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 February 25, 2015 - 4:02 PM EST
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Penn Virginia Corporation Announces Fourth Quarter and Full-Year 2014 Results

RADNOR, Pa., Feb. 25, 2015 (GLOBE NEWSWIRE) -- Penn Virginia Corporation (NYSE:PVA) today reported financial results for the three months and year ended December 31, 2014 and provided details of its 2015 guidance.

Key Highlights

Fourth quarter 2014 results compared, as applicable, to third quarter 2014 results were as follows:

  • As previously disclosed, production during the fourth quarter was 2.0 million barrels of oil equivalent (MMBOE), or 21,308 barrels of oil equivalent (BOE) per day (BOEPD), compared to 20,874 BOEPD, pro forma to exclude production from Mississippi properties sold in July 2014 and volumes associated with a settlement of litigation in the Mid-Continent.
    • During full-year 2014, pro forma total production increased 22% and oil production increased 35% over full-year 2013.
  • Realized oil, natural gas liquids (NGLs) and gas prices declined to $69.82 per barrel, $23.43 per barrel and $3.81 per thousand cubic feet (Mcf) from $95.19 per barrel, $31.76 per barrel and $4.17 per Mcf.
    • Including oil and gas derivatives, oil and gas prices were $77.99 per barrel and $4.03 per Mcf, compared to $89.08 per barrel and $4.19 per Mcf.
  • Product revenues from the sale of oil, NGLs and natural gas were $101.4 million, or $51.73 per barrel of oil equivalent (BOE), compared to $141.9 million, or $67.91 per BOE.
    • Including oil and gas derivatives, product revenues were $111.8 million, or $57.03 per BOE, compared to $134.3 million, or $64.29 per BOE.
  • Production costs, including lease operating expense, gathering, processing and transportation expenses and production and ad valorem taxes, decreased to $22.6 million, or $11.52 per BOE, from $27.8 million, or $13.35 per BOE.
    • Excluding production and ad valorem taxes, which decreased by $2.2 million due to lower commodity prices, other production costs were $8.72 per BOE, compared to $9.66 per BOE.
  • Operating loss, excluding impairments and net gains or losses on the sale of assets, was $14.6 million, compared to operating income of $28.5 million.
  • Adjusted EBITDAX, a non-GAAP (generally accepted accounting principles) measure, was $84.8 million, compared to $97.7 million.
  • Borrowing base under our revolving credit facility increased to $500 million during the fourth quarter, providing financial liquidity, including cash and equivalents, of $470 million at year-end 2014.
  • Leverage ratio was 3.0 times at year-end 2014.

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, "Our fourth quarter product revenues were impacted by lower commodity prices, but our oil and gas hedges, along with lower operating costs, helped to partially offset the lower revenues and enabled us to maintain solid cash margins. As previously disclosed, our fourth quarter production was affected by delays in the timing of certain completions and higher than expected shut-in production due to offset completion activity. With January 2015 production of approximately 25,200 BOEPD, we expect first quarter 2015 production to be 10% to 20% higher than the fourth quarter of 2014. We also expect total year-over-year production growth in 2015 of 10% to 20%, with pro forma production growth of 17% to 29%.

"Our 2015 drilling program will focus on higher reserve and higher rate-of-return drilling opportunities in both the Lower and Upper Eagle Ford. Based on reduced well cost levels, which we are already achieving, we estimate that we will generate pretax returns of 20% or greater even with lower commodity prices."

Mr. Whitehead concluded, "Our balance sheet remains sound with $470 million of financial liquidity at year-end 2014, compared to $240 million at year-end 2013. We will continue to focus on our financial health during this lower price environment and with our strong hedge position, operating cash flows and revolver availability, we believe that we will have the flexibility and adequate liquidity throughout the year to execute upon our investment strategy and remain below covenant limits."

