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Penn Virginia Corporation Announces Third Quarter 2011 Results and Provides Operational Update

11/02/2011

43 Percent Increase in Adjusted EBITDAX over Prior Year Quarter

Oil and NGLs Represented 33 Percent of Production and 58 Percent of Product Revenues

Eagle Ford Shale Results Driving Improved Financial Performance

RADNOR, Pa.--(BUSINESS WIRE)-- Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months ended September 30, 2011 and provided an update of 2011 guidance.

Third Quarter 2011 Highlights

Third quarter 2011 results, as compared to third quarter 2010 results, were as follows:

  • Product revenues from the sale of natural gas, crude oil and natural gas liquids (NGLs) of $82.0 million, or $6.86 per thousand cubic feet of natural gas equivalent (Mcfe), an increase of 20 percent as compared to $68.3 million, or $5.15 per Mcfe
  • Oil and NGL revenues of $47.8 million, or 58 percent of product revenues, an increase of 129 percent as compared to $20.9 million, or 31 percent of product revenues
  • Gross operating margin, defined as product revenues less direct cash operating expenses, of $4.72 per Mcfe, an increase of $1.83 per Mcfe, or 63 percent, as compared to $2.89 per Mcfe
  • Operating loss of $9.0 million, a decrease of $44.1 million as compared to a loss of $53.1 million
  • Adjusted EBITDAX, a non-GAAP (generally accepted accounting principles) measure, of $65.7 million, an increase of $19.8 million, or 43 percent, as compared to $45.9 million
  • Net loss of $6.7 million, or $0.15 per diluted share, a decrease of $23.5 million as compared to a loss of $30.2 million, or $0.66 per diluted share
  • Adjusted net loss, a non-GAAP measure, of $6.7 million, or $0.15 per diluted share, a decrease of $7.2 million as compared to a loss of $13.9 million, or $0.31 per diluted share
  • Oil and NGL production of 649 thousand barrels, or 33 percent of total equivalent production, an increase of 63 percent as compared to 399 thousand barrels, or 18 percent of total equivalent production, primarily as a result of our drilling activity in the Eagle Ford Shale
  • Production of 11.9 billion cubic feet of natural gas equivalent (Bcfe), or 129.9 million cubic feet of natural gas equivalent (MMcfe) per day, a decrease of ten percent as compared to 13.3 Bcfe, or 144.3 MMcfe per day, primarily as a result of a 26 percent decrease in natural gas production due to our planned shift away from natural gas drilling since mid-2010, partially offset by the 63 percent increase in oil and NGL production

Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear on page nine of this release.

Additional operational highlights included:

  • Eight (6.6 net) Eagle Ford Shale wells have been completed and turned in line since our last report in August 2011, bringing the total to 20 (16.7 net) Eagle Ford Shale wells to date, with an average peak gross production rate of 1,012 barrels of oil equivalent (BOE) per day (BOEPD) per well
    • To date, 17 wells have had a 30-day average gross production rate of 688 BOEPD per well
  • Four rigs are currently drilling the 25th through 28th Eagle Ford Shale wells, with four wells waiting on completion
  • Approximately 2,000 net acres were added to the Eagle Ford Shale play in the third quarter of 2011, bringing total acreage to approximately 17,900 (14,700 net) acres in Gonzales County, Texas with approximately 140 identified well locations

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “Our greatly improved third quarter financial results reflected our transition to and focus on oil drilling opportunities. Oil and liquids production increased 63 percent over the prior year quarter and comprised 33 percent of third quarter production. Oil and liquids revenues increased 129 percent over the prior year period and comprised 58 percent of product revenues, resulting in a 63 percent improvement in our gross operating margin per Mcfe of production. In the fourth quarter of 2011, we expect oil and liquids to comprise approximately 42 to 44 percent of production.

“Our improved third quarter financial results were driven primarily by our oily Eagle Ford Shale play. We are currently operating four rigs in the Eagle Ford Shale and expect to exit 2011 with three rigs drilling in this play. Altogether, our results in the Eagle Ford Shale have been strong, and we continue to review leasing and acquisition opportunities to expand our drilling inventory in this play.”

