Exhibit 99.1

 

Four Radnor Corporate Center, Suite 200

Radnor, PA 19087

Ph: (610) 687-8900 Fax: (610) 687-3688

www.pennvirginia.com

 

 

FOR IMMEDIATE RELEASE

PENN VIRGINIA CORPORATION ANNOUNCES FOURTH QUARTER AND FULL-YEAR 2011 RESULTS;

PROVIDES OPERATIONAL UPDATE AND INITIAL FULL-YEAR 2012 GUIDANCE

34 PERCENT INCREASE IN ADJUSTED EBITDAX OVER THE PRIOR YEAR QUARTER

OIL / LIQUIDS REPRESENTED 37 PERCENT OF PRODUCTION AND 70 PERCENT OF PRODUCT REVENUES DURING THE QUARTER

OIL / LIQUIDS EXPECTED TO BE 42 PERCENT OF 2012 TOTAL PRODUCTION AND 78 PERCENT OF 2012 PRODUCT REVENUES

DRIVEN BY THE EAGLE FORD SHALE, 2012 OIL PRODUCTION GROWTH EXPECTED TO BE 56 TO 77 PERCENT

2012 CAPITAL EXPENDITURES GUIDANCE OF $300 TO $325 MILLION, 27 TO 33 PERCENT LOWER THAN 2011

CURRENT HEDGES COVER APPROXIMATELY 47 PERCENT OF 2012 OIL PRODUCTION AND 32 PERCENT OF 2012 GAS PRODUCTION

RADNOR, PA (BusinessWire) February 22, 2012 – Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months and twelve months ended December 31, 2011 and provided initial full-year 2012 guidance.

Fourth Quarter 2011 Highlights

Fourth quarter 2011 results, as compared to fourth quarter 2010 results, were as follows:

 

•

Product revenues from the sale of natural gas, crude oil and natural gas liquids (NGLs) of $77.4 million, or $7.20 per thousand cubic feet of natural gas equivalent (Mcfe), increases of 21 percent and 48 percent, respectively, compared to $63.9 million, or $4.88 per Mcfe

 

•

Oil and NGL revenues of $53.9 million, or 70 percent of product revenues, an increase of 99 percent compared to $27.1 million, or 42 percent of product revenues

 

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Gross operating margin, a non-GAAP (generally accepted accounting principles) measure defined as total product revenues less total direct operating expenses, of $5.22 per Mcfe, an increase of 83 percent compared to $2.85 per Mcfe

 

•

Operating loss of $37.1 million, compared to a loss of $25.0 million

 

•

Adjusted EBITDAX, a non-GAAP measure, of $62.2 million, an increase of 34 percent compared to $46.6 million

 

•

Net loss from continuing operations of $27.9 million, or $0.61 per diluted share, compared to a loss of $24.8 million, or $0.54 per diluted share

 

•

Adjusted net loss, a non-GAAP measure which excludes the effects of changes in derivatives fair value, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, of $6.2 million, or $0.14 per diluted share, compared to a loss of $11.0 million, or $0.24 per diluted share

 

•

Oil and NGL production of 662 thousand barrels, or 37 percent of total equivalent production, an increase of 43 percent compared to 463 thousand barrels, or 21 percent of total equivalent production

Definitions of non-GAAP financial measures or reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release.

Recent operational highlights are as follows:

 

•

14 (11.7 net) Eagle Ford Shale wells have been completed and turned in line since our last report in November 2011, bringing the total to 35 (29.2 net) producing Eagle Ford Shale wells to date, with an average peak gross production rate of approximately 1,000 barrels of oil equivalent (BOE) per day (BOEPD) per well

 

•

To date, 26 wells have at least 30 days of production history and have had an initial 30-day average gross production rate of approximately 675 BOEPD per well.

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Three rigs are currently drilling the 40th through 42nd Eagle Ford wells, with three wells in the process of being completed and one well waiting on completion (WOC).

 

•

Eagle Ford Shale production was approximately 9,800 (6,280 net) BOEPD at the end of January, with oil comprising approximately 89 percent, NGLs comprising approximately six percent and natural gas comprising approximately five percent.

 

•

In late 2011, we announced a 13,500 acre AMI with a major oil and gas company in Lavaca County, Texas pursuant to which, during 2012, we can earn a minimum of approximately 8,000 net acres. This would bring our Eagle Ford Shale position in Gonzales and Lavaca Counties, Texas to approximately 31,400 (23,100 net) acres, with up to 190 well locations assuming down-spacing is successful on a majority of our acreage.

 

•

The first well on the Lavaca County acreage is expected to spud late in the first quarter

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “Fourth quarter 2011 operating results continued the positive trend of improved margins due to increased oil production. Operating cash flows and margins remained strong due to increasing oil production volumes, continued high oil prices and generally lower operating expenses. Oil and liquids revenues increased 99 percent over the prior year period and comprised 70 percent of product revenues, resulting in an 83 percent improvement in our gross operating margin per Mcfe of production. Oil and liquids production increased 43 percent over the prior year quarter and represented 37 percent of fourth quarter production. In 2012, we expect oil and liquids to comprise approximately 78 percent of product revenues and approximately 42 percent of production.

“Our improved financial results, achieved despite very weak gas prices, were driven primarily by our oily Eagle Ford Shale play where we have significantly increased our acreage and potential drilling locations during 2011. Building on this success, we plan to devote approximately 85 percent of estimated 2012 capital expenditures to the Eagle Ford Shale, drilling 31 (26.7 net) wells. At the same time, we intend to reduce the outspend of cash flow. We are currently operating three rigs in the Eagle Ford Shale, but will decrease the rig count to two to reduce 2012 capital expenditures by approximately 30 percent compared to 2011. To further improve liquidity, we are also considering the sale of some of our non-strategic assets. Despite the reduction in capital expenditures, an approximate 21 to 24 percent decrease in pro forma gas production and lower gas prices, we expect operating cash flows to increase in 2012.”

Full-Year 2011 Consolidated Results

For the year ended December 31, 2011, we incurred an operating loss of $155.4 million, which included impairment charges of $104.7 million, compared to a loss in 2010 of $98.8 million, which included impairment charges of $46.0 million. The adjusted net loss attributable to PVA, which excludes the effects of changes in derivatives fair value, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, was $47.7 million, or $1.04 per diluted share, in 2011 compared to an adjusted loss of $32.7 million, or $0.72 per diluted share, in 2010. The net loss from continuing operations was $132.9 million, or $2.90 per diluted share, in 2011 compared to a loss of $65.3 million, or $1.43 per diluted share, in 2010, due primarily to the increase in operating loss, a $25.4 million loss on the extinguishment of debt in 2011, a $26.3 million decrease in derivatives income and a $4.6 million increase in interest and other expenses. Pro forma to exclude production from the Mid-Continent assets sold in August 2011 and the Gulf Coast assets sold in January 2010, oil and gas production in 2011 was 44.2 Bcfe, compared to 43.6 Bcfe in 2010. Year-end 2011 proved reserves were 883 Bcfe, compared to 903 Bcfe at year-end 2011, pro forma to exclude year-end 2010 proved reserves from the Mid-Continent assets sold in 2011.

