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 THIRD QUARTER 2010 RESULTS
27 PERCENT SEQUENTIAL QUARTERLY PRODUCTION INCREASE
19 PERCENT YEAR-OVER-YEAR PRO FORMA QUARTERLY PRODUCTION INCREASE
PRELIMINARY 2011 GUIDANCE REFLECTS PRODUCTION GROWTH AND REDUCED CAPITAL SPENDING
RADNOR, PA (BusinessWire) November 3, 2010 –Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months ended September 30, 2010, provided an update of full-year 2010 guidance and issued preliminary full-year 2011 guidance.
Third Quarter 2010 Highlights
Third quarter 2010 results, with comparisons to third quarter 2009 results, included the following:
• | Quarterly oil and gas production of 13.3 billion cubic feet of natural gas equivalent (Bcfe), or 144.3 million cubic feet of natural gas equivalent (MMcfe) per day, a 19 percent increase as compared to 11.2 Bcfe, or 121.3 MMcfe per day, pro forma to exclude production from Gulf Coast assets sold in January 2010 (27 percent sequential increase as compared to 10.5 Bcfe, or 115.1 MMcfe per day, in the second quarter of 2010); |
• | Operating loss of $53.1 million, as compared to a loss of $122.1 million, with significant impairment charges in both periods; |
• | Net loss from continuing operations of $30.2 million, or $0.66 per diluted share, as compared to a loss of $84.7 million, or $1.87 per diluted share; and |
• | Adjusted net loss attributable to PVA, a non-GAAP measure which excludes the effects of impairments, non-cash change in derivatives fair value, drilling rig standby charges, restructuring costs, and other gains or losses that affect comparability to the prior year period, of $13.9 million, or $0.31 per diluted share, as compared to a loss of $10.9 million, or $0.24 per diluted share. |
The operating loss and net loss from continuing operations in the third quarter of 2010, as reported above, included impairment charges of $35.1 million and dry hole costs of $9.0 million in the Mid-Continent region, as discussed in further detail below.
Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the financial tables later in this release.
Management Comment
A. James Dearlove, President and Chief Executive Officer said, “Production increased significantly during the third quarter of 2010 as compared to the previous quarter and the prior year quarter due to a resumption of drilling activity in late 2009 and a “catch-up” of completion activity following delays earlier in 2010. Production increases from the Granite Wash and Haynesville Shale were the primary drivers of production growth in the third quarter.
“Due to the recent decline in natural gas prices, in both the spot and futures markets, and with little in the way of catalysts to improve the situation in the near-term, we have elected to further increase our exposure to oil and liquids plays by shifting drilling from East Texas to our recently acquired Eagle Ford Shale acreage. In addition, we will shift drilling from Mississippi to the Marcellus Shale as we commence testing of our acreage in Pennsylvania. We believe that testing both our Eagle Ford Shale and Marcellus Shale positions are more value-added uses of capital in the near term than drilling in East Texas and Mississippi, despite encouraging recent results, as acreage in these two areas is largely held-by-production.
“As a result of this shift in drilling activity, we expect declines in production from East Texas and Mississippi until there is a meaningful recovery in natural gas prices. These production declines are expected to be offset in 2011 by production growth from the Granite Wash and other liquids-rich Mid-Continent plays, as well as expected production contributions from the Eagle Ford and Marcellus Shales.
“In this release, we have provided a preliminary view into 2011 where, relative to 2010, we expect to spend approximately 40 percent less on capital expenditures, while still growing production by a midpoint of approximately 11 percent. This reduction in capital spending, along with expected financial liquidity of over $500 million as we enter 2011, plus operating cash flows expected during 2011, will keep Penn Virginia on very solid financial footing and allow us to react to changing market conditions.”