Third Quarter 2011 Financial and Operational Results

Overview of Financial Results

The $9.0 million operating loss was $44.1 million lower than the $53.1 million loss in the prior year quarter primarily due to a $35.1 million decrease in impairment expense (none in the current year quarter), a $26.9 million increase in oil and liquids revenues, a $4.3 million decrease in total direct operating expenses and a $2.7 million decrease in exploration expense. The effect of these items was partially offset by a $13.3 million decrease in natural gas revenues and a $12.1 million increase in DD&A expense. Oil and NGL revenues were $47.8 million in the third quarter of 2011, 129 percent higher than the $20.9 million in the prior year quarter and 38 percent higher than the $34.7 million in the second quarter of 2011. Oil and NGL revenues were 58 percent of product revenues in the third quarter of 2011, as compared to 31 percent in the prior year quarter and 48 percent in the second quarter of 2011.

Pricing

Our third quarter 2011 realized oil price was $87.03 per barrel, 23 percent higher than the $70.97 per barrel price in the third quarter of 2010 and 12 percent lower than the $98.45 per barrel price in the second quarter of 2011. Our third quarter 2011 realized NGL price was $48.00 per barrel, 35 percent higher than the $35.57 per barrel price in the third quarter of 2010 and eight percent lower than the $52.04 per barrel price in the second quarter of 2011. Our third quarter 2011 realized natural gas price was $4.24 per thousand cubic feet (Mcf), three percent lower than the $4.36 per Mcf price in the third quarter of 2010 and two percent lower than the $4.32 per Mcf price in the second quarter of 2011. Adjusting for oil and gas hedges, our third quarter 2011 effective natural gas price was $4.87 per Mcf and our effective oil price was $88.28 per barrel, or increases of $0.63 per Mcf and $1.25 per barrel over the realized prices.

Production

As shown in the table below, production in the third quarter of 2011 was approximately 11.9 Bcfe, or 129.9 MMcfe per day, a ten percent decrease as compared to 13.3 Bcfe, or 144.3 MMcfe per day, in the prior year quarter and a two percent increase from 11.7 Bcfe, or 128.6 MMcfe per day, in the second quarter of 2011. As a percentage of total equivalent production, oil and NGL volumes were 33 percent in the third quarter of 2011, as compared to 18 percent in the prior year quarter, 24 percent in the second quarter of 2011 and 20 percent in the first quarter of 2011.

     
Total and Daily Equivalent Production for the Three Months Ended

Region / Play Type

      Sept. 30,

2011

      Sept. 30,

2010

      June 30,

2011

      Sept. 30,

2011

      Sept. 30,

2010

      June 30,

2011

(in Bcfe) (in MMcfe per day)
Texas 4.9       4.0       4.2 53.3       43.7       46.4
Cotton Valley 1.8 1.7 2.1 19.9 18.0 22.7
Haynesville Shale 1.0 2.4 1.2 11.1 25.7 13.1

Eagle Ford / Other(1)

2.1 --- 1.0 22.4 --- 10.6
Appalachia 2.3 2.7 2.3 24.7 29.4 24.7
Mid-Continent 3.2 4.5 3.5 34.8 48.6 38.8
Granite Wash 2.7 3.5 2.9 29.7 38.1 31.6
Other(2) 0.5 1.0 0.7 5.1 10.5 7.2
Mississippi 1.6       2.1       1.7 17.0       22.6       18.6
Totals 11.9       13.3       11.7 129.9       144.3       128.6
 
 

(1)

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

(2)

Includes properties, primarily in the Arkoma Basin, sold in August 2011.

Note - Numbers may not add due to rounding.

 

The year-over-year production decrease was due to a 2.8 Bcfe, or 26 percent, decrease in natural gas production resulting from our planned shift away from natural gas drilling since mid-2010 and the subsequent natural production declines. The decrease in natural gas production was partially offset by a 1.5 Bcfe, or 63 percent, increase in oil and NGL production primarily associated with our drilling activity in the Eagle Ford Shale and increased NGL volumes from the Granite Wash. The sequential quarterly increase in production was primarily attributable to higher oil and NGL volumes from the Eagle Ford Shale, partially offset by natural gas production declines, the August 2011 sale of Arkoma Basin properties and lower NGL production in the Granite Wash as a result of a fire at a third-party processing plant, which has reduced NGL sales volumes since July 2011.

Operating Expenses

As discussed below, third quarter 2011 total direct operating expenses decreased $4.3 million, or approximately 14 percent, to $25.6 million, or $2.14 per Mcfe produced, as compared to $29.9 million, or $2.25 per Mcfe produced, in the third quarter of 2010 and $28.8 million, or $2.47 per Mcfe produced, in the second quarter of 2011.

