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Penn Virginia Corporation Announces Record Quarterly Oil Production and 2013 Oil Production Growth Guidance of 67 Percent

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Core Eagle Ford Shale Position Expanded to 62,000 Net Acres

Drilling Inventory Increased to Approximately 750 Locations

Excellent Recent Drilling Results in the Eagle Ford Shale

Financial Liquidity of Approximately $300 Million

RADNOR, Pa., Aug. 7, 2013 (GLOBE NEWSWIRE) -- Penn Virginia Corporation (NYSE:PVA) today reported financial results for the three months ended June 30, 2013 and provided updates of its operations and 2013 guidance.

Second Quarter 2013 Highlights

Second quarter 2013 financial results, as compared to first quarter 2013 results, were as follows:

  • Product revenues from the sale of oil, natural gas liquids (NGLs) and natural gas were $109.7 million, or $62.78 per barrel of oil equivalent (BOE), an increase of 34 percent compared to $82.2 million, or $57.61 per BOE;
  • Oil and NGL revenues were $94.2 million, or 86 percent of product revenues, an increase of 34 percent compared to $70.2 million, or 85 percent of product revenues;
  • Operating margin, a non-GAAP (generally accepted accounting principles) measure, excluding acquisition transaction expenses of $2.4 million, was $46.09 per BOE, an increase of 20 percent compared to $38.55 per BOE;
  • Operating income, also excluding acquisition transaction expenses, was $5.6 million, compared to an operating loss of $3.0 million;
  • Adjusted EBITDAX, a non-GAAP measure, was $83.1 million, an increase of 38 percent compared to $60.3 million;
  • Loss attributable to common shareholders (which includes our preferred stock dividend) was $27.2 million, or $0.43 per diluted share, compared to a loss of $18.1 million, or $0.33 per diluted share; and
  • Adjusted loss attributable to common shareholders (which includes our preferred stock dividend), a non-GAAP measure which excludes the effects of certain costs and other gains or losses that affect comparability to other periods, was $10.9 million, or $0.17 per diluted share, compared to a loss of $10.4 million, or $0.19 per diluted share.

Recent operational highlights were as follows:

  • Second quarter production of 1.7 million BOE (MMBOE), or 19,209 BOE per day (BOEPD), up 21 percent compared to 1.4 MMBOE, or 15,857 BOEPD, in the first quarter.
  • Second quarter Eagle Ford Shale production of 11,476 BOEPD, up 53 percent compared to 7,523 BOEPD in the first quarter.
  • Record quarterly oil production of 9,430 barrels of oil per day (BOPD), an increase of 42 percent over 6,655 BOPD in the first quarter of 2013.
  • Including the Eagle Ford Shale assets acquired from Magnum Hunter Resources Corporation in April 2013 (MHR Acquisition), we currently have a total of 139 (94.3 net) Eagle Ford Shale producing wells, with 15 (8.4 net) wells either completing or waiting on completion and five (2.1 net) wells being drilled.
  • The average peak gross production rate per well for the 120 (84.9 net) operated wells completed to date was 1,094 BOEPD. The initial 30-day average gross production rate for the 116 of these 120 wells with a 30‑day production history was 702 BOEPD. The average lateral length for these operated wells was approximately 4,475 feet, with an average of 19 fracturing (frac) stages.
  • The average peak gross production rate per well for the 22 (13.5 net) most recent operated wells was 1,282 BOEPD. The initial 30-day average gross production rate for the 19 of these 22 wells with a 30-day production history was 787 BOEPD. The average lateral length for these recent wells was approximately 5,520 feet, with an average of 22 frac stages.
  • The average stimulation (completion) cost per frac stage was approximately $150,000 in the second quarter of 2013, compared to approximately $200,000 in the first quarter of 2013. This average is expected to decrease further to approximately $110,000 per frac stage beginning in the third quarter of 2013, as we transition to new pumping service providers.
  • Currently, we have a total of approximately 110,000 gross (62,000 net) acres in the Eagle Ford Shale.
  • Approximately 9,000 net acres in the Eagle Ford Shale have been added recently at a cost of approximately $1,600 per acre; and
  • As previously announced in June 2013, approximately 1,300 net acres and associated production were divested pursuant to exercises of preferential rights in connection with the MHR Acquisition, with net proceeds to PVA of approximately $21.4 million before purchase price adjustments.
  • We estimate that we currently have approximately 750 undeveloped drilling locations, which is a drilling inventory of approximately 10 years, assuming an ongoing six-rig program.
  • This has increased from 645 locations that had been disclosed previously.
  • 14 of our recently drilled wells were drilled off of six multi-well pads, with effective spacing of between 45 and 70 acres.

Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release. Second quarter financial and production results reflect contributions from the MHR acquisition from April 24, 2013 through June 30, 2013.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, "In the second quarter, our operating cash flows and margins remained strong as a result of the continued growth in oil production, including contributions from the MHR Acquisition, as well as lower unit operating costs. We expect oil production to increase by approximately 67 percent in 2013 over 2012, comprising approximately 82 percent of product revenues and approximately 53 percent of production. Substantial growth in oil production and cash flows is expected to continue into 2014 and 2015.

"New leasing in the Eagle Ford Shale has materially increased our net acreage at a cost of approximately $1,600 per net acre. As a result and in conjunction with successful downspaced drilling, we have an approximate ten-year drilling inventory at the current pace of drilling. We believe we will be able to continue to add acreage at attractive costs, providing for further increases to our drilling inventory. We expect to see significant reductions in our well costs beginning in the second half of 2013 and expect that our overall Eagle Ford Shale program will contribute substantial production and cash flow growth over the next few years. Our balance sheet remains sound with approximately $300 million of financial liquidity and a leverage ratio of approximately 3.5 times net debt to pro forma Adjusted EBITDAX. We expect to fund our 2013 and 2014 capital programs with increasing operating cash flows and borrowings under our revolver, decreasing our leverage ratio over time. We remain excited about Penn Virginia's future with an ongoing six-rig program providing estimated annual oil production growth of between 30 and 40 percent over the next two years, with the expectation of self-funding our capital program by the end of 2015 going into 2016."

Second Quarter 2013 Results

Overview of Financial Results

The $3.2 million operating income in the second quarter was a $6.2 million improvement over the $3.0 million loss in the first quarter, due primarily to a $27.5 million increase in total product revenues. The effect of this increase was partially offset by a $4.3 million increase in total direct operating expenses (including $2.4 million of acquisition transaction expenses), a $12.7 million increase in depreciation, depletion and amortization (DD&A) expense, a $1.6 million increase in share-based compensation expense, a $1.6 million increase in exploration expense and a $1.1 million decrease in other revenues. The changes in revenue and expense items were attributable primarily to the MHR Acquisition in late April 2013.

Product Revenues

Total product revenues were $109.7 million in the second quarter, a 34 percent increase compared to $82.2 million in the first quarter, due primarily to increased production, as well as a nine percent increase in average product pricing from $57.61 per BOE to $62.78 per BOE. Oil and NGL revenues were $94.2 million in the second quarter, a 34 percent increase compared to $70.2 million in the first quarter, due primarily to increased production. Oil and NGL revenues were 86 percent of product revenues in the second quarter, compared to 85 percent in the first quarter.

Operating Expenses

As discussed below, second quarter total direct operating expenses, excluding $2.4 million of acquisition transaction expenses, increased $2.0 million to $29.2 million, or $16.68 per BOE produced, compared to $27.2 million, or $19.06 per BOE produced, in the first quarter.

  • Lease operating expenses increased by $0.8 million to $8.6 million, or $4.94 per BOE, from $7.8 million, or $5.47 per BOE, due to higher production;
  • Gathering, processing and transportation expenses decreased by $0.6 million to $3.0 million, or $1.70 per BOE, from $3.6 million, or $2.51 per BOE, due primarily to certain non-recurring charges recorded during the first quarter;
  • Production and ad valorem taxes increased by $1.0 million to $7.0 million, or 6.4 percent of product revenues, from $6.0 million, or 7.2 percent of product revenues, due primarily to production increases in the Eagle Ford Shale; and
  • General and administrative expenses, excluding share-based compensation and acquisition transaction expenses, increased by $0.7 million to $10.6 million, or $6.05 per BOE, from $9.9 million, or $6.91 per BOE, due primarily to higher employee-related costs in the second quarter, as well as transition services related to the MHR Acquisition.

Exploration expense increased by $1.6 million to $7.8 million in the second quarter from $6.2 million in the first quarter. The increase was due primarily to the cost of seismic data acquired in connection with the MHR Acquisition.

DD&A expense increased by $12.7 million to $64.3 million, or $36.80 per BOE produced, in the second quarter of 2013 from $51.6 million, or $36.14 per BOE produced, in the first quarter due primarily to production increases in the Eagle Ford Shale.

