2009 Proved Reserves of 942 Bcfe
161 Percent Reserve Replacement - 285 Percent Excluding Price Revisions
Reserve Replacement Cost of $2.09 Per Mcfe - $1.18 Excluding Price Revisions
2009 Pro Forma Production Growth of 13 Percent
2010 Pro Forma Production Growth Guidance of Six to 13 Percent
Currently Running Six Operated Rigs
RADNOR, Pa.-- Penn Virginia Corporation (NYSE: PVA) today announced record levels of proved oil and gas reserves and production and provided an update of its oil and gas operations, including full-year and fourth quarter 2009 results, guidance and liquidity.
Full-Year and Fourth Quarter 2009 Highlights
Operational results for our oil and gas segment for the year ended December 31, 2009 included the following:
-- Record year-end proved oil and gas reserves of 942 billion cubic feet of natural gas equivalent (Bcfe), an increase of three percent over 916 Bcfe at year-end 2008; -- Record oil and gas production of 51.0 Bcfe, an increase of nine percent over 46.9 Bcfe in 2008; -- Pro forma to exclude production from Gulf Coast assets that were sold in January 2010, oil and gas production was 45.2 Bcfe, an increase of 13 percent over 39.9 Bcfe in 2008; -- Reserve replacement ratio, excluding price revisions, of 285 percent at a cost of $1.18 per thousand cubic feet of natural gas equivalent (Mcfe); and -- Oil and gas capital expenditures of approximately $172 million, including approximately $143 million for drilling and completion activities to drill 32 (20.7 net) wells, with a 96 percent success rate.
Operational results for our oil and gas segment during the fourth quarter of 2009 included the following:
-- Oil and gas production of 11.3 Bcfe, as compared to 13.2 Bcfe in the fourth quarter of 2008; -- Pro forma to exclude production from Gulf Coast assets, oil and gas production was 10.3 Bcfe, as compared to 11.1 Bcfe in the fourth quarter of 2008; and -- Oil and gas capital expenditures of approximately $28 million, including approximately $19 million for drilling and completion activities to drill five (2.3 net) wells, with one (0.4 net) successful well and four (1.8 net) wells waiting on completion.
A. James Dearlove, President and Chief Executive Officer, said, "During 2009, we were able to achieve a record level of production and grew our proved reserves in spite of sharply lower natural gas prices and capital expenditures that were less than a third of those incurred in 2008.
"As the natural gas price environment appears to have stabilized in late 2009 and early 2010, we began to increase our drilling activity in two core areas, the Granite Wash and the Lower Bossier (Haynesville) Shale, which deliver solid returns. As the result of this resumed drilling, and assuming gas prices do not decrease significantly again, we expect to reverse recent quarterly production declines and deliver sequential production growth during 2010, setting the stage for more meaningful growth in 2011. We also bolstered our cash liquidity during 2009 and early 2010 with new financing and divestitures, providing more liquidity than needed to conduct our planned activities. While we expect higher levels of capital expenditures in 2010 to support our plan, we will continue to monitor natural gas prices and will remain flexible as to our spending levels as 2010 progresses.
"We have a multi-year inventory of high-quality drilling projects in some of the best domestic unconventional and resource plays and we have ample capital resources to develop these projects at the appropriate pace depending on market conditions. Our horizontal drilling success and increased production in these plays over the past two years has positioned us for relatively low-risk, high-return growth in both production and reserves in coming years."
Full-Year 2010 Guidance and Liquidity Updates
Full-year 2010 guidance and liquidity highlights are as follows:
-- Production guidance of 47.0 to 51.0 Bcfe, unchanged as compared to previous guidance, and representing a six to 13 percent increase over 2009 production of 45.2 Bcfe, pro forma for production from Gulf Coast assets that were sold in January 2010; -- Oil and gas capital expenditures guidance of $375 to $425 million, as compared to a range of $300 to $400 million of previous guidance; and -- Approximately $400 million of current financial liquidity comprised of cash on hand and availability under our revolving credit facility.
