Penn Virginia Corporation Announces Fourth Quarter and Full-Year 2012 Results; Provides Initial 2013
Penn Virginia Corporation Announces Fourth Quarter and Full-Year 2012 Results; Provides Initial 2013 Guidance
Oil / NGLs Represented 56 Percent of Production and 83 Percent of Product Revenues in the Fourth Quarter
Oil / NGLs Expected to Be over 60 Percent of 2013 Production and over 85 Percent of Product Revenues
2013 Oil Production Growth Expected to Be 23 to 37 Percent
Hedges Cover over 55 Percent of Projected 2013 Oil Production and over 53 Percent of Projected 2013 Gas Production
Year-End 2012 Financial Liquidity of Approximately $316 Million, with a Leverage Ratio of 2.3 Times Adjusted EBITDAX
2012 Adjusted EBITDAX of $248 Million and Fourth Quarter Adjusted EBITDAX of $62 Million
Fourth Quarter 2012 Highlights
Fourth quarter 2012 results, as compared to third quarter 2012 results where applicable, were as follows:
- As previously reported, production in the fourth quarter of 2012 was 1.4 million barrels of oil equivalent (MMBOE), or 15,444 barrels of oil equivalent (BOE) per day (BOEPD), compared to 1.4 MMBOE, or 15,245 BOEPD, pro forma to exclude production from assets sold
- Product revenues from the sale of crude oil, natural gas liquids (NGLs) and natural gas were $76.0 million, or $53.48 per BOE, increases of one percent and six percent compared to $75.6 million, or $50.25 per BOE
- Oil and NGL revenues were $63.2 million, or 83 percent of product revenues, a decrease of one percent compared to $63.7 million, or 84 percent of product revenues
- Operating margin, a non-GAAP (generally accepted accounting principles) measure, was $39.29 per BOE, an increase of 15 percent compared to $34.11 per BOE
- Operating loss was $6.0 million, compared to a loss of $6.5 million, excluding impairments and loss on firm transportation commitment
- Adjusted EBITDAX, a non-GAAP measure, was $62.3 million, an increase of two percent compared to $61.2 million
- Loss attributable to common shareholders (which includes our preferred stock dividend) was $56.1 million, or $1.05 per diluted share, compared to a loss of $32.6 million, or $0.71 per diluted share
- 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, of $11.8 million, or $0.22 per diluted share, compared to a loss of $7.3 million, or $0.16 per diluted share
A recently completed Eagle Ford Shale (0.9 net) well, the Technik #1H in Lavaca County with 18 frac stages, tested at an initial rate of 1,136 barrels of oil and 1,853 thousand cubic feet (Mcf) per day on a 25/64th inch choke, with flowing casing pressure of approximately 2,350 psi.
Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release.
H. Baird Whitehead, President and Chief Executive Officer stated, "In the fourth quarter, our operating cash flows remained strong and our margins continued to improve as a result of increased oil production, attractive oil prices and lower operating expenses. We expect oil production to increase further in 2013 and comprise over 85 percent of product revenues and over 60 percent of production.
"We also strengthened our balance sheet in 2012. At year-end 2012, we had over $300 million of financial liquidity and a leverage ratio of approximately 2.3 times Adjusted EBITDAX, so that we expect to be able to fund our 2013 capital program from operating cash flows and borrowings under our revolver. Moreover, we are considering the sale of a portion of our working interest in our Lavaca County Eagle Ford Shale acreage, which would further improve liquidity and reduce the outspend of cash flows."
Mr. Whitehead concluded, "Our steadily improving results have been driven primarily by our oily Eagle Ford Shale play where we significantly increased our acreage and drilling inventory during 2012. Building on this success, we plan to commit approximately 88 percent of estimated 2013 capital expenditures to the Eagle Ford Shale, drilling approximately 38 (28.8 net) wells and focusing on expanding our Eagle Ford Shale position."
