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 SECOND QUARTER 2011 RESULTS
39 PERCENT INCREASE IN OIL AND GAS REVENUES AND 12 PERCENT INCREASE IN PRODUCTION OVER PRIOR YEAR
EAGLE FORD SHALE RESULTS DROVE 44 PERCENT INCREASE IN EBITDAX OVER PRIOR YEAR
RADNOR, PA (BusinessWire) August 3, 2011 –Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months ended June 30, 2011 and provided an update of full-year 2011 guidance.
Second Quarter 2011 Highlights
Second quarter 2011 results, as compared to second quarter 2010 results, were as follows:
| | • | | Production of 11.7 billion cubic feet of natural gas equivalent (Bcfe), or 128.6 million cubic feet of natural gas equivalent (MMcfe) per day, a 12 percent increase as compared to 10.5 Bcfe, or 115.1 MMcfe per day |
| | • | | Oil and natural gas liquid (NGL) production increased to 472 thousand barrels, or 24 percent of total equivalent production, from 224 thousand barrels, or 13 percent of total equivalent production |
| | • | | Total product revenues from the sale of natural gas, crude oil and NGLs of $73.0 million, or $6.24 per thousand cubic feet of natural gas equivalent (Mcfe), up 39 percent as compared to $52.4 million, or $5.00 per Mcfe |
| | • | | Oil and NGL revenues increased by 156 percent to $34.7 million from $13.5 million |
| | • | | Total direct operating expenses of $28.8 million, or $2.47 per Mcfe, a decrease of $0.9 million as compared to $29.7 million, or $2.84 per Mcfe (a 13 percent decrease on a per-unit basis) |
| | • | | Operating loss of $80.7 million, an increase of $59.8 million as compared to a loss of $20.9 million, due to higher impairment and exploration expenses |
| | • | | Adjusted EBITDAX, a non-GAAP (generally accepted accounting principles) measure, of $47.5 million, an increase of $14.5 million, or 44 percent, as compared to $33.0 million |
| | • | | Net loss from continuing operations of $71.9 million, or $1.57 per diluted share, an increase of $50.8 million as compared to a net loss of $21.1 million, or $0.46 per diluted share, due primarily to the higher operating loss and a loss on the extinguishment of debt |
| | • | | Adjusted net loss attributable to PVA, a non-GAAP measure, of $11.9 million, or $0.26 per diluted share, as compared to a net loss of $9.4 million, or $0.21 per diluted share |
The operating loss was $59.8 million greater than the prior year quarter, due primarily to a $71.1 million impairment related to non-core, primarily Arkoma Basin properties that we recently agreed to sell and a $9.8 million increase in exploration expense. The net loss from continuing operations was $50.8 million greater than the prior year quarter due to the higher operating loss and a pretax $24.2 million loss on the extinguishment of debt related to the previously announced refinancing of our 4.5 percent convertible notes due in 2012.
Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear on page eight of this release.
Management Comment
H. Baird Whitehead, President and Chief Executive Officer stated, “Our second quarter 2011 results demonstrate that we have made significant progress in transforming PVA from a focus on natural gas to a new focus on oil and NGLs, which has resulted in higher revenues and cash flows. In the second quarter of 2011, oil and NGL revenues increased by 156 percent over the prior year quarter and were 31 percent higher than the first quarter of 2011. In addition, oil and NGL revenues comprised 48 percent of total product revenues in the second quarter of 2011, as compared to 26 percent in the prior year quarter and 39 percent in the first quarter of 2011. We remain believers in natural gas over the long-term, however, and retain our exposure to an eventual recovery in the price of natural gas.
“The second quarter of 2011 is the first full quarter of contributions from our oily Eagle Ford Shale properties, which had a significant impact on our recurring financial results. We are operating three rigs in the Eagle Ford Shale and are currently drilling our 15th through 17th wells. We recently completed our 12th well, and we have two wells waiting on completion. Current production from the Eagle Ford Shale is approximately 8,000 (5,000 net) barrels of oil equivalent per day (BOEPD), and we expect to increase production from this play to approximately 11,000 to 13,000 (7,000 to 8,000 net) BOEPD by the end of 2011. We recently expanded our position to approximately 13,900 net acres, which we feel is in the core of the play, and increased our total location well inventory to up to 142 locations. In addition, we have our midstream facilities connected and are experiencing no delays in obtaining completion or fracturing services. In short, our early results in this play have been excellent. We will continue to review leasing and acquisition opportunities to expand our inventory of locations.
“We expect oil and NGLs to contribute between 30 and 32 percent of total 2011 equivalent production, as compared to approximately 18 percent of 2010 total equivalent production, and we expect to exit 2011 with approximately 40 to 45 percent of fourth quarter total equivalent production from oil and NGLs. As a result of this shift in production mix towards higher-margin oil and NGLs, and despite the decreased guidance for natural gas production, we expect second-half 2011 revenues, EBITDAX and other cash flows to increase and for that trend to continue into 2012.”