As discussed further in our operational update below, currently anticipated oil and gas capital expenditures for 2010 include approximately $300 million for drilling wells in our horizontal Granite Wash, Lower Bossier Shale, Selma Chalk and Cotton Valley development plays and to test wells on our Marcellus shale leasehold position. In addition, we plan to spend approximately $80 million for leasehold acquisition, primarily in the Marcellus Shale and Granite Wash plays. We plan to release additional 2010 guidance details in a separate fourth quarter and full-year 2009 financial results press release on February 10, 2010.
2009 Proved Reserves, Production and Capital Expenditures
Proved reserves increased three percent to a record 942 Bcfe at year-end 2009 from 916 Bcfe at year-end 2008. Natural gas comprised approximately 83 percent of year-end proved reserves and 46 percent of the reserves were proved developed. Excluding price revisions, which reduced reserves by 63 Bcfe, we replaced 285 percent of our 2009 production by adding approximately 145 Bcfe of proved reserves from extensions, discoveries and additions, net of other revisions. The reserve increases were primarily attributable to the Granite Wash, Lower Bossier Shale and Selma Chalk, with decreases in the Cotton Valley and royalty properties in Appalachia. Capital expenditures related to exploration and development, as well as leasehold acquisition, were approximately $172 million, or $1.18 per Mcfe of proved reserves added, excluding price revisions. Pro forma for the Gulf Coast divestiture, proved reserves increased four percent and, excluding price revisions, our reserve replacement ratio was 321% and our reserve replacement cost was $1.18 per Mcfe.
Proves Reserves at December 31, 2009(1) Natural Gas Natural Gas Oil and (in Bcfe) Equivalent Reserves Condensate Reserves (Bcf) Reserves (Bcfe) (MMBbls) Proved reserves at December 31, 2008 916.0 754.1 27.0 2009 production (51.0 ) (43.3 ) (1.3 ) 2009 extensions, discoveries and other 235.7 180.4 9.2 additions 2009 revisions - price (63.1 ) (52.2 ) (1.8 ) 2009 revisions - other (90.5 ) (50.7 ) (6.6 ) 2009 purchases (sales) of reserves in (4.7 ) (4.2 ) (0.1 ) place Proved reserves at December 31, 2009 942.4 784.1 26.4 Percentage of equivalent reserves 100.0 % 83.2 % 16.8 % Proved developed reserves at December 429.4 379.3 8.4 31, 2009 Percentage of proved reserves 45.6 % 48.4 % 31.7 % 2009 reserve replacement ratio(2) Including all revisions 161.0 % Excluding price revisions 284.7 % Excluding all revisions 462.1 % 2009 oil and gas capital expenditures $171.8 ($mil.) 2009 reserve replacement cost ($ per Mcfe)(2) Including all revisions $2.09 Excluding price revisions $1.18 Excluding all revisions $0.73 Present value of future net cash flows $708.4 before income taxes ($mil.)(1)
Production for the Production for the Proved Reserves (in Bcfe) Three Months Ended Year Ended As of December 31, December 31, December 31, Region 2009 2008 2009 2008 2009 2008 East Texas 2.7 3.4 13.1 13.4 403 419 Mid-Continent 3.1 2.9 12.8 7.6 199 141 Mississippi 1.7 1.9 7.8 7.3 175 155 Appalachia 2.7 2.9 11.5 11.5 141 170 Gulf Coast(3) 1.0 2.1 5.8 7.0 24 31 Totals 11.3 13.2 51.0 46.9 942 916 Pro Forma Totals(4) 10.3 11.1 45.2 39.9 918 885
The estimated reserves and present values were based on flat pricing assumptions for Henry Hub natural gas of $3.87 per million British thermal units (MMBtu) and West Texas Intermediate crude oil of $61.18 per barrel. (1) These compare to prices of $5.71 per MMBtu and $44.60 per barrel at December 31, 2008, respectively. Both prices exclude the effects of hedged production and six Mcfe equals one barrel of liquids. MMBbls is defined as one million barrels. Reserve replacement ratio is defined as the sum of reserve additions (reserve extensions, discoveries and other additions plus revisions plus (2) reserve purchases) divided by production for the year. Reserve replacement cost per Mcfe is defined as oil and gas capital expenditures divided by reserve additions. (3) We sold our Gulf Coast assets on January 29, 2010. (4) Pro forma to exclude divested Gulf Coast assets.