Full-Year 2014 Financial Results

For the year ended December 31, 2014, we had operating income of $55.1 million, excluding impairment charges of $791.8 million and a net gain on the sale of assets of $120.8 million, compared to $40.4 million in 2013, excluding impairment charges $132.2 million. Impairment charges of $791.8 million included commodity-price driven writedowns of our assets in East Texas and Oklahoma, as well as a writedown of our Mississippi properties in conjunction with the sale of those assets. Adjusted loss attributable to common shareholders, excluding the effects of changes in derivatives fair value, acquisition transaction expenses, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, and including preferred stock dividends, was $47.3 million, or $0.68 per diluted share, in 2014 compared to a loss of $30.7 million, or $0.49 per diluted share, in 2013. Total production increased by 16% in 2014, from 6.8 MMBOE to 7.9 MMBOE, while pro forma production increased 22% in 2014 from 6.1 MMBOE to 7.4 MMBOE.

Fourth Quarter 2014 Results

Overview of Results

Operating loss, excluding $667.8 million of impairments of our East Texas and Oklahoma properties and $0.5 million of net gain on the sale of assets, was $14.6 million in the fourth quarter of 2014, compared to operating income of $28.5 million, excluding $63.5 million of net gain on the sale of assets and $6.1 million impairments, in the third quarter of 2014. This decrease was due primarily to a $40.4 million decrease in product revenues and a $12.7 million increase in depletion, depreciation and amortization (DD&A) expense. The effect of these unfavorable changes was partially offset by a $10.9 million decrease in general and administrative (G&A), lease operating, gathering, processing, transportation, and production and ad valorem tax expenses. 

Net loss attributable to common shareholders for the fourth quarter was $423.8 million, or $5.90 per diluted share, compared to net income of $81.1 million, or $0.87 per diluted share, in the prior quarter. Adjusted net loss attributable to common shareholders for the fourth 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 $25.4 million, or $0.35 per diluted share, compared to a loss of $7.4 million, or $0.10 per diluted share, in the prior quarter.

Product Revenues

Total product revenues decreased 28% to $101.4 million, or $51.73 per BOE, in the fourth quarter of 2014, from $141.9 million, or $67.91 per BOE, in the third quarter due primarily to the 24% decrease in the realized oil equivalent price and a 6% decrease in production. For the fourth quarter, the realized oil price decreased by 27%, the realized natural gas price decreased by 9% and the realized NGL price decreased by 26% compared to the third quarter.

Operating Expenses

As discussed below, fourth quarter 2014 total direct operating expenses, excluding share-based compensation and non-recurring expenses, decreased by $8.9 million to $29.6 million, or $15.08 per BOE produced, compared to $38.5 million, or $18.41 per BOE, in the third quarter of 2014.

  • Lease operating expense decreased by $3.4 million to $11.4 million, or $5.82 per BOE, from $14.8 million, or $7.06 per BOE, due to lower workover expenses, water disposal costs and chemical costs.
  • Gathering, processing and transportation expense increased by $0.3 million to $5.7 million, or $2.90 per BOE, from $5.4 million, or $2.60 per BOE, due to higher gas volumes in the Eagle Ford.
  • Production and ad valorem taxes decreased by $2.2 million to $5.5 million, or 5.4% of product revenues, from $7.7 million, or 5.4% of product revenues, due to the decreases in commodity prices and reductions in ad valorem tax liabilities.
  • G&A expense, excluding share-based compensation and non-recurring expenses, decreased by $3.6 million to $7.0 million, or $3.56 per BOE, from $10.6 million, or $5.06 per BOE in the third quarter. The decrease in recurring G&A expense was due primarily to lower incentive compensation expense.

DD&A expense increased by $12.7 million to $84.7 million, or $43.18 per BOE, in the fourth quarter, from $72.0 million, or $34.47 per BOE, in the third quarter, due to a higher depletion rate for Eagle Ford produced volumes.

In the fourth quarter, we incurred a $667.8 million impairment charge primarily associated with our East Texas and Mid-Continent assets due primarily to the substantial declines in commodity prices.