Mr. Whitehead concluded, “As disclosed in our separate news release today, we entered into a new revolving credit facility which has a more favorable leverage ratio through its maturity than our current credit facility. This will help accommodate the expansion of our position in the Eagle Ford Shale and, potentially, other oily plays. This new leverage ratio covenant, together with the previously announced sale of our primarily Arkoma Basin assets, places us in a solid liquidity position to execute on our capital plans.”
Second Quarter 2011 Financial and Operational Results
The $80.7 million operating loss was $59.8 million higher than the $20.9 million operating loss in the prior year quarter, due primarily to a $69.9 million increase in impairment expense and a $9.8 million increase in exploration expense. These expense increases were partially offset by a $20.7 million, or 39 percent, increase in total product revenues and a $0.9 million decrease in total direct operating expenses. Oil and NGL revenues were $34.7 million in the second quarter of 2011, 156 percent higher than the $13.5 million in the prior year quarter and 31 percent higher than the $26.5 million in the first quarter of 2011. Oil and NGL revenues were 48 percent of total product revenues in the second quarter of 2011, as compared to 26 percent in the prior year quarter and 39 percent in the first quarter of 2011.
As shown in the table below, production in the second quarter of 2011 was approximately 11.7 Bcfe, or 128.6 MMcfe per day, a 12 percent increase as compared to 10.5 Bcfe, or 115.1 MMcfe per day, in the prior year quarter and a five percent decrease from 12.2 Bcfe, or 135.2 MMcfe per day, in the first quarter of 2011. As a percentage of total equivalent production, oil and NGL volumes were 24 percent in the second quarter of 2011, as compared to 13 percent in the prior year quarter and 20 percent in the first quarter of 2011.
The year-over-year production increase was due to our new Eagle Ford Shale wells and contributions from 2010 drilling in the horizontal Cotton Valley and Haynesville Shale plays. The 111 percent increase in oil and NGL production as compared to the prior year quarter was due to drilling activity in the Eagle Ford Shale and increased NGL volumes from the Granite Wash. The sequential quarterly decrease in production was attributable primarily to natural gas production declines, partially offset by higher oil and NGL volumes in the Eagle Ford Shale. Please see our separate operational update news release dated August 3, 2011 for a more detailed discussion of operations.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Total and Daily Equivalent Production for the Three Months Ended | |
Region / Play Type | | June 30,
2011 | | | June 30,
2010 | | | Mar. 31,
2011 | | | June 30,
2011 | | | June 30,
2010 | | | Mar. 31,
2011 | |
| | | (in Bcfe) | | | (in MMcfe per day) | |
Texas | | | 4.2 | | | | 2.6 | | | | 3.8 | | | | 46.4 | | | | 28.8 | | | | 42.5 | |
Cotton Valley | | | 2.1 | | | | 1.7 | | | | 2.2 | | | | 22.7 | | | | 18.3 | | | | 24.8 | |
Haynesville Shale | | | 1.2 | | | | 0.9 | | | | 1.4 | | | | 13.1 | | | | 10.5 | | | | 16.0 | |
Eagle Ford / Other (1) | | | 1.0 | | | | — | | | | 0.1 | | | | 10.6 | | | | — | | | | 1.6 | |
Appalachia | | | 2.3 | | | | 2.6 | | | | 2.4 | | | | 24.7 | | | | 28.5 | | | | 26.3 | |
Mid-Continent | | | 3.5 | | | | 3.5 | | | | 4.1 | | | | 38.8 | | | | 38.5 | | | | 45.8 | |
Granite Wash | | | 2.9 | | | | 2.6 | | | | 3.1 | | | | 31.6 | | | | 28.9 | | | | 33.9 | |
Other (2) | | | 0.7 | | | | 0.9 | | | | 1.1 | | | | 7.2 | | | | 9.6 | | | | 11.9 | |
Mississippi | | | 1.7 | | | | 1.8 | | | | 1.9 | | | | 18.6 | | | | 19.4 | | | | 20.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Totals | | | 11.7 | | | | 10.5 | | | | 12.2 | | | | 128.6 | | | | 115.1 | | | | 135.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | Initial production from the Eagle Ford Shale commenced in February 2011. |
| (2) | Includes properties, primarily in the Arkoma Basin, which we have agreed to sell. |
Note-Numbers may not add due to rounding.
Our second quarter 2011 realized natural gas price was $4.32 per thousand cubic feet (Mcf), two percent higher than both the $4.25 per Mcf price in the second quarter of 2010 and the $4.23 per Mcf price in the first quarter of 2011. Our second quarter 2011 realized oil price was $98.45 per barrel, 34 percent higher than the $73.64 per barrel price in the second quarter of 2010 and 11 percent higher than the $88.37 per barrel price in the first quarter of 2011. Our second quarter 2011 realized NGL price was $52.04 per barrel, 49 percent higher than the $34.97 per barrel price in the second quarter of 2010 and 15 percent higher than the $45.11 per barrel price in the first quarter of 2011. Adjusting for oil and gas hedges, our second quarter 2011 effective natural gas price was $4.80 per Mcf and our effective oil price was $97.87 per barrel, or an increase of $0.48 per Mcf and a decrease of $0.58 per barrel over the realized prices.
