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 October 29, 2014 - 4:05 PM EDT
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Penn Virginia Corporation Announces Third Quarter 2014 Results

Total Production Up 4% Quarter-Over-Quarter, Exceeding Guidance

Eagle Ford Production Up 8% Quarter-Over-Quarter

Adjusted EBITDAX Increased to $98 Million

Borrowing Base Increased to $500 Million

RADNOR, Pa., Oct. 29, 2014 (GLOBE NEWSWIRE) -- Penn Virginia Corporation (NYSE:PVA) today reported financial results for the three months ended September 30, 2014 and provided updates of its operations and 2014 guidance.

Key Third Quarter Highlights

Production

  • Total production increased 4% to 22,706 barrels of oil equivalent per day (BOEPD) compared to the prior quarter, exceeding the upper end of guidance by 3%.
    • Eagle Ford Shale production increased 8% to 16,929 BOEPD compared to the prior quarter.
    • Pro forma for the sale of Mississippi properties in July, total production increased 11% to 22,054 BOEPD.
    • Oil and NGL volumes were 74% of total equivalent production compared to 70% in the prior quarter.

Operations – Eagle Ford

  • Initial potential (IP) from operated horizontal wells (excluding shallow wells) averaged 1,350 BOEPD, including five wells with IPs of over 1,900 BOEPD.
  • 12 (8.5 net) wells are currently completing or flowing back (including six (5.7 net) Upper Eagle Ford wells), 14 (8.5 net) wells are currently waiting on completion (including six (5.2 net) Upper Eagle Ford wells) and eight (6.3 net) operated wells are currently being drilled (including three (2.9 net) Upper Eagle Ford wells).
  • Eagle Ford acreage now approximates 145,500 (104,300 net) acres.
    • Approximately 2,500 net acres were added since the last quarterly report at an average cost of $1,700 per acre.

Financial Resources and Liquidity

  • Adjusted EBITDAX, a non-GAAP (generally accepted accounting principles) measure, grew to $97.7 million in the third quarter from $95.0 million in the prior quarter.
  • Borrowing base under our revolving credit facility increased to $500 million, providing pro forma financial liquidity at quarter end of $622 million.
  • Leverage ratio significantly improved at quarter end.

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

Management Comment

H. Baird Whitehead, President and Chief Executive Officer, stated, "In the third quarter of 2014, production exceeded the upper end of guidance, supporting strong cash flows and margins in line with our expectations. Our continued focus on improving execution is showing results as we transition to using larger production casing. This change is driving fewer operational delays and eliminating inefficiencies with our service providers. Based on these improvements, we are reaffirming production guidance for the fourth quarter of 2014. In addition, we have begun completions of our most recently drilled Upper Eagle Ford wells and we believe the play is highly prospective across our acreage.

Whitehead added, "With respect to 2015, we expect to see continued growth in production and cash flow, but we are reassessing our previously announced preliminary guidance and our level of capital expenditures for 2015 in light of the current and projected oil price environment. We plan to release updated 2015 guidance in mid-December after our budget is finalized. Importantly, our current financial liquidity, together with future operating cash flows, is sufficient to fully fund any reasonable capital program we might consider in this evolving environment. Also, in view of our depressed share price and to expand our capital allocation options, we will seek an amendment to our credit facility to permit us to repurchase our common stock under appropriate circumstances."

Third Quarter 2014 Results

Overview of Results

Operating income increased $3.0 million to $29.3 million, excluding $63.5 million of gains on the sale of assets and $6.1 million of impairments, in the third quarter of 2014 from $26.3 million, excluding $117.9 million of impairments, in the second quarter of 2014. This increase was due primarily to a $5.4 million increase in product revenues, a $1.4 million decrease in exploration expense, a $1.2 million decrease in share-based compensation expenses and a $1.2 million decrease in recurring general and administrative (G&A) expense. The effect of these favorable changes was partially offset by a $4.4 million increase in lease operating, gathering, processing and transportation expenses and production and ad valorem taxes and a $0.6 million increase in depletion, depreciation and amortization (DD&A) expense.

Net income attributable to common shareholders for the third quarter was $81.1 million, or $0.87 per diluted share, compared to net loss of $105.9 million, or $1.59 per diluted share, in the prior quarter. Adjusted net loss attributable to common shareholders for the third quarter, a non-GAAP measure which includes our preferred stock dividend but excludes the effects of other items that affect comparability to other periods, was $7.4 million, or $0.10 per diluted share, compared to a loss of $4.3 million, or $0.07 per diluted share, in the prior quarter.