Fourth Quarter 2011 Financial and Operational Results

Overview of Financial Results

The $37.1 million operating loss was $12.1 million higher than the $25.0 million loss in the prior year quarter, due primarily to a $23.9 million increase in impairment expense, a $13.4 million decrease in natural gas revenues and a $10.0 million increase in depreciation, depletion and amortization (DD&A) expense. The effect of these items was partially offset by a $26.8 million increase in oil and liquids revenues, a $5.2 million decrease in total direct operating expenses, a $3.0 million increase in gain on the sale of property associated with the divestiture of approximately 2,500 acres of Marcellus acreage and a $1.3 million decrease in exploration expense. Oil and NGL revenues were $53.9 million in the fourth quarter of 2011, 99 percent higher than the $27.1 million in the prior year quarter and 13 percent higher than the $47.8 million in the third quarter of 2011. Oil and NGL revenues were 70 percent of product revenues in the fourth quarter of 2011, compared to 42 percent in the prior year quarter and 58 percent in the third quarter of 2011.

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Pricing

Our fourth quarter 2011 realized oil price was $98.49 per barrel, 19 percent higher than the $82.84 per barrel price in the fourth quarter of 2010 and 13 percent higher than the $87.03 per barrel price in the third quarter of 2011. Our fourth quarter 2011 realized NGL price was $45.46 per barrel, eight percent higher than the $42.15 per barrel price in the fourth quarter of 2010 and five percent lower than the $48.00 per barrel price in the third quarter of 2011. Our fourth quarter 2011 realized natural gas price was $3.46 per thousand cubic feet (Mcf), three percent lower than the $3.57 per Mcf price in the fourth quarter of 2010 and 18 percent lower than the $4.24 per Mcf price in the third quarter of 2011. Adjusting for oil and gas hedges, our fourth quarter 2011 effective oil price was $101.21 per barrel and our effective natural gas price was $4.33 per Mcf, or increases of $2.72 per barrel and $0.87 per Mcf over the realized prices.

Production

As shown in the table below, production in the fourth quarter of 2011 was 10.7 Bcfe, or 116.7 MMcfe per day, an 18 percent decrease compared to 13.1 Bcfe, or 142.5 MMcfe per day, in the prior year quarter and a 10 percent decrease from 11.9 Bcfe, or 129.9 MMcfe per day, in the third quarter of 2011. As a percentage of total equivalent production, oil and NGL volumes were 37 percent in the fourth quarter of 2011, compared to 21 percent in the prior year quarter and 33 percent in the third quarter of 2011. On a pro forma basis to exclude production from the Mid-Continent assets sold in 2011, production in the prior year quarter was 12.3 Bcfe, or 134.0 MMcfe per day. The pro forma decrease of 1.6 Bcfe, or 13 percent, was primarily the result of a 2.8 Bcfe, or 29 percent, decrease in pro forma natural gas production due to reduced natural gas drilling since mid-2010 in East Texas, Mississippi and, to a lesser extent, in the Granite Wash, partially offset by a 200 thousand barrel (1.2 Bcfe), or 43 percent, increase in pro forma oil and NGL production.

 

		Total and Daily Equivalent Production for the Three Months  Ended
Region / Play Type		Dec. 31, 2011				Dec. 31, 2010				Sept. 30, 2011				Dec. 31, 2011				Dec. 31, 2010				Sept. 30, 2011
		(in Bcfe)												(in MMcfe per day)
Texas			4.9				4.3				4.9				53.2				46.7				53.3
Cotton Valley/Other			1.6				2.0				1.8				17.6				21.2				19.9
Haynesville Shale			0.9				2.3				1.0				9.6				25.5				11.1
Eagle Ford (1)			2.4				—				2.1				26.0				—				22.4
Appalachia			2.2				2.5				2.3				23.6				27.2				24.7
Mid-Continent			2.2				4.2				3.2				24.3				45.1				34.8
Granite Wash			2.2				3.3				2.7				24.4				35.9				29.7
Other(2)			—				0.9				0.5				—				9.3				5.1
Mississippi			1.4				2.1				1.6				15.6				23.4				17.0
Totals			10.7				13.1				11.9				116.7				142.5				129.9
Pro Forma Totals(3)			10.7				12.3				11.6				116.7				134.0				126.5

 

(1)	Initial production from the Eagle Ford Shale commenced in February 2011.

(2)	Includes production from the Mid-Continent assets sold in 2011.

(3)	Pro forma to exclude production from the Mid-Continent assets sold in 2011.

Note - Numbers may not add due to rounding.

Operating Expenses

As discussed below, fourth quarter 2011 total direct operating expenses decreased $5.2 million, or approximately 20 percent, to $21.3 million, or $1.99 per Mcfe produced, compared to $26.5 million, or $2.02 per Mcfe produced, in the fourth quarter of 2010 and $25.6 million, or $2.14 per Mcfe produced, in the third quarter of 2011.

 

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Lease operating expenses decreased by $1.1 million, or 13 percent, to $7.5 million, or $0.70 per Mcfe produced, from $8.6 million, or $0.66 per Mcfe produced, in the prior year quarter due to lower production volumes as well as the sale of higher cost Arkoma Basin properties in August 2011. The unit cost increased slightly due to lower production volumes.

 

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Gathering, processing and transportation expenses decreased by $0.1 million, or three percent, to $3.9 million, or $0.36 per Mcfe produced, from $4.0 million, or $0.31 per Mcfe produced, in the prior year quarter resulting from lower production volumes, partially offset by higher processing costs associated with higher NGL production. The unit cost increased slightly due to lower production volumes.

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Production and ad valorem taxes increased 95 percent to $2.4 million, or 3.1 percent of product revenues, from $1.2 million, or 1.9 percent of product revenues, in the prior year quarter resulting primarily from higher product revenues, as well as favorable tax adjustments during the prior year quarter.

 

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General and administrative (G&A) expenses, excluding share-based compensation, decreased by $5.1 million, or 40 percent, to $7.6 million, or $0.71 per Mcfe produced, from $12.7 million, or $0.97 per Mcfe produced, in the prior year quarter. This decrease reflects a $1.0 million decrease in restructuring costs and a $4.1 million reduction in recurring G&A expenses due primarily to lower employee headcount and lower support costs following restructuring actions taken during 2010 and 2011, including the sale of our Arkoma Basin assets in August 2011.

