Exhibit 99.1
Four Radnor Corporate Center, Suite 200
Radnor, PA 19087
Ph: (610) 687-8900 Fax: (610) 687-3688
www.pennvirginia.com
FOR IMMEDIATE RELEASE
PENN VIRGINIA CORPORATION ANNOUNCES FOURTH QUARTER AND FULL-YEAR 2010 RESULTS
RADNOR, PA (BusinessWire) February 23, 2011 –Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months and year ended December 31, 2010 and provided an update of full-year 2011 guidance.
Fourth Quarter 2010 Highlights
Fourth quarter 2010 results, with comparisons to fourth quarter 2009 results, included the following:
| | • | | Record proved oil and gas reserves of 942 billion cubic feet of natural gas equivalent (Bcfe) as of December 31, 2010, as compared to 911 Bcfe as of December 31, 2009, pro forma to exclude 24.0 Bcfe of Gulf Coast reserves sold in January 2010; |
| | • | | Quarterly production of 13.1 Bcfe, or 142.5 million cubic feet of natural gas equivalent (MMcfe) per day, a 27 percent increase as compared to 10.3 Bcfe, or 111.8 MMcfe per day, pro forma to exclude 1.0 Bcfe of production from Gulf Coast assets sold in January 2010; |
| | • | | Operating loss of $25.0 million, as compared to an operating loss of $16.5 million, due primarily to a 16 percent decline in our realized natural gas price and significant impairment charges in both periods; |
| | • | | Direct operating expenses of $26.5 million, or $2.02 per Mcfe produced, as compared to $29.2 million, or $2.58 per Mcfe produced; |
| | • | | Net loss from continuing operations of $24.8 million, or $0.54 per diluted share, as compared to a net loss of $9.3 million, or $0.21 per diluted share; and |
| | • | | Adjusted net loss attributable to PVA, a non-GAAP (generally accepted accounting principle) measure which excludes the effects of change in derivatives fair value, drilling rig standby charges, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, of $11.0 million, or $0.24 per diluted share, as compared to an adjusted net loss of $0.7 million, or $0.02 per diluted share. |
The operating loss and net loss from continuing operations in the fourth quarter of 2010, as reported above and discussed in further detail below, included impairment charges of $9.7 million and exploratory dry hole costs of $2.2 million.
Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the text and financial tables later in this release.
Management Comment
A. James Dearlove, Chief Executive Officer stated, “Fourth quarter 2010 operating results reflect the success of our strategic repositioning which began earlier in the year. Production was in the upper end of guidance and cash operating costs were at the lower end of guidance. Production increased 27 percent over pro forma fourth quarter 2009 levels and liquids comprised approximately 21 percent of the quarterly production volumes, primarily due to contributions from the liquids-rich Granite Wash and Cotton Valley. The fourth quarter was
negatively impacted by impairment and dry-hole charges related primarily to exploratory results in Mid-Continent prospect areas.
“Proved reserves increased to a record 942 Bcfe from 911 Bcfe at year-end 2009 (pro forma to exclude 24.0 Bcfe of Gulf Coast reserves sold in January 2010). As compared to year-end 2009, proved developed reserves increased to 53 percent from 46 percent, while proved oil and natural gas liquids (NGL) reserves increased to 21 percent from 17 percent. The change in the proved developed and liquids content of our reserves contributed to a nearly 28 percent increase in the PV-10 value (pre-tax present value of proved reserves, discounted at 10 percent), which totaled approximately $880 million at year-end 2010. Reserve replacement, excluding revisions to proved undeveloped reserves which will not be developed within a five-year horizon in accordance with Securities and Exchange Commission (SEC) regulations, was 122 Bcfe, or approximately 260 percent of 2010 production. Over the past five years, we have nearly tripled our proved reserve base, growing at a 23 percent annual compounded rate.
Mr. Dearlove continued, “Looking ahead in 2011, as a result of a successful first Eagle Ford Shale well in Gonzales County, Texas, together with encouraging nearby industry results, we expect a significant increase in our capital investment and drilling activity in the Eagle Ford Shale where we recently added to our leasehold position. We have elected to shift one of two operated rigs from the Mid-Continent to the Eagle Ford Shale and to add a third rig to the Eagle Ford Shale. These contemplated changes to our drilling program are expected to occur by mid-year 2011. In the Marcellus Shale, we have drilled our first horizontal well and are currently drilling our second well from the same pad in Potter County, Pennsylvania. We expect initial production from this play by mid-year.
“During 2011, we expect increases in oil, condensate and NGL production volumes, which are expected to comprise approximately 26 percent of full-year production. Production increases in 2011 are expected from the Eagle Ford Shale, Granite Wash, Marcellus Shale and other play types in the Mid-Continent region.”