Second Quarter 2013 Operational Results

Production

Production in the second quarter was 1.7 MMBOE, or 19,209 BOEPD, compared to 1.4 MMBOE, or 15,857 BOEPD, in the first quarter. As a percentage of total equivalent production, oil and NGL volumes were 64 percent in the second quarter of 2013, compared to 58 percent in the first quarter. The table below shows quarterly production detail.

Total and Daily Equivalent Production for the Three Months Ended
Region / Play Type June 30,
2013
March 31,
2013
June 30,
2012
June 30,
2013
March 31,
2013
June 30,
2012
(in MBOE) (in BOEPD)
Texas 1,304 954 935 14,331 10,599 10,271
Eagle Ford 1,044 677 596 11,476 7,523 6,553
Cotton Valley 184 195 215 2,025 2,169 2,364
Haynesville Shale 71 82 123 780 906 1,355
Mid-Continent 243 271 298 2,671 3,015 3,279
Mississippi 195 196 217 2,139 2,177 2,380
Other 11 6 326 118 67 3,581
Totals 1,748 1,427 1,775 19,209 15,857 19,511
Pro Forma Totals(1) 1,748 1,427 1,458 19,209 15,857 16,026
(1) Pro forma to exclude production from the Appalachian assets sold in July 2012.
Notes - Numbers may not add due to rounding.

Capital Expenditures

During the second quarter, capital expenditures were approximately $145 million, an increase of 53 percent compared to $96 million in the first quarter, consisting of:

  • $116 million for drilling and completion activities;
  • $9 million for seismic, pipeline, gathering and facilities; and
  • $20 million for leasehold acquisitions, field projects and other.

The approximate $50 million increase in capital expenditures from the first quarter to the second quarter was attributable to increased drilling, completion and facility costs as a result of a larger drilling program following the MHR Acquisition, as well as an approximate $15 million increase in lease acquisition costs, primarily in the Eagle Ford Shale.

Operational Update

Eagle Ford Shale

Net production from the Eagle Ford Shale was 11,476 BOEPD in the second quarter, compared to 7,523 BOEPD in the first quarter, or an increase of 53 percent. During the second quarter, we completed 17 (10.8 net) operated wells and participated in the completion of two (0.9 net) non-operated wells. Currently, we have a total of 139 (94.3 net) Eagle Ford Shale producing wells, with 15 (8.4 net) wells either completing or waiting on completion and five (2.1 net) wells being drilled. We are currently running four operated rigs, three of which are drilling and one of which is being retro-fitted to a walking rig for use in pad drilling, and two non-operated rigs.

Set forth below are the results and statistics for recent Eagle Ford Shale wells:

Peak Gross Daily
Production Rates(2)
30-Day Average
Gross Daily
Production Rates(2)
Well Name Field /
Operator
Lateral
Length
Frac
Stages
Oil
Rate
Equivalent
Rate
Oil
Rate
Equivalent
Rate
Feet BOPD BOEPD BOPD BOEPD
Operated wells
Othold #1H Shiner 5,432 17 1,052 1,625 722 1,137
Elk Hunter #1H Peach Creek 6,107 22 1,232 1,303 709 783
Elk Hunter #2H Peach Creek 6,664 25 1,427 1,520 643 705
Elk Hunter #3H Peach Creek 6,080 21 1,339 1,456 615 672
Hinze #1H Shiner 5,323 22 742 1,113 538 849
Addax Hunter #1H Peach Creek 5,880 25 1,095 1,168 595 639
Addax Hunter #3H Peach Creek 5,727 24 1,157 1,246 681 737
Addax Hunter #2H Peach Creek 5,640 24 1,370 1,582 719 772
Dubose Unit 1 #2H Cannonade 5,428 22 1,333 1,429 966 1,058
Dubose Unit 2 #1H Cannonade 6,048 24 435 464 376 402
Garza-Kodack #1H Cannonade 5,135 21 482 519 373 403
Netardus #1H Shiner 5,404 22 751 1,132 538 791
Douglas Raab #1H Shiner 5,928 24 904 1,233 534 779
Buffalo Hunter #1H Peach Creek 6,178 25 776 826 563 610
Gonzo South #1H Peach Creek 6,428 18 707 752 443 481
Hefe Hunter #1H Shiner 5,590 23 1,641 1,894 1,090 1,295
Pilsner Hunter #1H Shiner 7,066 29 1,917 2,191 1,045 1,270
Schacherl #2H Shiner 4,295 18 1,131 1,272 678 788
Vana #3H Shiner 5,138 21 1,039 1,212 ------ ------
Vana #4H Shiner 4,852 20 888 1,038 ------ ------
Moose Hunter #2H Shiner 4,326 18 1,379 1,528 ------ ------
Moose Hunter #4H Shiner 5,836 24 1,506 1,694 ------ ------
Averages (22 most recent operated wells) 5,466 22 1,105 1,282 613 787
Averages (all 120 operated wells) 4,476 19 976 1,094 657 702
Non-operated wells
Cinco Ranch J #1H Hunt 24 442 468 307 326
Bubba Goodwin #1H Hunt 29 465 478 119 171
(2) Wellhead rates only; the natural gas associated with these wells is yielding between 165 and 315 barrels of NGLs per million cubic feet in Gonzales and Lavaca Counties.