Capital Expenditures

During the fourth quarter of 2014, capital expenditures were $237 million, an increase of $32 million, or 16%, compared to $205 million in the third quarter of 2014, consisting of:

  • $229 million for drilling and completion activities, compared to $149 million.
  • $8 million for pipeline, gathering, facilities, seismic, leasehold acquisition and other capital expenditures, compared to $56 million.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of December 31, 2014, we had total debt of $1,110 million, consisting of $300 million principal amount of 7.25% senior unsecured notes due 2019, $775 million principal amount of 8.50% senior unsecured notes due 2020 and $35 million drawn under our revolving credit facility (Revolver). As previously announced, in October 2014, the borrowing base under our Revolver was increased from $438 million to $500 million. Together with cash and equivalents of $6 million and net of letters of credit of $2 million, our financial liquidity was $470 million at December 31, 2014. Our leverage ratio under the Revolver at December 31, 2014 was 3.0 times trailing twelve months' Adjusted EBITDAX of $371 million.

During the fourth quarter, interest expense was $21.1 million, of which $20.0 million was cash interest expense, compared to $22.0 million in the third quarter, of which $20.9 million was cash interest expense. In addition, during the fourth quarter, we paid $7.6 million in preferred stock dividends, compared to $1.3 million in the third quarter.

During the fourth quarter, derivatives income was $154.1 million, compared to derivatives income of $66.5 million in the third quarter. Fourth quarter 2014 cash settlements of derivatives resulted in net cash receipts of $10.4 million, compared to $7.6 million of net cash outlays in the third quarter.

Pricing

Our fourth quarter 2014 realized oil price was $69.82 per barrel, compared to $95.19 per barrel in the third quarter of 2014. Our fourth quarter 2014 realized NGL price was $23.43 per barrel, compared to $31.76. Our fourth quarter 2014 realized natural gas price was $3.81 per Mcf, compared to $4.17 per Mcf. Adjusting for oil and gas hedges, our fourth quarter 2014 effective oil price was $77.99 per barrel and our fourth quarter 2014 effective natural gas price was $4.03 per Mcf, or an increase of $8.17 per barrel from and $0.22 per Mcf from the realized prices.

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. Currently, we have hedged 11,992 barrels of daily crude oil production during 2015, or about 80% to 90% of our expected oil production, at a weighted average floor/swap price of $90.20 per barrel. We have also sold puts for 5,496 barrels of daily crude oil production during 2015 at a strike price of $70.00 per barrel. For 2016, we have hedged 4,000 barrels of daily crude oil production at a weighted average floor/swap price of $88.12 per barrel.

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.

Full-Year 2015 Guidance

Full-year 2015 guidance highlights are as follows:

  • Production is expected to be 8.7 to 9.6 MMBOE, or 23,800 to 26,200 BOEPD, an increase of 10% to 20% over 2014 production and 17% to 29% over pro forma 2014 production.
    • 2015 crude oil production guidance is 5.0 to 5.5 million barrels, or 13,800 to 15,100 barrels of oil per day, an increase of 10% to 18% over 2014 and an increase of 6% to 15% over the fourth quarter of 2014.
    • Production in the first quarter of 2015 is expected to range between 23,500 and 25,500 BOEPD, an increase of 10% to 20% over the fourth quarter of 2014.
  • Product revenues, excluding the impact of any hedges, are expected to be $312 to $343 million.
    • Our crude oil revenue estimate assumes realized pricing of West Texas Intermediate (WTI) crude oil benchmark pricing of $56.75 per barrel (ranging from $49 per barrel in the first quarter to $64 per barrel in the fourth quarter of 2015), with realized pricing of $3 to $4 per barrel less. Benchmark (Henry Hub) natural gas pricing is assumed to be $2.84 per Mcf (ranging from $2.95 per Mcf in the first quarter to $2.80 per Mcf for the final three quarters of 2015), with an approximate $0.06 per Mcf differential, while NGL pricing is assumed to be 25% of the WTI price.
    • Cash receipts from the settlement of derivatives are expected to be $120 million based on the foregoing assumptions, or $13 per BOE.
  • Adjusted EBITDAX, a non-GAAP measure, is expected to be $300 to $340 million. 
    • Net cash provided by operating activities, including expected working capital changes, is expected to be $155 to $195 million.
    • Net of capital expenditures and dividends on preferred stock, we anticipate a $150 to $190 million increase in borrowings under the Revolver during 2015, assuming no other sources of capital.
  • Capital expenditures are expected to be $295 to $345 million, a decrease of 57% to 63% from 2014, with 60% to 65% of the expenditures being incurred during the first half of the year. 
    • Drilling and completion capital expenditures, which will be focused on the Upper Eagle Ford, are expected to be $270 to $310 million.
    • Pipeline, gathering, facilities, seismic and other capital expenditures are expected to be $10 to $15 million.
    • Lease acquisition capital expenditures are expected to be $15 to $20 million. 