Exploration expense decreased $1.3 million to approximately $10.7 million in the fourth quarter of 2011 from approximately $12.0 million in the prior year quarter. The decrease was due primarily to a $2.2 million decrease in dry-hole costs (zero in the fourth quarter of 2011) and a $0.4 million decrease in drilling rig related charges, partially offset by a $0.9 million increase in unproved property amortization and a $0.5 million increase in geological and geophysical costs.

DD&A expense increased by $10.0 million, or 25 percent, to $49.3 million, or $4.59 per Mcfe produced, in the fourth quarter of 2011 from $39.3 million, or $3.00 per Mcfe produced, in the prior year quarter, due primarily to higher DD&A costs attributable to our Eagle Ford Shale oil wells, which is typical for this and other oily plays, as well as downward revisions in proved reserves located primarily in the Granite Wash, East Texas and Mississippi.

Impairment expense increased to $33.6 million in the fourth quarter of 2011 from $9.7 million in the prior year quarter due primarily to an impairment of horizontal coalbed methane assets in Appalachia and certain Selma Chalk assets in Mississippi.

Capital Expenditures

During the fourth quarter of 2011, oil and gas capital expenditures were approximately $123 million, compared to $108 million in the fourth quarter of 2010 and $114 million in the third quarter of 2011, consisting of:

 

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$111 million for drilling and completion activities, including 12 (9.7 net) wells, all of which were successful

 

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$8 million for seismic, pipeline, gathering and facilities

 

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$4 million for leasehold acquisitions and other

2011 Proved Reserves

Proved reserves decreased to 883 Bcfe at year-end 2011 from 942 Bcfe at year-2010 (903 Bcfe, pro forma to exclude 39 Bcfe of Mid-Continent reserves sold in August 2011). Compared to year-end 2010, proved developed reserves decreased to 49 percent from 53 percent, while proved oil and NGL reserves increased to 24 percent from 21 percent.

During 2011, we added 119 Bcfe of proved reserves from extensions, discoveries, purchases and other additions, including 65 Bcfe in the Eagle Ford Shale, 40 Bcfe in the Marcellus Shale and 12 Bcfe in the Selma Chalk. During 2011, we had 94 Bcfe of negative revisions, including 45 Bcfe in the Granite Wash due primarily to previously disclosed well interference issues, 28 Bcfe in East Texas and 17 Bcfe in the Selma Chalk.

The decreases in the Securities & Exchange Commission (SEC)-assumed gas price and gas proved reserves during 2011 were almost entirely offset by the increases in SEC-assumed oil and NGL prices and oil and NGL proved reserves, resulting in a 0.5 percent decrease in the PV-10 value (present value of proved reserves, discounted at 10 percent) to $874 million at year-end 2011. Approximately 72 percent of the PV-10 value was attributable to oil and NGLs, while 28 percent was attributable to natural gas.

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		Proved Reserves at December 31, 2011(4)
(in Bcfe)		Natural Gas Equivalent Reserves (Bcfe)				Natural Gas Reserves (Bcf)				Oil and Condensate Reserves (MMBbls)
Proved reserves at December 31, 2010			941.8				745.0				32.8
2011 production			(46.6	)			(33.4	)			(2.2	)
2011 extensions, discoveries and other additions			118.7				56.3				10.4
2011 revisions – price			(0.5	)			(1.3	)			0.1
2011 revisions – other			(93.1	)			(59.9	)			(5.5	)
2011 purchases (sales) of reserves in place, net			(37.0	)			(36.8	)			(0.0	)
Proved reserves at December 31, 2011			883.3				669.9				35.6
Percentage of equivalent reserves			100.0	%			75.8	%			24.2	%
Proved developed reserves at December 31, 2010			501.5				412.6				14.8
Percentage of proved reserves			53.3	%			55.4	%			45.2	%
Proved developed reserves at December 31, 2011			429.4				330.6				16.5
Percentage of proved reserves			48.6	%			49.3	%			46.3	%
2011 reserve replacement ratio(5)
Including all revisions			54.2	%
Excluding all revisions			255.3	%
2011 oil and gas capital expenditures ($mil.)
All costs		$	445.6
Excluding proved and unproved leasehold acquisition costs		$	397.7
2011 reserve replacement cost ($ per Mcfe)(5)
Including all costs and all revisions		$	17.67
Excluding all revisions		$	3.75
Excluding proved and unproved leasehold acquisition costs and purchased reserves		$	15.85
Excluding proved and unproved leasehold acquisition costs, purchased reserves and all revisions		$	3.35
Standardized measure of discounted future net cash flows ($mil.)(4)		$	654.5
Present value of future net cash flows before income taxes ($mil.)(4)		$	874.4

 

(4)

The estimated reserves, standardized measure and present value were based on pricing assumptions for Henry Hub natural gas of $4.12 per million British thermal units (MMBtu) and West Texas Intermediate crude oil of $96.19 per barrel. These compare to prices of $4.38 per MMBtu and $79.43 per barrel, respectively, at December 31, 2010. Both prices exclude the effects of hedged production and six Mcfe is assumed to equal one barrel equivalent of liquids. MMBbls is defined as one million barrels.

(5)	Reserve replacement ratio is defined as the sum of reserve additions (reserve extensions, discoveries and other additions plus revisions plus reserve purchases) divided by production for the year. Reserve replacement cost per Mcfe is defined as capital expenditures divided by reserve additions.

Operational Update

Eagle Ford Shale

During the fourth quarter of 2011, we drilled 11 (9.2 net) operated wells in the Eagle Ford Shale, all of which were successful. We currently have three rigs drilling our 40^th through 42^nd wells, three wells that in the process of being completed, one well that is WOC and 35 (29.2 net) wells that are producing. As shown in the table below, our producing wells in the Eagle Ford Shale have had an average peak gross production rate of approximately 1,000 BOEPD per well (approximately 675 BOEPD 30-day average per well for the 26 of these wells with sufficient production history). Eagle Ford Shale production was approximately 9,800 (6,280 net) BOEPD at the end of January, with oil comprising approximately 89 percent, NGLs comprising approximately six percent and natural gas comprising approximately five percent.