Full-Year 2010 Consolidated Results
For the year ended December 31, 2010, we incurred an operating loss of $98.8 million, which included impairment charges of $46.0 million, as compared to an operating loss in 2009 of $205.3 million, which included charges of $106.4 million for impairments and drilling rig standby charges of $20.1 million. The adjusted net loss attributable to PVA, which excludes the effects of change in derivatives fair value, drilling rig standby charges, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, was $32.7 million, or $0.72 per diluted share, in 2010 as compared to an adjusted net loss attributable to PVA of $20.4 million, or $0.46 per diluted share, in 2009. The net loss attributable to PVA was $8.4 million, or $0.19 per diluted shared, in 2010 as compared to a net loss attributable to PVA of $114.6 million, or $2.62 per diluted share, in 2009 due primarily to the decrease in operating loss and the gain on sale of discontinued operations in 2010. Oil and gas production in 2010 was 47.2 Bcfe and proved reserves increased to a record 942 Bcfe.
Fourth Quarter 2010 Financial and Operational Results
As shown in the table below, production in the fourth quarter of 2010 was approximately 13.1 Bcfe, or 142.5 MMcfe per day, 27 percent more than the pro forma 10.3 Bcfe, or 111.8 MMcfe per day, in the fourth quarter of 2009 (reported production was 11.3 Bcfe, or 123.1 MMcfe per day) and down slightly from the 13.3 Bcfe, or 144.3 MMcfe per day, in the third quarter of 2010. The year-over-year increase was due to the effects of significantly increased drilling activity during 2010 and, to a lesser extent, by increased production of NGLs and crude oil primarily from the Granite Wash play. Please see our separate operational update news release dated February 23, 2011 for a more detailed discussion of operations.
| | | | | | | | | | | | | | | | | | | | |
| | | Production for the
Three Months Ended | | | Production for the
Year Ended | |
Region | | Dec. 31,
2010 | | | Dec. 31,
2009 | | | Sept. 30,
2010 | | | Dec. 31,
2010 | | | Dec. 31,
2009 | |
| | | (in Bcfe) | | | (in Bcfe) | |
| | | | | |
Mid-Continent | | | 4.2 | | | | 3.1 | | | | 4.5 | | | | 15.3 | | | | 12.8 | |
East Texas | | | 4.3 | | | | 2.7 | | | | 4.0 | | | | 13.5 | | | | 13.1 | |
Mississippi | | | 2.1 | | | | 1.7 | | | | 2.1 | | | | 7.6 | | | | 7.8 | |
Appalachia | | | 2.5 | | | | 2.7 | | | | 2.7 | | | | 10.4 | | | | 11.5 | |
Gulf Coast (1) | | | — | | | | 1.0 | | | | — | | | | 0.3 | | | | 5.8 | |
| | | | | | | | | | | | | | | | | | | | |
Totals | | | 13.1 | | | | 11.3 | | | | 13.3 | | | | 47.2 | | | | 51.0 | |
| | | | | | | | | | | | | | | | | | | | |
Pro Forma Totals(2) | | | 13.1 | | | | 10.3 | | | | 13.3 | | | | 46.9 | | | | 45.2 | |
| | | | | | | | | | | | | | | | | | | | |
| (1) | We sold our Gulf Coast assets in January 2010. |
| (2) | Pro forma to exclude divested Gulf Coast assets. |
Note - Numbers may not add due to rounding.
Our realized natural gas price, prior to the impact of derivatives, during the fourth quarter of 2010 was $3.57 per thousand cubic feet (Mcf), 16 percent lower than the $4.26 per Mcf price in the fourth quarter of 2009 and 18 percent lower than the $4.36 per Mcf price in the third quarter of 2010.
Our realized oil price, prior to the impact of derivatives, during the fourth quarter of 2010 was $82.84 per barrel, 13 percent higher than the $73.12 per barrel price in the fourth quarter of 2009 and 17 percent higher than the $70.97 per barrel price in the third quarter of 2010. Our realized NGLs price during the fourth quarter of 2010 was $42.15 per barrel, 19 percent higher than the $35.49 per barrel price in the fourth quarter of 2009 and 19 percent higher than the $35.57 per barrel price in the third quarter of 2010. Adjusting for oil and gas hedges, our effective natural gas price during the fourth quarter of 2010 was $4.39 per Mcf and our effective oil price was $81.41 per barrel, or an increase of $0.82 per Mcf and decrease of $1.43 per barrel, respectively, over the realized prices.
The operating loss of $25.0 million was $8.5 million more than the operating loss of $16.5 million in the prior year quarter, due primarily to an approximate $9.2 million increase in exploration expense and a $7.1 million increase in depreciation, depletion and amortization (DD&A) expenses, partially offset by a $5.3 million increase in total revenues and a $2.7 million decrease in direct operating expenses.