2015 capital expenditures are expected to breakdown as follows:

   
  Gross/Net Gross/Net Midpoint Percent
  Wells Wells of Capital of Capital
Project Area Spud Completed Expenditures Expenditures
      (millions)  
Drilling and Completions        
Eagle Ford – Upper Eagle Ford 25/15.1 24/15.2 $133.0 42%
Eagle Ford – Peach Creek 14/6.9 23/10.5 $64.0 20%
Eagle Ford – Shiner "Other" 3/2.6 7/5.4 $32.0 10%
Eagle Ford – Shiner "Six Pack" 5/2.6 7/3.1 $28.0 9%
Eagle Ford – Rock Creek 2/1.3 3/1.2 $10.0 3%
Eagle Ford – Contingency(1) --- --- $20.0 6%
Workovers --- --- $3.0 1%
Lease acquisition --- --- $17.5 5%
 Pipeline, production facilities, seismic and other --- --- $12.5 4%
Totals 49/28.5 64/35.5 $320.0 100%
         
(1) Contingency refers to costs related to unforeseen drilling and/or completion difficulties for the 2015 program.

Please see the Guidance Table included in this release for guidance estimates for full-year 2015. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Fourth Quarter and Full-Year 2014 Conference Call

A conference call and webcast, during which management will discuss fourth quarter 2014 financial and operational results, is scheduled for Thursday, February 26, 2015 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 59449147), 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 59449147. 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, natural gas liquids and natural gas; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, natural gas liquids 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 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; physical, electronic and cybersecurity breaches; uncertainties relating to general domestic and international economic and political conditions; and; and other risks set forth in our filings with the 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 Twelve months ended
  December 31, September 30, December 31,
  2014 2013 2014 2014 2013
Revenues          
Crude oil  $ 83,904  $ 96,918  $ 118,716  $ 420,286  $ 347,407
Natural gas liquids (NGLs)  7,352  8,096  9,790  34,552  30,748
Natural gas  10,185  12,073  13,354  58,044  52,538
Total product revenues  101,441  117,087  141,860  512,882  430,693
Gain (loss) on sales of property and equipment, net  474  213  63,520  120,769  (266)
Other  236  (298)  16  3,122  1,041
Total revenues  102,151  117,002  205,396  636,773  431,468
Operating expenses          
Lease operating (a)  11,420  10,570  14,761  48,298  35,461
Gathering, processing and transportation (a)  5,689  3,241  5,428  18,294  12,839
Production and ad valorem taxes  5,485  2,872  7,690  27,990  22,404
General and administrative (excluding equity-classified share-based compensation) (b)  4,961  13,722  10,540  45,378  48,217
Total direct operating expenses  27,555  30,405  38,419  139,960  118,921
Share-based compensation - equity classified awards (c)  989  1,000  987  3,627  5,781
Exploration  3,068  2,897  1,986  17,063  20,994
Depreciation, depletion and amortization  84,676  67,239  71,999  300,299  245,594
Impairments  667,817  --  6,084  791,809  132,224
Total operating expenses  784,105  101,541  119,475  1,252,758  523,514
           
Operating income (loss)  (681,954)  15,461  85,921  (615,985)  (92,046)
           