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										Cumulative Gross Production(6)								Peak Gross Daily Production Rates(6)								30-Day Average Gross Daily Production Rates(6)
Well Name		Lateral Length				Frac Stages				Equivalent Production				Days On Line				Oil Rate				Equivalent Rate				Oil Rate				Equivalent Rate
		Feet								BOE								BOPD				BOEPD				BOPD				BOEPD
Previously Reported On-Line Wells
Gardner #1H			4,792				16				148,055				370				1,084				1,247				732				881
Hawn Holt #1H			4,352				15				91,310				277				759				837				606				668
Hawn Holt #4H			4,106				14				57,773				274				534				582				357				394
Hawn Holt #6H			4,166				17				61,157				245				670				711				342				370
Hawn Holt #2H			4,476				17				92,006				244				869				986				668				728
Hawn Holt #9H			4,453				18				116,246				240				1,652				1,877				1,044				1,153
Hawn Holt #10H			3,913				16				83,645				216				1,080				1,188				771				839
Hawn Holt #5H			3,950				16				46,532				208				474				528				321				349
Hawn Holt #3H			3,800				15				55,983				209				607				651				478				522
Munson Ranch #1H			4,163				17				129,171				199				1,755				1,921				1,207				1,315
Munson Ranch #3H			3,953				16				96,343				198				1,448				1,538				1,007				1,092
Hawn Holt #11H			3,931				16				70,640				194				1,120				1,190				786				860
Dickson Allen #1H			3,953				15				37,278				162				465				508				358				393
Hawn Holt #7H			4,345				18				49,389				163				730				798				493				541
Hawn Holt #12H			3,320				18				59,640				155				1,458				1,495				619				668
Hawn Holt #13H			2,805				11				49,523				142				1,347				1,399				591				650
Cannonade Ranch #1H			4,403				18				35,770				146				377				403				255				274
Hawn Holt #15H			4,153				17				72,673				123				1,191				1,298				779				838
Hawn Holt #8H			4,203				17				34,208				114				427				492				361				409
Dickson Allen #2H			3,853				16				45,218				115				552				601				460				516
New On-Line Wells
Gardner #2H			2,953				12				20,629				90				551				579				312				346
Munson Ranch #2H			3,953				16				36,623				86				819				869				515				572
Rock Creek Ranch #1H			3,444				14				35,620				59				1,158				1,257				639				708
Munson Ranch #8H			3,403				14				24,597				52				914				964				561				606
Munson Ranch #4H			3,864				16				34,702				51				1,317				1,416				807				870
Munson Ranch #6H			3,415				14				32,734				42				1,717				1,808				845				928
Schaefer #2H			3,707				12				9,529				29				586				638				—				—
Schaefer #3H			2,903				12				16,758				27				1,035				1,129				—				—
Schaefer #1H			2,992				13				16,603				28				871				941				—				—
Munson Ranch #5H			3,153				13				8,563				8				1,063				1,164				—				—
Munson Ranch #7H			3,153				13				5,923				8				757				824				—				—
Hawn Dickson #1H			3,153				13				2,145				4				923				969				—				—
Averages			3,787				15												947				1,025				612				673
Maximums			4,792				18												1,755				1,921				1,207				1,315
Minimums			2,805				11												377				403				255				274
Other Wells
Cannonade Ranch #3H(7)			3,451				12				1,339				—				205				228
Munson Ranch #9H(7)			1,700				7				7,116				42				393				400				184				202
D. Foreman #1H			Producing
Rock Creek Ranch #2H			Completing
Rock Creek Ranch #3H			Completing
Rock Creek Ranch #4H			Completing
Culpepper #2H			WOC
Rock Creek Ranch #6H			Drilling
Henning #1H			Drilling
Effenberger #1H			Drilling

 

(6)	Wellhead rates only; the natural gas associated with these wells is yielding approximately 145 barrels of NGLs per million cubic feet (MMcf).

(7)

The Cannonade Ranch #3H had been shut-in to address H2S production issues, but has recently been brought back online, while the Munson Ranch #9H had a short lateral and only seven frac stages due to faulting issues. As a result, production data for these two wells has been excluded from the statistics.

In late 2011, we announced a 13,500 acre AMI with a major oil and gas company in Lavaca County, Texas pursuant to which, during 2012, we can earn a minimum of approximately 8,000 net acres. This would bring our Eagle Ford Shale position in Gonzales and Lavaca Counties, Texas to approximately 31,400 (23,100 net) acres, with up to 190 well locations assuming down-spacing is successful on a majority of our acreage. The first well on the Lavaca County acreage is expected to spud late in the first quarter. Our full-year 2012 guidance anticipates up to 31 (26.7 net) new wells in the Eagle Ford Shale. We continue efforts to expand our Eagle Ford Shale position through additional leasing and selective acquisitions.

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Mid-Continent

During the fourth quarter of 2011, one (0.5 net) non-operated Granite Wash well was drilled in the Mid-Continent. Our full-year 2012 guidance includes up to seven (2.3 net) new Granite Wash wells. In addition, during the first half of 2012, we plan to drill one (0.5 net) horizontal well to test the Viola Limestone, which is an oil prospect.

Full-Year 2012 Guidance

Full-year 2012 guidance highlights are as follows:

 

•

Full-year 2012 production is expected to be 40.0 to 43.0 Bcfe, a decrease of 1.2 to 4.2 Bcfe, or three to 10 percent, over full-year 2011 production of 44.2 Bcfe, pro forma to exclude 2.3 Bcfe of production from divested assets

 

•

The estimated 1.2 to 4.2 Bcfe pro forma decrease in production is due primarily to an expected 6.7 to 7.6 Bcf decrease in natural gas production and an expected 0.5 to 0.9 Bcfe (81 to 157 thousand barrels) decrease in NGL production from gas weighted plays, including the Granite Wash and Cotton Valley. These decreases are expected to be largely offset by an expected 4.3 to 6.0 Bcfe (722 thousand to approximately one million barrels) net increase in crude oil production

 

•

Crude oil and NGL production is expected to increase by 26 to 42 percent during 2012 over 2011 production levels (56 to 77 percent for crude oil, only). Crude oil and liquids are expected to comprise approximately 42 percent of total production during 2012, compared to 28 percent during 2011

 

•

Full-year 2012 product revenues are expected to be approximately $288 to $319 million, compared to 2011 product revenues of $300.0 million, adjusted to reflect any premiums or discounts for quality, basis differentials and other adjustments, but exclude the impact of any hedges

 

•

Crude oil and NGL product revenues are expected to be approximately 78 percent of total product revenues during 2012, compared to 54 percent during 2011

 

•

2012 settlements of current commodity hedges are expected to results in cash receipts of approximately $25 million

 

•

Currently, approximately 47 percent of estimated 2012 crude oil production and 32 percent of estimated 2012 natural gas production is hedged

 

•

Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be $200 to $240 million, compared to 2011 Adjusted EBITDAX of $219.5 million

 

•

Full-year 2012 cash flow from operating activities is expected to be $175 to $205 million, including an anticipated $30 million income tax refund in the fourth quarter of 2012, compared to 2011 cash flow from operating activities of $144.7 million

 

•

Full-year 2012 capital expenditures are expected to be $300 to $325 million, a decrease of between approximately $121 and $146 million, or 27 to 33 percent, from 2011 capital expenditures of $445.6 million

 

•

Approximately 85 percent of the 2012 capital expenditures are expected to be allocated to the Eagle Ford Shale and approximately eight percent to the Mid-Continent, with $270 to $280 million for drilling and completions, $20 to $25 million for lease acquisitions and $10 to $20 million for pipeline, gathering, seismic and facilities.