As discussed below, and despite the 12 percent increase in reported oil and gas production volumes, second quarter 2011 total direct operating expenses decreased $0.9 million, or approximately three percent, to $28.8 million, or $2.47 per Mcfe produced, as compared to $29.7 million, or $2.84 per Mcfe produced, in the second quarter of 2010.
| | • | | Lease operating expenses increased by $1.6 million, or 18 percent, to $10.8 million, or $0.92 per Mcfe produced, from $9.2 million, or $0.87 per Mcfe produced, due to higher maintenance, compression and workover costs |
| | • | | Gathering, processing and transportation expenses increased by $1.0 million, or 29 percent, to $4.3 million, or $0.37 per Mcfe produced, from $3.3 million, or $0.32 per Mcfe produced, resulting from higher production volume and processing costs associated with NGLs, which comprised a significantly larger proportion of the total production volume in the current year quarter |
| | • | | Production and ad valorem taxes decreased nine percent to $2.8 million, or 3.9 percent of total product revenues, from $3.1 million, or 5.9 percent of total product revenues, resulting primarily from a production tax settlement in the Oklahoma |
| | • | | General and administrative expenses, excluding share-based compensation, decreased by $3.2 million, or 23 percent, to $10.9 million, or $0.94 per Mcfe produced, from $14.2 million, or $1.35 per Mcfe produced, due primarily to a $4.1 million decrease in restructuring costs from the prior period quarter |
Exploration expense increased $9.8 million to approximately $19.4 million in the second quarter of 2011 from $9.5 million in the prior year quarter, due primarily to a $7.5 million increase in unproved leasehold amortization expense and a $2.1 million increase in dry hole costs related to a previously disclosed, unsuccessful vertical exploratory well in the Texas panhandle.
Depreciation, depletion and amortization (DD&A) expense increased by $0.9 million, or three percent, to $33.0 million, or $2.82 per Mcfe produced, in the second quarter of 2011 from $32.1 million, or $3.06 per Mcfe produced, in the prior year quarter, due primarily to higher production volumes.
Full-Year 2011 Guidance Update
Full-year 2011 guidance highlights are as follows:
| | • | | Production guidance of 48.5 to 50.5 Bcfe, a decrease of 1.5 to 3.5 Bcfe from previous guidance of 50.0 to 54.0 Bcfe, due primarily to an approximate 3.6 Bcfe reduction in estimated Mid-Continent production following forecasting adjustments associated with the ongoing Granite Wash well communication issue related to stimulations (2.7 Bcfe), along with the previously announced sale of non-core producing assets, primarily in the Arkoma Basin (0.9 Bcfe). These decreases are expected to be partially offset by increased production from the Eagle Ford Shale due to very successful early results and shortened drilling times |
| | • | | Oil and NGL production guidance of between 30 and 32 percent of total equivalent production, compared to between 28 and 30 percent of total equivalent production in previous guidance (approximately 40 to 45 percent in the fourth quarter of 2011), due primarily to expected increases in oil and NGL volumes from the Eagle Ford Shale |
| | • | | Capital expenditures guidance of $360 to $380 million, an increase of between $10 and $40 million from previous guidance of $320 to $370 million, due primarily to additional Eagle Ford Shale drilling, partially offset by decreased drilling in the Marcellus Shale |
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 June 30, 2011, we had total debt with a carrying value of $598 million ($605 million aggregate principal amount), consisting of $293 million of 10.375 percent senior unsecured notes due 2016, $300 million principal amount of 7.25 percent senior unsecured notes due 2019 and $5 million principal amount of 4.5 percent convertible senior subordinated notes due 2012. As of June 30, 2011, we had with no borrowings under our revolving credit facility. Net of cash and equivalents of approximately $31 million, our indebtedness at June 30, 2011 was approximately $567 million, or 39 percent of book capitalization.
In April 2011, we completed the offering of $300 million of 7.25 percent senior unsecured notes due 2019. Approximately $241 million of the net proceeds of $293 million was used to fund a tender offer pursuant to which we acquired approximately 98 percent of our 4.5 percent convertible senior subordinated notes. The remaining net proceeds of approximately $52 million are being used to fund a portion of our capital expenditures program and for general corporate purposes.
Interest expense increased slightly to $14.1 million in the second quarter of 2011 from $13.3 million in the second quarter of 2010 due to higher average levels of debt outstanding, partially offset by lower effective interest rates.
During the second quarter of 2011, derivatives income was $7.0 million, as compared to derivatives loss of $0.6 million in the prior year quarter. Second quarter 2011 cash settlements of derivatives resulted in net cash receipts of $5.0 million, as compared to $9.1 million of net cash receipts in the prior year quarter.
Second Quarter 2011 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss second quarter 2011 financial and operational results, is scheduled for Thursday, August 4, 2011 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 1-866-630-9986 five to ten minutes before the scheduled start of the conference call (use the passcode 5475077), 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 5475077. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.