Other income (expense)          
Interest expense  (21,115)  (22,336)  (21,953)  (88,831)  (78,841)
Loss on extinguishment of debt  --  (17)  --  --  (29,174)
Derivatives  154,082  2,356  66,457  162,212  (20,852)
Other  (46)  68  1,349  1,334  147
           
Income (loss) before income taxes  (549,033)  (4,468)  131,774  (541,270)  (220,766)
Income tax (expense) benefit  131,339  2,119  (42,113)  131,678  77,696
Net income (loss)  (417,694)  (2,349)  89,661  (409,592)  (143,070)
Preferred stock dividends  (6,067)  (1,725)  (7,641)  (17,148)  (6,900)
Induced conversion of preferred stock  --  --  (888)  (4,256)  --
           
Net income (loss) attributable to common shareholders  $ (423,761)  $ (4,074)  $ 81,132  $ (430,996)  $ (149,970)
           
Net income (loss) per share:          
Basic  $ (5.90)  $ (0.06)  $ 1.13  $ (6.26)  $ (2.41)
Diluted  $ (5.90)  $ (0.06)  $ 0.87  $ (6.26)  $ (2.41)
           
Weighted average shares outstanding, basic  71,790  65,490  71,536  68,887  62,335
Weighted average shares outstanding, diluted  71,790  65,490  103,606  68,887  62,335
 
           
  Three months ended Three months ended Twelve months ended
  December 31, September 30, December 31,
  2014 2013 2014 2014 2013
Production          
Crude oil (MBbls)  1,202  1,024  1,247  4,644  3,435
NGLs (MBbls)  314  234  308  1,110  983
Natural gas (MMcf)  2,672  3,502  3,201  13,085  14,435
Total crude oil, NGL and natural gas production (MBOE)  1,961  1,842  2,089  7,934  6,824
           
Prices          
Crude oil ($ per Bbl)  $ 69.82  $ 94.66  $ 95.19  $ 90.50  $ 101.13
NGLs ($ per Bbl)  $ 23.43  $ 34.56  $ 31.76  $ 31.14  $ 31.30
Natural gas ($ per Mcf)  $ 3.81  $ 3.45  $ 4.17  $ 4.44  $ 3.64
           
Prices - Adjusted for derivative settlements          
Crude oil ($ per Bbl)  $ 77.99  $ 91.48  $ 89.08  $ 89.17  $ 100.38
NGLs ($ per Bbl)  $ 23.43  $ 34.56  $ 31.76  $ 31.14  $ 31.30
Natural gas ($ per Mcf)  $ 4.03  $ 3.61  $ 4.19  $ 4.34  $ 3.75
           
(a) Effective with the three months ended December 31, 2014, we have reclassified certain natural gas compression costs from lease operating expense to gathering, processing and transportation expenses. The reclassification only impacts 2014 reporting. The amounts that have been reclassified for the three and nine months ended September 30, 2014 were $0.5 and $1.2 million, respectively.
(b) 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 $(2.1) million and $2.6 million attributable to these awards is included in the three months ended December 31, 2014 and 2013 and a total of $4.5 million and $4.1 million is included in the twelve months ended December, 2014 and 2013.
(c) 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
        December 31, December 31,
        2014 2013
Assets          
Current assets        $ 335,027  $ 233,696
Net property and equipment        1,825,098  2,237,304
Other assets        66,309  36,087
Total assets        $ 2,226,434  $ 2,507,087
           
Liabilities and shareholders' equity          
Current liabilities        $ 312,227  $ 258,145
Revolving credit facility        35,000  206,000
Senior notes due 2019        300,000  300,000
Senior notes due 2020        775,000  775,000
Other liabilities and deferred income taxes        128,390  179,138
Total shareholders' equity        675,817  788,804
Total liabilities and shareholders' equity        $ 2,226,434  $ 2,507,087
           