Please see the Guidance Table included in this release for guidance estimates for full-year 2012. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of December 31, 2011, we had total debt with a carrying value of $697 million ($704 million aggregate principal amount), consisting of $294 million of 10.375 percent senior unsecured notes due 2016, $300 million principal amount of 7.25 percent senior unsecured notes due 2019, $5 million principal amount of 4.5 percent convertible senior subordinated notes due 2012 and $99 million of borrowings under our revolving credit facility (the “Revolver”). Net of cash and equivalents of approximately $7 million, our indebtedness at December 31, 2011 was approximately $690 million, which was 45 percent of book capitalization and 3.1 times full-year 2011 Adjusted EBITDAX of $219.5 million.

We have no material debt maturities until 2016. Our business strategy for 2012 requires capital expenditures in excess of our anticipated operating cash flows as laid out in the table below.

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		Guidance Range
In millions		Low				High
Net cash provided by operating activities (8)		$	175.0			$	205.0
Less: Common stock dividends			(10.3	)			(10.3	)
Less: Repayment of 4.5 percent convertible senior subordinated notes due December  2012			(4.9	)			(4.9	)
Less: Capitalized interest			(2.0	)			(2.0	)
Cash flows available for investment		$	157.8			$	187.8
Less: Capital expenditures (including seismic expenditures)			(325.0	)			(300.0	)
Plus: Seismic expenditures (included in cash flows from operating activities)			10.0				5.0
Capital outspend of cash flows		$	(157.2	)		$	(107.2	)

 

(8)

Please see the Guidance Table included in this release for guidance estimates for full-year 2012, which include production of 40.0 to 43.0 Bcfe (6.7 to 7.2 million BOE) and average benchmark prices of $91.25 per barrel for crude oil, $42.62 per barrel for NGLs and $3.00 per MMBtu for natural gas, adjusted to reflect any premium or discount for quality, basin differentials and other adjustments. In addition, cash flows from operating activities include an estimated $30 million cash income tax refund expected to be received in the fourth quarter of 2012.

Subject to the variability of commodity prices that impact our cash flows from operating activities, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our 2012 capital program with operating cash flows and borrowings under the Revolver. We expect to supplement these sources of liquidity with proceeds from the sale of non-core assets or, possibly, by accessing the capital markets. There can be no assurance that such actions would be successful, however, in which case we could further reduce our 2012 planned capital expenditures.

In August 2011, we entered into the Revolver which matures in August 2016. The Revolver provides for a $300 million commitment amount and has a borrowing base of $380 million. The borrowing base is re-determined semi-annually, and the next re-determination is scheduled to occur during April 2012. The primary assets supporting our borrowing base are our proved developed reserves, approximately 77 percent of which are natural gas. Due primarily to the significant decline in natural gas prices that has continued into the first quarter of 2012 and despite the increase in our oil reserves, we anticipate a potentially material reduction in our borrowing base from its current level of $380 million. Currently, we are unable to determine a meaningful potential range of the reduction, due primarily to the fact that a number of determinative variables are not known at this time; however, we do not anticipate a material reduction to our current Revolver commitment of $300 million. Accordingly, our current business plans anticipate us borrowing amounts under the Revolver that are within the current commitment level of $300 million. Currently, we have approximately $14 million of cash on hand and approximately $183 million of unused borrowing capacity under our Revolver commitment, net of outstanding letters of credit of $1.4 million.

Interest expense increased to $14.4 million in the fourth quarter of 2011 from $13.5 million in the fourth quarter of 2010 due to higher average levels of debt outstanding.

During the fourth quarter of 2011, derivatives loss was $4.2 million, compared to derivatives loss of $2.5 million in the prior year quarter. Fourth quarter 2011 cash settlements of derivatives resulted in net cash receipts of $7.1 million, compared to $8.5 million of net cash receipts in the prior year quarter.

Explanation of Non-GAAP Gross Operating Margin per Mcfe

Gross operating margin is a non-GAAP financial measure under SEC regulations which represents total product revenues less total direct operating expenses. Gross operating margin per Mcfe is equal to gross operating margin divided by total natural gas, crude oil and NGL production. Gross operating margin is not adjusted for the impact of hedges. We believe that gross operating margin per Mcfe is an important measure that can be used by security analysts and investors to evaluate our operating margin per unit of production and to compare it to other oil and gas companies, as well as for comparisons to other time periods.

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Explanation of Non-GAAP PV-10 Value

PV-10 Value is a non-GAAP financial measure under SEC regulations and differs from the Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) in that PV-10 Value is a pre-tax value, while the Standardized Measure includes the effect of estimated future income taxes, discounted at 10 percent. We believe that the PV-10 Value is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 Value is widely used by security analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure enhances comparability of assets when evaluating companies. The Standardized Measure at year-end 2011 of $654.5 million, plus $219.9 million of present value of future income tax discounted at 10 percent, is equal to the PV-10 Value of $874.4 million.

Fourth Quarter and Full-Year 2011 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss fourth quarter and full-year 2011 financial and operational results, is scheduled for Thursday, February 23, 2012 at 10:00 a.m. ET. Prepared remarks by H. Baird Whitehead, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-866-630-9986 five to 10 minutes before the scheduled start of the conference call (use the passcode 4339698), or via webcast by logging on to our website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available for two weeks beginning approximately 24 hours after the call. The replay can be accessed by dialing toll free 888-203-1112 (international: 719-457-0820) and using the replay code 4339698. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.

******

Penn Virginia Corporation (NYSE: PVA) is an independent oil and gas company engaged primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions including Texas, Appalachia, the Mid-Continent and Mississippi. For more information, please visit our website at www.pennvirginia.com.

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for natural gas, NGLs and oil; our ability to develop, explore for and replace oil and gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of natural gas, NGLs and oil; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC).