Of our recent wells, 14 wells (Elk Hunter wells, Addax Hunter wells, Buffalo Hunter and Gonzo South wells, Hefe Hunter and Pilsner Hunter wells, the Vana wells and the Moose Hunter wells) were drilled off of six pads, with effective spacing of between 45 and 70 acres. With continued leasing, primarily in Gonzales and Lavaca Counties contiguous to our current acreage positions, and continued success of our pad drilling efforts and shallower development spacing, we anticipate that, over time, additional wells will be added to our 750-well drilling inventory.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of June 30, 2013, we had total debt of $1,142 million, consisting of $300 million principal amount of 7.25 percent senior unsecured notes due 2019, $775 million of 8.50 percent senior unsecured notes due 2020 and $67 million outstanding under our revolving credit facility (Revolver), with approximately $280 million of unused borrowing capacity under the Revolver. Our indebtedness at June 30, 2013, net of cash and cash equivalents, was $1,123 million, representing 56 percent of book capitalization, with a leverage ratio under the Revolver of 3.5 times trailing twelve months' pro forma Adjusted EBITDAX of approximately $329 million.

In May, the borrowing base and commitment under the Revolver was increased from $276.2 million to $350.0 million. As a result, together with cash and cash equivalents of $19 million, our financial liquidity was approximately $300 million at June 30, 2013. The next borrowing base redetermination is scheduled for November 2013.

During the second quarter, interest expense was $21.8 million, compared to $14.5 million in the first quarter. We reported a $29.2 million loss on extinguishment of debt ($10.0 million of which was non-cash) in connection with the tender offer and redemption of our 10.375 percent senior notes due 2016.

During the second quarter, derivatives income was $8.6 million, compared to a derivatives loss of $7.8 million in the first quarter. Second quarter 2013 cash settlements of derivatives resulted in net cash receipts of $2.2 million, compared to $3.6 million of net cash receipts in the first quarter.

Derivatives Update

To support our operating cash flows, we hedge a portion of our oil and natural gas production at pre-determined prices or price ranges. Based on hedges currently in place, we have hedged approximately 9,500 barrels of daily crude oil production in the second half of 2013, or approximately 76 percent of the midpoint of guidance for second half 2013 crude oil production, at a weighted average floor/swap price of $94.69 per barrel. We have also hedged approximately 25,000 MMBtu of daily natural gas production in the second half of 2013, or approximately 67 percent of the midpoint of guidance for second half 2013 natural gas production, at a weighted average floor/swap price of $3.79 per Mcf.

Please see the Derivatives Table included in this release for our current derivative positions.

2013 Guidance

Previous guidance refers to guidance provided in the first quarter 2013 earnings release, which excluded the impact of the exercise of preferential rights by our Eagle Ford Shale partners as announced in June 2013. Updated 2013 guidance highlights are as follows:

  • Production is expected to be 6.8 to 7.5 MMBOE, or approximately 18,500 to 20,600 BOEPD, compared to previous guidance of 6.7 to 7.3 MMBOE, or approximately 18,200 to 20,000 BOEPD.
  • Crude oil production is expected to increase by 55 to 78 percent over 2012 levels, compared to previous guidance of 60 to 78 percent growth. Crude oil and NGLs are expected to comprise 63 to 69 percent of total production, compared to previous guidance of 65 to 69 percent growth.
  • Product revenues, excluding the impact of any hedges, are expected to be $416 to $471 million, slightly higher than previous guidance of $414 to $469 million.
  • Crude oil and NGL product revenues are expected to be 86 to 89 percent of total product revenues, unchanged from previous guidance.
  • Settlements of current commodity hedges are expected to result in cash receipts of approximately $12 million in 2013.
  • Adjusted EBITDAX, a non-GAAP measure, is expected to be $310 to $350 million, compared to previous guidance of $300 to $360 million.
  • Capital expenditures are expected to be $470 to $510 million, compared to previous guidance of $445 to $505 million. The increase is due primarily to $13 to $19 million of additional lease acquisition opportunities, primarily in the Eagle Ford Shale.
  • Approximately 92 percent of capital expenditures are expected to be allocated to the Eagle Ford Shale.
  • 2013 capital expenditures include $413 to $437 million for drilling and completions (compared to previous guidance of $400 to $450 million), $36 to $49 million for lease acquisitions (compared to previous guidance of $23 to $30 million) and $21 to $24 million for pipeline, gathering, seismic and facilities (compared to previous guidance of $22 to $25 million).
  • We expect to drill 69 (42.3 net) Eagle Ford Shale wells during 2013, excluding 16 (7.0 net) wells drilled by MHR and another operator prior to the closing of the MHR Acquisition.

Please see the Guidance Table included in this release for guidance estimates for 2013. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Explanation of Non-GAAP Operating Margin per BOE

Operating margin is a non-GAAP financial measure under SEC regulations which represents total product revenues less total direct operating expenses, excluding acquisition transaction expenses. Operating margin per BOE is equal to operating margin divided by total equivalent crude oil, NGL and natural gas production. Operating margin is not adjusted for the impact of hedges. We believe that operating margin per BOE 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.

Second Quarter 2013 Conference Call

A conference call and webcast, during which management will discuss second quarter 2013 financial and operational results, is scheduled for Thursday, August 8, 2013 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 toll free 1-877-316-5288 (international: 1-734-385-4977) five to 10 minutes before the scheduled start of the conference call (use the conference code 33058530), 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 1-855-859-2056 (international: 1-404-537-3406) and using the replay code 33058530. 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 exploration, development and production of oil, NGLs and natural gas in various domestic onshore regions of the United States, with a primary focus in Texas, and to a lesser extent, the Mid-Continent, Mississippi and the Marcellus Shale in Appalachia. 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 oil, NGLs and natural gas; our ability to develop, explore for, acquire and replace oil and natural 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 oil, NGLs and natural gas; 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 natural 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 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 OPERATIONS - unaudited
(in thousands, except per share data)
Three months ended
June 30,
Six months ended
June 30,
2013 2012 2013 2012
Revenues
Crude oil $ 86,867 $ 58,382 $ 149,925 $ 117,105
Natural gas liquids (NGLs) 7,313 7,556 14,440 16,627
Natural gas 15,554 10,303 27,593 25,189
Total product revenues 109,734 76,241 191,958 158,921
Gain (loss) on sales of property and equipment, net 256 78 (293) 834
Other (335) 526 1,188 1,501
Total revenues 109,655 76,845 192,853 161,256
Operating expenses
Lease operating 8,629 9,264 16,434 18,407
Gathering, processing and transportation 2,980 4,391 6,559 8,545
Production and ad valorem taxes 6,976 (254) 12,935 3,326
General and administrative (excluding equity-classified share-based compensation) (a) 12,970 10,411 22,828 20,937
Total direct operating expenses 31,555 23,812 58,756 51,215
Share-based compensation - equity classified awards (b) 2,686 1,336 3,771 2,951
Exploration 7,845 9,384 14,140 17,382
Depreciation, depletion and amortization 64,329 51,740 115,905 102,557
Impairments -- 28,616 -- 28,616
Total operating expenses 106,415 114,888 192,572 202,721
Operating income (loss) 3,240 (38,043) 281 (41,465)
Other income (expense)
Interest expense (21,808) (15,084) (36,287) (29,858)
Loss on extinguishment of debt (29,157) -- (29,157) --
Derivatives 8,588 43,826 827 43,521
Other 17 28 44 29
Loss before income taxes (39,120) (9,273) (64,292) (27,773)
Income tax benefit 13,682 3,635 22,471 10,236
Net loss (25,438) (5,638) (41,821) (17,537)
Preferred stock dividends (1,725) -- (3,450) --
Loss applicable to common shareholders $ (27,163) $ (5,638) $ (45,271) $ (17,537)
Loss per share:
Basic $ (0.43) $ (0.12) $ (0.77) $ (0.38)
Diluted $ (0.43) $ (0.12) $ (0.77) $ (0.38)
Weighted average shares outstanding, basic 62,899 46,030 59,141 45,988
Weighted average shares outstanding, diluted 62,899 46,030 59,141 45,988
Three months ended
June 30,
Six months ended
June 30,
2013 2012 2013 2012
Production
Crude oil (MBbls) 858 572 1,457 1,120
NGLs (MBbls) 260 227 494 442
Natural gas (MMcf) 3,778 5,859 7,342 12,153
Total crude oil, NGL and natural gas production (MBOE) 1,748 1,775 3,175 3,588
Prices
Crude oil ($ per Bbl) $ 101.23 $ 102.14 $ 102.89 $ 104.55
NGLs ($ per Bbl) $ 28.10 $ 33.23 $ 29.21 $ 37.60
Natural gas ($ per Mcf) $ 4.12 $ 1.76 $ 3.76 $ 2.07
Prices - Adjusted for derivative settlements
Crude oil ($ per Bbl) $ 104.10 $ 102.03 $ 106.52 $ 104.40
NGLs ($ per Bbl) $ 28.10 $ 33.23 $ 29.21 $ 37.60
Natural gas ($ per Mcf) $ 4.06 $ 2.72 $ 3.83 $ 3.20
(a) Includes liability-classified share-based compensation expense attributable to our performance-based restricted stock units which are payable in cash upon the achievement of certain market-based performance metrics. A total of $0.4 million and $0.6 million attributable to these awards is included in the three and six months ended June 30, 2013 and 2012.