As discussed below and in spite of a 16 percent increase in reported oil and gas production volumes, fourth quarter 2010 direct operating expenses decreased $2.7 million, or nine percent, to $26.5 million, or $2.02 per Mcfe produced, as compared to $29.2 million, or $2.58 per Mcfe produced, in the fourth quarter of 2009.
| | • | | Lease operating expenses decreased by $1.6 million, or 15 percent, to $8.6 million, or $0.66 per Mcfe produced, from $10.2 million, or $0.90 per Mcfe produced, resulting primarily from decreased wellhead expenses; |
| | • | | Gathering, processing and transportation expenses increased by $1.3 million, or 47 percent, to $4.0 million, or $0.31 per Mcfe produced, from $2.7 million, or $0.24 per Mcfe produced, resulting primarily from higher production volumes and a change in the geographic distribution of production from the Gulf Coast to the Mid-Continent region, including higher processing costs in the Mid-Continent region; |
| | • | | Production and ad valorem taxes decreased by $2.5 million, or 67 percent, to $1.2 million from $3.7 million due to favorable tax adjustments in the fourth quarter of 2010. Exclusive of these |
| | adjustments, production and ad valorem taxes decreased to 6.3 percent of total revenue from 6.5 percent; and |
| | • | | General and administrative (G&A) expense was slightly higher at $12.7 million as compared to $12.5 million. Excluding restructuring costs of $1.8 million in the fourth quarter of 2010 and $0.5 million in the prior year quarter, pro forma G&A expense decreased by $1.1 million, or nine percent, to $10.9 million from $12.0 million. |
Exploration expense increased $9.2 million to $12.1 million in the fourth quarter of 2010 from $2.9 million in the prior year quarter, due to a $4.7 million increase in unproved property amortization resulting from acquisitions of unproved leasehold, a $2.2 million increase in dry hole costs attributable primarily to exploratory drilling in the Mid-Continent region and a $1.9 million increase in geological and geophysical costs attributable to an expanded drilling and exploration program.
DD&A expenses increased by $7.1 million, or 22 percent, to $39.3 million, or $3.00 per Mcfe produced, in the fourth quarter of 2010 from $32.3 million, or $2.85 per Mcfe produced, in the prior year quarter due to higher production volumes and a higher depletion rate resulting from higher drilling, completion and leasehold acquisition costs, as we shift our emphasis to higher-value oil and liquids play types, as well as year-end proved reserve revisions.
Impairments increased by approximately $0.1 million to $9.7 million in the fourth quarter of 2010 from $9.6 million in the prior year quarter. The impairment charge in the fourth quarter of 2010 related primarily to the initial Granite Wash well in the East Sayre Field, while the impairment charge in the prior year quarter primarily related to Gulf Coast assets held for sale which were subsequently sold in January 2010.
Full-Year 2011 Guidance Update
Full-year 2011 guidance highlights are as follows:
| | • | | Full-year 2011 production guidance of 50.0 to 54.0 Bcfe, which is unchanged from previous guidance; |
| | • | | Oil and gas capital expenditures guidance of $300 to $345 million, which is an increase of $35 to $55 million of previous guidance ($20 to $37 million increase in drilling and completion expenditures) due primarily to an acreage acquisition and acceleration of drilling in the Eagle Ford Shale, as well as increased drilling in the Marcellus Shale, partially offset by reduced drilling in the Granite Wash. |
We have elected to shift one of two operated rigs from the Mid-Continent to the Eagle Ford Shale and to add a third rig to the Eagle Ford Shale. These contemplated changes to our drilling program are expected to occur by mid-year 2011. Production guidance remains unchanged for the year due to the startup timing of new production from incremental Eagle Ford Shale drilling and the decrease in expected Mid-Continent production growth, while the increase in drilling and completion capital expenditures will support future production growth.
Please see the Guidance Table included in this release for guidance estimates for full-year 2011. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.
Capital Resources and Liquidity, Interest Expense and Impact of Derivatives
As of December 31, 2010, we had outstanding borrowings of $530 million ($506 million carrying value), consisting of $300 million ($292 million carrying value) of senior unsecured notes due 2016 and $230 million ($214 million carrying value) of convertible senior subordinated notes due 2012, with no borrowings under our revolving credit facility. Net of cash and equivalents of $121 million, our net indebtedness at December 31, 2010 was $386 million, or 28 percent of book capitalization.
As of December 31, 2010, we had approximately $540 million of financial liquidity, excluding cash flows from operating activities, comprised of cash on hand of $121 million and availability under our revolving credit facility
of $300 million ($420 million including uncommitted amounts). Together with ongoing cash flows from operating activities, supplemented by natural gas and crude oil hedges, we expect our financial liquidity to be sufficient to fund our anticipated capital needs for 2011.
Interest expense increased to $13.5 million in the fourth quarter of 2010 from $12.4 million in the fourth quarter of 2009 due to a decrease in capitalized interest and an increase in other interest expense. Cash interest expense increased $0.3 million, from $10.5 million in the prior year quarter to $10.8 million in the fourth quarter of 2010.
Due to fluctuations in commodity prices during the fourth quarter of 2010, derivatives expense was $2.5 million as compared to derivatives income of $11.1 million in the prior year quarter. Fourth quarter 2010 cash settlements of our derivatives resulted in net cash receipts of $8.5 million, as compared to $10.3 million of net cash receipts in the prior year quarter.
Explanation of Non-GAAP PV-10 Value
PV-10 Value is a non-GAAP financial measure under SEC regulations and differs from the Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) in that PV-10 Value is a pre-tax value, while the Standardized Measure includes the effect of estimated future income taxes, discounted at 10 percent. We believe that the PV-10 Value is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 Value is widely used by security analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure enhances comparability of assets when evaluating companies. The Standardized Measure at year-end 2010 of $641.4 million, plus $236.7 million of present value of future income tax discounted at 10 percent, is equal to the PV-10 Value of $878.1 million.