Product Revenues

Total product revenues increased 4% to $141.9 million, or $67.91 per barrel of oil equivalent (BOE), in the third quarter of 2014, from $136.4 million, or $68.81 per BOE, in the second quarter due primarily to a 5% increase in total production, partially offset by an overall 1% decrease in the weighted average product price per BOE. For the third quarter, the realized oil price decreased by 5%, the realized natural gas price decreased by 7% and the realized natural gas liquid (NGL) price increased by 3% over the second quarter. Oil and NGL revenues were $128.5 million in the third quarter, a 7% increase compared to $120.1 million in the second quarter due to a 13% increase in combined oil and NGL production, partially offset by a 5% decrease in combined oil and NGL prices. Oil and NGL revenues were 91% of product revenues in the third quarter, compared to 88% in the second quarter. Natural gas revenues were $13.4 million in the third quarter, an 18% decrease compared to $16.3 million in the second quarter, primarily due to the sale of our Mississippi Selma Chalk properties in July 2014.

Production

As shown in the table below, total production in the third quarter of 2014 was 22,706 BOEPD, compared to 21,786 BOEPD in the second quarter of 2014. As a percentage of total equivalent production, oil and NGL volumes were 74% in the third quarter of 2014, compared to 70% in the second quarter of 2014.

  Total and Daily Equivalent Production for the Three Months Ended
  Sept. 30, June 30, Mar. 31, Sept. 30, June 30, Mar. 31,
Region / Play Type 2014 2014 2014 2014 2014 2014
  (in MBOE) (in BOEPD)
             
Eagle Ford Shale 1,557 1,421 1,329 16,929 15,618 14,761
East Texas 208 220 215 2,257 2,417 2,394
Mid-Continent 258 161 174 2,802 1,770 1,931
Mississippi / Other  66 180 184 719 1,981 2,047
Totals 2,089 1,983 1,902 22,706 21,786 21,133
Pro Forma Totals(1) 2,029 1,809 1,724 22,054 19,872 19,153
 
Note - Numbers may not add due to rounding. MBOE equals one thousand barrels of oil equivalent.
(1)  Pro forma to exclude volumes from Mississippi properties sold at the end of July 2014.

Operating Expenses

As discussed below, third quarter 2014 total direct operating expenses, excluding share-based compensation and non-recurring expenses, increased by $3.2 million to $38.5 million, or $18.41 per BOE produced, compared to $35.3 million, or $17.80 per BOE, in the second quarter of 2014.

  • Lease operating expense increased by $2.9 million to $15.3 million, or $7.32 per BOE, from $12.4 million, or $6.26 per BOE, due to higher compression, subsurface equipment and workover costs.
  • Gathering, processing and transportation expense increased by $1.4 million to $4.9 million, or $2.34 per BOE, compared to $3.5 million, or $1.78 per BOE, due to higher processing costs.
  • Production and ad valorem taxes increased by $0.2 million to $7.7 million, or 5.4% of product revenues, from $7.5 million, or 5.5% of product revenues, due to higher production.
  • G&A expense, excluding share-based compensation and non-recurring expenses of $0.9 million, decreased by $1.2 million to $10.6 million, or $5.06 per BOE, from $11.8 million, or $5.98 per BOE, excluding share-based compensation and non-recurring expenses of $3.0 million. The decrease in recurring G&A expense was due to reduced office rent, telecommunications, information technology and other corporate expenses. The decrease in share-based compensation expenses was due to a lower common stock price in the third quarter of 2014.

Exploration expense decreased $1.4 million from the second quarter to $2.0 million in the third quarter, due primarily to lower unproved leasehold amortization expense.

DD&A expense increased by $0.6 million to $72.0 million, or $34.47 per BOE, in the third quarter, from $71.4 million, or $36.03 per BOE, in the second quarter, due to higher production, partially offset by lower depletion rates.

In the third quarter, we incurred a $6.1 million impairment charge in the Mid-Continent with respect to an exploratory prospect and we recorded a $63.5 million gain on the sale of assets due primarily to our sale of rights to construct an oil gathering system in south Texas. 

Capital Expenditures

During the third quarter of 2014, capital expenditures were $205 million, an increase of $35 million, or 21%, compared to $170 million in the second quarter of 2014, consisting of:

  • $149 million for drilling and completion activities, compared to $154 million in the second quarter;
  • $51 million for leasehold acquisitions, compared to $13 million in the second quarter; and
  • $5 million for pipeline, gathering, facilities, seismic and other, compared to $3 million in the second quarter.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of September 30, 2014, we had total debt of $1,075 million, consisting of $300 million principal amount of 7.25% senior unsecured notes due 2019 and $775 million principal amount of 8.50% senior unsecured notes due 2020. At September 30, 2014, we had a zero balance under our revolving credit facility (Revolver). In October 2014, the borrowing base under our Revolver was increased from $438 million to $500 million. Together with cash and equivalents of $124 million and net of letters of credit of approximately $2 million at September 30, 2014, our pro forma financial liquidity was approximately $622 million at September 30, 2014. Our leverage ratio under the Revolver at September 30, 2014 was 2.6 times trailing twelve months' pro forma Adjusted EBITDAX of approximately $372 million, compared to 3.1 times at June 30, 2014. 