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
           
  Three months ended Three months ended Twelve months ended
  December 31, September 30, December 31,
  2014 2013 2014 2014 2013
Cash flows from operating activities          
Net income (loss)  $ (417,694)  $ (2,349)  $ 89,661  $ (409,592)  $ (143,070)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:        
Loss on extinguishment of debt  --  17  --  --  29,174
Depreciation, depletion and amortization  84,676  67,239  71,999  300,299  245,594
Impairments  667,817  --  6,084  791,809  132,224
Accretion of firm transportation obligation  310  411  407  1,301  1,674
Derivative contracts:          
Net losses (gains)  (154,082)  (2,356)  (66,457)  (162,212)  20,852
Cash settlements, net  10,412  (2,667)  (7,557)  (7,424)  (1,042)
Deferred income tax expense (benefit)  (134,888)  (2,119)  42,113  (135,227)  (77,696)
(Gain) loss on sales of assets, net  (474)  (213)  (63,520)  (120,769)  266
Non-cash exploration expense  1,959  3,284  1,808  10,346  17,451
Non-cash interest expense  1,083  998  1,063  4,197  3,844
Share-based compensation (equity-classified)  989  1,000  987  3,627  5,781
Other, net  (231)  99  44  94  297
Changes in operating assets and liabilities  22,397  (26,666)  24,625  6,275  26,163
Net cash provided by operating activities  82,274  36,678  101,257  282,724  261,512
Cash flows from investing activities          
Acquisition, net  --  --  --  --  (358,239)
Receipts (payments) to settle obligations assumed in acquisition, net  --  20,568  33,712  33,712  (22,455)
Capital expenditures - property and equipment  (229,108)  (147,239)  (194,451)  (774,139)  (504,203)
Proceeds from sales of assets, net  2,020  (707)  215,281  313,933  (54)
Net cash used in (provided by) investing activities  (227,088)  (127,378)  54,542  (426,494)  (884,951)
Cash flows from financing activities          
Proceeds from the issuance of preferred stock, net  --  --  (316)  313,330  --
Payments made to induce conversion of preferred stock  --  --  (888)  (4,256)  --
Proceeds from the issuance of senior notes  --  --  --  --  775,000
Retirement of senior notes  --  --  --  --  (319,090)
Proceeds from revolving credit facility borrowings  35,000  83,000  75,000  412,000  297,000
Repayment of revolving credit facility borrowings  --  (5,000)  (130,000)  (583,000)  (91,000)
Debt issuance costs paid  --  (435)  --  (151)  (25,634)
Dividends paid on preferred and common stock  (7,638)  (1,725)  (1,329)  (12,803)  (6,862)
Other, net  14  13  329  1,428  (151)
Net cash provided by (used in) financing activities  27,376  75,853  (57,204)  126,548  629,263
Net increase (decrease) in cash and cash equivalents  (117,438)  (14,847)  98,595  (17,222)  5,824
Cash and cash equivalents - beginning of period  123,690  38,321  25,095  23,474  17,650
Cash and cash equivalents - end of period  $ 6,252  $ 23,474  $ 123,690  $ 6,252  $ 23,474
 
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
           
  Three months ended Three months ended Twelve months ended
  December 31, September 30, December 31,
  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)  $ (417,694)  $ (2,349)  $ 89,661  $ (409,592)  $ (143,070)
Adjustments for derivatives:          
Net losses (gains)  (154,082)  (2,356)  (66,457)  (162,212)  20,852
Cash settlements, net  10,412  (2,667)  (7,557)  (7,424)  (1,042)
Adjustment for acquisition transaction expenses  --   191  --   --   2,587
Adjustment for impairments  667,817  --   6,084  791,809  132,224
Adjustment for restructuring costs  (17)  2  18  10  7
Adjustment for (gain) loss on sale of assets, net  (474)  (213)  (63,520)  (120,769)  266
Adjustment for loss on extinguishment of debt  --   17  --   --   29,174
Impact of adjustments on income taxes  (125,268)  2,384  42,004  (121,982)  (64,781)
Preferred stock dividends  (6,067)  (1,725)  (7,641)  (17,148)  (6,900)
Net loss applicable to common shareholders, as adjusted (a)  $ (25,373)  $ (6,716)  $ (7,408)  $ (47,308)  $ (30,683)
           