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

 

Contact:		James W. Dean
		Vice President, Corporate Development
		Ph: (610) 687-7531 Fax: (610) 687-3688
		E-Mail: invest@pennvirginia.com

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PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited

(in thousands, except per share data)

 

		Three months ended December 31,								Year ended December 31,
		2011				2010				2011				2010
Revenues
Natural gas		$	23,410			$	36,858			$	137,070			$	171,141
Crude oil			44,304				15,415				119,582				53,532
Natural gas liquids (NGLs)			9,636				11,676				43,394				26,663
Total product revenues			77,350				63,949				300,046				251,336
Gain on sales of property and equipment			3,047				32				3,570				648
Other			54				338				2,389				2,454
Total revenues			80,451				64,319				306,005				254,438
Operating Expenses
Lease operating			7,466				8,609				36,988				35,757
Gathering, processing and transportation			3,896				4,015				15,157				14,180
Production and ad valorem taxes			2,401				1,233				13,690				13,917
General and administrative (excluding share-based compensation) (a)			7,586				12,675				40,898				50,572
Total direct operating expenses			21,349				26,532				106,733				114,426
Share-based compensation (b)			1,801				1,411				7,430				7,811
Exploration			10,724				12,051				78,943				49,641
Depreciation, depletion and amortization			49,310				39,342				162,534				134,700
Impairments			33,617				9,708				104,688				45,959
Other			796				244				1,096				709
Total operating expenses			117,597				89,288				461,424				353,246
Operating loss			(37,146	)			(24,969	)			(155,419	)			(98,808	)
Other income (expense)
Interest expense			(14,383	)			(13,489	)			(56,216	)			(53,679	)
Loss on extinguishment of debt (c)			(18	)			—				(25,421	)			—
Derivatives			(4,176	)			(2,504	)			15,651				41,906
Other			1				298				335				2,403
Loss from continuing operations before income taxes			(55,722	)			(40,664	)			(221,070	)			(108,178	)
Income tax benefit			27,783				15,827				88,155				42,851
Loss from continuing operations			(27,939	)			(24,837	)			(132,915	)			(65,327	)
Income from discontinued operations, net of tax			—				(34	)			—				33,448
Gain on sale of discontinued operations, net of tax			—				1,934				—				51,546
Net income (loss)			(27,939	)			(22,937	)			(132,915	)			19,667
Less net income attributable to noncontrolling interests in discontinued operations			—				—				—				(28,090	)
Income (loss) attributable to PVA		$	(27,939	)		$	(22,937	)		$	(132,915	)		$	(8,423	)
Income (loss) per share attributable to PVA - Basic
Continuing operations		$	(0.61	)		$	(0.54	)		$	(2.90	)		$	(1.43	)
Discontinued operations			—				(0.00	)			—				0.12
Gain on sale of discontinued operations			—				0.04				—				1.13
Net income (loss) attributable to PVA		$	(0.61	)		$	(0.50	)		$	(2.90	)		$	(0.19	)
Income (loss) per share attributable to PVA - Diluted
Continuing operations		$	(0.61	)		$	(0.54	)		$	(2.90	)		$	(1.43	)
Discontinued operations			—				(0.00	)			—				0.12
Gain on sale of discontinued operations			—				0.04				—				1.13
Net income (loss) attributable to PVA		$	(0.61	)		$	(0.50	)		$	(2.90	)		$	(0.19	)
Weighted average shares outstanding, basic			45,864				45,615				45,784				45,553
Weighted average shares outstanding, diluted			45,864				45,615				45,784				45,553
		Three months ended December 31,								Year ended December 31,
		2011				2010				2011				2010
Production
Natural gas (MMcf)			6,765				10,329				33,410				38,919
Crude oil (MBbls)			450				186				1,283				709
NGLs (MBbls)			212				277				907				672
Total natural gas, crude oil and NGL production (MMcfe)			10,736				13,108				46,553				47,201
Prices
Natural gas ($ per Mcf)		$	3.46			$	3.57			$	4.10			$	4.40
Crude oil ($ per Bbl)		$	98.49			$	82.84			$	93.19			$	75.56
NGLs ($ per Bbl)		$	45.46			$	42.15			$	47.83			$	39.69
Prices - Adjusted for derivative settlements
Natural gas ($ per Mcf)		$	4.33			$	4.39			$	4.77			$	5.27
Crude oil ($ per Bbl)		$	101.21			$	81.41			$	94.29			$	74.94
NGLs ($ per Bbl)		$	45.46			$	42.15			$	47.83			$	39.69

 

(a)	Includes restructuring costs of approximately $0.7 million and $1.8 million and $2.4 million and $8.2 million for the three months and years ended December 31, 2011 and 2010, respectively.

(b)	Our share-based compensation expense includes our stock option expense and the amortization of common, deferred and restricted stock and restricted stock unit awards related to employee and director compensation in accordance with accounting guidance for share-based payments.

(c)	Attributable primarily to the repurchase in April 2011 of approximately 98% of our 4.5% convertible senior subordinated notes due 2012.

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PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

 

		As of December 31,
		2011				2010
Assets
Current assets		$	145,346			$	214,340
Net property and equipment			1,777,575				1,705,584
Other assets			20,132				24,676
Total assets		$	1,943,053			$	1,944,600
Liabilities and shareholders’ equity
Current liabilities		$	106,607			$	106,994
Revolving credit facility			99,000				—
Senior notes due 2016			293,561				292,487
Senior notes due 2019			300,000				—
Convertible notes due 2012 (a)			—				214,049
Other liabilities and deferred income taxes			297,576				350,794
Total shareholders’ equity			846,309				980,276
Total liabilities and shareholders’ equity		$	1,943,053			$	1,944,600

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

 