(b) Our equity-classified share-based compensation expense includes non-cash charges for our stock option expense and the amortization of common, deferred and restricted stock and restricted stock unit awards related to equity-classified employee and director compensation in accordance with accounting guidance for share-based payments.
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
As of
June 30,
2013
December 31,
2012
Assets
Current assets $169,829 $96,515
Net property and equipment 2,234,256 1,723,359
Other assets 40,918 23,115
Total assets $2,445,003 $1,842,989
Liabilities and shareholders' equity
Current liabilities $188,380 $112,025
Revolving credit facility 67,000 --
Senior notes due 2016 -- 294,759
Senior notes due 2019 300,000 300,000
Senior notes due 2020 775,000 --
Other liabilities and deferred income taxes 219,236 241,089
Total shareholders' equity 895,387 895,116
Total liabilities and shareholders' equity $2,445,003 $1,842,989
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
Three months ended
June 30,
Six months ended
June 30,
2013 2012 2013 2012
Cash flows from operating activities
Net loss $(25,438) $(5,638) $(41,821) $(17,537)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on extinguishment of debt 29,157 -- 29,157 --
Depreciation, depletion and amortization 64,329 51,740 115,905 102,557
Impairments -- 28,616 -- 28,616
Derivative contracts:
Net gains (8,588) (43,826) (827) (43,521)
Cash settlements 2,233 6,970 5,790 14,951
Deferred income tax benefit (13,682) (3,635) (22,471) (10,236)
Loss (gain) on sales of assets, net (256) (78) 293 (834)
Non-cash exploration expense 5,146 8,284 10,408 16,455
Non-cash interest expense 939 1,035 1,885 2,050
Share-based compensation (equity-classified) 2,686 1,336 3,771 2,951
Other, net 650 147 938 203
Changes in operating assets and liabilities 26,960 73 26,723 20,070
Net cash provided by operating activities 84,136 45,024 129,751 115,725
Cash flows from investing activities
Acquisition, net (358,239) -- (358,239) --
Payments to settle obligations assumed in acquisition, net (36,310) -- (36,310) --
Capital expenditures - property and equipment (143,346) (93,767) (229,319) (188,236)
Proceeds from sales of assets, net (11) (251) 867 527
Other, net -- 180 -- 180
Net cash used in investing activities (537,906) (93,838) (623,001) (187,529)
Cash flows from financing activities
Proceeds from the issuance of senior notes 775,000 -- 775,000 --
Retirement of senior notes (319,090) -- (319,090) --
Proceeds from revolving credit facility borrowings 115,000 61,000 153,000 84,000
Repayment of revolving credit facility borrowings (86,000) -- (86,000) (3,000)
Debt issuance costs paid (24,698) -- (24,698) --
Dividends paid on preferred and common stock (1,725) (2,590) (3,412) (5,176)
Other, net (49) -- (110) --
Net cash provided by financing activities 458,438 58,410 494,690 75,824
Net increase (decrease) in cash and cash equivalents 4,668 9,596 1,440 4,020
Cash and cash equivalents - beginning of period 14,422 1,936 17,650 7,512
Cash and cash equivalents - end of period $19,090 $11,532 $19,090 $11,532
Supplemental disclosures of cash paid for:
Interest (net of amounts capitalized) $22,875 $26,099 $23,215 $26,656
Income taxes (net of refunds received) $-- $(10) $-- $(311)
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
Three months ended
June 30,
Six months ended
June 30,
2013 2012 2013 2012
Reconciliation of GAAP "Net loss" to Non-GAAP "Net loss applicable to common shareholders, as adjusted"
Net loss $ (25,438) $ (5,638) $ (41,821) $ (17,537)
Adjustments for derivatives:
Net losses (8,588) (43,826) (827) (43,521)
Cash settlements 2,233 6,970 5,790 14,951
Adjustment for acquisition transaction expenses 2,396 -- 2,396 --
Adjustment for impairments -- 28,616 -- 28,616
Adjustment for restructuring costs -- (148) -- (148)
Adjustment for loss (gain) on sale of assets, net (256) (78) 293 (834)
Adjustment for loss on extinguishment of debt 29,157 -- 29,157 --
Impact of adjustments on income taxes (8,723) 3,319 (12,865) 345
Preferred stock dividends (1,725) -- (3,450) --
Net loss applicable to common shareholders, as adjusted (a) $ (10,944) $ (10,785) $ (21,327) $ (18,128)
Net loss applicable to common shareholders, as adjusted, per share, diluted $ (0.17) $ (0.23) $ (0.36) $ (0.39)
Reconciliation of GAAP "Net loss" to Non-GAAP "Adjusted EBITDAX"
Net loss $ (25,438) $ (5,638) $ (41,821) $ (17,537)
Income tax benefit (13,682) (3,635) (22,471) (10,236)
Interest expense 21,808 15,084 36,287 29,858
Depreciation, depletion and amortization 64,329 51,740 115,905 102,557
Exploration 7,845 9,384 14,140 17,382
Share-based compensation expense (equity-classified awards) 2,686 1,336 3,771 2,951
EBITDAX 57,548 68,271 105,811 124,975
Adjustments for derivatives:
Net losses (8,588) (43,826) (827) (43,521)
Cash settlements 2,233 6,970 5,790 14,951
Adjustment for acquisition transaction expenses 2,396 -- 2,396 --
Adjustment for impairments -- 28,616 -- 28,616
Adjustment for loss (gain) on sale of assets, net (256) (78) 293 (834)
Adjustment for other non-cash items 647 -- 854 --
Adjustment for loss on extinguishment of debt 29,157 -- 29,157 --
Adjusted EBITDAX (b) $ 83,137 $ 59,953 $ 143,474 $ 124,187
(a) Net loss applicable to common shareholders, as adjusted, represents the net loss adjusted to exclude the effects of non-cash changes in the fair value of derivatives, acquisition transaction expenses, impairments, restructuring costs, net gains and losses on the sale of assets, loss on extinguishment of debt and preferred stock dividends. 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 loss applicable to common, 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 loss.