Third Quarter 2010 Financial and Operational Results
Production in the third quarter of 2010 was approximately 13.3 Bcfe, or 144.3 MMcfe per day, 19 percent more than the pro forma 11.2 Bcfe, or 121.3 MMcfe per day, in the third quarter of 2009 and 27 percent more than the 10.5 Bcfe, or 115.1 MMcfe per day, in the second 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 natural gas liquids (NGLs) and crude oil primarily from the Granite Wash play. See our separate operational update news release dated November 3, 2010 for a more detailed discussion of operations.
Our realized natural gas price, prior to the impact of derivatives, during the third quarter of 2010 was $4.36 per thousand cubic feet (Mcf), 26 percent higher than the $3.45 per Mcf price in the third quarter of 2009 and three percent higher than the $4.25 per Mcf price in the second quarter of 2010. Our realized oil price, prior to the impact of derivatives, during the third quarter of 2010 was $70.97 per barrel, eight percent higher than the $65.64 per barrel price in the third quarter of 2009, but four percent lower than the $73.58 per barrel price in the second quarter of 2010. Our realized NGLs price during the third quarter of 2010 was $35.57 per barrel, 17 percent higher than the $30.29 per barrel price in the third quarter of 2009 and two percent higher than the $35.03 per barrel price in the second quarter of 2010. Adjusting for oil and gas hedges, our effective natural gas price during the third quarter of 2010 was $5.05 per Mcf and our effective oil price was $70.62 per barrel, or an increase of $0.69 per Mcf and decrease of $0.35 per barrel, respectively, over the realized prices.
The operating loss of $53.1 million was a $69.0 million improvement over the operating loss of $122.1 million in the prior year quarter, due primarily to an approximate $57.2 million decrease in impairment charges. The remaining $11.8 million decrease in operating loss was primarily due to the production increase and a 21 percent increase in the realized gas equivalent commodity price, from $4.25 to $5.15 per Mcfe.
As discussed below, third quarter 2010 direct operating expenses increased $3.4 million, or 13 percent, to $29.9 million as compared to $26.5 million in the third quarter of 2009.
• | Lease operating expenses decreased by $1.5 million, or 14 percent, to $9.3 million, or $0.70 per Mcfe produced, from $10.8 million, or $0.87 per Mcfe produced, resulting primarily from lower charges for equipment and compressor rentals, water disposal and contract labor, partially offset by higher repairs and maintenance costs; |
• | Gathering, processing and transportation expenses increased by $1.2 million, or 50 percent, to $3.6 million, or $0.27 per Mcfe produced, from $2.4 million, or $0.20 per Mcfe produced, resulting primarily from the production increase and a change in the geographic distribution of production |
from divested Gulf Coast assets to the Mid-Continent region; |
• | Production and ad valorem taxes increased by $1.5 million, or 38 percent, to $5.3 million, or 7.8 percent of total oil and gas revenues, from $3.8 million, or 7.3 percent of total oil and gas revenues, due to the production increase and a shift in production mix towards higher tax areas in the current year period; and |
• | General and administrative expense increased by $2.3 million to $11.7 million from $9.5 million, resulting from restructuring charges of $0.8 million as well as higher consulting and professional fees in the third quarter of 2010. |
Exploration expense increased $5.9 million, or 37 percent, to $22.0 million in the third quarter of 2010 from $16.1 million in the prior year quarter, primarily due to a $9.0 million charge for a dry hole in the Granite Wash and a $4.0 million increase in seismic costs, partially offset by a decrease in drilling rig standby charges relative to the prior year quarter.
Depreciation, depletion and amortization expenses decreased by $7.1 million, or 18 percent, to $33.2 million, or $2.50 per Mcfe, in the third quarter of 2010 from $40.3 million, or $3.25 per Mcfe, in the prior year quarter due to lower depletion rates in various plays due to mid-year reserve additions and impairments.
Impairments decreased by approximately $57.2 million, or 62 percent, to $35.1 million in the third quarter of 2010 from $92.4 million in the prior year quarter. In the prior year quarter, we recorded an $87.9 million impairment charge related to Gulf Coast assets held for sale. We recorded a $32.6 million impairment charge in the third quarter of 2010 primarily related to coal bed methane properties in the Mid-Continent region due to market declines in spot and future natural gas prices.