		Three months ended December 31,								Year ended December 31,
		2011				2010				2011				2010
Cash flows from operating activities
Net income (loss)		$	(27,939	)		$	(22,937	)		$	(132,915	)		$	19,667
Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations:
Income from discontinued operations before income taxes			—				—				—				(36,832	)
Gain on sale of discontinued operations before income taxes			—				(1,922	)			—				(86,662	)
Non-cash portion of loss on extinguishment of debt			—				—				22,456				—
Depreciation, depletion and amortization			49,310				39,342				162,534				134,700
Impairments			33,617				9,708				104,688				45,959
Derivative contracts:
Net (gains) losses			4,176				2,504				(15,651	)			(41,906	)
Cash settlements			7,078				8,531				27,380				32,818
Deferred income taxes (benefit)			(25,129	)			36,379				(85,501	)			42,528
Loss (gain) on the sale of property and equipment, net			(2,251	)			212				(2,474	)			61
Dry hole and unproved leasehold expense			8,483				9,774				60,940				36,275
Non-cash interest expense			995				2,895				6,807				11,984
Share-based compensation			1,801				1,411				7,430				7,811
Other, net			50				132				275				(209	)
Changes in operating assets and liabilities			(8,614	)			(75,065	)			(11,228	)			(86,355	)
Net cash provided by operating activities from continuing operations			41,577				10,964				144,741				79,839
Cash flows from investing activities
Capital expenditures - property and equipment			(127,349	)			(92,284	)			(445,623	)			(405,994	)
Proceeds from the sale of PVG units, net (a)			—				—				—				139,120
Proceeds from the sale of property, plant and equipment, net			8,291				395				39,368				25,567
Other, net			—				—				100				1,192
Net cash used in investing activities for continuing operations			(119,058	)			(91,889	)			(406,155	)			(240,115	)
Cash flows from financing activities
Dividends paid			(2,580	)			(2,571	)			(10,316	)			(10,271	)
Proceeds from revolving credit facility borrowings			84,000				—				114,000
Repayment of revolving credit facility borrowings			—				—				(15,000	)			—
Proceeds from the issuance of Senior Notes due 2019			—				—				300,000				—
Repurchase of Convertible Notes			—				—				(232,963	)			—
Debt issuance costs paid			(4	)			—				(8,854	)			—
Proceeds from the sale of PVG units, net (b)			—				—				—				199,125
Distributions received from discontinued operations			—				—				—				11,218
Other, net			—				(45	)			1,148				2,098
Net cash provided by (used in) financing activities from continuing operations			81,416				(2,616	)			148,015				202,170
Cash flows from discontinued operations
Net cash provided by operating activities			—				—				—				77,759
Net cash used in investing activities			—				—				—				(18,112	)
Net cash used in financing activities			—				—				—				(59,647	)
Net cash provided by discontinued operations			—				—				—				—
Net increase (decrease) in cash and cash equivalents			3,935				(83,541	)			(113,399	)			41,894
Cash and cash equivalents - beginning of period			3,577				204,452				120,911				79,017
Cash and cash equivalents - end of period		$	7,512			$	120,911			$	7,512			$	120,911
Supplemental disclosures of cash paid for:
Interest (net of amounts capitalized)		$	27,301			$	20,885			$	44,589			$	43,531
Income taxes (net of refunds received)		$	(223	)		$	3,016			$	210			$	28,184

 

(a)	The Convertible Notes are due in November 2012 and are included in current liabilities.

(b)

Net proceeds from the sale of Penn Virginia GP Holdings, L.P. (PVG) units included in investing activities is attributable to the sale of the final tranche of PVG units, which resulted in the loss of control and deconsolidation of PVG from our financial statements. Net proceeds from the sale of PVG units included in financing activities represents proceeds received from sales of our ownership interests in PVG while we still maintained control of PVG.

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PENN VIRGINIA CORPORATION

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

 

		Three months ended December 31,								Year ended December 31,
		2011				2010				2011				2010
Reconciliation of GAAP “Net Income (loss) attributable to PVA” to Non-GAAP “Net Income (loss) attributable to PVA, as adjusted”
Net income (loss) attributable to PVA		$	(27,939	)		$	(22,937	)		$	(132,915	)		$	(8,423	)
Adjustments for derivatives:
Net (gains) losses included in net income			4,176				2,504				(15,651	)			(41,906	)
Cash settlements			7,078				8,531				27,380				32,818
Adjustment for impairments			33,617				9,708				104,688				45,959
Adjustment for restructuring costs			728				1,766				2,351				8,200
Adjustment for net loss (gain) on sale of assets			(2,251	)			212				(2,474	)			61
Adjustment for loss on extinguishment of debt			18				—				25,421				—
Adjustment for gain on sale of discontinued operations			—				(1,922	)			—				(86,662	)
Impact of adjustments on income taxes			(21,622	)			(8,855	)			(56,511	)			17,239
		$	(6,195	)		$	(10,993	)		$	(47,711	)		$	(32,714	)
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes			—				—				—				(28	)
Net income (loss) attributable to PVA, as adjusted (a)		$	(6,195	)		$	(10,993	)		$	(47,711	)		$	(32,742	)
Net loss attributable to PVA, as adjusted, per share, diluted		$	(0.14	)		$	(0.24	)		$	(1.04	)		$	(0.72	)
Reconciliation of GAAP “Net income (loss) from continuing operations” to Non-GAAP “Adjusted EBITDAX”
Net loss from continuing operations		$	(27,939	)		$	(24,837	)		$	(132,915	)		$	(65,327	)
Income tax benefit			(27,783	)			(15,827	)			(88,155	)			(42,851	)
Interest expense			14,383				13,489				56,216				53,679
Depreciation, depletion and amortization			49,310				39,342				162,534				134,700
Exploration			10,724				12,051				78,943				49,641
Share-based compensation expense			1,801				1,411				7,430				7,811
EBITDAX			20,496				25,629				84,053				137,653
Adjustments for derivatives:
Net gains included in net income			4,176				2,504				(15,651	)			(41,906	)
Cash settlements			7,078				8,531				27,380				32,818
Adjustment for impairments			33,617				9,708				104,688				45,959
Adjustment for net loss (gain) on sale of assets			(2,251	)			212				(2,474	)			61
Adjustment for other non-cash items			(907	)			—				(907	)			(1,238	)
Adjustment for non-cash portion of loss on extinguishment of debt			—				—				22,456				—
Adjusted EBITDAX (b)		$	62,209			$	46,584			$	219,545			$	173,347

 

(a)

Net income (loss) attributable to PVA, as adjusted, represents net income (loss) attributable to PVA adjusted to exclude the effects of non-cash changes in the fair value of derivatives, impairments, restructuring costs, net gains and losses on the sale of assets, loss on the extinguishment of debt, gain on the sale of discontinued operations and net income of Penn Virginia Resource Partners, L.P. (PVR) allocated to unvested PVR restricted units awarded as equity compensation that are held until vesting. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Net income (loss) attributable to PVA, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss) attributable to PVA.

(b)

Adjusted EBITDAX represents net income (loss) from continuing operations before income tax expense or benefit, interest expense, depreciation, depletion and amortization expense, exploration expense and share-based compensation expense, further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, impairments, net gains and losses on the sale of assets, the non-cash portion of loss on the extinguishment of debt and other non-cash items. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss) from continuing operations. Adjusted EBITDAX represents EBITDAX as defined in our revolving credit facility, with the exception of excluding distributions received from PVG and PVR.

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PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited

(dollars in millions except where noted)

We are providing the following guidance regarding financial and operational expectations for full-year 2012. These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes.