  • Lease operating expenses decreased by $0.8 million, or nine percent, to $8.5 million, or $0.71 per Mcfe produced, from $9.3 million, or $0.70 per Mcfe produced, in the prior year quarter due to lower production volumes as well as lower maintenance, compression and workover costs, partially offset by higher environmental, water disposal and employee-related costs. The unit cost increased slightly due to lower production volumes
  • Gathering, processing and transportation expenses decreased by $0.6 million, or 19 percent, to $3.0 million, or $0.25 per Mcfe produced, from $3.6 million, or $0.27 per Mcfe produced, in the prior year quarter resulting from lower production volumes, partially offset by higher processing costs associated with higher NGL production
  • Production and ad valorem taxes decreased 36 percent to $3.4 million, or 4.1 percent of product revenues, from $5.3 million, or 7.8 percent of product revenues, in the prior year quarter resulting primarily from a property tax recovery in Appalachia, as well as lower production volumes
  • General and administrative (G&A) expenses, excluding share-based compensation, decreased by $0.9 million, or eight percent, to $10.8 million, or $0.91 per Mcfe produced, from $11.7 million, or $0.88 per Mcfe produced, in the prior year quarter. This decrease reflects a $1.7 million reduction in recurring G&A expenses resulting from lower employee headcount and lower support costs following our 2010 restructuring actions, partially offset by a $0.8 million increase in restructuring costs following the sale of our Arkoma Basin assets in August 2011. The unit cost increased slightly due to lower production volumes

Exploration expense decreased $2.7 million to approximately $19.3 million in the third quarter of 2011 from $22.0 million in the prior year quarter. The decrease was primarily due to a $9.3 million decrease in dry hole costs and a $1.2 million decrease in geological and geophysical costs, partially offset by $4.8 million of rig-related charges incurred in the third quarter of 2011 in connection with the temporary suspension of our exploratory drilling program in the Marcellus Shale and a $3.1 million increase in amortization of unproved leasehold properties related to significant acquisitions during 2010.

DD&A expense increased by $12.1 million, or 36 percent, to $45.3 million, or $3.80 per Mcfe produced, in the third quarter of 2011 from $33.2 million, or $2.50 per Mcfe produced, in the prior year quarter, primarily due to higher DD&A costs attributable to our Eagle Ford Shale oil wells, which can be typical for this and other oily plays, partially offset by lower production volumes.

Operational Update

Eagle Ford Shale

During the third quarter of 2011, we drilled 10 (8.3 net) operated wells in the Eagle Ford Shale, all of which were successful. We currently have four rigs drilling our 25th through 28th wells, four wells that are waiting on completion (WOC) and 20 (16.7 net) wells that are producing. As shown in the table below, our initial 20 wells in the Eagle Ford Shale have had an average peak gross production rate of 1,012 BOEPD per well (688 BOEPD 30-day average per well for 17 of these wells).(3)

 
           

Cumulative Gross

Production(3)

    Peak Gross Daily

Production Rates(3)

   

30-Day Average Gross

Daily Production Rates(3)

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 16 129,946 275 1,084 1,247 732 881
Hawn Holt #1H 4,053 15 73,952 182 759 837 606 668
Hawn Holt #2H 4,476 17 71,524 149 869 986 668 728
Hawn Holt #4H 4,106 14 45,281 179 534 582 357 394
Hawn Holt #6H 4,166 17 46,111 150 670 711 342 370
Hawn Holt #9H 4,453 18 90,538 145 1,652 1,877 1,044 1,153
Hawn Holt #10H 3,913 16 62,836 121 1,080 1,188 771 839
Hawn Holt #3H 3,800 15 41,232 114 607 651 478 522
Hawn Holt #5H 3,950 16 32,735 113 474 528 321 349
Munson Ranch #1H 4,163 17 90,609 104 1,755 1,921 1,207 1,315
Munson Ranch #3H 3,953 16 66,241 103 1,448 1,538 1,007 1,092
Hawn Holt #11H 3,931 16 51,640 99 1,120 1,190 786 860
 
New On-Line Wells
Hawn Holt #7H 4,345 18 27,960 68 730 798 493 541
Dickson Allen #1H 3,953 15 20,305 67 465 508 358 393
Hawn Holt #12H 3,320 18 33,255 60 1,458 1,495 619 668
Cannonade Ranch #1H 4,403 18 14,361 51 377 403 255 274
Hawn Holt #13H 2,805 11 25,877 47 1,347 1,399 585 650
Hawn Holt #15H 4,153 17 23,388 28 1,191 1,298 --- ---
Dickson Allen #2H 3,853 16 9,120 20 552 601 --- ---
Hawn Holt #8H 4,203 17 6,383 19 427 492 --- ---
 