Fourth Quarter and Full-Year 2010 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss fourth quarter and full-year 2010 financial and operational results, is scheduled for Thursday, February 24, 2011 at 10:00 a.m. ET. Prepared remarks by A. James Dearlove, Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-866-823-5017 five to ten minutes before the scheduled start of the conference call (use the passcode 9013804), or via webcast by logging on to our website,www.pennvirginia.com, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available for two weeks beginning approximately 24 hours after the call. The replay can be accessed by dialing toll free 888-203-1112 (international: 719-457-0820) and using the replay code 9013804. 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 natural gas and oil company focused on the exploration, acquisition, development and production of reserves in onshore regions of the U.S., including Oklahoma, Texas, the Appalachian Basin and Mississippi.
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 natural gas, NGLs and oil; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of natural gas, NGLs and oil; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable 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; uncertainties related to expected benefits from acquisitions of oil and natural gas properties; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulation 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 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.
| | |
| Contact: | | James W. Dean |
| | Vice President, Corporate Development |
| | Ph: (610) 687-7531 Fax: (610) 687-3688 |
| | E-Mail:invest@pennvirginia.com |
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - unaudited
(in thousands, except per share data)
| | | | | | | | | | | | | | | | |
| | | Three months ended
December 31, | | | Year ended
December 31, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
Revenues | | | | | | | | | | | | | | | | |
Natural gas | | $ | 36,858 | | | $ | 40,361 | | | $ | 171,141 | | | $ | 169,666 | |
Crude oil | | | 15,415 | | | | 11,846 | | | | 53,532 | | | | 43,258 | |
Natural gas liquids (NGLs) | | | 11,676 | | | | 5,182 | | | | 26,663 | | | | 15,735 | |
Gain (loss) on sale of property and equipment | | | 32 | | | | 427 | | | | 648 | | | | 2,372 | |
Other | | | 338 | | | | 1,194 | | | | 2,454 | | | | 4,175 | |
| | | | | | | | | | | | | | | | |
Total revenues | | | 64,319 | | | | 59,010 | | | | 254,438 | | | | 235,206 | |
| | | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | | | | | |
Lease operating | | | 8,609 | | | | 10,184 | | | | 35,757 | | | | 44,392 | |
Gathering, processing and transportation | | | 4,015 | | | | 2,727 | | | | 14,180 | | | | 11,307 | |
Production and ad valorem taxes | | | 1,233 | | | | 3,739 | | | | 13,917 | | | | 15,044 | |
General and administrative (excluding equity compensation) (a) | | | 12,675 | | | | 12,542 | | | | 50,572 | | | | 40,628 | |
| | | | | | | | | | | | | | | | |
Total direct operating expenses | | | 26,532 | | | | 29,192 | | | | 114,426 | | | | 111,371 | |
Equity-based compensation (b) | | | 1,411 | | | | 1,617 | | | | 7,811 | | | | 9,062 | |
Exploration | | | 12,051 | | | | 3,083 | | | | 49,641 | | | | 37,670 | |
Exploration - drilling rig standby charges (c) | | | — | | | | (230 | ) | | | — | | | | 20,084 | |
Depreciation, depletion and amortization | | | 39,342 | | | | 32,256 | | | | 134,700 | | | | 154,351 | |
Impairments | | | 9,708 | | | | 9,587 | | | | 45,959 | | | | 106,415 | |
Other | | | 244 | | | | — | | | | 709 | | | | 1,599 | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 89,288 | | | | 75,505 | | | | 353,246 | | | | 440,552 | |
| | | | | | | | | | | | | | | | |
| | | | |
Operating loss | | | (24,969 | ) | | | (16,495 | ) | | | (98,808 | ) | | | (205,346 | ) |
| | | | |
Other income (expense) | | | | | | | | | | | | | | | | |
Interest expense | | | (13,489 | ) | | | (12,385 | ) | | | (53,679 | ) | | | (44,231 | ) |
Derivatives | | | (2,504 | ) | | | 11,085 | | | | 41,906 | | | | 31,568 | |
Other | | | 298 | | | | 5 | | | | 2,403 | | | | 1,259 | |
| | | | | | | | | | | | | | | | |
| | | | |
Loss from continuing operations before income taxes | | | (40,664 | ) | | | (17,790 | ) | | | (108,178 | ) | | | (216,750 | ) |
Income tax benefit | | | 15,827 | | | | 8,495 | | | | 42,851 | | | | 85,894 | |
| | | | | | | | | | | | | | | | |
| | | | |
Net loss from continuing operations | | | (24,837 | ) | | | (9,295 | ) | | | (65,327 | ) | | | (130,856 | ) |