(b) Adjusted EBITDAX represents net loss 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, acquisition transaction expenses, impairments, net gains and losses on the sale of assets, loss on 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 loss. Adjusted EBITDAX represents EBITDAX as defined in our revolving credit facility.
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 2013. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes.
First
Quarter
2013
Second
Quarter
2013
Year-to-Date
2013
Full-Year
2013 Guidance
Production:
Crude oil (MBbls) 599 858 1,457 3,500 -- 4,000
NGLs (MBbls) 234 260 494 925 -- 1,025
Natural gas (MMcf) 3,565 3,778 7,342 14,000 -- 15,000
Equivalent production (MBOE) 1,427 1,748 3,175 6,758 -- 7,525
Equivalent daily production (BOEPD) 15,857 19,209 17,542 18,516 -- 20,616
Percent crude oil and NGLs 58.4% 64.0% 61.5% 63.0% -- 69.0%
Production revenues (a):
Crude oil $63.1 86.9 149.9 340.0 -- 385.0
NGLs $7.1 7.3 14.4 26.0 -- 29.0
Natural gas $12.0 15.6 27.6 50.0 -- 57.0
Total product revenues $82.2 109.7 192.0 416.0 -- 471.0
Total product revenues ($ per BOE) $57.61 62.78 60.46 61.55 -- 62.59
Percent crude oil and NGLs 85.4% 85.8% 85.6% 86.3% -- 89.4%
Operating expenses:
Lease operating ($ per BOE) $5.47 4.94 5.18 5.60 -- 6.00
Gathering, processing and transportation costs ($ per BOE) $2.51 1.70 2.07 1.70 -- 1.85
Production and ad valorem taxes (percent of oil and gas revenues) 7.2% 6.4% 6.7% 6.6% -- 7.0%
General and administrative:
Recurring general and administrative $9.9 10.6 20.4 41.0 -- 43.0
Share-based compensation $1.1 2.7 3.8 5.0 -- 6.5
Acquisition transaction expenses $------ 2.4 2.4 2.4 -- 2.4
Total reported G&A $10.9 15.7 26.6 48.4 -- 51.9
Exploration:
Total reported exploration $6.3 7.8 14.1 40.0 -- 43.0
Unproved property amortization $5.3 5.1 10.4 36.5 -- 39.0
Depreciation, depletion and amortization ($ per BOE) $36.14 36.80 36.50 36.00 -- 39.00
Adjusted EBITDAX (b) $60.3 83.1 143.5 310.0 -- 350.0
Capital expenditures:
Drilling and completion $86.5 116.3 202.9 413.0 -- 437.0
Pipeline, gathering, facilities $3.0 8.2 11.2 18.0 -- 20.0
Seismic (c) $1.0 1.8 2.8 3.0 -- 4.0
Lease acquisitions, field projects and other $5.1 19.9 25.0 36.0 -- 49.0
Total capital expenditures $95.6 146.2 241.8 470.0 -- 510.0
End of period debt outstanding $633.1 1,142.0 1,142.0 1,210.0 -- 1,250.0
Interest expense:
Total reported interest expense $14.5 21.8 36.3 78.0 -- 84.0
Cash interest expense $13.5 20.9 34.4 76.0 -- 77.0
Preferred stock dividends paid $1.7 1.7 3.4 6.9 -- 6.9
Income tax benefit rate 34.9% 35.0% 35.0% 35.5% -- 36.5%
(a) Assumes average benchmark prices of $92.87 per barrel for crude oil and $3.69 per MMBtu for natural gas, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments. NGL realized pricing is assumed to be $28.49 per barrel.