Averages 4,040 16 930 1,012 625 688
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 WOC
Gardner #2H WOC
Munson Ranch #2H WOC
Schaefer #1H WOC
Munson Ranch #4H Drilling
Munson Ranch #6H Drilling
Rock Creek Ranch #1H Drilling
Schaefer #2H Drilling
 
 

(3)

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

In the third quarter of 2011, we increased our net Eagle Ford Shale leasehold position by approximately 2,000 net acres to 14,700 net acres. Thus far in 2011, we have added 7,300 net acres in Gonzales County for approximately $27 million. We have identified approximately 140 horizontal well locations on our current acreage position of approximately 17,900 gross acres, including the 24 wells that have been drilled. Our full-year 2011 guidance anticipates up to 33 (27.5 net) wells, with up to 12 (10.0 net) wells to be drilled during the fourth quarter of 2011. We continue efforts to expand our Eagle Ford Shale position in Gonzales County and other prospective areas in the play through additional leasing and selective acquisitions.

Granite Wash

During the third quarter of 2011, three (1.1 net) non-operated Granite Wash wells were drilled in the Mid-Continent, of which PVA went non-consent on the completion of one (0.05 net) well. Our full-year 2011 guidance includes up to 20 (8.7 net) wells, with up to four (1.2 net) wells to be drilled during the fourth quarter of 2011.

Capital Expenditures

During the third quarter of 2011, oil and gas capital expenditures were approximately $114 million, as compared to $147 million in the third quarter of 2010 and $105 million in the second quarter of 2011, consisting of:

  • $102 million for drilling and completion activities, including 13 (9.5 net) wells, 12 (9.4 net) of which were successful and one (0.05 net) of which PVA went non-consent on the completion
  • $6 million for seismic, pipeline, gathering and facilities
  • $6 million for leasehold acquisitions and other

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of September 30, 2011, we had total debt with a carrying value of $613 million ($620 million aggregate principal amount), consisting of $293 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 $15 million of borrowings under our revolving credit facility. Net of cash and equivalents of approximately $4 million, our indebtedness at September 30, 2011 was approximately $609 million, or 38 percent of book capitalization.

In August 2011, we announced an amended and restated senior secured revolving credit facility with a five-year maturity, a $300 million commitment amount and an accordion feature to expand commitment amounts by up to $300 million, with the total commitments not to exceed the borrowing base. The current borrowing base of $380 million, which has been adjusted for the impact of the recent sale of our Arkoma Basin assets and was recently reaffirmed, is subject to redetermination on a semi-annual basis. As of September 30, 2011, our available borrowing capacity under the revolver, as reduced by outstanding borrowings and letters of credit of $16.4 million, was approximately $284 million, which, together with cash and equivalents, comprised financial liquidity of approximately $288 million.

Interest expense increased to $14.2 million in the third quarter of 2011 from $13.2 million in the third quarter of 2010 due to higher average levels of debt outstanding, partially offset by lower effective interest rates.

During the third quarter of 2011, derivatives income was $11.5 million, as compared to derivatives income of $15.1 million in the prior year quarter. Third quarter 2011 cash settlements of derivatives resulted in net cash receipts of $8.5 million, as compared to $6.8 million of net cash receipts in the prior year quarter.

Fourth Quarter 2011 Guidance Update

Fourth quarter 2011 guidance highlights are as follows:

  • Fourth quarter production guidance of 12.2 to 12.7 Bcfe, 32 to 33 percent of which is expected to be crude oil and 10 to 11 percent of which is expected to be NGLs
    • Full-year 2011 production, including fourth quarter guidance, is expected to be 48.0 to 48.5 Bcfe, a decrease of 0.5 to 2.0 Bcfe from previous guidance of 48.5 to 50.5 Bcfe, primarily due to delays in completions in the Eagle Ford Shale and the Granite Wash (non-operated), reduced NGL recoveries in the Granite Wash during the second half of 2011 and delays in initial production by the Marcellus Shale horizontal wells which were drilled earlier in 2011
  • Fourth quarter capital expenditures guidance of $110 to $120 million
    • Full-year 2011 capital expenditures, including fourth quarter guidance, is expected to be $433 to $443 million, an increase of between $63 and $73 million from previous guidance of $360 to $380 million, primarily due to increased drilling, completion and other costs for recent Eagle Ford Shale wells

Please see the Guidance Table included in this release for guidance estimates for full-year 2011. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.