Full-Year 2010 Guidance Update
Full-year 2010 guidance highlights are as follows:
• | Full-year 2010 production guidance of 46.5 to 47.5 Bcfe, which reflects a reduction from the previous guidance range of 47.0 to 50.0 Bcfe as a result of an expected reduction in non-operated drilling and completion activity in the Granite Wash play, as well as East Texas and Mississippi, during the fourth quarter of 2010; |
• | Decreased fourth quarter production guidance to a range of 12.4 to 13.4 Bcfe, from a previous guidance range of 14.0 to 15.7 Bcfe, as discussed above; and |
• | Decreased oil and gas capital expenditures guidance to a range of $465 to $485 million from a range of $480 to $520 million of previous guidance (adjusted to reflect a $31.1 million Eagle Ford Shale acquisition announced in August 2010) due to reduced drilling and completion activity in the Granite Wash (non-operated), East Texas and Mississippi. |
Our currently anticipated oil and gas capital expenditures for 2010 include $300 to $310 million for drilling and completion activity and $145 to $150 million for land acquisitions. The reduced level of non-operated Granite Wash drilling during the fourth quarter of 2010 relates to a scheduled rotation of rigs operated by our joint venture partner to other locations outside of our area of mutual interest (AMI). The non-operated rig count, which has decreased to one rig currently, is expected to increase in the first quarter of 2011.
See the Guidance Table included in this release for guidance estimates for full-year 2010. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.
Preliminary Full-Year 2011 Guidance
As a result of the sale of non-core assets and other financing transactions during the past two years, we expect to have over $500 million of available liquidity in the form of cash and equivalents and revolver availability as we enter 2011. Assuming 2011 oil and gas capital expenditures are between $250 and $300 million, or approximately 35 to 45 percent lower than the midpoint of revised 2010 capital expenditures guidance, full-year 2011 production is estimated to be approximately 50 to 54 Bcfe. This range of preliminary 2011 production guidance is approximately six to 15 percent higher than the midpoint of revised 2010 production guidance. Our existing financial liquidity and expected cash flows from operating activities are expected to be sufficient to fund our anticipated 2011 activity levels.
Capital Resources and Liquidity, Interest Expense and Impact of Derivatives
As of September 30, 2010, we had outstanding borrowings of $530.0 million ($504.5 million carrying value), consisting of $300 million ($292 million carrying value) of senior unsecured notes due 2016 and $230 million ($212 million carrying value) of convertible senior subordinated notes due 2012, with no borrowings under our revolving credit facility. Net of cash and equivalents of $205 million, our net indebtedness at September 30, 2010 was $300 million.
Currently, we have approximately $625 million of financial liquidity, excluding cash flows from operating activities, comprised of cash on hand ($205 million), committed availability under our revolving credit facility ($300 million) and an additional $120 million of borrowing base availability. Together with ongoing cash flows from operating activities, supplemented by natural gas and crude oil hedges, we expect this financial liquidity to be sufficient to fund our anticipated capital needs for the remainder of 2010 and 2011.
Interest expense decreased to $13.2 million in the third quarter of 2010 from $16.3 million in the third quarter of 2009. The decrease was primarily due to a $2.9 million reclassification to expense from accumulated other comprehensive income in the third quarter of 2009 as a result of the discontinuation of hedge accounting related to our interest rate swaps. Cash interest expense decreased from $11.1 million in the prior year quarter to $10.8 million in the third quarter of 2010, because we had no outstanding borrowings under our revolving credit facility during 2010.
Due to fluctuations in commodity prices during the third quarter of 2010, derivatives income was $15.1 million as compared to derivatives income of $0.3 million in the prior year quarter. Third quarter 2010 cash settlements of our derivatives resulted in net cash receipts of $6.8 million, as compared to $15.8 million of net cash receipts in the prior year quarter.
Third Quarter 2010 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss third quarter 2010 financial and operational results, is scheduled for Thursday, November 4, 2010 at 10:00 a.m. ET. Prepared remarks by A. James Dearlove, 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 9601694), 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 9601694. 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.