 

		First Quarter 2011				Second Quarter 2011				Third Quarter 2011				Fourth Quarter 2011				Full Year 2011				Full-Year 2012 Guidance
Production:
Natural gas (Bcf)			9.7				8.9				8.1				6.8				33.4				23.5				—				24.4
Crude oil (MBbls)			188				219				427				450				1,283				2,000				—				2,275
NGLs (MBbls)			220				253				222				212				907				750				—				825
Equivalent production (Bcfe)			12.2				11.7				11.9				10.7				46.6				40.0				—				43.0
Equivalent daily production (MMcfe per day)			135.2				128.6				129.9				116.7				127.5				109.3				—				117.5
Equivalent production (MBOE)			2,029				1,950				1,991				1,789				7,759				6,667				—				7,167
Equivalent daily production (MBOE per day)			22.5				21.4				21.6				19.4				21.3				18.2				—				19.6
Percent crude oil and NGLs			20.1	%			24.2	%			32.6	%			37.0	%			28.2	%			41.3	%			—				43.3	%
Production revenues (a):
Natural gas		$	41.2				38.3				34.2				23.4				137.1				66.5				—				69.1
Crude oil		$	16.6				21.5				37.1				44.3				119.6				189.0				—				215.0
NGLs		$	9.9				13.2				10.7				9.6				43.4				32.0				—				35.2
Total product revenues		$	67.7				73.0				82.0				77.4				300.0				287.5				—				319.2
Total product revenues ($ per Mcfe)		$	5.56				6.24				6.86				7.20				6.45				7.19				—				7.42
Total product revenues ($ per BOE)		$	33.37				37.44				41.18				43.23				38.67				43.12				—				44.54
Percent crude oil and NGLs		$	39.2	%			47.5	%			58.3	%			69.7	%			54.3	%			76.9	%			—				78.4	%
Operating expenses:
Lease operating ($ per Mcfe)		$	0.84				0.92				0.71				0.70				0.79				0.80				—				0.85
Lease operating ($ per BOE)		$	5.04				5.52				4.26				4.17				4.77				4.80				—				5.10
Gathering, processing and transportation costs ($ per Mcfe)		$	0.33				0.37				0.25				0.36				0.33				0.28				—				0.33
Gathering, processing and transportation costs ($ per BOE)		$	1.98				2.22				1.50				2.18				1.95				1.68				—				1.98
Production and ad valorem taxes (percent of oil and gas revenues)			7.5	%			3.9	%			4.1	%			3.1	%			4.6	%			4.0	%			—				4.5	%
General and administrative:
Recurring general and administrative		$	11.5				10.9				9.3				6.9				38.5				39.0				—				41.0
Share-based compensation		$	1.8				2.0				1.8				1.8				7.4				6.5				—				7.0
Restructuring		$	0.1				0.1				1.6				0.7				2.4
Total reported G&A		$	13.4				13.0				12.6				9.4				48.3				45.5				—				48.0
Exploration expense		$	29.5				19.4				19.3				10.7				78.9				43.0				—				46.0
Unproved property amortization		$	10.6				12.0				11.0				8.5				42.0				36.0				—				38.0
Depreciation, depletion and amortization ($ per Mcfe)		$	2.86				2.82				3.80				4.59				3.49				4.75				—				5.25
Depreciation, depletion and amortization ($ per BOE)		$	17.16				16.92				22.77				27.56				20.95				28.50				—				31.50
Adjusted EBITDAX (b)		$	44.1				47.5				65.7				62.2				219.5				200.0				—				240.0
Net cash provided by operating activities (c)		$	29.4				34.3				39.4				41.6				144.7				175.0				—				205.0
Capital expenditures:
Development drilling		$	36.8				82.9				88.2				99.9				307.8				240.0				—				245.0
Exploratory drilling		$	26.9				12.9				13.4				10.9				64.1				30.0				—				35.0
Pipeline, gathering, facilities		$	0.4				3.2				2.7				6.2				12.5				5.0				—				10.0
Seismic (d)		$	1.8				4.3				2.9				2.2				11.2				5.0				—				10.0
Lease acquisitions, field projects and other		$	38.3				1.6				6.5				3.6				50.0				20.0				—				25.0
Total oil and gas capital expenditures		$	104.2				104.9				113.7				122.8				445.6				300.0				—				325.0

 

(a)	Assumes average benchmark prices of $91.25 per barrel for crude oil, $42.62 per barrel for NGLs and $3.00 per MMBtu for natural gas, adjusted for any premiums or discounts for quality, basis differentials and other adjustments. The amounts shown exclude the impact of commodity hedges.

(b)	Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income from continuing operations. The amounts shown reflect the impact of commodity hedges.

(c)	Includes an estimated $30 million cash income tax refund expected to be received in the fourth quarter of 2012.

(d)	Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities from continuing operations.

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PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited - (continued)

Note to Guidance Table:

The following table shows our current derivative positions.

 

								Weighted Average Price
		Instrument Type		Average Volume Per Day				Floor/ Swap				Ceiling
				(MMBtu)				($ / MMBtu)
Natural gas:
First quarter 2012		Collars			20,000				6.00				8.50
First quarter 2012		Swaps			10,000				5.10
Second quarter 2012		Swaps			20,000				5.31
Third quarter 2012		Swaps			20,000				5.31
Fourth quarter 2012		Swaps			10,000				5.10
				(barrels)				($ / barrel)
Crude oil:
First quarter 2012		Collars			1,000				90.00				97.00
Second quarter 2012		Collars			1,000				90.00				97.00
Third quarter 2012		Collars			1,000				90.00				97.00
Fourth quarter 2012		Collars			1,000				90.00				97.00
First quarter 2013		Collars			1,000				90.00				100.00
Second quarter 2013		Collars			1,000				90.00				100.00
Third quarter 2013		Collars			1,000				90.00				100.00
Fourth quarter 2013		Collars			1,000				90.00				100.00
First quarter 2012		Swaps			2,059				101.27
Second quarter 2012		Swaps			2,000				101.06
Third quarter 2012		Swaps			1,500				101.00
Fourth quarter 2012		Swaps			1,500				101.00
First quarter 2013		Swaps			750				100.60
Second quarter 2013		Swaps			750				100.60
Third quarter 2013		Swaps			500				100.30
Fourth quarter 2013		Swaps			500				100.30
First quarter 2013		Swaption			1,100				100.00
Second quarter 2013		Swaption			1,000				100.00
Third quarter 2013		Swaption			900				100.00
Fourth quarter 2013		Swaption			750				100.00

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, operating income for the remainder of 2012 would increase or decrease by approximately $24 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the remainder of 2012 would increase or decrease by approximately $25 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.