******
Penn Virginia Corporation (NYSE: PVA) is an independent oil and gas company engaged primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions including Texas, Appalachia, the Mid-Continent and Mississippi.
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 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 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.
| | |
| 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
June 30, | | | Six months ended
June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Revenues | | | | | | | | | | | | | | | | |
Natural gas | | $ | 38,300 | | | $ | 38,819 | | | $ | 79,489 | | | $ | 86,807 | |
Crude oil | | | 21,548 | | | | 10,875 | | | | 38,131 | | | | 24,721 | |
Natural gas liquids (NGLs) | | | 13,161 | | | | 2,662 | | | | 23,082 | | | | 7,528 | |
| | | | | | | | | | | | | | | | |
Total product revenues | | | 73,009 | | | | 52,356 | | | | 140,702 | | | | 119,056 | |
Gain (loss) on sale of property and equipment | | | (28 | ) | | | 125 | | | | 452 | | | | 336 | |
Other | | | 637 | | | | 807 | | | | 1,047 | | | | 1,774 | |
| | | | | | | | | | | | | | | | |
Total revenues | | | 73,618 | | | | 53,288 | | | | 142,201 | | | | 121,166 | |
Operating Expenses | | | | | | | | | | | | | | | | |
Lease operating | | | 10,787 | | | | 9,155 | | | | 21,064 | | | | 17,892 | |
Gathering, processing and transportation | | | 4,281 | | | | 3,309 | | | | 8,309 | | | | 6,540 | |
Production and ad valorem taxes | | | 2,834 | | | | 3,105 | | | | 7,898 | | | | 7,375 | |
General and administrative (excluding share-based compensation) (a) | | | 10,941 | | | | 14,159 | | | | 22,497 | | | | 26,163 | |
| | | | | | | | | | | | | | | | |
Total direct operating expenses | | | 28,843 | | | | 29,728 | | | | 59,768 | | | | 57,970 | |
Share-based compensation (b) | | | 2,013 | | | | 1,668 | | | | 3,809 | | | | 4,689 | |
Exploration | | | 19,368 | | | | 9,541 | | | | 48,916 | | | | 15,570 | |
Depreciation, depletion and amortization | | | 33,036 | | | | 32,105 | | | | 67,879 | | | | 62,134 | |
Impairments (c) | | | 71,071 | | | | 1,124 | | | | 71,071 | | | | 1,124 | |
Other | | | — | | | | — | | | | — | | | | 465 | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 154,331 | | | | 74,166 | | | | 251,443 | | | | 141,952 | |
| | | | | | | | | | | | | | | | |
Operating loss | | | (80,713 | ) | | | (20,878 | ) | | | (109,242 | ) | | | (20,786 | ) |
Other income (expense) | | | | | | | | | | | | | | | | |
Interest expense | | | (14,143 | ) | | | (13,321 | ) | | | (27,627 | ) | | | (26,992 | ) |
Loss on extinguishment of debt (d) | | | (24,238 | ) | | | — | | | | (24,238 | ) | | | — | |
Derivatives | | | 7,001 | | | | (580 | ) | | | 8,329 | | | | 29,297 | |
Other | | | 129 | | | | 517 | | | | 273 | | | | 1,763 | |
| | | | | | | | | | | | | | | | |
Loss from continuing operations before income taxes | | | (111,964 | ) | | | (34,262 | ) | | | (152,505 | ) | | | (16,718 | ) |
Income tax benefit | | | 40,046 | | | | 13,165 | | | | 54,247 | | | | 6,387 | |
| | | | | | | | | | | | | | | | |
Loss from continuing operations | | | (71,918 | ) | | | (21,097 | ) | | | (98,258 | ) | | | (10,331 | ) |
Income from discontinued operations, net of tax | | | — | | | | 21,308 | | | | — | | | | 33,482 | |
Gain on sale of discontinued operations, net of tax | | | — | | | | 49,612 | | | | — | | | | 49,612 | |
| | | | | | | | | | | | | | | | |
Net income (loss) | | | (71,918 | ) | | | 49,823 | | | | (98,258 | ) | | | 72,763 | |
Less net income attributable to noncontrolling interests in discontinued operations | | | — | | | | (18,744 | ) | | | — | | | | (28,090 | ) |
| | | | | | | | | | | | | | | | |
Income (loss) attributable to PVA | | $ | (71,918 | ) | | $ | 31,079 | | | $ | (98,258 | ) | | $ | 44,673 | |
| | | | | | | | | | | | | | | | |
Income (loss) per share attributable to PVA – Basic | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (1.57 | ) | | $ | (0.46 | ) | | $ | (2.15 | ) | | $ | (0.23 | ) |
Discontinued operations | | | — | | | | 0.06 | | | | — | | | | 0.12 | |
Gain on sale of discontinued operations | | | — | | | | 1.08 | | | | — | | | | 1.09 | |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to PVA | | $ | (1.57 | ) | | $ | 0.68 | | | $ | (2.15 | ) | | $ | 0.98 | |