During the third quarter, interest expense was $22.0 million, of which $20.9 million was cash interest expense, compared to $23.2 million in the second quarter, of which $22.2 million was cash interest expense.

During the third quarter, derivatives income was $66.5 million, compared to derivatives loss of $42.7 million in the second quarter. Third quarter 2014 cash settlements of derivatives resulted in net cash outlays of $7.6 million, compared to $7.2 million of net cash outlays in the second quarter.

Pricing

Our third quarter 2014 realized oil price was $95.19 per barrel, compared to $100.16 per barrel in the second quarter of 2014. Our third quarter 2014 realized NGL price was $31.76 per barrel, compared to $30.85 per barrel in the second quarter. Our third quarter 2014 realized natural gas price was $4.17 per thousand cubic feet (Mcf), compared to $4.51 per Mcf in the second quarter. Adjusting for oil and gas hedges, our third quarter 2014 effective oil price was $89.08 per barrel and our third quarter 2014 effective natural gas price was $4.19 per Mcf, or a decrease of $6.11 per barrel from the realized oil price and an increase of $0.02 per Mcf from the realized gas price.

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 13,000 barrels of daily crude oil production, or approximately 79% of the midpoint of guidance for the fourth quarter of 2014, at a weighted average floor/swap price of $92.92 per barrel. For 2015, we have hedged 11,992 barrels of daily crude oil production at a weighted average floor/swap price of $90.20 per barrel. For 2016, we have hedged 3,000 barrels of daily crude oil production at a weighted average floor/swap price of $90.84 per barrel.

We have also hedged 5,000 MMBtu (million British Thermal Units) of daily natural gas production, or approximately 13% of the midpoint of guidance for the fourth quarter of 2014, at a weighted average floor/swap price of $4.50 per MMBtu. For the first quarter of 2015, we have hedged 5,000 MMBtu of daily natural gas production at a weighted average floor/swap price of $4.50 per MMBtu.

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

Eagle Ford Shale Operational Update

Third Quarter 2014 Update

Third quarter production from our Eagle Ford operations was 16,929 BOEPD, up 8% compared to 15,618 BOEPD in the second quarter. Approximately 76% of our third quarter production was from crude oil, 13% was from NGLs and 11% was from natural gas. In September 2014, our average production was 17,936 BOEPD, 75% of which was from crude oil, 13% was from NGLs and 12% was from natural gas. Year-to-date, we have turned in line 55 (32.9 net) operated wells (excludes six shallow and five non-operated wells).

Below are the results and statistics for Eagle Ford wells (excluding shallow and non-operated wells) over the past six quarters: (1)

    Averages
          Peak Gross Daily 30-Day Average Gross Daily 
          Production Rates(2) Production Rates(2)
  Gross/  Lateral  Frac   Oil Equivalent Oil  Oil Equivalent Oil 
  Net Wells Length   Stages Proppant Rate Rate Percentage Rate Rate Percentage
    Feet   lbs. BOPD BOEPD   BOPD BOEPD  
Time Period                    
2013 - 2nd quarter 14 / 8.6 5,588 23.0 5,184,664 1,181 1,397 85% 691 845 82%
2013 - 3rd quarter 10 / 5.6 5,901 23.8 6,526,680 1,375 1,596 86% 879 1,036 85%
2013 - 4th quarter 15 / 7.3 5,730 24.1 7,789,759 1,418 1,624 87% 960 1,119 86%
2014 - 1st quarter 14 / 10.2 5,836 25.2 7,791,564 1,159 1,457 80% 695 844 82%
2014 - 2nd quarter 24 / 14.4 5,462 25.1 9,179,233 1,174 1,469 80% 726 896 81%
2014 – 3rd quarter(3) 17 / 8.3 6,017 27.3 10,311,303 1,132 1,350 84% 787 867 92%
Totals and averages 94 / 54.4 5,726 24.9 8,078,448 1,226 1,473 83% 780 934 83%
                     
Operating Area                    
Upper Eagle Ford(4) 2 / 1.9 5,917 26.5 9,970,830 917 1,763 52% 830 1,502 55%
Shiner ---- "Beer Six Pack"(3) 27 / 12.7 6,036 26.4 9,478,535 1,344 1,641 82% 984 1,184 83%
Rock Creek / Bozka(3) 10 / 4.6 5,952 26.4 9,230,353 1,449 1,649 88% 935 1,055 89%
Peach Creek 29 / 13.6 5,982 25.8 7,800,856 1,295 1,426 91% 816 899 91%
Shiner - Mod. GOR 12 / 9.2 5,124 21.7 6,579,536 1,118 1,346 83% 628 763 82%
Shiner - High GOR 14 / 12.5 4,928 21.6 6,144,944 833 1,189 70% 500 706 70%
Totals and averages 94 / 54.4 5,726 24.9 8,078,448 1,226 1,473 83% 780 934 83%
 
(1) Excludes non-operated wells and "shallow" wells, defined as wells whose vertical depth, including the "curve," is 10,500 feet or less.
(2) Wellhead rates only; the natural gas associated with these wells is yielding between 135 and 155 barrels of NGLs per million cubic feet.
(3) 30-day information for the Kosmo #2H ---- #5H wells, the Porter #3H ---- #7H and #9H, or the L&J Lee #1H ---- #2H wells (12 wells in total) is not yet available.
(4) Does not include the Fojtik #1H (Upper Eagle Ford well brought on line in March 2013).