Net loss applicable to common shareholders, as adjusted, per share, diluted  $ (0.35)  $ (0.10)  $ (0.10)  $ (0.69)  $ (0.49)
           
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX"          
Net income (loss)  $ (417,694)  $ (2,349)  $ 89,661  $ (409,592)  $ (143,070)
Income tax benefit  (131,339)  (2,119)  42,113  (131,678)  (77,696)
Interest expense  21,115  22,336  21,953  88,831  78,841
Depreciation, depletion and amortization  84,676  67,239  71,999  300,299  245,594
Exploration  3,068  2,897  1,986  17,063  20,994
Share-based compensation expense (equity-classified awards)  989  1,000  987  3,627  5,781
EBITDAX  (439,185)  89,004  228,699  (131,450)  130,444
Adjustments for derivatives:          
Net losses (gains)  (154,082)  (2,356)  (66,457)  (162,212)  20,852
Cash settlements, net  10,412  (2,667)  (7,557)  (7,424)  (1,042)
Adjustment for acquisition transaction expenses  --   191  --   --   2,587
Adjustment for impairments  667,817  --   6,084  791,809  132,224
Adjustment for (gain) loss on sale of assets, net  (474)  (213)  (63,520)  (120,769)  266
Adjustment for other non-cash items  310  411  407  1,301  1,674
Adjustment for loss on extinguishment of debt  --   17  --   --   29,174
Adjusted EBITDAX (b)  84,798  84,387  97,656  371,255  316,179
Pro forma EBITDAX from our 2013 Eagle Ford Shale acquisition  --   --   --   --   26,256
Pro forma Adjusted EBITDAX  $ 84,798  $ 84,387  $ 97,656  $ 371,255  $ 342,435
           
(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 2015. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes.
                 
  First Second Third Fourth        
  Quarter Quarter Quarter Quarter Full-Year Full-Year
  2014 2014 2014 2014 2014 2015 Guidance
Production:                
Crude oil (MBbls) 1,076 1,119 1,247 1,202 4,644 5,050  --  5,500
NGLs (MBbls) 227 261 308 314 1,110 1,700  --  1,850
Natural gas (MMcf) 3,593 3,618 3,201 2,672 13,085 11,621  --  13,277
Equivalent production (MBOE) 1,902 1,983 2,089 1,961 7,934 8,687  --  9,563
Equivalent daily production (BOEPD) 21,133 21,786 22,706 21,314 21,738 23,800  --  26,200
                 
Production revenues (a):                
Crude oil  $ 105.6 112.1 118.7 83.9 420.3 255.0  --  280.0
NGLs  $ 9.4 8.0 9.8 7.4 34.6 23.5  --  26.0
Natural gas  $ 18.2 16.3 13.4 10.2 58.0 33.0  --  36.5
Total product revenues  $ 133.2 136.4 141.9 101.4 512.9 311.5  --  342.5
                 
Operating expenses:                
Lease operating  $ 10.1 12.0 14.8 11.4 48.3 44.0  --  46.0
Lease operating ($ per BOE)  $ 5.3 6.06 7.07 5.82 6.09 4.60  --  5.30
Gathering, processing and transportation costs  $ 3.2 3.9 5.4 5.7 18.3 37.5  --  40.0
Gathering, processing and transportation costs ($ per BOE)  $ 1.7 1.98 2.60 2.90 2.31 3.92  --  4.60
Production and ad valorem taxes  $ 7.3 7.5 7.7 5.5 28.0 20.0  --  21.5
Production and ad valorem taxes (percent of oil and gas revenues) 5.5% 5.5% 5.4% 5.4% 5.5% 5.8%  --  6.9%
                 