| | | | | | | | | | | | | | | | |
Income (loss) per share attributable to PVA – Diluted | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (1.57 | ) | | $ | (0.46 | ) | | $ | (2.15 | ) | | $ | (0.23 | ) |
Discontinued operations | | | — | | | | 0.06 | | | | — | | | | 0.12 | |
Gain on sale of discontinued operations | | | — | | | | 1.08 | | | | — | | | | 1.09 | |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to PVA | | $ | (1.57 | ) | | $ | 0.68 | | | $ | (2.15 | ) | | $ | 0.98 | |
| | | | | | | | | | | | | | | | |
Weighted average shares outstanding, basic | | | 45,768 | | | | 45,539 | | | | 45,724 | | | | 45,508 | |
Weighted average shares outstanding, diluted | | | 45,768 | | | | 45,790 | | | | 45,724 | | | | 45,767 | |
| | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Production | | | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | 8,869 | | | | 9,132 | | | | 18,594 | | | | 17,700 | |
Crude oil (MBbls) | | | 219 | | | | 148 | | | | 407 | | | | 334 | |
NGLs (MBbls) | | | 253 | | | | 76 | | | | 473 | | | | 185 | |
Total natural gas, crude oil and NGL production (MMcfe) | | | 11,699 | | | | 10,475 | | | | 23,870 | | | | 20,813 | |
Prices | | | | | | | | | | | | | | | | |
Natural gas ($ per Mcf) | | $ | 4.32 | | | $ | 4.25 | | | $ | 4.27 | | | $ | 4.90 | |
Crude oil ($ per Bbl) | | $ | 98.45 | | | $ | 73.64 | | | $ | 93.80 | | | $ | 74.09 | |
NGLs ($ per Bbl) | | $ | 52.04 | | | $ | 34.97 | | | $ | 48.82 | | | $ | 40.66 | |
Prices – Adjusted for derivative settlements | | | | | | | | | | | | | | | | |
Natural gas ($ per Mcf) | | $ | 4.80 | | | $ | 5.24 | | | $ | 4.88 | | | $ | 5.92 | |
Crude oil ($ per Bbl) | | $ | 97.87 | | | $ | 71.96 | | | $ | 92.93 | | | $ | 73.78 | |
NGLs ($ per Bbl) | | $ | 52.04 | | | $ | 34.97 | | | $ | 48.82 | | | $ | 40.66 | |
| (a) | Includes restructuring costs of approximately $4.2 million and $5.6 million for the three and six months ended June 30, 2010. |
| (b) | Our share-based compensation expense includes our stock option expense and the amortization of common, deferred and restricted stock and restricted stock unit awards related to employee and director compensation in accordance with accounting guidance for share-based payments. |
| (c) | Impairment of $71.1 million in the second quarter of 2011 relates to non-core, primarily Arkoma Basin properties for which we have signed an agreement to sell. |
| (d) | Attributable to the repurchase in April 2011 of approximately 98% of our 4.5% Convertible Senior Subordinated Notes due 2012. |
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited
(in thousands)
| | | | | | | | |
| | | As of | |
| | | June 30,
2011 | | | December 31,
2010 | |
Assets | | | | | | | | |
Current assets | | $ | 116,804 | | | $ | 214,340 | |
Net property and equipment | | | 1,728,121 | | | | 1,705,584 | |
Other assets | | | 24,705 | | | | 24,676 | |
| | | | | | | | |
Total assets | | $ | 1,869,630 | | | $ | 1,944,600 | |
| | | | | | | | |
Liabilities and shareholders’ equity | | | | | | | | |
Current liabilities | | $ | 95,372 | | | $ | 106,994 | |
Revolving credit facility | | | — | | | | — | |
Senior notes due 2016 | | | 293,009 | | | | 292,487 | |
Senior notes due 2019 | | | 300,000 | | | | — | |
Convertible notes due 2012 | | | 4,659 | | | | 214,049 | |
Other liabilities and deferred income taxes | | | 294,983 | | | | 350,794 | |
Total shareholders’ equity | | | 881,607 | | | | 980,276 | |
| | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 1,869,630 | | | $ | 1,944,600 | |
| | | | | | | | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Cash flows from operating activities | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | (71,918 | ) | | $ | 49,823 | | | $ | (98,258 | ) | | $ | 72,763 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations: | | | | | | | | | | | | | | | | |
Income from discontinued operations before income taxes | | | — | | | | (22,877 | ) | | | — | | | | (36,832 | ) |
Gain on sale of discontinued operations before income taxes | | | — | | | | (84,740 | ) | | | — | | | | (84,740 | ) |
Non-cash portion of loss on extinguishment of debt | | | 21,822 | | | | — | | | | 21,822 | | | | — | |
Depreciation, depletion and amortization | | | 33,036 | | | | 32,105 | | | | 67,879 | | | | 62,134 | |