(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.

(c) Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities.
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)
Third quarter 2013 Collars 10,000 3.50 4.30
Fourth quarter 2013 Collars 15,000 3.67 4.37
First quarter 2014 Collars 5,000 4.00 4.50
Third quarter 2013 Swaps 15,000 3.92
Fourth quarter 2013 Swaps 10,000 4.04
First quarter 2014 Swaps 10,000 4.28
Second quarter 2014 Swaps 15,000 4.10
Third quarter 2014 Swaps 15,000 4.10
Fourth quarter 2014 Swaps 5,000 4.50
First quarter 2015 Swaps 5,000 4.50
Crude oil: (barrels) ($ / barrel)
Bitmap Bitmap Bitmap Bitmap Third quarter 2013 Collars 2,232 90.74 99.78
Fourth quarter 2013 Collars 2,400 91.04 100.02
First quarter 2014 Collars 500 90.00 97.60
Second quarter 2014 Collars 500 90.00 97.60
Third quarter 2013 Swaps 6,832 95.84
Fourth quarter 2013 Swaps 7,500 95.98
First quarter 2014 Swaps 7,500 93.86
Second quarter 2014 Swaps 7,500 93.86
Third quarter 2014 Swaps 7,000 93.23
Fourth quarter 2014 Swaps 6,500 92.98
First quarter 2014 Swaption (a) 812 100.00
Second quarter 2014 Swaption (a) 812 100.00
Third quarter 2014 Swaption (a) 812 100.00
Fourth quarter 2014 Swaption (a) 812 100.00
(a) This written swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for calendar year 2014 is higher than or equal to $100.00 per barrel on December 31, 2013, the counterparty will exercise its option to enter into a fixed price swap at $100.00 per barrel for calendar year 2014, at which point the contract functions as a fixed price swap. If the forward commodity price for calendar year 2014 is lower than $100.00 per barrel on December 31, 2013, the option expires and no fixed price swap is in effect.

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 2013 would increase or decrease by approximately $6.7 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for 2013 would increase or decrease by approximately $31.1 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.

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

Source:Penn Virginia Corporation