During the third quarter of 2014, we turned in line 17 (8.3 net) operated wells (excludes four shallow wells and one non-operated well). As a group, these 17 wells had an average IP rate of 1,350 BOEPD over an average of 27.3 frac stages, with 84% of production from crude oil. Of these 17 wells, five wells with sufficient production history had a 30-day average rate of 867 BOEPD, with 92% of production from crude oil. 

Among these wells, the more notable wells and their IP rates included the Cinco J Ranch #1H (2,611 BOEPD with 32 frac stages), the L&J Lee #2H (2,166 BOEPD with 25 frac stages), the L&J Lee #1H (2,102 BOEPD with 25 frac stages), the Porter #6H (2,019 BOEPD with 27 frac stages) and the Porter #7H (1,944 BOEPD with 24 frac stages). The average amount of proppant per stage for these 17 wells was approximately 368,000 pounds, flat with the second quarter of 2014. 

Upper Eagle Ford (Marl) Shale Update

Thus far in the second half of 2014, we have completed six Upper Eagle Ford wells, all of which are now flowing back and being tested. Two of those wells (the Netardus #2H and Netardus #3H) have been flowing into sales for approximately 25 days. In addition to the Netardus wells, the Welhausen #7H and Welhausen #8H wells have recently been turned in line and are cleaning up, while the Hinze #2H and Hinze #3H wells were just completed and are in the early stages of clean-up. To date during 2014, we have completed eight Upper Eagle Ford wells and for the remainder of 2014 we expect ten additional Upper Eagle Ford wells to be drilled, completed and turned in line. 

The Welhausen #A2H was turned in line in March 2014 and has cumulative production of 179,394 BOE (52% oil), or an average of 1,008 BOEPD over 178 producing days, along with a 60-day rate of 1,519 BOEPD, a 30-day rate of 1,767 BOEPD and a peak rate of 2,238 BOEPD.

The Martinsen #2H was turned in line in May 2014 and has cumulative production of 178,584 BOE (54% oil), or an average of 1,038 BOEPD over 172 producing days, along with a 60-day rate of 1,149 BOEPD, a 30-day rate of 1,238 BOEPD and a peak rate of 1,599 BOEPD.

After observing the performance of these wells relative to adjacent wells in the Lower Eagle Ford and the fact that their initial decline rates are less than what we have typically seen with the Lower Eagle Ford, we are increasingly confident that the Upper Eagle Ford and Lower Eagle Ford are separate reservoirs, but additional completion and production information from additional wells will be necessary to confirm that belief. During the fourth quarter of 2014 and into 2015, we will continue to test the Upper Eagle Ford across our Lavaca County acreage.

Updated Full-Year 2014 Guidance

2014 capital expenditures are expected to range between $754 and $800 million ($197 to $243 million for the fourth quarter of 2014), which is an increase of $22 to $28 million from previous guidance. This reflects increases in drilling and completion capital expenditures of between $13 and $14 million and in lease acquisition capital expenditures of between $10 and $11 million. The increase in drilling and completion expenditures is attributable to higher tubular steel, sand, trucking and completion costs. We expect to turn in line 33 (23.0 net) wells (excludes three non-operated wells) during the fourth quarter of 2014, for an estimated total of 88 (55.9 net) operated wells (excludes six shallow and eight non-operated wells) to be turned in line during 2014. For 2014, we expect to turn in line 18 (16.4 net) Upper Eagle Ford wells.

2014 production is expected to range between approximately 8.4 and 8.6 MMBOE (2.4 to 2.6 MMBOE in the fourth quarter of 2014). This represents an increase of 169 MBOE from the lower end of previous fourth quarter guidance and a decrease of 12 MBOE from the upper end of previous fourth quarter guidance.

2014 Adjusted EBITDAX, which includes the cash impact of derivatives, is expected to range between $387 and $427 million ($100 to $140 million during the fourth quarter of 2014). This represents a decrease of $7 to $12 million from previous guidance. Our estimates assume the benchmark (WTI) oil price will average $80.67 per barrel and the benchmark (Henry Hub) natural gas price will average $3.97 per MMBTU in the fourth quarter of 2014.

