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 2012 RESULTS;
PROVIDES UPDATES OF OPERATIONS AND FULL-YEAR 2012 GUIDANCE
20 PERCENT INCREASE IN ADJUSTED EBITDAX OVER THE PRIOR YEAR QUARTER
OIL / LIQUIDS REPRESENTED 45 PERCENT OF PRODUCTION AND 86 PERCENT OF PRODUCT REVENUES DURING THE QUARTER
161 PERCENT INCREASE IN OIL PRODUCTION OVER THE PRIOR YEAR QUARTER
CONTINUED SUCCESS IN THE EAGLE FORD SHALE
CLOSED $100 MILLION SALE OF APPALACHIAN ASSETS
THIRD DRILLING RIG TO BE ADDED AND QUARTERLY CASH DIVIDEND DISCONTINUED
RADNOR, PA (BusinessWire) August 1, 2012 –Penn Virginia Corporation (NYSE: PVA) today reported results for the three months ended June 30, 2012 and provided an update of operations and full-year 2012 guidance.
Second Quarter 2012 Highlights
Second quarter 2012 results compared to the second quarter of 2011 were as follows:
| | • | | Oil and natural gas liquids (NGLs) production of 799 thousand barrels of oil equivalent (MBOE), or 45 percent of total equivalent production, an increase of 69 percent compared to 472 MBOE, or 24 percent of total equivalent production |
| | • | | Product revenues from the sale of natural gas, crude oil and NGLs of $76.2 million, or $7.16 per thousand cubic feet of natural gas equivalent (Mcfe), an increase of four percent compared to $73.0 million, or $6.24 per Mcfe (15 percent increase in per unit revenues) |
| | • | | Oil and NGL revenues of $65.9 million, or 86 percent of product revenues, an increase of 90 percent compared to $34.7 million, or 48 percent of product revenues |
| | • | | Gross operating margin, a non-GAAP (generally accepted accounting principles) measure defined as total product revenues less total direct operating expenses, of $4.92 per Mcfe, an increase of 30 percent compared to $3.78 per Mcfe |
| | • | | Adjusted EBITDAX, a non-GAAP measure, of $60.0 million, an increase of 20 percent compared to $50.0 million |
| | • | | Operating loss of $38.0 million, including $28.6 million of impairment charges, compared to a loss of $80.7 million, including $71.1 million of impairment charges |
| | • | | Net loss of $5.6 million, or $0.12 per diluted share, compared to a loss of $71.9 million, or $1.57 per diluted share |
| | • | | Adjusted net loss, a non-GAAP measure which excludes the effects of changes in derivatives fair value, impairments, restructuring costs and other gains or losses that affect comparability to the prior year period, of $10.8 million, or $0.23 per diluted share, compared to a loss of $11.9 million, or $0.26 per diluted share |
Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release.
Recent operational highlights are as follows:
| | • | | Seven (5.4 net) Eagle Ford Shale wells have been completed since early May, bringing the total to 51 (42.0 net) producing wells |
| | • | | The average peak gross production rate per well for the 44 of these wells with full-length laterals was 1,001 barrels of oil equivalent (BOE) per day (BOEPD) |
| | • | | The initial 30-day average gross production rate for 43 of these 44 wells with sufficient production history was 657 BOEPD |
| | • | | We currently have two active rigs, one rig drilling our 53rd well and the other rig in transit to drill our 54th well, with one (0.6 net) well waiting on completion. |
| | • | | A third drilling rig is expected to be added late in the third quarter of 2012 |
| | • | | Our Eagle Ford Shale net production was approximately 6,550 BOEPD during the second quarter of 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent |
| | • | | The first five “earning” wells on our 13,500-acre area of mutual interest (AMI) in Lavaca County, Texas have been drilled, with four wells completed and turned in line since April, one well waiting on completion and a rig in transit to drill the sixth and final earning well |
Management Comment
H. Baird Whitehead, President and Chief Executive Officer stated, “We are excited about our continuing success in the Eagle Ford Shale, particularly our recent expansion into Lavaca County where early drilling results are very promising. Our Eagle Ford Shale program has driven an overall year-over-year increase of approximately 70% in oil and NGLs production. In addition, second quarter oil and NGL revenues, excluding hedge impacts, were more than six times our natural gas revenue. We expect oil and NGLs to comprise approximately 84 percent of product revenues and 47 percent of production in 2012. Building on this success, we plan to devote over 90 percent of 2012 capital expenditures to the Eagle Ford Shale and to add a third rig back into our Eagle Ford Shale program late in the third quarter.