Income from discontinued operations, net of tax | | | (34 | ) | | | 20,707 | | | | 33,448 | | | | 53,488 | |
Gain on sale of discontinued operations, net of tax | | | 1,934 | | | | — | | | | 51,546 | | | | — | |
| | | | | | | | | | | | | | | | |
| | | | |
Net income (loss) | | | (22,937 | ) | | | 11,412 | | | | 19,667 | | | | (77,368 | ) |
Less net income attributable to noncontrolling interests in discontinued operations | | | — | | | | (16,763 | ) | | | (28,090 | ) | | | (37,275 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Income (loss) attributable to PVA | | $ | (22,937 | ) | | $ | (5,351 | ) | | $ | (8,423 | ) | | $ | (114,643 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Income (loss) per share attributable to PVA - Basic | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (0.54 | ) | | $ | (0.21 | ) | | $ | (1.44 | ) | | $ | (2.99 | ) |
Discontinued operations | | | — | | | | 0.09 | | | | 0.12 | | | | 0.37 | |
Gain on sale of discontinued operations | | | 0.04 | | | | — | | | | 1.13 | | | | — | |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to PVA | | $ | (0.50 | ) | | $ | (0.12 | ) | | $ | (0.19 | ) | | $ | (2.62 | ) |
| | | | | | | | | | | | | | | | |
Income (loss) per share attributable to PVA - Diluted | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (0.54 | ) | | $ | (0.21 | ) | | $ | (1.44 | ) | | $ | (2.99 | ) |
Discontinued operations | | | — | | | | 0.09 | | | | 0.12 | | | | 0.37 | |
Gain on sale of discontinued operations | | | 0.04 | | | | — | | | | 1.13 | | | | — | |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to PVA | | $ | (0.50 | ) | | $ | (0.12 | ) | | $ | (0.19 | ) | | $ | (2.62 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Weighted average shares outstanding, basic | | | 45,615 | | | | 45,434 | | | | 45,553 | | | | 43,811 | |
Weighted average shares outstanding, diluted | | | 45,615 | | | | 45,434 | | | | 45,553 | | | | 43,811 | |
| | | | | | | | | | | | | | | | |
| | | Three months ended
December 31, | | | Year ended
December 31, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
Production | | | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | 10,329 | | | | 9,480 | | | | 38,919 | | | | 43,338 | |
Crude oil (MBbls) | | | 186 | | | | 162 | | | | 709 | | | | 750 | |
NGLs (MBbls) | | | 277 | | | | 146 | | | | 672 | | | | 527 | |
Total natural gas, crude oil and NGL production (MMcfe) | | | 13,108 | | | | 11,328 | | | | 47,201 | | | | 51,000 | |
| | | | |
Prices | | | | | | | | | | | | | | | | |
Natural gas ($ per Mcf) | | $ | 3.57 | | | $ | 4.26 | | | $ | 4.40 | | | $ | 3.91 | |
Crude oil ($ per Bbl) | | $ | 82.84 | | | $ | 73.12 | | | $ | 75.56 | | | $ | 57.68 | |
NGLs ($ per Bbl) | | $ | 42.15 | | | $ | 35.49 | | | $ | 39.69 | | | $ | 29.86 | |
| | | | |
Prices - Adjusted for derivative settlements | | | | | | | | | | | | | | | | |
Natural gas ($ per Mcf) | | $ | 4.39 | | | $ | 5.35 | | | $ | 5.27 | | | $ | 5.20 | |
Crude oil ($ per Bbl) | | $ | 81.41 | | | $ | 77.27 | | | $ | 74.94 | | | $ | 63.49 | |
NGLs ($ per Bbl) | | $ | 42.15 | | | $ | 35.49 | | | $ | 39.69 | | | $ | 29.86 | |
| (a) | Includes restructuring costs of $1.8 million and $8.2 million for the three months and year ended December 31, 2010, respectively, and $0.5 million for both the three months and year ended December 31, 2009. |
| (b) | Our equity-based compensation expense includes our stock option expense and the amortization of restricted stock and restricted stock units related to employee awards in accordance with accounting guidance for share-based payments. |
| (c) | Drilling rig standby charges represent fees paid in connection with the deferral of drilling associated with contractually committed rigs and frac tank rentals. |
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
| | | | | | | | |
| | | December 31,
2010 | | | December 31,
2009 | |
Assets | | | | | | | | |
Current assets | | $ | 214,340 | | | $ | 192,134 | |
Current assets of discontinued operations | | | — | | | | 107,108 | |
Net property and equipment | | | 1,705,584 | | | | 1,479,452 | |
Other assets | | | 24,676 | | | | 26,470 | |
Noncurrent assets of discontinued operations | | | — | | | | 1,083,343 | |
| | | | | | | | |
Total assets | | $ | 1,944,600 | | | $ | 2,888,507 | |
| | | | | | | | |
| | |
Liabilities and shareholders’ equity | | | | | | | | |
Current liabilities | | $ | 106,994 | | | $ | 75,620 | |
Current liabilities of discontinued operations | | | — | | | | 77,915 | |
Revolving credit facility | | | — | | | | — | |
Senior notes | | | 292,487 | | | | 291,749 | |