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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, natural gas liquids, or NGLs, and crude oil; our ability to access external sources of capital; uncertainties relating to the occurrence and success of capital-raising transactions, including securities offerings and asset sales; reductions in the borrowing base under the Revolver; our ability to develop and replace oil and gas reserves and the price for which such reserves can be acquired; any impairment write-downs of our reserves or assets; reductions in our anticipated capital expenditures; the relationship between natural gas, NGL and crude oil; the projected demand for and supply of natural gas, NGLs and crude oil; the availability and costs of required drilling rigs, production equipment and materials; our ability to obtain adequate pipeline transportation capacity for our oil and gas production; competition among producers in the oil and natural gas industry generally; the extent to which the amount and quality of actual production of our oil and natural gas differ from estimated proved oil and gas reserves; operating risks, including unanticipated geological problems, incidental to our business; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated start-up dates of our oil and natural gas production; environmental risks affecting the drilling and producing of oil and gas wells; the timing of receipt of necessary governmental permits by us; hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks); and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2009. 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 | ||
Mail: invest@pennvirginia.com |
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - unaudited
(in thousands, except per share data)
Three months ended | Nine months ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues | ||||||||||||||||
Natural gas | $ | 47,476 | $ | 36,654 | $ | 134,283 | $ | 129,305 | ||||||||
Crude oil | 13,396 | 13,259 | 38,117 | 31,412 | ||||||||||||
Natural gas liquids (NGLs) | 7,459 | 2,847 | 14,987 | 10,553 | ||||||||||||
Gain on sale of property and equipment | 280 | 1,945 | 616 | 1,945 | ||||||||||||
Other | 342 | 1,014 | 2,116 | 2,981 | ||||||||||||
68,953 | 55,719 | 190,119 | 176,196 | |||||||||||||
Operating Expenses | ||||||||||||||||
Lease operating | 9,256 | 10,787 | 27,148 | 34,208 | ||||||||||||
Gathering, processing and transportation | 3,625 | 2,424 | 10,165 | 8,580 | ||||||||||||
Production and ad valorem taxes | 5,309 | 3,842 | 12,684 | 11,305 | ||||||||||||
General and administrative (excluding equity compensation) (a) | 11,734 | 9,456 | 37,897 | 28,086 | ||||||||||||
Total direct operating expenses | 29,924 | 26,509 | 87,894 | 82,179 | ||||||||||||
Equity-based compensation (b) | 1,711 | 2,490 | 6,400 | 7,445 | ||||||||||||
Exploration | 22,020 | 12,406 | 37,590 | 34,587 | ||||||||||||
Exploration - drilling rig standby charges (c) | — | 3,711 | — | 20,314 | ||||||||||||
Depreciation, depletion and amortization | 33,224 | 40,319 | 95,358 | 122,095 | ||||||||||||
Impairments | 35,127 | 92,353 | 36,251 | 96,828 | ||||||||||||
Other | — | — | 465 | 1,599 | ||||||||||||
Total operating expenses | 122,006 | 177,788 | 263,958 | 365,047 | ||||||||||||