General and administrative:                
Recurring general and administrative  $ 9.7 11.8 10.6 7.0 39.1 41.5  --  43.5
Non-recurring general and administrative  $ 0.2 1.1 0.3 0.0 1.8      
Share-based compensation  $ 6.8 1.9 0.6 (1.1) 8.1 3.0  --  4.0
Total reported G&A  $ 16.7 14.8 11.5 6.0 49.0 44.5  --  47.5
                 
Exploration:                
Total reported exploration  $ 8.6 3.4 2.0 3.1 17.1 10.0  --  11.0
Unproved property amortization  $ 3.3 3.3 1.8 1.9 10.3 5.0  --  5.5
                 
Depreciation, depletion and amortization  $ 72.2 71.4 72.0 84.7 300.3 335.0  --  345.0
Depreciation, depletion and amortization ($ per BOE)  $ 38.0 36.03 34.47 43.18 37.85 35.03  --  39.72
                 
Adjusted EBITDAX (b)  $ 93.8 95.0 97.7 84.8 371.3 300.0  --  340.0
                 
Capital expenditures:                
Drilling and completion  $ 135.5 154.0 148.7 229.2 667.4 270.0  --  310.0
Lease acquisitions  $ 36.1 12.8 51.0 (1.5) 98.4 15.0  --  20.0
Seismic (c)  $ 4.5 0.1 0.2 0.3 5.1 1.0  --  2.0
Pipeline, gathering, facilities and other  $ 6.3 2.6 5.0 9.1 23.0 9.0  --  13.0
Total capital expenditures  $ 182.4 169.5 204.9 237.1 793.9 295.0  --  345.0
                 
End of period debt outstanding  $ 1,265.0 1,130.0 1,075.0 1,110.0 1,110.0 1,260.0  --  1,300.0
Interest expense:                
Total reported interest expense  $ 22.5 23.2 22.0 21.1 88.8 97.0  --  100.0
Cash interest expense  $ 21.5 22.2 20.9 20.0 84.6 93.0  --  95.0
Preferred stock dividends paid  $ 1.7 2.1 1.4 7.6 12.8 24.0  --  24.5
Effective tax rate 42.6% 36.0% 32.0% 23.9% 24.3%      
                 
(a) Assumes average benchmark prices of $56.79 per barrel for crude oil and $2.84 per MMBtu for natural gas in 2015, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments. NGL realized pricing is assumed to be $13.94 per barrel in 2015.
                 
(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 / Option Ceiling
         
Natural gas:   (MMBtu) ($ / MMBtu)
First quarter 2015 Swaps 5,000 4.50  
         
Crude oil:   (barrels) ($ / barrel)
Bitmap Bitmap Bitmap Bitmap First quarter 2015 Collars 4,000 87.50 94.66
Second quarter 2015 Collars 4,000 87.50 94.66
Third quarter 2015 Collars 3,000 86.67 94.73
Fourth quarter 2015 Collars 3,000 86.67 94.73
First quarter 2015 Swaps 9,000 91.81  
Second quarter 2015 Swaps 9,000 91.81  
Third quarter 2015 Swaps  8,000 91.06  
Fourth quarter 2015 Swaps 8,000 91.06  
First quarter 2016 Swaps 4,000 88.12  
Second quarter 2016 Swaps 4,000 88.12  
Third quarter 2016 Swaps 4,000 88.12  
Fourth quarter 2016 Swaps 4,000 88.12  
First quarter 2015 Sold Puts (a) 6,000 70.00  
Second quarter 2015 Sold Puts (a) 6,000 70.00  
Third quarter 2015 Sold Puts (a) 5,000 70.00  
Fourth quarter 2015 Sold Puts (a) 5,000 70.00  
         
(a) These "lower" puts were sold at a strike price of $70 per barrel. If the price of WTI oil goes below $70 per barrel, the cash receipts on other corresponding 2015 derivatives will be limited to the difference between the swap / floor price and $70 per barrel.
         
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 2015 would increase or decrease by approximately $46.3 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 2015 would increase or decrease by approximately $9.9 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 (February 25, 2015 - 4:02 PM EST)

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