Please see the Guidance Table included in this release for guidance estimates for full-year 2014. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Third Quarter 2014 Conference Call

A conference call and webcast, during which management will discuss third quarter 2014 financial and operational results, is scheduled for Thursday, October 30, 2014 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 3713192), 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 3713192. 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 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 the Eagle Ford Shale in south Texas. 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 oil and gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental obligations, costs and 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; compliance with and 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. All subsequent written and oral forward-looking statements attributable to PVA or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. 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, except as may be required by applicable law.

PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited
(in thousands, except per share data)
           
  Three months ended Three months ended Nine months ended
  September 30, June 30, September 30,
  2014 2013 2014 2014 2013
Revenues          
Crude oil  $ 118,716  $ 100,564  $ 112,090  $ 336,382  $ 250,489
Natural gas liquids (NGLs)  9,790  8,212  8,037  27,200  22,652
Natural gas  13,354  12,872  16,302  47,859  40,465
Total product revenues  141,860  121,648  136,429  411,441  313,606
(Loss) gain on sales of property and equipment, net  63,520  (186)  (51)  120,295  (479)
Other  16  151  2,983  2,886  1,339
Total revenues  205,396  121,613  139,361  534,622  314,466
Operating expenses          
Lease operating  15,296  8,457  12,403  38,103  24,891
Gathering, processing and transportation  4,893  3,039  3,526  11,380  9,598
Production and ad valorem taxes  7,690  6,597  7,510  22,505  19,532
General and administrative (excluding equity-classified share-based compensation) (a)  10,540  11,667  14,014  40,417  34,495
Total direct operating expenses  38,419  29,760  37,453  112,405  88,516
Share-based compensation - equity classified awards (b)  987  1,010  826  2,638  4,781
Exploration  1,986  3,957  3,373  13,995  18,097
Depreciation, depletion and amortization  71,999  62,450  71,437  215,623  178,355
Impairments  6,084  132,224  117,908  123,992  132,224
Total operating expenses  119,475  229,401  230,997  468,653  421,973
           
Operating income (loss)  85,921  (107,788)  (91,636)  65,969  (107,507)
           
Other income (expense)          
Interest expense  (21,953)  (20,218)  (23,229)  (67,716)  (56,505)
Loss on extinguishment of debt  --  --  --  --  (29,157)
Derivatives  66,457  (24,035)  (42,665)  8,130  (23,208)
Other  1,349  35  30  1,380  79
           
Income (loss) before income taxes  131,774  (152,006)  (157,500)  7,763  (216,298)
Income tax (expense) benefit  (42,113)  53,106  56,716  339  75,577
Net income (loss)  89,661  (98,900)  (100,784)  8,102  (140,721)
Preferred stock dividends  (7,641)  (1,725)  (1,718)  (11,081)  (5,175)
Induced conversion of preferred stock  (888)  --  (3,368)  (4,256)  --
           
Net income (loss) attributable to common shareholders  $ 81,132  $ (100,625)  $ (105,870)  $ (7,235)  $ (145,896)
           
Net income (loss) per share:          
Basic  $ 1.13  $ (1.54)  $ (1.59)  $ (0.11)  $ (2.38)
Diluted  $ 0.87  $ (1.54)  $ (1.59)  $ (0.11)  $ (2.38)
           
Weighted average shares outstanding, basic  71,536  65,465  66,514  67,909  61,272
Weighted average shares outstanding, diluted  103,606  65,465  66,514  67,909  61,272
 
           
  Three months ended Three months ended Nine months ended
  September 30, June 30, September 30,
  2014 2013 2014 2014 2013
Production          
Crude oil (MBbls)  1,247  954  1,119  3,442  2,411
NGLs (MBbls)  308  254  261  796  748
Natural gas (MMcf)  3,201  3,591  3,618  10,412  10,933
Total crude oil, NGL and natural gas production (MBOE)  2,089  1,807  1,983  5,973  4,982
           
Prices          
Crude oil ($ per Bbl)  $ 95.19  $ 105.37  $ 100.16  $ 97.72  $ 103.87
NGLs ($ per Bbl)  $ 31.76  $ 32.34  $ 30.85  $ 34.18  $ 30.27
Natural gas ($ per Mcf)  $ 4.17  $ 3.58  $ 4.51  $ 4.60  $ 3.70
           
Prices - Adjusted for derivative settlements          
Crude oil ($ per Bbl)  $ 89.08  $ 100.50  $ 94.72  $ 93.08  $ 104.13
NGLs ($ per Bbl)  $ 31.76  $ 32.34  $ 30.85  $ 34.18  $ 30.27
Natural gas ($ per Mcf)  $ 4.19  $ 3.71  $ 4.20  $ 4.42  $ 3.79
           
(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, $1.1 million, $6.6 million and $1.5 million attributable to these awards is included in the three and nine months ended September 30, 2014 and 2013, respectively.
(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
        September 30, December 31,
        2014 2013
Assets          
Current assets        $ 339,044  $ 233,696
Net property and equipment        2,342,903  2,237,304
Other assets        40,432  36,087
Total assets        $ 2,722,379  $ 2,507,087
           