Convertible notes | | | 214,049 | | | | 206,678 | |
Other liabilities and deferred taxes | | | 350,794 | | | | 351,409 | |
Noncurrent liabilities of discontinued operations | | | — | | | | 647,137 | |
PVA shareholders’ equity | | | 980,276 | | | | 908,088 | |
Noncontrolling interests in discontinued operations | | | — | | | | 329,911 | |
| | | | | | | | |
Total shareholders’ equity | | | 980,276 | | | | 1,237,999 | |
| | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 1,944,600 | | | $ | 2,888,507 | |
| | | | | | | | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three months ended
December 31, | | | Year ended
December 31, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
Cash flows from operating activities | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | (22,937 | ) | | $ | 11,412 | | | $ | 19,667 | | | $ | (77,368 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | | | | | |
Income from discontinued operations | | | — | | | | (23,537 | ) | | | (36,832 | ) | | | (64,130 | ) |
Gain on sale of discontinued operations | | | (1,922 | ) | | | — | | | | (86,662 | ) | | | — | |
Depreciation, depletion and amortization | | | 39,342 | | | | 32,256 | | | | 134,700 | | | | 154,351 | |
Impairments | | | 9,708 | | | | 9,587 | | | | 45,959 | | | | 106,415 | |
Derivative contracts: | | | | | | | | | | | | | | | | |
Total derivative gains | | | 2,504 | | | | (10,978 | ) | | | (41,906 | ) | | | (28,033 | ) |
Cash receipts to settle derivatives | | | 8,531 | | | | 10,346 | | | | 32,818 | | | | 58,147 | |
Deferred income taxes | | | 36,379 | | | | (12,494 | ) | | | 42,528 | | | | (83,222 | ) |
Loss (gain) on the sale of property and equipment, net | | | 212 | | | | 35 | | | | 61 | | | | (1,910 | ) |
Dry hole and unproved leasehold expense | | | 9,774 | | | | 2,802 | | | | 36,275 | | | | 33,278 | |
Non-cash interest expense | | | 2,895 | | | | 2,989 | | | | 11,984 | | | | 10,202 | |
Share-based compensation | | | 1,411 | | | | 1,617 | | | | 7,811 | | | | 9,062 | |
Other, net | | | 132 | | | | (1,340 | ) | | | (209 | ) | | | 748 | |
Changes in operating assets and liabilities | | | (75,065 | ) | | | (12,155 | ) | | | (86,355 | ) | | | 193 | |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 10,964 | | | | 10,540 | | | | 79,839 | | | | 117,733 | |
| | | | | | | | | | | | | | | | |
Cash flows from investing activities | | | | | | | | | | | | | | | | |
Capital expenditures - property and equipment | | | (92,284 | ) | | | (22,148 | ) | | | (405,994 | ) | | | (205,676 | ) |
Proceeds from the sale of PVG units, net (a) | | | — | | | | — | | | | 139,120 | | | | — | |
Proceeds from the sale of property, plant and equipment, net | | | 395 | | | | 7,268 | | | | 25,567 | | | | 15,083 | |
Other, net | | | — | | | | — | | | | 1,192 | | | | 11 | |
| | | | | | | | | | | | | | | | |
Net cash used in investing activities | | | (91,889 | ) | | | (14,880 | ) | | | (240,115 | ) | | | (190,582 | ) |
| | | | | | | | | | | | | | | | |
Cash flows from financing activities | | | | | | | | | | | | | | | | |
Dividends paid | | | (2,571 | ) | | | (2,558 | ) | | | (10,271 | ) | | | (9,836 | ) |
Distributions received from discontinued operations | | | — | | | | 7,347 | | | | 11,218 | | | | 42,279 | |
Repayments of short-term borrowings | | | — | | | | — | | | | — | | | | (7,542 | ) |
Repayment of revolving credit facility borrowings | | | — | | | | — | | | | — | | | | (332,000 | ) |
Proceeds from the issuance of Senior notes, net | | | — | | | | — | | | | — | | | | 291,009 | |
Proceeds from the issuance of common stock, net | | | — | | | | — | | | | — | | | | 64,835 | |
Proceeds from the sale of PVG units, net (a) | | | — | | | | — | | | | 199,125 | | | | 118,080 | |
Debt issuance costs paid | | | — | | | | (5,272 | ) | | | — | | | | (14,959 | ) |
Other, net | | | (45 | ) | | | — | | | | 2,098 | | | | — | |
| | | | | | | | | | | | | | | | |
Net cash provided by (used in) financing activities | | | (2,616 | ) | | | (483 | ) | | | 202,170 | | | | 151,866 | |
| | | | | | | | | | | | | | | | |
Cash flows from discontinued operations | | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | — | | | | 43,384 | | | | 77,759 | | | | 158,214 | |
Net cash used in investing activities | | | — | | | | (5,231 | ) | | | (18,112 | ) | | | (80,506 | ) |
Net cash used in financing activities | | | — | | | | (38,153 | ) | | | (59,647 | ) | | | (77,708 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by discontinued operations | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (83,541 | ) | | | (4,823 | ) | | | 41,894 | | | | 79,017 | |