Impairments | | | 71,071 | | | | 1,124 | | | | 71,071 | | | | 1,124 | |
Derivative contracts: | | | | | | | | | | | | | | | | |
Net (gains) losses | | | (7,001 | ) | | | 580 | | | | (8,329 | ) | | | (29,297 | ) |
Cash settlements | | | 5,031 | | | | 9,050 | | | | 11,775 | | | | 17,484 | |
Deferred income tax benefit | | | (40,046 | ) | | | 1,267 | | | | (54,247 | ) | | | (7,733 | ) |
Loss (gain) on the sale of property and equipment, net | | | 28 | | | | (125 | ) | | | (452 | ) | | | 129 | |
Dry hole and unproved leasehold expense | | | 14,082 | | | | 4,435 | | | | 41,081 | | | | 9,518 | |
Non-cash interest expense | | | 1,478 | | | | 2,965 | | | | 4,750 | | | | 6,220 | |
Share-based compensation | | | 2,013 | | | | 1,668 | | | | 3,809 | | | | 4,689 | |
Other, net | | | 29 | | | | 43 | | | | 265 | | | | (462 | ) |
Changes in operating assets and liabilities | | | 4,698 | | | | 19,606 | | | | 2,593 | | | | 30,672 | |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities from continuing operations | | | 34,323 | | | | 14,924 | | | | 63,759 | | | | 45,669 | |
| | | | | | | | | | | | | | | | |
Cash flows from investing activities | | | | | | | | | | | | | | | | |
Capital expenditures – property and equipment | | | (110,352 | ) | | | (103,589 | ) | | | (211,081 | ) | | | (168,081 | ) |
Proceeds from the sale of PVG units, net (a) | | | — | | | | 139,120 | | | | — | | | | 139,120 | |
Proceeds from the sale of property, plant and equipment, net | | | 336 | | | | 4 | | | | 696 | | | | 23,277 | |
Other, net | | | — | | | | 1,192 | | | | 100 | | | | 1,192 | |
| | | | | | | | | | | | | | | | |
Net cash (used in) provided by investing activities for continuing operations | | | (110,016 | ) | | | 36,727 | | | | (210,285 | ) | | | (4,492 | ) |
| | | | | | | | | | | | | | | | |
Cash flows from financing activities | | | | | | | | | | | | | | | | |
Dividends paid | | | (2,580 | ) | | | (2,575 | ) | | | (5,156 | ) | | | (5,131 | ) |
Proceeds from the issuance of Senior Notes due 2019 | | | 300,000 | | | | — | | | | 300,000 | | | | — | |
Repurchase of Convertible Notes | | | (232,963 | ) | | | — | | | | (232,963 | ) | | | — | |
Debt issuance costs paid | | | (6,559 | ) | | | — | | | | (6,559 | ) | | | — | |
Proceeds from the sale of PVG units, net (a) | | | — | | | | 22,125 | | | | — | | | | 199,125 | |
Distributions received from discontinued operations | | | — | | | | 3,566 | | | | — | | | | 11,218 | |
Other, net | | | 136 | | | | 1,232 | | | | 974 | | | | 1,844 | |
| | | | | | | | | | | | | | | | |
Net cash provided by financing activities from continuing operations | | | 58,034 | | | | 24,348 | | | | 56,296 | | | | 207,056 | |
| | | | | | | | | | | | | | | | |
Cash flows from discontinued operations | | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | — | | | | 29,237 | | | | — | | | | 77,759 | |
Net cash used in investing activities | | | — | | | | (1,743 | ) | | | — | | | | (18,112 | ) |
Net cash used in financing activities | | | — | | | | (27,494 | ) | | | — | | | | (59,647 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by discontinued operations | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (17,659 | ) | | | 75,999 | | | | (90,230 | ) | | | 248,233 | |
Cash and cash equivalents – beginning of period | | | 48,340 | | | | 251,251 | | | | 120,911 | | | | 79,017 | |
| | | | | | | | | | | | | | | | |
Cash and cash equivalents – end of period | | $ | 30,681 | | | $ | 327,250 | | | $ | 30,681 | | | $ | 327,250 | |
| | | | | | | | | | | | | | | | |
Supplemental disclosures of cash paid for: | | | | | | | | | | | | | | | | |
Interest (net of amounts capitalized) | | | 19,318 | | | | 20,190 | | | $ | 19,705 | | | $ | 20,975 | |
Income taxes (net of refunds received) | | | 24 | | | | 3,260 | | | $ | (96 | ) | | $ | 3,150 | |
| (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 of PVG. |
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES – unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
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 | | $ | (71,918 | ) | | $ | 31,079 | | | $ | (98,258 | ) | | $ | 44,673 | |
Adjustments for derivatives: | | | | | | | | | | | | | | | | |
Net (gains) losses included in net income | | | (7,001 | ) | | | 580 | | | | (8,329 | ) | | | (29,297 | ) |