Operating loss | (53,053 | ) | (122,069 | ) | (73,839 | ) | (188,851 | ) | ||||||||
Other income (expense) | ||||||||||||||||
Interest expense | (13,198 | ) | (16,279 | ) | (40,190 | ) | (31,846 | ) | ||||||||
Derivatives | 15,113 | 281 | 44,410 | 20,483 | ||||||||||||
Other | 342 | 4 | 2,105 | 1,254 | ||||||||||||
Loss from continuing operations before income taxes | (50,796 | ) | (138,063 | ) | (67,514 | ) | (198,960 | ) | ||||||||
Income tax benefit | 20,637 | 53,351 | 27,024 | 77,399 | ||||||||||||
Net loss from continuing operations | (30,159 | ) | (84,712 | ) | (40,490 | ) | (121,561 | ) | ||||||||
Income from discontinued operations, net of tax | — | 15,321 | 33,482 | 32,781 | ||||||||||||
Gain on sale of discontinued operations, net of tax | — | — | 49,612 | — | ||||||||||||
Net income (loss) | (30,159 | ) | (69,391 | ) | 42,604 | (88,780 | ) | |||||||||
Less net income attributable to noncontrolling interests in discontinued operations | — | (10,509 | ) | (28,090 | ) | (20,512 | ) | |||||||||
Income (loss) attributable to PVA | $ | (30,159 | ) | $ | (79,900 | ) | $ | 14,514 | $ | (109,292 | ) | |||||
Income (loss) per share attributable to PVA - Basic | ||||||||||||||||
Continuing operations | $ | (0.66 | ) | $ | (1.87 | ) | $ | (0.89 | ) | $ | (2.80 | ) | ||||
Discontinued operations | — | 0.11 | 0.12 | 0.28 | ||||||||||||
Gain on sale of discontinued operations | — | — | 1.09 | — | ||||||||||||
Net income (loss) attributable to PVA | $ | (0.66 | ) | $ | (1.76 | ) | $ | 0.32 | $ | (2.52 | ) | |||||
Income (loss) per share attributable to PVA - Diluted | ||||||||||||||||
Continuing operations | $ | (0.66 | ) | $ | (1.87 | ) | $ | (0.89 | ) | $ | (2.80 | ) | ||||
Discontinued operations | — | 0.11 | 0.12 | 0.28 | ||||||||||||
Gain on sale of discontinued operations | — | — | 1.09 | — | ||||||||||||
Net income (loss) attributable to PVA | $ | (0.66 | ) | $ | (1.76 | ) | $ | 0.32 | $ | (2.52 | ) | |||||
Weighted average shares outstanding, basic | 45,591 | 45,427 | 45,534 | 43,324 | ||||||||||||
Weighted average shares outstanding, diluted | 45,591 | 45,427 | 45,733 | 43,324 | ||||||||||||
Three months ended | Nine months ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Production | ||||||||||||||||
Natural gas (MMcf) | 10,890 | 10,634 | 28,590 | 33,858 | ||||||||||||
Crude oil (MBbls) | 189 | 202 | 522 | 588 | ||||||||||||
NGLs (MBbls) | 210 | 94 | 395 | 381 | ||||||||||||
Total natural gas, crude oil and NGL production (MMcfe) | 13,280 | 12,410 | 34,093 | 39,672 | ||||||||||||
Prices | ||||||||||||||||
Natural gas ($ per Mcf) | $ | 4.36 | $ | 3.45 | $ | 4.70 | $ | 3.82 | ||||||||
Crude oil ($ per Bbl) | $ | 70.97 | $ | 65.64 | $ | 72.96 | $ | 53.42 | ||||||||
NGLs ($ per Bbl) | $ | 35.57 | $ | 30.29 | $ | 37.96 | $ | 27.70 | ||||||||
Prices - Adjusted for derivative settlements | ||||||||||||||||
Natural gas ($ per Mcf) | $ | 5.05 | $ | 4.90 | $ | 5.59 | $ | 5.15 | ||||||||
Crude oil ($ per Bbl) | $ | 70.62 | $ | 70.39 | $ | 72.64 | $ | 59.70 | ||||||||
NGLs ($ per Bbl) | $ | 35.57 | $ | 30.29 | $ | 37.96 | $ | 27.70 |
(a) | Includes restructuring costs of $0.8 million and $6.4 million for the three and nine months ended September 30, 2010, respectively. |
(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)