Liabilities and shareholders' equity          
Current liabilities        $ 277,638  $ 258,145
Revolving credit facility        --  206,000
Senior notes due 2019        300,000  300,000
Senior notes due 2020        775,000  775,000
Other liabilities and deferred income taxes        271,074  179,138
Total shareholders' equity        1,098,667  788,804
Total liabilities and shareholders' equity        $ 2,722,379  $ 2,507,087
           
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
           
  Three months ended Three months ended Nine months ended
  September 30, June 30, September 30,
  2014 2013 2014 2014 2013
Cash flows from operating activities          
Net income (loss)  $ 89,661  $ (98,900)  $ (100,784)  $ 8,102  $ (140,721)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Loss on extinguishment of debt  --  --  --  --  29,157
Depreciation, depletion and amortization  71,999  62,450  71,437  215,623  178,355
Impairments  6,084  132,224  117,908  123,992  132,224
Accretion of firm transportation obligation  407  407  230  991  1,263
Derivative contracts:          
Net losses (gains)  (66,457)  24,035  42,665  (8,130)  23,208
Cash settlements, net  (7,557)  (4,165)  (7,222)  (17,836)  1,625
Deferred income tax expense (benefit)  42,113  (53,106)  (56,516)  (339)  (75,577)
(Gain) loss on sales of assets, net  (63,520)  186  51  (120,295)  479
Non-cash exploration expense  1,808  3,759  3,285  8,387  14,167
Non-cash interest expense  1,063  961  1,039  3,114  2,846
Share-based compensation (equity-classified)  987  1,010  826  2,638  4,781
Other, net  44  116  75  325  198
Changes in operating assets and liabilities  24,625  26,106  (40,361)  (16,122)  52,829
Net cash provided by operating activities  101,257  95,083  32,633  200,450  224,834
Cash flows from investing activities          
Acquisition, net  --  --  --  --  (358,239)
Receipts (payments) to settle obligations assumed in acquisition, net  33,712  (6,713)  --  33,712  (43,023)
Capital expenditures - property and equipment  (194,451)  (127,645)  (190,776)  (545,031)  (356,964)
Proceeds from sales of assets, net  215,281  (214)  668  311,913  653
Net cash used in investing activities  54,542  (134,572)  (190,108)  (199,406)  (757,573)
Cash flows from financing activities          
Proceeds from the issuance of preferred stock, net  (316)  --  313,646  313,330  --
Payments made to induce conversion of preferred stock  (888)  --  (3,368)  (4,256)  --
Proceeds from the issuance of senior notes  --  --  --  --  775,000
Retirement of senior notes  --  --  --  --  (319,090)
Proceeds from revolving credit facility borrowings  75,000  66,000  217,000  377,000  219,000
Repayment of revolving credit facility borrowings  (130,000)  (5,000)  (352,000)  (583,000)  (91,000)
Debt issuance costs paid  --  (501)  (151)  (151)  (25,199)
Dividends paid on preferred and common stock  (1,329)  (1,725)  (2,111)  (5,165)  (5,137)
Other, net  329  (54)  --  1,414  (164)
Net cash provided by (used in) financing activities  (57,204)  58,720  173,016  99,172  553,410
Net increase (decrease) in cash and cash equivalents  98,595  19,231  15,541  100,216  20,671
Cash and cash equivalents - beginning of period  25,095  19,090  9,554  23,474  17,650
Cash and cash equivalents - end of period  $ 123,690  $ 38,321  $ 25,095  $ 123,690  $ 38,321
           
Supplemental disclosures of cash paid for:          
Interest  $ 744  $ 1,036  $ 46,009  $ 47,778  $ 24,251
Income taxes (net of refunds received)  $ --   $ --   $ 100  $ 100  $ -- 
 
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
           
           
  Three months ended Three months ended Nine months ended
  September 30, June 30, September 30,
  2014 2013 2014 2014 2013
Reconciliation of GAAP "Net income (loss) " to Non-GAAP "Net income (loss) applicable to common shareholders, as adjusted"          
Net income (loss)  $ 89,661  $ (98,900)  $ (100,784)  $ 8,102  $ (140,721)
Adjustments for derivatives:          
Net losses (gains)  (66,457)  24,035  42,665  (8,130)  23,208
Cash settlements, net  (7,557)  (4,165)  (7,222)  (17,836)  1,625
Adjustment for acquisition transaction expenses  --   --   --   --   2,396
Adjustment for impairments  6,084  132,224  117,908  123,992  132,224
Adjustment for restructuring costs  18  --   (3)  27  -- 
Adjustment for (gain) loss on sale of assets, net  (63,520)  186  51  (120,295)  479
Adjustment for loss on extinguishment of debt  --   --   --   --   29,157
Impact of adjustments on income taxes  42,004  (53,202)  (55,239)  (971)  (66,070)
Preferred stock dividends  (7,641)  (1,725)  (1,718)  (11,081)  (5,175)
Net income (loss) applicable to common shareholders, as adjusted (a)  $ (7,408)  $ (1,547)  $ (4,342)  $ (26,192)  $ (22,877)
           