“To help fund our drilling program, we sold our Appalachian assets and we have hedged approximately 67 percent of expected oil production and 32 percent of expected gas production in the second half of 2012 at average prices of approximately $101 per barrel and $5.24 per MMBtu. Our Board of Directors has also decided to discontinue our quarterly cash dividend, which will add more than $10 million annually to our cash flow available for reinvestment.
“We are optimistic about the future. We expect continued success in the Eagle Ford Shale and, in light of the recent increase in natural gas prices, we view our significant natural gas positions in East Texas, Mississippi and the Granite Wash as having additional upside potential.”
Second Quarter 2012 Financial and Operational Results
Pricing
Our second quarter 2012 realized oil price of $102.14 per barrel was four percent higher than the $98.45 per barrel price in the prior year quarter. Our second quarter 2012 realized NGL price of $33.23 per barrel was 36 percent lower than the $52.04 per barrel price in the prior year quarter. Our second quarter 2012 realized natural gas price of $1.76 per thousand cubic feet (Mcf) was 59 percent lower than the $4.32 per Mcf price in the prior year quarter. Adjusting for oil and gas hedges, our second quarter 2012 effective oil price was $102.03 per barrel and our effective natural gas price was $2.72 per Mcf, or a decrease of $0.11 per barrel and an increase of $0.96 per Mcf over the realized prices.
Overview of Financial Results
The $38.0 million operating loss was $42.7 million, or 53 percent better than the $80.7 million loss in the prior year quarter, due primarily to a $31.2 million increase in oil and NGL revenues, a $42.5 million decrease in impairments, a $10.0 million decrease in exploration expense and a $5.0 million decrease in total direct operating expenses. The positive effect of these items was partially offset by a $28.0 million decrease in natural gas revenue and an $18.7 million increase in depreciation, depletion and amortization (DD&A) expense. Oil and NGL revenues were $65.9 million in the second quarter of 2012, 90 percent higher than the $34.7 million in the prior year quarter. Oil and NGL revenues were 86 percent of product revenues in the second quarter of 2012, compared to 48 percent in the prior year quarter.
Production
As shown in the table below, production in the second quarter of 2012 was 10.7 Bcfe, or 117.1 MMcfe per day, a nine percent decrease compared to 11.7 Bcfe, or 128.6 MMcfe per day, in the prior year quarter. As a percentage of total equivalent production, oil and NGL volumes were 45 percent in the second quarter of 2012 compared to 24 percent in the prior year quarter. Oil production increased 161 percent from 219 thousand barrels (MBbls) in the prior year quarter to 572 MBbls in the second quarter of 2012. On a pro forma basis, excluding production from the Mid-Continent assets sold in 2011, production in the prior year quarter was 11.1 Bcfe, or 122.3 MMcfe per day. The pro
forma four percent decrease was primarily the result of a 2.5 Bcfe, or 30 percent, decrease in natural gas production due to reduced natural gas drilling since mid-2010 in East Texas, Mississippi and, to a lesser extent, the Granite Wash, partially offset by a 337 MBOE (2.0 Bcfe), or 73 percent, increase in oil and NGL production.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Total and Daily Equivalent Production for the Three Months Ended | |
Region / Play Type | | June 30,
2012 | | | June 30,
2011 | | | Mar. 31,
2012 | | | June 30,
2012 | | | June 30,
2011 | | | Mar. 31,
2012 | |
| | | (in Bcfe) | | | (in MMcfe per day) | |
Texas | | | 5.6 | | | | 4.2 | | | | 5.3 | | | | 61.6 | | | | 46.2 | | | | 58.7 | |
Cotton Valley/Other | | | 1.3 | | | | 2.5 | | | | 1.4 | | | | 14.2 | | | | 27.7 | | | | 15.5 | |
Haynesville Shale | | | 0.7 | | | | 1.2 | | | | 0.8 | | | | 8.1 | | | | 13.1 | | | | 8.7 | |
Eagle Ford Shale (1) | | | 3.6 | | | | 0.5 | | | | 3.1 | | | | 39.3 | | | | 5.7 | | | | 34.6 | |
Appalachia | | | 2.0 | | | | 2.3 | | | | 2.1 | | | | 21.5 | | | | 24.7 | | | | 22.7 | |
Mid-Continent(2) | | | 1.8 | | | | 3.5 | | | | 2.1 | | | | 19.7 | | | | 38.8 | | | | 23.6 | |
Granite Wash | | | 1.7 | | | | 2.9 | | | | 2.0 | | | | 18.9 | | | | 31.6 | | | | 22.0 | |
Mississippi | | | 1.3 | | | | 1.7 | | | | 1.3 | | | | 14.3 | | | | 18.6 | | | | 14.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Totals | | | 10.7 | | | | 11.7 | | | | 10.9 | | | | 117.1 | | | | 128.6 | | | | 119.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Pro Forma Totals(3) | | | 10.7 | | | | 11.1 | | | | 10.9 | | | | 117.1 | | | | 122.3 | | | | 119.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | Initial production from the Eagle Ford Shale commenced in February 2011 |
| (2) | Includes production from the Mid-Continent assets sold in 2011 |
| (3) | Pro forma to exclude production from the Mid-Continent assets sold in 2011 |
Note - Numbers may not add due to rounding
Operating Expenses
Second quarter 2012 total direct operating expenses decreased $5.0 million, or approximately 17 percent, to $23.8 million, or $2.24 per Mcfe produced, compared to $28.8 million, or $2.47 per Mcfe produced, in the prior year quarter.