Third Quarter 2011 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss third quarter 2011 financial and operational results, is scheduled for Thursday, November 3, 2011 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 ten minutes before the scheduled start of the conference call (use the passcode 7085147), 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 7085147. 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, natural gas liquids and oil; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of natural gas, natural gas liquids 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 costs 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; uncertainties related to expected benefits from acquisitions of oil and natural gas properties; 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 regulations 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.

 
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - unaudited
(in thousands, except per share data)
 
 
    Three months ended     Nine months ended
September 30, September 30,
2011     2010 2011     2010
Revenues
Natural gas $ 34,171 $ 47,476 $ 113,660 $ 134,283
Crude oil 37,147 13,396 75,278 38,117
Natural gas liquids (NGLs)   10,676     7,459     33,758     14,987  
Total product revenues 81,994 68,331 222,696 187,387
Gain on sales of property and equipment 71 280 523 616
Other   1,288     342     2,335     2,116  
Total revenues 83,353 68,953 225,554 190,119
Operating Expenses
Lease operating 8,458 9,256 29,522 27,148
Gathering, processing and transportation 2,952 3,625 11,261 10,165
Production and ad valorem taxes 3,391 5,309 11,289 12,684
General and administrative (excluding share-based compensation) (a)   10,815     11,734     33,312     37,897  
Total direct operating expenses 25,616 29,924 85,384 87,894
Share-based compensation (b) 1,820 1,711 5,629 6,400
Exploration 19,303 22,020 68,219 37,590
Depreciation, depletion and amortization 45,345 33,224 113,224 95,358
Impairments (c) - 35,127 71,071 36,251
Other   300     -     300     465  
Total operating expenses   92,384     122,006     343,827     263,958  
 
Operating loss (9,031 ) (53,053 ) (118,273 ) (73,839 )
 
Other income (expense)
Interest expense (14,206 ) (13,198 ) (41,833 ) (40,190 )
Loss on extinguishment of debt (d) (1,165 ) - (25,403 ) -
Derivatives 11,498 15,113 19,827 44,410
Other   61     342     334     2,105  
 
Loss from continuing operations before income taxes (12,843 ) (50,796 ) (165,348 ) (67,514 )
Income tax benefit   6,125     20,637     60,372     27,024  
 
Loss from continuing operations (6,718 ) (30,159 ) (104,976 ) (40,490 )
Income from discontinued operations, net of tax - - - 33,482
Gain on sale of discontinued operations, net of tax   -     -     -     49,612  
 
Net income (loss) (6,718 ) (30,159 ) (104,976 ) 42,604
Less net income attributable to noncontrolling interests in discontinued operations   -     -     -     (28,090 )
 
Income (loss) attributable to PVA $ (6,718 ) $ (30,159 ) $ (104,976 ) $ 14,514  
 
Income (loss) per share attributable to PVA - Basic
Continuing operations $ (0.15 ) $ (0.66 ) $ (2.29 ) $ (0.89 )
Discontinued operations - - - 0.12
Gain on sale of discontinued operations   -     -     -     1.09  
Net income (loss) attributable to PVA $ (0.15 ) $ (0.66 ) $ (2.29 ) $ 0.32  
Income (loss) per share attributable to PVA - Diluted
Continuing operations $ (0.15 ) $ (0.66 ) $ (2.29 ) $ (0.89 )
Discontinued operations - - - 0.12
Gain on sale of discontinued operations   -     -     -     1.09  
Net income (loss) attributable to PVA $ (0.15 ) $ (0.66 ) $ (2.29 ) $ 0.32  
 
Weighted average shares outstanding, basic 45,817 45,591 45,758 45,534
Weighted average shares outstanding, diluted 45,817 45,591 45,758 45,733
                                         
 
Three months ended Nine months ended
September 30, September 30,
2011 2010 2011 2010
Production
Natural gas (MMcf) 8,051 10,890 26,646 28,590
Crude oil (MBbls) 427 189 833 522
NGLs (MBbls) 222 210 695 395
Total natural gas, crude oil and NGL production (MMcfe) 11,947 13,280 35,817 34,093
 
Prices
Natural gas ($ per Mcf) $ 4.24 $ 4.36 $ 4.27 $ 4.70
Crude oil ($ per Bbl) $ 87.03 $ 70.97 $ 90.33 $ 72.96
NGLs ($ per Bbl) $ 48.00 $ 35.57 $ 48.56 $ 37.96
 
Prices - Adjusted for derivative settlements
Natural gas ($ per Mcf) $ 4.87 $ 5.05 $ 4.88 $ 5.59
Crude oil ($ per Bbl) $ 88.28 $ 70.62 $ 90.55 $ 72.64
NGLs ($ per Bbl) $ 48.00 $ 35.57 $ 48.56 $ 37.96
 