Record full-year 2009 production of 51.0 Bcfe, or 139.7 MMcfe per day, was nine percent higher than 46.9 Bcf, or 128.1 MMcfe per day, in 2008. Pro forma to exclude production from Gulf Coast assets, which were sold in January 2010, production in 2009 was 45.2 Bcfe, or 123.9 MMcfe per day, an increase of 13 percent over 39.9 Bcfe, or 109.0 MMcfe per day, in 2008. The production increase was attributable to production increases in the Granite Wash, the Lower Bossier Shale and the Selma Chalk plays, partially offset by a decrease in production from the Cotton Valley play and the Gulf Coast (subsequently divested) primarily due natural production declines and a decision to discontinue drilling on a temporary basis during 2009.
During 2009, oil and gas capital expenditures of approximately $172 million, consisted of:
-- $143 million to drill 32 (20.7 net) wells, including: o $140 million to drill 30 (19.7 net) development wells with 25 (16.9 net) successful wells, one (1.0 net) unsuccessful well (a 96 percent success rate) and four (1.8 net) wells waiting on completion at year-end 2009; and o $3 million to drill two (1.0 net) successful exploratory wells; -- $15 million for leasehold acquisition; -- $9 million for the expansion of gathering systems and other production facilities; and -- $5 million for the acquisition of seismic data and other geological and geophysical expenditures.
Fourth Quarter 2009 Operational Results
Production in the fourth quarter of 2009 was 11.3 Bcfe, or 123.1 MMcfe per day, 14 percent less than the 13.2 Bcfe, or 143.8 MMcfe per day, in the fourth quarter of 2008, and nine percent less than the 12.4 Bcfe, or 134.9 MMcfe per day, in the third quarter of 2009. Pro forma fourth quarter 2009 production was 10.3 Bcfe, or 111.8 MMcfe per day, a decrease of eight percent as compared to 11.1 Bcfe, or 121.1 MMcfe per day, in the fourth quarter of 2008. The decreases in production were due to natural production declines and significantly reduced drilling activity in the second half of 2009 due to low natural gas prices.
The realized natural gas price, prior to the impact of derivatives, during the fourth quarter of 2009 was $4.26 per thousand cubic feet (Mcf), 32 percent lower than the $6.29 per Mcf natural gas price in the fourth quarter of 2008 and 23 percent higher than the $3.45 per Mcf natural gas price in the third quarter of 2009. The realized oil price, prior to the impact of derivatives, during the fourth quarter of 2009 was $73.12 per barrel, 41 percent higher than the $51.93 per barrel oil price in the fourth quarter of 2008 and 11 percent higher than the $65.64 per barrel oil price in the third quarter of 2009. The realized natural gas liquids (NGLs) price during the fourth quarter of 2009 was $35.49 per barrel, 36 percent higher than the $26.14 per barrel NGLs price in the fourth quarter of 2008 and 17 percent higher than the $30.29 per barrel NGLs price in the third quarter of 2009. Adjusting for oil and gas hedges, the effective natural gas price during the fourth quarter of 2009 was $5.35 per Mcf and the effective oil price was $77.26 per barrel, or increases of $1.09 per Mcf and $4.14 per barrel, respectively.
During the fourth quarter of 2009, unit cash operating expenses of $1.92 per thousand cubic feet of natural gas equivalent (Mcfe) were four percent lower as compared to $1.99 per Mcfe in the fourth quarter of 2008, but were five percent higher as compared to the $1.82 per Mcfe in the third quarter of 2009, primarily due to the sequential production decrease. Exploration expense and impairments (on assets held for sale and subsequently divested in the Gulf Coast) were approximately $3 million and $10 million during the fourth quarter of 2009, respectively, decreases as compared to $23 million and $20 million in the fourth quarter of 2008. We plan to release full financial results in a separate fourth quarter and full-year 2009 financial results press release on February 10, 2010.