| | • | | Lease operating expenses decreased by $1.5 million, or 14 percent, to $9.3 million, or $0.87 per Mcfe produced, from $10.8 million, or $0.92 per Mcfe produced, in the prior year quarter due to lower repair and maintenance expenses, lower compression costs and the sale of the higher-cost Arkoma Basin properties in August 2011. |
| | • | | Gathering, processing and transportation expenses increased by approximately $0.1 million, or three percent, to $4.4 million, or $0.41 per Mcfe produced, from $4.3 million, or $0.37 per Mcfe produced, in the prior year quarter, despite lower overall production volumes, due primarily to higher pipeline transportation costs in the Appalachian region. |
| | • | | Production and ad valorem taxes decreased 109 percent to a credit of $0.3 million from $2.8 million of expense in the prior year quarter due primarily to Oklahoma severance tax rebates of $2.8 million attributable to horizontal and ultra-deep wells drilled from July 2009 to June 2011 and lower natural gas prices. |
| | • | | General and administrative expenses, excluding share-based compensation, decreased by $0.5 million, or five percent, to $10.4 million, or $0.98 per Mcfe produced, from $10.9 million, or $0.94 per Mcfe produced, in the prior year quarter. This decrease was due primarily to lower employee headcount and lower support costs following restructuring actions taken during 2011, with the unit cost increasing due to lower gas production volumes. |
Exploration expense decreased $10.0 million, or 52 percent, to $9.4 million in the second quarter of 2012 from $19.4 million in the prior year quarter. The decrease was due primarily to a $3.7 million decrease in unproved property amortization, a $3.5 million decrease in geological and geophysical costs and a $2.1 million decrease in dry-hole costs (zero in the second quarter of 2012).
DD&A expense increased by $18.7 million, or 57 percent, to $51.7 million, or $4.86 per Mcfe produced, in the second quarter of 2012 from $33.0 million, or $2.82 per Mcfe produced, in the prior year quarter, due primarily to higher DD&A costs attributable to our Eagle Ford Shale oil wells and reserve revisions associated with our gas assets at year-end 2011.
Capital Expenditures
During the second quarter of 2012, capital expenditures were approximately $92 million, compared to $105 million in the prior year quarter, consisting of:
| | • | | $80 million for drilling and completion activities |
| | • | | $5 million for pipeline, gathering, facilities and seismic |
| | • | | $7 million for leasehold acquisitions and other |
Operational Update
Eagle Ford Shale
During the second quarter of 2012, we drilled eight (7.0 net) operated wells in the Eagle Ford Shale, all of which were successful. We currently have two active rigs, one rig drilling our 53rd well and the other rig in transit to drill our 54th well, with one (0.6 net) well waiting on completion and 51 (42.0 net) producing wells. The average peak gross production rate per well for the 44 of these wells with full-length laterals was 1,001 BOEPD. The initial 30-day average gross production rate for 43 of these 44 wells with sufficient production history was 657 BOEPD. Our Eagle Ford Shale production was approximately 6,550 net BOEPD during the second quarter of 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent.
In late 2011, we announced a 13,500 acre AMI with a major oil and gas company in Lavaca County, Texas pursuant to which, during 2012, we can earn a minimum of approximately 8,000 net acres. This would bring our Eagle Ford Shale position in Gonzales and Lavaca Counties, Texas to a minimum of approximately 36,700 (25,100 net) acres, with up to 250 total well locations (51 of which are producing) assuming down-spacing is successful on a majority of our acreage.