September 30, 2010 | December 31, 2009 | |||||||
Assets | ||||||||
Current assets | $ | 293,840 | $ | 192,134 | ||||
Current assets of discontinued operations | — | 107,108 | ||||||
Net property and equipment | 1,657,683 | 1,479,452 | ||||||
Other assets | 28,900 | 26,470 | ||||||
Noncurrent assets of discontinued operations | — | 1,083,343 | ||||||
Total assets | $ | 1,980,423 | $ | 2,888,507 | ||||
Liabilities and shareholders’ equity | ||||||||
Current liabilities | $ | 158,722 | $ | 75,620 | ||||
Current liabilities of discontinued operations | — | 77,915 | ||||||
Revolving credit facility | — | — | ||||||
Senior notes | 292,369 | 291,749 | ||||||
Convertible notes | 212,155 | 206,678 | ||||||
Other liabilities and deferred taxes | 314,286 | 351,409 | ||||||
Noncurrent liabilities of discontinued operations | — | 647,137 | ||||||
PVA shareholders’ equity | 1,002,891 | 908,088 | ||||||
Noncontrolling interests in discontinued operations | — | 329,911 | ||||||
Total shareholders’ equity | 1,002,891 | 1,237,999 | ||||||
Total liabilities and shareholders’ equity | $ | 1,980,423 | $ | 2,888,507 | ||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
Three months ended | Nine months ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net income (loss) | $ | (30,159 | ) | $ | (69,391 | ) | $ | 42,604 | $ | (88,780 | ) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Net income from discontinued operations | — | (18,267 | ) | (36,832 | ) | (40,593 | ) | |||||||||
Gain on sale of discontinued operations | — | — | (84,740 | ) | — | |||||||||||
Depreciation, depletion and amortization | 33,224 | 40,319 | 95,358 | 122,095 | ||||||||||||
Impairments | 35,127 | 92,353 | 36,251 | 96,828 | ||||||||||||
Derivative contracts: | ||||||||||||||||
Total derivative gains | (15,113 | ) | 2,644 | (44,410 | ) | (17,055 | ) | |||||||||
Cash receipts to settle derivatives | 6,803 | 15,821 | 24,287 | 47,801 | ||||||||||||
Deferred income taxes | 13,882 | (51,928 | ) | 6,149 | (70,728 | ) | ||||||||||
Gain on the sale of property and equipment, net | (280 | ) | (1,945 | ) | (151 | ) | (1,945 | ) | ||||||||
Dry hole and unproved leasehold expense | 17,010 | 10,593 | 26,501 | 30,476 | ||||||||||||
Non-cash interest expense | 2,869 | 2,818 | 9,089 | 7,213 | ||||||||||||
Share-based compensation | 1,711 | 2,490 | 6,400 | 7,445 | ||||||||||||
Other, net | 94 | (1,910 | ) | (341 | ) | 2,088 | ||||||||||
Changes in operating assets and liabilities | (41,962 | ) | 18,154 | (11,290 | ) | 12,348 | ||||||||||
Net cash provided by operating activities | 23,206 | 41,751 | 68,875 | 107,193 | ||||||||||||
Cash flows from investing activities | ||||||||||||||||
Capital expenditures - property and equipment | (145,629 | ) | (18,260 | ) | (313,710 | ) | (183,528 | ) | ||||||||
Proceeds from the sale of PVG units, net (a) | — | — | 139,120 | — | ||||||||||||
Proceeds from the sale of property, plant and equipment, net | 1,895 | 2,576 | 25,172 | 7,815 | ||||||||||||
Other, net | — | — | 1,192 | 11 | ||||||||||||
Net cash used in investing activities | (143,734 | ) | (15,684 | ) | (148,226 | ) | (175,702 | ) | ||||||||
Cash flows from financing activities | ||||||||||||||||
Dividends paid | (2,569 | ) | (2,559 | ) | (7,700 | ) | (7,278 | ) | ||||||||