Full-Year 2012 Financial Results
For the year ended December 31, 2012, we incurred an operating loss of $147.1 million, which included impairment charges and loss on firm transportation obligations of $121.8 million, compared to a loss in 2011 of $155.4 million, which included impairment charges of $104.7 million. Adjusted loss attributable to common shareholders, excluding the effects of changes in derivatives fair value, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, and including the preferred stock dividend of $1.7 million, was $36.6 million, or $0.76 per diluted share, in 2012 compared to a loss of $47.7 million, or $1.04 per diluted share, in 2011. Loss attributable to common shareholders (which includes our preferred stock dividend) was $106.3 million, or $2.22 per diluted share, in 2012 compared to a loss of $132.9 million, or $2.90 per diluted share, in 2011. The decrease was due primarily to the $8.3 million decrease in operating loss, a $22.3 million decrease in the loss on the extinguishment of debt and a $20.5 million increase in derivatives income.
Fourth Quarter 2012 Results
Overview of Financial Results
The $81.1 million operating loss in the fourth quarter of 2012 was $56.6 million higher than the $24.5 million loss in the third quarter of 2012 due primarily to a $74.5 million increase in impairment expense associated with our Marcellus Shale assets and a $5.1 million increase in depreciation, depletion and amortization (DD&A) expenses. The effect of these items was partially offset by a $4.1 million decrease in total direct operating expenses, a $17.3 million decrease in loss on firm transportation obligations and a $1.8 million decrease in exploration expenses. Oil and NGL revenues were $63.2 million in the fourth quarter of 2012, a slight decrease compared to $63.7 million in the third quarter of 2012 due primarily to slightly lower prices. Oil and NGL revenues were 83 percent of product revenues in the fourth quarter of 2012, compared to 84 percent in the third quarter of 2012.
Our fourth quarter 2012 realized oil price was $99.30 per barrel, compared to $99.45 per barrel in the third quarter of 2012. Our fourth quarter 2012 realized NGL price was $32.40 per barrel, compared to $32.94 per barrel in the third quarter of 2012. Our fourth quarter 2012 realized natural gas price was $3.41 per Mcf, compared to $2.72 per Mcf in the third quarter of 2012. Adjusting for oil and gas hedges, our fourth quarter 2012 effective oil price was $106.33 per barrel and our effective natural gas price was $3.83 per Mcf, or increases of $7.03 per barrel and $0.42 per Mcf over the realized prices.
Production in the fourth quarter of 2012 and full-year 2012 exceeded the upper end of our guidance. On a pro forma basis to exclude production from assets sold in 2011 and 2012, production in the fourth quarter of 2012 was 1.4 MMBOE, or 15,444 BOEPD, compared to 1.4 MMBOE, or 15,245 BOEPD, in the third quarter of 2012. As a percentage of total equivalent production, oil and NGL volumes were 56 percent in the fourth quarter of 2012, compared to 52 percent in the third quarter of 2012.
As discussed below, fourth quarter 2012 total direct operating expenses decreased $4.1 million, or approximately 17 percent, to $20.2 million, or $14.19 per BOE produced, compared to $24.3 million, or $16.14 per BOE produced, in the third quarter of 2012.
- Lease operating expenses increased by $0.4 million to $6.6 million, or $4.68 per BOE produced, from $6.2 million, or $4.13 per BOE produced, in the third quarter due primarily to higher subsurface workover expenses in East Texas.
- Gathering, processing and transportation expenses decreased by $0.6 million to $2.5 million, or $1.78 per BOE produced, from $3.1 million, or $2.08 per BOE produced, in the third quarter due primarily to the divestiture of Appalachian assets in July 2012.
- Production and ad valorem taxes decreased by 41 percent to $2.7 million, or 3.6 percent of product revenues, from $4.6 million, or 6.1 percent of product revenues, in the third quarter due primarily to the divestiture of Appalachian assets in July 2012.
- General and administrative (G&A) expenses, excluding share-based compensation, decreased by $2.1 million, or 20 percent, to $8.3 million, or $5.82 per BOE produced, from $10.4 million, or $6.88 per BOE produced, in the third quarter due primarily to a $1.4 million decrease in restructuring costs as a result of higher costs in the third quarter related to the sale of our Appalachian assets and the closing of our Pittsburgh office.
Exploration expenses decreased by $1.9 million, or 20 percent, to approximately $7.4 million in the fourth quarter of 2012 from approximately $9.3 million in the third quarter due primarily to the divestiture of Appalachian assets in July 2012.