The first four wells on the Lavaca County acreage (Effenberger #1H, Vana #1H, Schacherl #1H and Sralla #1H) have been completed and turned in line over the past few months. All of these wells have met or exceeded our expectations with the two most recent wells being the Schacherl #1H (22 frac stages and lateral length of approximately 5,450 feet; previously reported), having a peak gross rate of 1,277 BOEPD of wellhead volumes, and the Sralla #1H (18 frac stages and lateral length of approximately 4,450 feet), having a peak gross rate of 827 BOEPD of wellhead volumes. The Lavaca wells thus far and most of our recent Gonzales wells are significantly choked initially, consistent with our belief that restricting early rates will result in a shallower decline profile and potentially higher recoverable reserves. Based on historical production data, we estimate Gonzales County Eagle Ford Shale wells will have gross reserves of approximately 400 MBOE and Lavaca County Eagle Ford Shale wells will have gross reserves of approximately 500 MBOE. The fifth well, the McCreary #1H has been drilled and is waiting on completion, while the sixth “earning” well in Lavaca County, the Pavlicek #1H, will spud soon.
Our full-year 2012 guidance anticipates 33 (25.6 net) new wells in the Eagle Ford Shale, including the wells drilled during the first half of 2012 and the impact of a third drilling rig to be added by the end of the third quarter. Efforts continue to expand our Eagle Ford Shale position through additional leasing and selective acquisitions.
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| | | | | | | | | Peak Gross Daily
Production Rates(4) | | | 30-Day Average Gross
Daily Production Rates(4) | |
Well Name | | Lateral
Length | | | Frac
Stages | | | Oil
Rate | | | Equivalent
Rate | | | Oil
Rate | | | Equivalent
Rate | |
| | | Feet | | | | | | BOPD | | | BOEPD | | | BOPD | | | BOEPD | |
New Wells On-Line | | | | | | | | | | | | | | | | | | | | | | | | |
Schacherl #1H(5) | | | 5,453 | | | | 22 | | | | 1,155 | | | | 1,277 | | | | 593 | | | | 709 | |
Rock Creek Ranch #9H | | | 5,153 | | | | 21 | | | | 785 | | | | 865 | | | | 606 | | | | 684 | |
Rock Creek Ranch #10H | | | 4,903 | | | | 20 | | | | 947 | | | | 1,036 | | | | 684 | | | | 763 | |
Sralla #1H(5) | | | 4,453 | | | | 18 | | | | 772 | | | | 827 | | | | — | | | | — | |
| | | | | | |
Averages (four wells) | | | 4,991 | | | | 20 | | | | 915 | | | | 1,001 | | | | 628 | | | | 719 | |
Averages (44 wells) | | | 3,889 | | | | 16 | | | | 923 | | | | 1,001 | | | | 581 | | | | 657 | |
| | | | | | |
Other New Wells On-Line | | | | | | | | | | | | | | | | | | | | | | | | |
Rock Creek Ranch #7H(6) | | | 2,653 | | | | 11 | | | | 657 | | | | 735 | | | | — | | | | — | |
Rock Creek Ranch #8H(6) | | | 3,455 | | | | 14 | | | | 503 | | | | 561 | | | | — | | | | — | |
Rock Creek Ranch #11H(7) | | | 3,562 | | | | 15 | | | | — | | | | — | | | | — | | | | — | |
| (4) | Wellhead rates only; the natural gas associated with these wells is yielding approximately 145 barrels of NGLs per million cubic feet. |
| (5) | Wells located in Lavaca County; all other wells are located in Gonzales County. |
| (6) | The Rock Creek Ranch #7H and #8H had shorter laterals and fewer frac stages. As a result, production data for these two wells has been excluded. |
| (7) | The Rock Creek Ranch #11H has just been completed and is flowing back frac fluids. As a result, production data for this well has been excluded. |
Mid-Continent
During the second quarter of 2012, we drilled one (0.5 net) non-operated well in the Granite Wash, which was successful. As previously discussed, we are currently drilling our first horizontal Viola Lime well in Jefferson County, Oklahoma with results expected to be known later in the third quarter. The Viola Lime is a carbonate formation at a depth of approximately 7,000 feet that is believed to be oil-productive based on offsetting vertical production. We have an acreage position of approximately 9,600 net acres which may be prospective in this play.