Cash settlements | | | 5,031 | | | | 9,050 | | | | 11,775 | | | | 17,484 | |
Adjustment for impairments | | | 71,071 | | | | 1,124 | | | | 71,071 | | | | 1,124 | |
Adjustment for restructuring costs | | | 52 | | | | 4,170 | | | | 70 | | | | 5,647 | |
Adjustment for net loss (gain) on sale of assets | | | 28 | | | | (125 | ) | | | (452 | ) | | | 129 | |
Adjustment for loss on extinguishment of debt | | | 24,238 | | | | — | | | | 24,238 | | | | — | |
Adjustment for gain on sale of discontinued operations | | | — | | | | (84,740 | ) | | | — | | | | (84,740 | ) |
Impact of adjustments on income taxes | | | (33,413 | ) | | | 29,442 | | | | (34,992 | ) | | | 37,005 | |
| | | | | | | | | | | | | | | | |
| | $ | (11,912 | ) | | $ | (9,420 | ) | | $ | (34,877 | ) | | $ | (7,975 | ) |
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes | | | — | | | | — | | | | — | | | | (28 | ) |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to PVA, as adjusted (a) | | $ | (11,912 | ) | | $ | (9,420 | ) | | $ | (34,877 | ) | | $ | (8,003 | ) |
| | | | | | | | | | | | | | | | |
Net loss attributable to PVA, as adjusted, per share, diluted | | $ | (0.26 | ) | | $ | (0.21 | ) | | $ | (0.76 | ) | | $ | (0.17 | ) |
Reconciliation of GAAP “Net income (loss) from continuing operations” to Non-GAAP “Adjusted EBITDAX” | | | | | | | | | | | | | | | | |
Net income (loss) from continuing operations | | $ | (71,918 | ) | | $ | (21,097 | ) | | $ | (98,258 | ) | | $ | (10,331 | ) |
Income tax expense (benefit) | | | (40,046 | ) | | | (13,165 | ) | | | (54,247 | ) | | | (6,387 | ) |
Interest expense | | | 14,143 | | | | 13,321 | | | | 27,627 | | | | 26,992 | |
Depreciation, depletion and amortization | | | 33,036 | | | | 32,105 | | | | 67,879 | | | | 62,134 | |
Exploration | | | 19,368 | | | | 9,541 | | | | 48,916 | | | | 15,570 | |
Share-based compensation expense | | | 2,013 | | | | 1,668 | | | | 3,809 | | | | 4,689 | |
| | | | | | | | | | | | | | | | |
EBITDAX | | | (43,404 | ) | | | 22,373 | | | | (4,274 | ) | | | 92,667 | |
Adjustments for derivatives: | | | | | | | | | | | | | | | | |
Net (gains) losses included in net income | | | (7,001 | ) | | | 580 | | | | (8,329 | ) | | | (29,297 | ) |
Cash settlements | | | 5,031 | | | | 9,050 | | | | 11,775 | | | | 17,484 | |
Adjustment for impairments | | | 71,071 | | | | 1,124 | | | | 71,071 | | | | 1,124 | |
Adjustment for net loss (gain) on sale of assets | | | 28 | | | | (125 | ) | | | (452 | ) | | | 129 | |
Adjustment for non-cash portion of loss on extinguishment of debt | | | 21,822 | | | | — | | | | 21,822 | | | | — | |
| | | | | | | | | | | | | | | | |
Adjusted EBITDAX (b) | | $ | 47,547 | | | $ | 33,002 | | | $ | 91,613 | | | $ | 82,107 | |
| | | | | | | | | | | | | | | | |
| (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, impairments, restructuring costs, loss on the extinguishment of debt, gains and losses on the sale of assets 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. |
| (b) | Adjusted EBITDAX represents net income (loss) from continuing operations before income tax expense or benefit, interest expense, depreciation, depletion and amortization expense, exploration expense and share-based compensation expense, further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, restructuring costs, loss on the extinguishment of debt, and gains and losses on the sale of assets. 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 from continuing operations. |
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
2011 | | | Second
Quarter
2011 | | | YTD
2011 | | | Full-Year
2011 Guidance | |
Production: | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (Bcf) | | | 9.7 | | | | 8.9 | | | | 18.6 | | | | 34.0 | | | | — | | | | 35.0 | |
Crude oil (MBbls) | | | 188 | | | | 219 | | | | 407 | | | | 1,450 | | | | — | | | | 1,600 | |
NGLs (MBbls) | | | 220 | | | | 253 | | | | 473 | | | | 950 | | | | — | | | | 1,050 | |
Equivalent production (Bcfe) | | | 12.2 | | | | 11.699 | | | | 23.9 | | | | 48.5 | | | | — | | | | 50.5 | |
Equivalent daily production (MMcfe per day) | | | 135.2 | | | | 128.6 | | | | 131.9 | | | | 132.9 | | | | — | | | | 138.4 | |
Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating ($ per Mcfe) | | $ | 0.84 | | | | 0.92 | | | | 0.88 | | | | 0.75 | | | | — | | | | 0.80 | |
Gathering, processing and transportation costs ($ per Mcfe) | | $ | 0.33 | | | | 0.37 | | | | 0.35 | | | | 0.34 | | | | — | | | | 0.35 | |
Production and ad valorem taxes (percent of oil and gas revenues) | | | 7.5 | % | | | 3.9 | % | | | 5.6 | % | | | 5.0 | % | | | — | | | | 6.0 | % |
General and administrative: | | | | | | | | | | | | | | | | | | | | | | | | |
Recurring general and administrative | | $ | 11.5 | | | | 10.9 | | | | 22.4 | | | | 44.5 | | | | — | | | | 45.5 | |
Share-based compensation | | $ | 1.8 | | | | 2.0 | | | | 3.8 | | | | 6.5 | | | | — | | | | 7.5 | |
Restructuring | | $ | 0.1 | | | | 0.1 | | | | 0.1 | | | | 0.1 | | | | — | | | | 0.1 | |
Total reported G&A | | $ | 13.4 | | | | 13.0 | | | | 26.3 | | | | 51.1 | | | | — | | | | 53.1 | |
Exploration: | | | | | | | | | | | | | | | | | | | | | | | | |
Dry hole costs | | $ | 16.4 | | | | 2.1 | | | | 18.5 | | | | 18.5 | | | | — | | | | 19.0 | |
Unproved property amortization | | $ | 10.6 | | | | 12.0 | | | | 22.6 | | | | 45.0 | | | | — | | | | 47.0 | |
Other | | $ | 2.5 | | | | 5.3 | | | | 7.8 | | | | 17.0 | | | | — | | | | 18.0 | |
Total reported Exploration | | $ | 29.5 | | | | 19.4 | | | | 48.9 | | | | 80.5 | | | | — | | | | 84.0 | |
Depreciation, depletion and amortization ($ per Mcfe) | | $ | 2.86 | | | | 2.82 | | | | 2.84 | | | | 3.10 | | | | — | | | | 3.25 | |
Capital expenditures: | | | | | | | | | | | | | | | | | | | | | | | | |
Development drilling | | $ | 36.8 | | | | 82.9 | | | | 119.7 | | | | 253.0 | | | | — | | | | 263.0 | |
Exploratory drilling | | $ | 26.9 | | | | 12.9 | | | | 39.8 | | | | 44.0 | | | | — | | | | 50.0 | |
Pipeline, gathering, facilities | | $ | 0.4 | | | | 3.2 | | | | 3.6 | | | | 9.0 | | | | — | | | | 10.0 | |
Seismic | | $ | 1.8 | | | | 4.3 | | | | 6.1 | | | | 8.0 | | | | — | | | | 9.0 | |
Lease acquisitions, field projects and other | | $ | 38.3 | | | | 1.6 | | | | 39.9 | | | | 46.0 | | | | — | | | | 48.0 | |
Total oil and gas capital expenditures | | $ | 104.2 | | | | 104.9 | | | | 209.1 | | | | 360.0 | | | | — | | | | 380.0 | |
End of period debt outstanding | | $ | 508.7 | | | | 597.7 | | | | 506.5 | | | | | | | | | | | | | |
Effective interest rate | | | 10.6 | % | | | 10.5 | % | | | 10.5 | % | | | | | | | | | | | | |
Income tax benefit rate | | | 35.0 | % | | | 35.8 | % | | | 35.6 | % | | | | | | | | | | | | |
PENN VIRGINIA CORPORATION
GUIDANCE TABLE – unaudited – (continued)
Note to Guidance Table:
The following table shows our current derivative positions.
| | | | | | | | | | | | | | |
| | | Instrument Type | | Average Volume
Per Day | | | Weighted Average Price | |
| | | | | Floor/Swap | | | Ceiling | |
Natural gas: | | | | | (MMBtu | ) | | | | |
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 | |
Third quarter 2011 | | Swaps | | | 40,000 | | | | 5.06 | | | | | |
Fourth quarter 2011 | | Swaps | | | 10,000 | | | | 5.01 | | | | | |
First quarter 2012 | | Swaps | | | 10,000 | | | | 5.10 | | | | | |
Second quarter 2012 | | Swaps | | | 20,000 | | | | 5.31 | | | | | |
Third quarter 2012 | | Swaps | | | 20,000 | | | | 5.31 | | | | | |
Fourth quarter 2012 | | Swaps | | | 10,000 | | | | 5.10 | | | | | |
| | | |
Crude oil: | | | | | (barrels | ) | | | | |
Third quarter 2011 | | Costless collars | | | 360 | | | | 80.00 | | | | 103.30 | |
Fourth quarter 2011 | | Costless collars | | | 360 | | | | 80.00 | | | | 103.30 | |
First quarter 2012 | | Costless collars | | | 500 | | | | 100.00 | | | | 120.00 | |
Second quarter 2012 | | Costless collars | | | 500 | | | | 100.00 | | | | 120.00 | |
Third quarter 2012 | | Costless collars | | | 500 | | | | 100.00 | | | | 120.00 | |
Fourth quarter 2012 | | Costless collars | | | 500 | | | | 100.00 | | | | 120.00 | |
Third quarter 2011 | | Swaps | | | 500 | | | | 109.00 | | | | | |
Fourth quarter 2011 | | Swaps | | | 500 | | | | 109.00 | | | | | |
We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, operating income for the remainder of 2011 would increase or decrease by approximately $15.8 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the remainder of 2011 would increase or decrease by approximately $13.2 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.