 
(a) Includes restructuring costs of approximately $1.5 million and $1.6 million for the three month periods and $0.8 million and $6.4 million for the nine month periods ended September 30, 2011 and 2010, respectively.
(b) Our share-based compensation expense includes our stock option expense and the amortization of common stock, deferred stock, restricted stock and restricted stock unit awards related to employee and director compensation.
(c) Impairment of $71.1 million in the nine months ended September 30, 2011 relates to non-core, primarily Arkoma Basin properties sold in August 2011.
(d) Attributable primarily to the repurchase in April 2011 of approximately 98% of our 4.5% Convertible Senior Subordinated Notes due 2012.
 
 
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
 
 
            As of
September 30,     December 31,
2011 2010
Assets
Current assets $ 101,855 $ 214,340
Net property and equipment 1,752,261 1,705,584
Other assets   22,891     24,676  
Total assets $ 1,877,007   $ 1,944,600  
 
Liabilities and shareholders' equity
Current liabilities $ 104,922 $ 106,994
Revolving credit facility 15,000 -
Senior notes due 2016 293,281 292,487
Senior notes due 2019 300,000 -
Convertible notes due 2012 4,702 214,049
Other liabilities and deferred income taxes 284,739 350,794
Total shareholders' equity   874,363     980,276  
Total liabilities and shareholders' equity $ 1,877,007   $ 1,944,600  
 
 
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
 
 
Three months ended Nine months ended
September 30, September 30,
2011 2010 2011 2010
Cash flows from operating activities
Net income (loss) $ (6,718 ) $ (30,159 ) $ (104,976 ) $ 42,604

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 - - - (84,740 )
Non-cash portion of loss on extinguishment of debt 634 - 22,456 -
Depreciation, depletion and amortization 45,345 33,224 113,224 95,358
Impairments - 35,127 71,071 36,251
Derivative contracts:
Net (gains) losses (11,498 ) (15,113 ) (19,827 ) (44,410 )
Cash settlements 8,527 6,803 20,302 24,287
Deferred income tax benefit (6,125 ) 13,882 (60,372 ) 6,149
Loss (gain) on the sale of property and equipment, net 229 (280 ) (223 ) (151 )
Dry hole and unproved leasehold expense 11,376 16,983 52,457 26,501
Non-cash interest expense 1,062 2,869 5,812 9,089
Share-based compensation 1,820 1,711 5,629 6,400
Other, net (40 ) 121 225 (341 )
Changes in operating assets and liabilities   (5,207 )   (41,962 )   (2,614 )   (11,290 )
Net cash provided by operating activities from continuing operations   39,405     23,206     103,164     68,875  
Cash flows from investing activities
Capital expenditures - property and equipment (107,193 ) (145,629 ) (318,274 ) (313,710 )
Proceeds from the sale of PVG units, net (a) - - - 139,120
Proceeds from the sale of property, plant and equipment, net 30,381 1,895 31,077 25,172
Other, net   -     -     100     1,192  
Net cash (used in) provided by investing activities for continuing operations   (76,812 )   (143,734 )   (287,097 )   (148,226 )
Cash flows from financing activities
Dividends paid (2,580 ) (2,569 ) (7,736 ) (7,700 )
Proceeds from revolving credit facility borrowings 30,000 - 30,000 -
Repayment of revolving credit facility borrowings (15,000 ) - (15,000 ) -
Proceeds from the issuance of Senior Notes due 2019 - - 300,000 -
Repurchase of Convertible Notes - - (232,963 ) -
Debt issuance costs paid (2,291 ) - (8,850 ) -
Proceeds from the sale of PVG units, net (a) - - - 199,125
Distributions received from discontinued operations - - - 11,218
Other, net   174     299     1,148     2,143  
Net cash provided by financing activities from continuing operations   10,303     (2,270 )   66,599     204,786  
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 (27,104 ) (122,798 ) (117,334 ) 125,435
Cash and cash equivalents - beginning of period   30,681     327,250     120,911     79,017  
Cash and cash equivalents - end of period $ 3,577   $ 204,452   $ 3,577   $ 204,452  
 
Supplemental disclosures of cash paid for:
Interest (net of amounts capitalized) $ (2,417 ) $ 1,671 $ 17,288 $ 22,646
Income taxes (net of refunds received) $ 529 $ 22,018 $ 433 $ 25,168
 
 
(a) 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.
 