Net income (loss) applicable to common shareholders, as adjusted, per share, diluted  $ (0.10)  $ (0.02)  $ (0.07)  $ (0.39)  $ (0.37)
           
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX"          
Net income (loss)  $ 89,661  $ (98,900)  $ (100,784)  $ 8,102  $ (140,721)
Income tax expense (benefit)  42,113  (53,106)  (56,716)  (339)  (75,577)
Interest expense  21,953  20,218  23,229  67,716  56,505
Depreciation, depletion and amortization  71,999  62,450  71,437  215,623  178,355
Exploration  1,986  3,957  3,373  13,995  18,097
Share-based compensation expense (equity-classified awards)  987  1,010  826  2,638  4,781
EBITDAX  228,699  (64,371)  (58,635)  307,735  41,440
Adjustments for derivatives:          
Net losses (gains)  (66,457)  24,035  42,665  (8,130)  23,208
Cash settlements, net  (7,557)  (4,165)  (7,222)  (17,836)  1,625
Adjustment for acquisition transaction expenses  --   2,396  --   --   2,396
Adjustment for impairments  6,084  132,224  117,908  123,992  132,224
Adjustment for (gain) loss on sale of assets, net  (63,520)  186  51  (120,295)  479
Adjustment for other non-cash items  407  647  230  991  854
Adjustment for loss on extinguishment of debt  --   --   --   --   29,157
Adjusted EBITDAX (b)  97,656  90,952  94,997  286,457  231,383
Pro forma EBITDAX from our 2013 Eagle Ford Shale acquisition  --   3,607  --   --   26,256
Pro forma Adjusted EBITDAX  $ 97,656  $ 94,559  $ 94,997  $ 286,457  $ 257,639
           
(a) Net income (loss) applicable to common shareholders, as adjusted, represents net income (loss), less preferred stock dividends, adjusted to exclude the effects, net of income taxes, 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 and loss on extinguishment of debt. 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) applicable to common shareholders, 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 applicable to common shareholders.

(b) Adjusted EBITDAX represents net income (loss) before income tax 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 income (loss). Pro forma Adjusted EBITDAX further adjusts Adjusted EBITDAX to include the pro forma EBITDAX from our Eagle Ford Shale acquisition in April 2013 and 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 2014. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes.
                     
  First Second Third Year-to-            
  Quarter Quarter Quarter Date Fourth Quarter Full-Year
  2014 2014 2014 2014 2014 Guidance 2014 Guidance
Production:                    
Crude oil (MBbls) 1,076 1,119 1,247 3,442 1,458  --  1,558 4,900  --  5,000
NGLs (MBbls)  227 261 308 796 384  --  424 1,180  --  1,220
Natural gas (MMcf)  3,593 3,618 3,201 10,412 3,238  --  3,658 13,650  --  14,070
Equivalent production (MBOE) 1,902 1,983 2,089 5,973 2,382  --  2,592 8,355  --  8,565
Equivalent daily production (BOEPD) 21,133 21,786 22,706 21,881 25,888  --  28,170 22,891  --  23,466
Percent crude oil and NGLs 68.5% 69.6% 74.5% 70.9% 76.5%  --  77.3% 71.9%  --  73.5%
                     
Production revenues (a):                    
Crude oil   $ 105.6 112.1 118.7 336.4 116.0  --  140.0 452.4  --  476.4
NGLs   $ 9.4 8.0 9.8 27.2 11.0  --  16.0 38.2  --  43.2
Natural gas  $ 18.2 16.3 13.4 47.9 12.0  --  18.0 59.9  --  65.9
Total product revenues  $ 133.2 136.4 141.9 411.4 139.0  --  174.0 550.5  --  585.5
Total product revenues ($ per BOE)  $ 70.01 68.81 67.91 68.88 58.37  --  67.15 65.88  --  68.35
Percent crude oil and NGLs 86.3% 88.1% 90.6% 88.4% 89.7%  --  91.4% 86.4%  --  91.5%
                     
Operating expenses:                    
Lease operating ($ per BOE)  $ 5.47 6.26 7.32 6.38 5.03  --  5.93 6.00  --  6.25
Gathering, processing and transportation costs ($ per BOE)  $ 1.56 1.78 2.34 1.91 1.61  --  1.79 1.82  --  1.87
Production and ad valorem taxes (percent of oil and gas revenues) 5.5% 5.5% 5.4% 5.5% 6.0%  --  6.6% 5.6%  --  5.8%
                     