Distributions received from discontinued operations | — | 11,868 | 11,218 | 34,932 | ||||||||||||
Repayments of short-term borrowings | — | — | — | (7,542 | ) | |||||||||||
Repayment of revolving credit facility borrowings | — | (70,000 | ) | — | (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) | — | 118,080 | 199,125 | 118,080 | ||||||||||||
Debt issuance costs paid | — | (860 | ) | — | (9,687 | ) | ||||||||||
Other, net | 299 | — | 2,143 | — | ||||||||||||
Net cash provided by (used in) financing activities | (2,270 | ) | 56,529 | 204,786 | 152,349 | |||||||||||
Cash flows from discontinued operations | ||||||||||||||||
Net cash provided by operating activities | — | 42,295 | 77,759 | 114,830 | ||||||||||||
Net cash used in investing activities | — | (42,972 | ) | (18,112 | ) | (75,275 | ) | |||||||||
Net cash used in financing activities | — | 677 | (59,647 | ) | (39,555 | ) | ||||||||||
Net cash provided by discontinued operations | — | — | — | — | ||||||||||||
Net increase (decrease) in cash and cash equivalents | (122,798 | ) | 82,596 | 125,435 | 83,840 | |||||||||||
Cash and cash equivalents - beginning of period | 327,250 | 1,244 | 79,017 | — | ||||||||||||
Cash and cash equivalents - end of period | $ | 204,452 | $ | 83,840 | $ | 204,452 | $ | 83,840 | ||||||||
(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 September 30, | Nine months ended September 30, | |||||||||||||||
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 | $ | (30,159 | ) | $ | (79,900 | ) | $ | 14,514 | $ | (109,292 | ) | |||||
Adjustments for derivatives: | ||||||||||||||||
Derivative (gains) losses included in net income | (15,113 | ) | 2,644 | (44,410 | ) | (17,055 | ) | |||||||||
Cash receipts to settle derivatives | 6,803 | 15,821 | 24,287 | 47,801 | ||||||||||||
Adjustment for drilling rig standby charges | — | 3,711 | — | 20,314 | ||||||||||||
Adjustment for impairments | 35,127 | 92,353 | 36,251 | 96,828 | ||||||||||||
Adjustment for restructuring costs | 787 | — | 6,434 | — | ||||||||||||
Adjustment for net gain on sale of assets | (280 | ) | (1,945 | ) | (151 | ) | (346 | ) | ||||||||
Adjustment for gain on sale of discontinued operations | — | — | (84,740 | ) | — | |||||||||||
Impact of adjustments on income taxes | (11,101 | ) | (43,505 | ) | 26,157 | (57,396 | ) | |||||||||
$ | (13,936 | ) | $ | (10,821 | ) | $ | (21,658 | ) | $ | (19,146 | ) | |||||
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes | — | (34 | ) | (28 | ) | (68 | ) | |||||||||
Net loss attributable to PVA, as adjusted (a) | $ | (13,936 | ) | $ | (10,855 | ) | $ | (21,686 | ) | $ | (19,214 | ) | ||||
Net loss attributable to PVA, as adjusted, per share, diluted | $ | (0.31 | ) | $ | (0.24 | ) | $ | (0.47 | ) | $ | (0.44 | ) |
(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 2010. 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 | YTD 2010 | Full-Year 2010 Guidance | ||||||||||||||||||||||||
Production: | ||||||||||||||||||||||||||||
Natural gas (Bcf) | 8.6 | 9.1 | 10.9 | 28.6 | 38.3 | - | 39.0 | |||||||||||||||||||||
Crude oil (MBbls) | 186 | 148 | 189 | 523 | 700 | - | 725 | |||||||||||||||||||||
NGLs (MBbls) | 109 | 76 | 210 | 395 | 675 | - | 700 | |||||||||||||||||||||
Equivalent production (Bcfe) | 10.3 | 10.5 | 13.3 | 34.1 | 46.5 | - | 47.5 | |||||||||||||||||||||