DD&A expenses increased by $5.1 million, or 10 percent, to $54.4 million, or $38.32 per BOE produced, in the fourth quarter of 2012 from $49.3 million, or $32.80 per BOE produced, in the third quarter due primarily to the continued transition towards higher cost oil versus gas wells, as well as the impact of negative natural gas reserve revisions.
Impairment expense increased to $75.2 million in the fourth quarter of 2012 from $0.7 million in the third quarter due to the write-down of our Marcellus Shale assets, primarily as a result of lower year-end gas prices and the resultant reduction in proved reserves.
During the fourth quarter of 2012, oil and gas capital expenditures were approximately $118 million, compared to $85 million in the third quarter, consisting of:
- $100 million for drilling and completion activities
- $5 million for seismic, pipeline, gathering and facilities
- $13 million for leasehold acquisitions, field projects and other
Capital expenditures during 2012 were approximately $384 million, approximately $34 million higher than the upper end of previous guidance. The increase was attributable to:
- an additional 38 percent working interest in six Lavaca County Eagle Ford Shale wells
- increased costs on recent Eagle Ford Shale wells due to operational issues
- an acceleration into 2012 of certain 2013 drilling and completion expenditures, along with related pipeline expansion costs
- additional Eagle Ford Shale lease acquisition costs
- a vertical core test of the Pearsall Shale
As previously disclosed, we added approximately 18.3 MMBOE of proved reserves during 2012, prior to negative revisions of 28.7 MMBOE due primarily to benchmark natural gas prices in 2012 which were 33 percent lower than in 2011. Reserve replacement cost per BOE, defined as capital expenditures divided by reserve additions, excluding revisions, was approximately $21 per BOE. During 2012, we replaced approximately 280 percent of production, excluding revisions.
2013 guidance assumes that our working interest in a majority of our 2013 Lavaca County Eagle Ford Shale wells averages approximately 94 percent. 2013 guidance highlights are as follows:
- Production is expected to be approximately 5.7 to 6.2 MMBOE (34.0 to 37.0 billion cubic feet of natural gas equivalent), or approximately 15,500 to 16,900 BOEPD, compared to 2012 production of approximately 5.8 MMBOE, or 15,776 BOEPD, pro forma to exclude 0.7 MMBOE of production in 2012 from divested Appalachian assets.
- Crude oil production is expected to increase by 23 to 37 percent over 2012 levels (a 12 to 24 percent increase in crude oil and NGLs combined). Crude oil and NGLs are expected to comprise approximately 60 to 65 percent of total production, compared to 48 percent during 2012.
- Production during January 2013 was approximately 15,600 BOEPD, approximately 42 percent of which was crude oil and approximately 16 percent of which was NGLs.
- Product revenues are expected to be approximately $330 to $364 million, compared to 2012 product revenues of $310 million, excluding the impact of any hedges.
- Crude oil and NGL product revenues are expected to be approximately 87 percent of total product revenues, compared to 84 percent during 2012.
- Approximately 58 percent of the midpoint of estimated crude oil production and 55 percent of the midpoint of estimated natural gas production are currently hedged.
- Settlements of current commodity hedges are expected to result in cash receipts of approximately $13 million.
- Adjusted EBITDAX, a non-GAAP measure, is expected to be approximately $235 to $280 million, compared to 2012 Adjusted EBITDAX of $248 million.
- Capital expenditures are expected to be $360 to $400 million, compared to approximately $385 million of 2012 capital expenditures.
- Approximately 88 percent of capital expenditures are expected to be allocated to the Eagle Ford Shale and approximately 91 percent to development activities.
- 2013 capital expenditures include $310 to $345 million for drilling and completions, $28 to $30 million for lease acquisitions and $22 to $25 million for pipeline, gathering, seismic and facilities.
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.
Capital Resources and Liquidity, Interest Expense and Impact of Derivatives
As of December 31, 2012, we had total debt with a carrying value of $595 million ($600 million aggregate principal amount), consisting of $295 million of 10.375 percent senior unsecured notes due 2016 and $300 million principal amount of 7.25 percent senior unsecured notes due 2019.