General and administrative:                    
Recurring general and administrative  $ 9.7 11.8 10.6 32.1 9.8  --  11.3 41.9  --  43.4
Non-recurring general and administrative  $ 0.2 1.1 0.3 1.7 0.0  --  0.0 1.7  --  1.7
Share-based compensation  $ 6.8 1.9 0.6 9.3 3.0  --  6.0 12.3  --  15.3
Total reported G&A  $ 16.7 14.8 11.5 43.1 12.8  --  17.3 55.8  --  60.3
                     
Exploration:                    
Total reported exploration  $ 8.6 3.4 2.0 14.0 6.0  --  9.0 20.0  --  23.0
Unproved property amortization  $ 3.3 3.4 1.8 8.5 1.5  --  2.0 10.0  --  10.5
                     
Depreciation, depletion and amortization ($ per BOE)  $ 37.95 36.03 34.47 36.10 34.00  --  35.00 35.50  --  35.77
                     
Adjusted EBITDAX (b)  $ 93.8 95.0 97.7 286.5 100.0  --  140.0 386.5  --  426.5
                     
Capital expenditures:                    
Drilling and completion  $ 135.5 154.0 148.7 438.2 185.0  --  205.0 623.2  --  643.2
Lease acquisitions  $ 36.1 12.8 51.0 99.9 8.0  --  25.0 107.9  --  124.9
Seismic (c)  $ 4.5 0.1 0.2 4.8 2.0  --  7.0 6.8  --  11.8
Pipeline, gathering, facilities and other  $ 6.3 2.6 5.0 13.9 2.0  --  6.0 15.9  --  19.9
Total capital expenditures  $ 182.4 169.5 204.9 556.8 197.0  --  243.0 753.7  --  799.8
                     
End of period debt outstanding  $ 1,265.0 1,130.0 1,075.0 1,075.0 1,075.0  --  1,075.0 1,075.0  --  1,075.0
Interest expense:                    
Total reported interest expense  $ 22.5 23.2 22.0 67.7 22.0  --  25.0 89.7  --  92.7
Cash interest expense  $ 21.5 22.2 20.9 64.6 21.0  --  23.5 85.6  --  88.1
Preferred stock dividends paid  $ 1.7 2.1 1.4 5.2 6.9  --  6.9 12.2  --  12.2
Effective tax rate  42.6% 36.0% 32.0% 4.4% 35.0%  --  36.0%      
                     
(a) Assumes average benchmark prices of $80.67 per barrel for crude oil and $3.97 per MMBtu for natural gas in the fourth quarter of 2014, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments. NGL realized pricing is assumed to be $35.00 per barrel in the fourth quarter of 2014.

(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)
Fourth quarter 2014 Swaps 5,000 4.50  
First quarter 2015 Swaps 5,000 4.50  
         
Crude oil:   (barrels) ($ / barrel)
Fourth quarter 2014 Collars  2,000 90.00 94.33
First quarter 2015 Collars (a) 4,000 87.50 94.66
Second quarter 2015 Collars (a) 4,000 87.50 94.66
Third quarter 2015 Collars (a) 3,000 86.67 94.73
Fourth quarter 2015 Collars (a) 3,000 86.67 94.73
Fourth quarter 2014 Swaps (a) 11,000 93.45  
First quarter 2015 Swaps (a) 9,000 91.81  
Second quarter 2015 Swaps (a) 9,000 91.81  
Third quarter 2015 Swaps (a) 8,000 91.06  
Fourth quarter 2015 Swaps (a) 8,000 91.06  
First quarter 2016 Swaps 3,000 90.84  
Second quarter 2016 Swaps 3,000 90.84  
Third quarter 2016 Swaps 3,000 90.84  
Fourth quarter 2016 Swaps 3,000 90.84  
First quarter 2015 Swaption (b) 1,000 88.00  
Second quarter 2015 Swaption (b) 1,000 88.00  
Third quarter 2015 Swaption (b) 1,000 88.00  
Fourth quarter 2015 Swaption (b) 1,000 88.00  
         
(a) All or a portion of these derivatives have include "lower" puts sold at a strike price of $70 per barrel. If the price of WTI oil goes below $70 per barrel, the cash receipts on the derivatives will be limited to the difference between the swap / floor price and $70 per barrel.
(b) This 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 2015 is higher than or equal to $88.00 per barrel on December 31, 2014, the counterparty will exercise its option to enter into a fixed price swap at $88.00 per barrel for calendar year 2015, at which point the contract functions as a fixed price swap. If the forward commodity price for calendar year 2015 is lower than $88.00 per barrel on December 31, 2014, the option expires and no fixed price swap is in effect.
We estimate that, excluding the derivative positions described above, for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the fourth quarter of 2014 would increase or decrease by approximately $12.9 million. In addition, 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 of 2014 would increase or decrease by approximately $2.9 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

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Source: GlobeNewswire (October 29, 2014 - 4:05 PM EDT)

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