Equivalent daily production (MMcfe per day) | 114.9 | 115.1 | 144.3 | 124.9 | 127.4 | - | 130.1 | |||||||||||||||||||||
Operating expenses: | ||||||||||||||||||||||||||||
Lease operating ($ per Mcfe)* | $ | 0.85 | 0.87 | 0.70 | 0.80 | 0.75 | - | 0.80 | ||||||||||||||||||||
Gathering, processing and transportation costs ($ per Mcfe)* | $ | 0.31 | 0.32 | 0.27 | 0.30 | 0.30 | - | 0.32 | ||||||||||||||||||||
Production and ad valorem taxes (percent of oil and gas revenues)* | 6.4 | % | 5.9 | % | 7.8 | % | 6.8 | % | 6.5 | % | - | 7.0 | % | |||||||||||||||
General and administrative* | $ | 10.5 | 10.0 | 10.9 | 31.4 | 42.5 | 43.5 | |||||||||||||||||||||
Equity-based compensation | $ | 3.0 | 1.7 | 1.7 | 6.4 | 8.0 | 8.5 | |||||||||||||||||||||
Restructuring | $ | 1.5 | 4.2 | 0.8 | 6.5 | 8.0 | 8.5 | |||||||||||||||||||||
Exploration | $ | 6.0 | 9.5 | 22.0 | 37.5 | 51.0 | - | 53.0 | ||||||||||||||||||||
Depreciation, depletion and amortization ($ per Mcfe) | $ | 2.90 | 3.06 | 2.50 | 2.80 | 2.70 | - | 2.80 | ||||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||||||
Development drilling | $ | 37.9 | 71.6 | 81.1 | 190.6 | 240.0 | - | 245.0 | ||||||||||||||||||||
Exploratory drilling | $ | 3.7 | 4.4 | 13.0 | 21.1 | 60.0 | - | 65.0 | ||||||||||||||||||||
Pipeline, gathering, facilities | $ | 0.2 | 0.5 | 0.2 | 0.9 | 5.0 | - | 6.0 | ||||||||||||||||||||
Seismic | $ | 0.4 | 4.1 | 4.0 | 8.5 | 17.0 | - | 19.0 | ||||||||||||||||||||
Lease acquisitions, field projects and other | $ | 35.5 | 36.1 | 48.7 | 120.3 | 143.0 | - | 150.0 | ||||||||||||||||||||
Total oil and gas capital expenditures | $ | 77.7 | 116.7 | 147.0 | 341.4 | 465.0 | - | 485.0 | ||||||||||||||||||||
End of period debt outstanding | $ | 500.5 | 502.5 | 504.5 | 504.5 | |||||||||||||||||||||||
Effective interest rate | 10.9 | % | 11.0 | % | 10.9 | % | 11.0 | % | ||||||||||||||||||||
Income tax benefit rate | 38.6 | % | 38.4 | % | 40.6 | % | 40.0 | % | ||||||||||||||||||||
Cash distributions received from PVG and PVR | $ | 7.7 | 3.5 | — | 11.2 | 11.2 | - | 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 as of September 30, 2010.
Weighted Average Price | ||||||||||||||||
Instrument Type | Average Volume Per Day | Floor | Ceiling | |||||||||||||
Natural gas: | (MMBtu | ) | ||||||||||||||
Fourth quarter 2010 | Costless collars | 50,000 | 5.65 | 8.77 | ||||||||||||
First quarter 2011 | Costless collars | 50,000 | 5.65 | 8.77 | ||||||||||||
Second quarter 2011 | Costless collars | 30,000 | 5.67 | 7.58 | ||||||||||||
Third quarter 2011 | Costless collars | 30,000 | 5.67 | 7.58 | ||||||||||||
Fourth quarter 2011 | Costless collars | 20,000 | 6.00 | 8.50 | ||||||||||||
First quarter 2012 | Costless collars | 20,000 | 6.00 | 8.50 | ||||||||||||
Second quarter 2012 | Swaps | 10,000 | 5.52 | |||||||||||||
Third quarter 2012 | Swaps | 10,000 | 5.52 | |||||||||||||
Crude oil: | (barrels | ) | ||||||||||||||
Fourth quarter 2010 | Costless collars | 500 | 60.00 | 74.75 | ||||||||||||
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 the remainder of 2010 would increase or decrease by approximately $10.1 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, operating income for 2010 would increase or decrease by approximately $1.5 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.