 
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
 
 
    Three months ended     Nine months ended
September 30, September 30,
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 $ (6,718 ) $ (30,159 ) $ (104,976 ) $ 14,514
Adjustments for derivatives:
Net gains included in net income (loss) (11,498 ) (15,113 ) (19,827 ) (44,410 )
Cash settlements 8,527 6,803 20,302 24,287
Adjustment for impairments - 35,127 71,071 36,251
Adjustment for restructuring costs 1,553 787 1,623 6,434
Adjustment for net loss (gain) on sale of assets 229 (280 ) (223 ) (151 )
Adjustment for loss on extinguishment of debt 1,165 - 25,403 -
Adjustment for gain on sale of discontinued operations - - - (84,740 )
Impact of adjustments on income taxes   11     (11,101 )   (35,909 )   26,157  
$ (6,731 ) $ (13,936 ) $ (42,536 ) $ (21,658 )
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes   -     -     -     (28 )
 
Net loss attributable to PVA, as adjusted (a) $ (6,731 ) $ (13,936 ) $ (42,536 ) $ (21,686 )
 
Net loss attributable to PVA, as adjusted, per share, diluted $ (0.15 ) $ (0.31 ) $ (0.93 ) $ (0.47 )
 

Reconciliation of GAAP "Net income (loss) from continuing operations" to Non-GAAP "Adjusted EBITDAX"

Net loss from continuing operations $ (6,718 ) $ (30,159 ) $ (104,976 ) $ (40,490 )
Income tax benefit (6,125 ) (20,637 ) (60,372 ) (27,024 )
Interest expense 14,206 13,198 41,833 40,190
Depreciation, depletion and amortization expense 45,345 33,224 113,224 95,358
Exploration expense 19,303 22,020 68,219 37,590
Share-based compensation expense   1,820     1,711     5,629     6,400  
EBITDAX 67,831 19,357 63,557 112,024
Adjustments for derivatives:
Net gains included in net income (loss) (11,498 ) (15,113 ) (19,827 ) (44,410 )
Cash settlements 8,527 6,803 20,302 24,287
Adjustment for impairments - 35,127 71,071 36,251
Adjustment for net loss (gain) on sale of assets 229 (280 ) (223 ) (151 )
Adjustment for non-cash portion of loss on extinguishment of debt 634 - 22,456 -
Adjustment for other non-cash items   -     -     -     (1,238 )
Adjusted EBITDAX (b) $ 65,723   $ 45,894   $ 157,336   $ 126,763  
 
 
(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 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.
 
 
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 2011. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes
 
 
  First   Second   Third          
Quarter Quarter Quarter YTD Previous Full-Year Revised Full-Year Changes in Implied Fourth Quarter.
2011 2011 2011 2011 2011 Guidance 2011 Guidance 2011 Guidance 2011 Guidance
Production:

 

Natural gas (Bcf) 9.7 8.9 8.1 26.6 34.0 - 35.0 33.9 - 34.0 (0.1 ) - (1.0 ) 7.3 - 7.4
Crude oil (MBbls) 188 219 427 833 1,450 - 1,600 1,475 - 1,525 25 - (75 ) 642 - 692
NGLs (MBbls) 220 253 222 695 950 - 1,050 875 - 900 (75 ) - (150 ) 180 - 205
Equivalent production (Bcfe) 12.2 11.7 11.9 35.8 48.5 - 50.5 48.0 - 48.5 (0.5 ) - (2.0 ) 12.2 - 12.7
Equivalent daily production (MMcfe per day) 135.2 128.6 129.9 131.2 132.9 - 138.4 131.5 - 132.9 (1.4 ) - (5.5 ) 132.4 - 137.9
 
Operating expenses:
Lease operating ($ per Mcfe) $ 0.84 0.92 0.71 0.82 0.80 - 0.85 0.80 - 0.82 0.00 - (0.03 ) 0.73 - 0.81
Gathering, processing and transportation costs ($ per Mcfe) $ 0.33 0.37 0.25 0.31 0.34 - 0.35 0.30 - 0.31 (0.04 ) - (0.04 ) 0.26 - 0.30
Production and ad valorem taxes (percent of oil and gas revenues) 7.5 % 3.9 % 4.1 % 5.1 % 5.0 % - 6.0 % 5.0 % - 5.5 % 0.0 % - (0.5 %) 5.0 % - 5.5 %
 