As of December 31, 2012, we had no borrowings under our revolving credit facility (the "Revolver"), with approximately $298 million of unused borrowing capacity under the Revolver commitment. Together with cash and cash equivalents of approximately $18 million, our financial liquidity was approximately $316 million. Our indebtedness at December 31, 2012, net of cash and cash equivalents, was approximately $577 million, representing 39 percent of book capitalization and 2.3 times 2012 Adjusted EBITDAX of $247.6 million. We have no debt maturities until 2016. As of February 15, 2013, we had approximately $270 million of available borrowing capacity under the Revolver and approximately $4 million of cash and cash equivalents, for available financial liquidity of approximately $274 million.
In October 2012, we completed concurrent public offerings of 9,200,000 shares of our common stock and 1,150,000 depositary shares, each representing a 1/100th interest in a share of our 6 percent Series A convertible perpetual preferred stock. The two offerings provided approximately $154 million of net proceeds after issuance costs.
Interest expense decreased to $14.5 million in the fourth quarter of 2012 from $15.0 million in the third quarter due to lower average levels of debt outstanding.
During the fourth quarter of 2012, derivatives income was $4.9 million, compared to a derivatives loss of $12.3 million in the third quarter. Fourth quarter 2012 cash settlements of derivatives resulted in net cash receipts of $5.5 million, compared to $9.2 million of net cash receipts in the third quarter.
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 4,600 barrels of daily crude oil production in 2013, or approximately 58 percent of the midpoint of 2013 crude oil production guidance, at a weighted average floor/swap price of $97.35 per barrel. We have also hedged approximately 20,000 Mcf of daily natural gas production in 2013, or approximately 55 percent of the midpoint of 2013 natural gas production guidance, at a weighted average floor/swap price of $3.76 per Mcf.
Please see the Derivatives Table included in this release for our current derivative positions.
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. 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.
Fourth Quarter and Full-Year 2012 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss fourth quarter and full-year 2012 financial and operational results, is scheduled for Thursday, February 21, 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 1-866-630-9986 five to 10 minutes before the scheduled start of the conference call (use the passcode 7342669), 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 1-888-203-1112 (international: 719-457-0820) and using the replay code 7342669. 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 (NYS: PVA) is an independent oil and gas company engaged primarily in the development, exploration and production of oil and natural gas in various domestic onshore regions including Texas, Oklahoma, Mississippi and Pennsylvania.For more information, please visit our website atwww.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 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||Year ended|
|December 31,||December 31,|
|Natural gas liquids (NGLs)||7,753||9,636||31,051||43,394|
|Total product revenues||75,988||77,350||310,484||300,046|
|Gain on sales of property and equipment, net||1,875||3,047||4,282||3,570|
|Gathering, processing and transportation||2,524||3,896||14,196||15,157|
|Production and ad valorem taxes||2,719||2,401||10,634||13,690|
|General and administrative (excluding equity-classified share-based compensation) (a)||8,264||7,586||39,553||40,898|
|Total direct operating expenses||20,160||21,349||95,649||106,733|
|Share-based compensation - equity classified awards (b)||2,114||1,801||6,347||7,430|
|Depreciation, depletion and amortization||54,448||49,310||206,336||162,534|
|Loss on firm transportation commitment||-||-||17,332||-|
|Total operating expenses||159,335||117,597||464,240||461,424|
|Other income (expense)|
|Loss on extinguishment of debt||(20||)||(18||)||(3,164||)||(25,421||)|
|Loss before income taxes||(90,699||)||(55,722||)||(173,291||)||(221,070||)|
|Income tax benefit||36,258||27,783||68,702||88,155|
|Preferred stock dividends||(1,687||)||-||(1,687||)||-|
|Loss attributable to common shareholders||$||(56,128||)||$||(27,939||)||$||(106,276||)||$||(132,915||)|
|Loss per share:|
|Weighted average shares outstanding, basic||53,607||45,864||47,919||45,784|
|Weighted average shares outstanding, diluted||53,607||45,864||47,919||45,784|
|Three months ended||Year ended|
|December 31,||December 31,|
|Crude oil (MBbls)||559||450||2,252||1,283|
|Natural gas (MMcf)||3,737||6,765||20,261||33,410|
|Total crude oil, NGL and natural gas production (MBOE)||1,421||1,789||6,513||7,759|