Cash and cash equivalents - beginning of period | | | 204,452 | | | | 83,840 | | | | 79,017 | | | | — | |
| | | | | | | | | | | | | | | | |
Cash and cash equivalents - end of period | | $ | 120,911 | | | $ | 79,017 | | | $ | 120,911 | | | $ | 79,017 | |
| | | | | | | | | | | | | | | | |
| (a) | Net proceeds from the sale of Penn Virginia GP Holdings, L.P. (PVG) units included in investing activities is attributable to the sale of the final tranche of PVG units, which resulted in the loss of control and deconsolidation of PVG from our financial statements. Net proceeds from the sale of PVG units included in financing activities represents proceeds received from sales of our ownership interests in PVG while we still maintained control. |
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three months ended
December 31, | | | Year ended
December 31, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
Reconciliation of GAAP “Net Income (loss) attributable to PVA” to Non-GAAP “Net Income (loss) attributable to PVA, as adjusted” | | | | | | | | | | | | | | | | |
Net income (loss) attributable to PVA | | $ | (22,937 | ) | | $ | (5,351 | ) | | $ | (8,423 | ) | | $ | (114,643 | ) |
Adjustments for derivatives: | | | | | | | | | | | | | | | | |
Derivative (gains) losses included in net income | | | 2,504 | | | | (10,978 | ) | | | (41,906 | ) | | | (28,033 | ) |
Cash receipts to settle derivatives | | | 8,531 | | | | 10,346 | | | | 32,818 | | | | 58,147 | |
Adjustment for drilling rig standby charges | | | — | | | | (230 | ) | | | — | | | | 20,084 | |
Adjustment for impairments | | | 9,708 | | | | 9,587 | | | | 45,959 | | | | 106,415 | |
Adjustment for restructuring costs | | | 1,766 | | | | 529 | | | | 8,200 | | | | 529 | |
Adjustment for net loss (gain) on sale of assets | | | 212 | | | | (427 | ) | | | 61 | | | | (773 | ) |
Adjustment for gain on sale of discontinued operations | | | (1,922 | ) | | | — | | | | (86,662 | ) | | | — | |
Impact of adjustments on income taxes | | | (8,855 | ) | | | (4,215 | ) | | | 17,239 | | | | (61,966 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
| | $ | (10,993 | ) | | $ | (739 | ) | | $ | (32,714 | ) | | $ | (20,240 | ) |
| | | | |
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes | | | — | | | | (48 | ) | | | (28 | ) | | | (116 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Net loss attributable to PVA, as adjusted (a) | | $ | (10,993 | ) | | $ | (787 | ) | | $ | (32,742 | ) | | $ | (20,356 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Net loss attributable to PVA, as adjusted, per share, diluted | | $ | (0.24 | ) | | $ | (0.02 | ) | | $ | (0.72 | ) | | $ | (0.46 | ) |
| (a) | Net income (loss) attributable to PVA, as adjusted, represents net income (loss) attributable to PVA adjusted to exclude the effects of non-cash changes in the fair value of derivatives, drilling rig standby charges, impairments, restructuring costs, gains and losses on the sale of assets, the gain on the sale of PVG (discontinued operations) and net income of Penn Virginia Resource Partners, L.P. (PVR) allocated to unvested PVR restricted units awarded as equity compensation that are held until vesting. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Net income (loss) attributable to PVA, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income attributable to PVA. |
PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited
(dollars in millions except where noted)
We are providing the following guidance regarding financial and operational expectations for full-year 2011. These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First
Quarter
2010 | | | Second
Quarter
2010 | | | Third
Quarter
2010 | | | Fourth
Quarter
2010 | | | Full Year
2010 | | | Full-Year
2011 Guidance | |
| | | | | | | | |
Production: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (Bcf) | | | 8.6 | | | | 9.1 | | | | 10.9 | | | | 10.3 | | | | 38.9 | | | | 37.4 | | | | — | | | | 39.6 | |
Crude oil (MBbls) | | | 186 | | | | 148 | | | | 189 | | | | 186 | | | | 709 | | | | 1,100 | | | | — | | | | 1,300 | |
NGLs (MBbls) | | | 109 | | | | 76 | | | | 210 | | | | 277 | | | | 672 | | | | 1,000 | | | | — | | | | 1,100 | |
Equivalent production (Bcfe) | | | 10.3 | | | | 10.5 | | | | 13.3 | | | | 13.1 | | | | 47.2 | | | | 50.0 | | | | — | | | | 54.0 | |
Equivalent daily production (MMcfe per day) | | | 114.9 | | | | 115.1 | | | | 144.3 | | | | 142.5 | | | | 129.3 | | | | 137.0 | | | | — | | | | 147.9 | |
| | | | | | | | |
Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating ($ per Mcfe)* | | $ | 0.85 | | | | 0.87 | | | | 0.70 | | | | 0.66 | | | | 0.76 | | | | 0.75 | | | | — | | | | 0.80 | |
Gathering, processing and transportation costs ($ per Mcfe)* | | $ | 0.31 | | | | 0.32 | | | | 0.27 | | | | 0.31 | | | | 0.30 | | | | 0.32 | | | | — | | | | 0.33 | |
Production and ad valorem taxes (percent of oil and gas revenues)* | | | 6.4 | % | | | 5.9 | % | | | 7.8 | % | | | 1.9 | % | | | 5.5 | % | | | 6.5 | % | | | — | | | | 7.0 | % |
General and administrative* | | $ | 10.5 | | | | 10.0 | | | | 10.9 | | | | 10.9 | | | | 42.3 | | | | 44.5 | | | | — | | | | 45.5 | |
Equity-based compensation | | $ | 3.0 | | | | 1.7 | | | | 1.7 | | | | 1.4 | | | | 7.8 | | | | 6.0 | | | | — | | | | 8.0 | |
Restructuring | | $ | 1.5 | | | | 4.2 | | | | 0.8 | | | | 1.8 | | | | 8.3 | | | | | | | | | | | | | |
Exploration | | $ | 6.0 | | | | 9.5 | | | | 22.0 | | | | 12.1 | | | | 49.6 | | | | 45.0 | | | | — | | | | 50.0 | |
Depreciation, depletion and amortization ($ per Mcfe) | | $ | 2.90 | | | | 3.06 | | | | 2.50 | | | | 3.00 | | | | 2.85 | | | | 2.75 | | | | — | | | | 3.00 | |
| | | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Development drilling | | $ | 37.9 | | | | 71.6 | | | | 81.1 | | | | 52.8 | | | | 243.4 | | | | 205.0 | | | | — | | | | 225.0 | |
Exploratory drilling | | $ | 3.7 | | | | 4.4 | | | | 13.0 | | | | 33.2 | | | | 54.3 | | | | 40.0 | | | | — | | | | 52.0 | |
Pipeline, gathering, facilities | | $ | 0.2 | | | | 0.5 | | | | 0.2 | | | | 0.5 | | | | 1.4 | | | | 8.0 | | | | — | | | | 11.0 | |
Seismic | | $ | 0.4 | | | | 4.1 | | | | 4.0 | | | | 1.7 | | | | 10.2 | | | | 17.0 | | | | — | | | | 21.0 | |
Lease acquisitions, field projects and other | | $ | 35.5 | | | | 36.1 | | | | 48.7 | | | | 20.2 | | | | 140.5 | | | | 30.0 | | | | — | | | | 36.0 | |
Total oil and gas capital expenditures | | $ | 77.7 | | | | 116.7 | | | | 147.0 | | | | 108.4 | | | | 449.8 | | | | 300.0 | | | | — | | | | 345.0 | |
| | | | | | | | |
End of period debt outstanding | | $ | 500.5 | | | | 502.5 | | | | 504.5 | | | | 506.5 | | | | 506.5 | | | | | | | | | | | | | |
Effective interest rate | | | 10.9 | % | | | 11.0 | % | | | 10.9 | % | | | 11.0 | % | | | 11.0 | % | | | | | | | | | | | | |
Income tax benefit rate | | | 38.6 | % | | | 38.4 | % | | | 40.6 | % | | | 38.9 | % | | | 39.6 | % | | | | | | | | | | | | |
Cash distributions received from PVG and PVR | | $ | 7.7 | | | | 3.5 | | | | — | | | | — | | | | 11.2 | | | | | | | | | | | | | |
| * | Prior to the sale of PVG, these line items were combined for guidance purposes and shown as “Cash operating expenses” with the Corporate G&A expenses reflected separately. With the sale of PVG, PVA will operate in only one industry segment. As such, we believe that a more detailed breakdown of these operating expenses, and presentation of consolidated G&A, will provide more useful guidance information to investors. |
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) | | | | | |
First quarter 2011 | | | Costless collars | | | | 50,000 | | | | 5.65 | | | | 8.77 | |
Second quarter 2011 | | | Costless collars | | | | 30,000 | | | | 4.83 | | | | 6.00 | |
Third quarter 2011 | | | Costless collars | | | | 30,000 | | | | 4.83 | | | | 6.00 | |
Fourth quarter 2011 | | | Costless collars | | | | 20,000 | | | | 6.00 | | | | 8.50 | |
First quarter 2012 | | | Costless collars | | | | 20,000 | | | | 6.00 | | | | 8.50 | |
Second quarter 2011 | | | Swaps | | | | 30,000 | | | | 5.22 | | | | | |
Third quarter 2011 | | | Swaps | | | | 30,000 | | | | 5.22 | | | | | |
Fourth quarter 2011 | | | Swaps | | | | 10,000 | | | | 5.01 | | | | | |
First quarter 2012 | | | Swaps | | | | 5,000 | | | | 5.10 | | | | | |
Second quarter 2012 | | | Swaps | | | | 15,000 | | | | 5.38 | | | | | |
Third quarter 2012 | | | Swaps | | | | 15,000 | | | | 5.38 | | | | | |
Fourth quarter 2012 | | | Swaps | | | | 5,000 | | | | 5.10 | | | | | |
| | | |
Crude oil: | | | | | | | (barrels) | | | | | |
First quarter 2011 | | | Costless collars | | | | 425 | | | | 80.00 | | | | 101.50 | |
Second quarter 2011 | | | Costless collars | | | | 425 | | | | 80.00 | | | | 101.50 | |
Third quarter 2011 | | | Costless collars | | | | 360 | | | | 80.00 | | | | 103.30 | |
Fourth quarter 2011 | | | Costless collars | | | | 360 | | | | 80.00 | | | | 103.30 | |
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 2011 would increase or decrease by approximately $38.5 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for 2011 would increase or decrease by approximately $16.7 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.