General and administrative:
Recurring general and administrative $ 11.5 10.9 9.3 31.7 44.5 - 45.5 40.7 - 41.2 (3.8 ) - (4.3 ) 9.0 - 9.5
Share-based compensation $ 1.8 2.0 1.8 5.6 6.5 - 7.5 7.1 - 7.6 0.6 - 0.1 1.5 - 2.0
Restructuring $ 0.1 0.1 1.6 1.7 0.1 - 0.1 2.3 - 2.5 2.2 - 2.4 0.6 - 0.8
Total reported G&A $ 13.4 13.0 12.6 39.0 51.1 - 53.1 50.1 - 51.3 (1.0 ) - (1.8 ) 11.1 - 12.3
 
Exploration:
Dry hole costs $ 16.4 2.1 0.3 18.9 18.5 - 19.0 18.9 - 19.1 0.4 - 0.1 0.0 - 0.2
Unproved property amortization $ 10.6 12.0 11.0 33.6 45.0 - 47.0 44.6 - 45.1 (0.4 ) - (1.9 ) 11.0 - 11.5
Other $ 2.5 5.3 7.9 15.7 17.0 - 18.0 17.7 - 19.7 0.7 - 1.7 2.0 - 4.0
Total reported Exploration $ 29.5 19.4 19.3 68.2 80.5 - 84.0 81.2 - 83.9 0.7 - (0.1 ) 13.0 - 15.7
 
Depreciation, depletion and amortization ($ per Mcfe) $ 2.86 2.82 3.80 3.16 3.10 - 3.25 3.55 - 3.60 0.45 - 0.35 4.67 - 4.86
 
Capital expenditures:
Development drilling $ 36.8 82.9 88.2 207.9 253.0 - 263.0 302.9 - 307.9 49.9 - 44.9 95.0 - 100.0
Exploratory drilling $ 26.9 12.9 13.4 53.2 44.0 - 50.0 59.2 - 60.2 15.2 - 10.2 6.0 - 7.0
Pipeline, gathering, facilities $ 0.4 3.2 2.7 6.3 9.0 - 10.0 10.3 - 12.3 1.3 - 2.3 4.0 - 6.0
Seismic $ 1.8 4.3 2.9 9.0 8.0 - 9.0 10.0 - 11.0 2.0 - 2.0 1.0 - 2.0
Lease acquisitions, field projects and other $ 38.3 1.6 6.5 46.4 46.0 - 48.0 50.4 - 51.4 4.4 - 3.4 4.0 - 5.0
Total oil and gas capital expenditures $ 104.2 104.9 113.7 322.8 360.0 - 380.0 432.8 - 442.8 72.8 - 62.8 110.0 - 120.0
 
End of period debt outstanding $ 508.7 597.7 613.0 613.0
Effective interest rate 10.6 % 10.5 % 10.5 % 10.5 %
Income tax benefit rate 35.0 % 35.8 % 47.7 % 36.5 %
 
 
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
 
Natural gas: (MMBtu) ($ / MMBtu)
Fourth quarter 2011 Costless collars 20,000 6.00 8.50
First quarter 2012 Costless collars 20,000 6.00 8.50
Fourth quarter 2011 Swaps 10,000 5.01
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
 
Crude oil: (barrels) ($ / barrel)
Fourth quarter 2011 Costless collars 360 80.00 103.30
First quarter 2012 Collars (a) 1,000 90.00 97.00
Second quarter 2012 Collars (a) 1,000 90.00 97.00
Third quarter 2012 Collars (a) 1,000 90.00 97.00
Fourth quarter 2012 Collars (a) 1,000 90.00 97.00
First quarter 2013 Collars (a) 1,000 90.00 100.00
Second quarter 2013 Collars (a) 1,000 90.00 100.00
Third quarter 2013 Collars (a) 1,000 90.00 100.00
Fourth quarter 2013 Collars (a) 1,000 90.00 100.00
Fourth quarter 2011 Swaps 500 109.00
First quarter 2012 Swaps (a) 500 100.00
Second quarter 2012 Swaps (a) 500 100.00
Third quarter 2012 Swaps (a) 500 100.00
Fourth quarter 2012 Swaps (a) 500 100.00
 

(a) Positions added in October 2011. A previous costless collar position for 500 barrels per day for calendar year 2012 at $100 x $120 per barrel was restructured as part of the consideration for the new positions. For the new collar positions, premiums of $7.63 per barrel in 2012 and $9.89 per barrel in 2013 will be paid as part of the net cash settlements during the applicable periods.

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 fourth quarter of 2011 would increase or decrease by approximately $7.3 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the fourth quarter of 2011 would increase or decrease by approximately $7.6 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.

Source: Penn Virginia Corporation