Mid-Continent - During the fourth quarter of 2009, we participated in four (1.3 net) Granite Wash horizontal wells, of which two (0.6 net) were completed and successful and two (0.6 net) are waiting on completion. The Sawawtsky 1-12H (45 percent working interest) and Janzen 1-27H (19 percent working interest) had initial rates of 16.5 and 15.5 MMcfe per day, respectively.
We are currently operating one drilling rig in the Granite Wash play and expect to add a second operated rig by the second quarter of 2010, with a third rig to be added to test recently acquired acreage during the second half of 2010. During 2010, we expect to drill up to 38 (17.4 net) horizontal development wells on our joint venture acreage in Washita County, Oklahoma and up to six (3.2 net) exploratory wells in new areas.
We continue to add to our acreage position in the Granite Wash play and have expanded our position in additional Granite Wash prospects, increasing our acreage position to approximately 24,000 net acres. We expect to spend up to $15 million in 2010 to add leasehold acreage in our existing and new prospect areas.
East Texas - During the fourth quarter of 2009, we participated in one (1.0 net) Lower Bossier (Haynesville) Shale horizontal well, which is waiting on completion.
We currently have three operated rigs drilling wells targeting the Lower Bossier Shale. We plan to reduce our rig count to two in the near future, drilling horizontal Lower Bossier Shale wells and horizontal Cotton Valley wells. During 2010, we expect to drill up to seven (7.0 net) horizontal Lower Bossier Shale wells and up to eight (6.5 net) horizontal Cotton Valley wells. At this time, we plan to defer testing of the Upper Bossier Shale as well as the Smackover Lime to 2011.
Mississippi - In January 2010, we recommenced horizontal drilling in the Selma Chalk with one operated rig. As previously announced, we made a $6.0 million acquisition in the Selma Chalk in January 2010, which added proved reserves of 3.4 Bcfe and production of approximately 1.0 MMcfe per day. The acquired 1,300 (925 net) acres are adjacent to our Gwinville Field assets and have an estimated 10 gross horizontal drilling locations. We expect to operate one rig in Mississippi drilling up to 18 (18.0 net) horizontal Selma Chalk wells.
Appalachia - In January 2010, we commenced drilling of our first Marcellus Shale well, a vertical test well, in Tioga County, Pennsylvania. A full core of the Marcellus section will be obtained during drilling, with the completion procedure dependent on the analyses of the core. During 2010, we expect to drill up to six (4.8 net) exploratory wells, with up to four of the wells being horizontal tests. We continue to add to our acreage position in the Marcellus Shale and were recently the successful bidder on approximately 3,700 net acres of State of Pennsylvania acreage in Potter County. We expect to spend up to $48 million in 2010 adding to our leasehold position.
Full-Year and Fourth Quarter 2009 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss fourth quarter 2009 financial and operational results, is scheduled for Thursday, February 11, 2010 at 3:00 p.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, 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 of the call will be available for two weeks by dialing 1-888-203-1112 (international: 1-719-457-0820) and using the following replay code: 7649645. An on-demand replay of the conference call will be available for two weeks at our website.
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 East Texas, the Mid-Continent region, Mississippi and the Appalachian Basin. PVA also owns approximately 51 percent of Penn Virginia GP Holdings, L.P. (NYSE: PVG), the owner of the general partner and the largest unit holder of Penn Virginia Resource Partners, L.P. (NYSE: PVR), a manager of coal and natural resource properties and related assets and the operator of a midstream natural gas gathering and processing business.
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 crude oil; our ability to develop and replace oil and gas reserves and the price for which such reserves can be acquired; the relationship between natural gas, NGL and crude oil prices; 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 coal industry generally; the extent to which the amount and quality of actual production of our oil and natural gas differs from estimated proved oil and gas reserves; 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, gathering and processing of natural gas; 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; uncertainties relating to the outcome of current and future litigation; 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).
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, 2008. 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 the result of new information, future events or otherwise.
Source: Penn Virginia Corporation
Released February 4, 2010