we had resumed active development in the Appalachian Basin by drilling two new wells and by recompleting behind pipe zones in older wells in the area. We also plan to begin our first Barnett Shale well in Texas before the end of 2007. Both of these areas offers significant potential for the future, and neither has the market problems that have reduced our gas prices in the Rocky Mountain region.

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 almost 40% 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. When fully completed, in 2009, 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, and to allow us to continue our development efforts in the area. We continue to expect the Rocky Mountain region to be our primary growth driver for the remainder of 2007 and 2008.

The Company anticipates continuing a very active development drilling schedule in the fourth 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 2007 production target and to allow us to continue to grow production and proved reserves next year.

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 the fourth quarter. However through higher production we saw a third quarter decrease in G&A per Mcfe, a trend we hope to extend into the fourth quarter and beyond. These improved systems, processes and a strengthened staff will help the Company meet its reporting obligations in a timely and accurate fashion.Continue to Page 9

Page 9

10-Q and Quarterly Conference Call

The Company will file its Quarterly Report on Form 10-Q on November 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 Thomas E. Riley, President and Richard McCullough, Chief Financial Officer, for a conference call on Friday, November 9, 2007 for a discussion of the results.

What: Petroleum Development Corporation Third Quarter Earnings Conference Call`

When: Friday, November 9, 2007, at 10:00 a.m. Eastern 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 #: 261404

(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. Its operations are focused in the Rocky Mountains with additional operations in the Appalachian Basin and Michigan. During the third quarter of 2004, PDC was added to the S&P SmallCap 600 Index. Additionally, PDC was added to the Russell 3000 Index of Companies in 2003.

Forward-Looking Statements

Certain matters discussed within this press release are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact included herein are forward-looking statements. 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 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 PDC's reports filed with the Securities and Exchange Commission, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K.

The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company uses in this presentation the terms “probable” and “possible” reserves, which SEC guidelines prohibit in filings of U.S. registrants. Probable reserves are unproved reserves that are more likely than not to be recoverable. Possible reserves are unproved reserves that are less likely to be recoverable than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, The Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

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