Full-Year 2012 Guidance
Full-year 2012 guidance highlights are as follows:
| | • | | Full-year 2012 production is expected to be approximately 37 to 40 Bcfe, a reduction compared to 40 to 43 Bcfe of previous guidance due primarily to the sale of producing assets in Appalachia which were expected to contribute approximately 3 Bcfe of production in the last five months of 2012 |
| | • | | Crude oil and NGLs are expected to comprise approximately 47 percent of total production during 2012, compared to previous guidance of approximately 43 percent, due primarily to the Appalachian asset sale |
| | • | | Full-year 2012 product revenues are expected to be approximately $284 to $303 million, compared to $292 to $316 million of previous guidance, excluding the impact of our hedges, due primarily to the Appalachian asset sale, partially offset by higher expected crude oil volumes |
| | • | | Crude oil and NGL product revenues are expected to be approximately 84 percent of total product revenues |
| | • | | Approximately 67 percent of estimated crude oil production volumes and 32 percent of estimated natural gas production volumes are hedged over the remaining two quarters of 2012 at weighted average prices of $100.80 per barrel and $5.24 per MMBtu |
| | • | | Full-year 2012 settlements of current commodity hedges are expected to result in cash receipts of approximately $31 million, approximately $14 million of which was received during the first half of 2012 |
| | • | | Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be $225 to $245 million, compared to previous guidance of $220 to $240 million, due to lower cash costs and higher Eagle Ford Shale margins |
| | • | | Full-year 2012 capital expenditures are expected to be $300 to $325 million, unchanged from previous guidance, despite the expected increase in Eagle Ford Shale drilling activity during the fourth quarter of 2012 |
| | • | | As a result of recent liquidity enhancing actions we have taken as well as the initial success we have achieved in Lavaca County, we expect to add a third rig in the Eagle Ford Shale by late in the third quarter of 2012 |
| | • | | Approximately 92 percent of 2012 capital expenditures are expected to be allocated to the Eagle Ford Shale and approximately seven percent to the Mid-Continent |
Please see the Guidance Table included in this release for guidance estimates for full-year 2012. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.
Capital Resources and Liquidity
As of June 30, 2012, we had total debt with a carrying value of approximately $779 million ($785 million aggregate principal amount), consisting of $294 million of 10.375 percent senior unsecured notes due 2016 ($300 million principal amount), $300 million principal amount of 7.25 percent senior unsecured notes due 2019, approximately $5 million principal amount of 4.5 percent convertible senior subordinated notes due in November 2012 (classified as a current liability) and $180 million of borrowings under our revolving credit facility (Revolver). Our indebtedness at June 30, 2012 was approximately 49 percent of book capitalization and 3.1 times the latest twelve months’ Adjusted EBITDAX of $253 million. As a result of the sale of Appalachian assets, pro forma debt-to-Adjusted EBITDAX was approximately 2.9 times.
We have no material debt maturities until 2016. Our capital expenditures for the second half of 2012 will be funded by operating cash flows, the proceeds from the sale of our Appalachian assets and borrowings under the Revolver.
Closing of the Sale of Appalachian Assets
On July 31, 2012, we closed the previously announced cash sale of our Appalachian assets, with the exception of the Marcellus Shale, for $100 million, subject to customary closing adjustments. We intend to use the net proceeds from this sale to partially fund our 2012 capital expenditure plan, as well as for general corporate purposes. In connection with the sale, we have recognized an impairment charge of $28.6 million and, during the third quarter of 2012, we expect additional charges for firm transportation as well as charges related to the planned closing of our office in Canonsburg, Pennsylvania.
Discontinuation of Dividend
As part of our plan to improve liquidity and help fund our Eagle Ford Shale drilling program, our Board of Directors has discontinued the quarterly cash dividend on shares of our common stock.
Explanation of Non-GAAP Gross Operating Margin per Mcfe
Gross operating margin is a non-GAAP financial measure under SEC regulations which represents total product revenues less total direct operating expenses. Gross operating margin per Mcfe is equal to gross operating margin divided by total natural gas, crude oil and NGL production. Gross operating margin is not adjusted for the impact of hedges. We believe that gross operating margin per Mcfe is an important measure that can be used by security analysts and investors to evaluate our operating margin per unit of production and to compare it to other oil and gas companies, as well as for comparisons to other time periods.
Second Quarter 2012 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss second quarter 2012 financial and operational results, is scheduled for Thursday, August 2, 2012 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 10 minutes before the scheduled start of the conference call (use the passcode 4082934), 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 4082934. 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 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 atwww.pennvirginia.com.
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for oil, NGLs and natural gas; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC).
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.
| | |
| 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 OPERATIONS - unaudited
(in thousands, except per share data)
| | | | | | | | | | | | | | | | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Revenues | | | | | | | | | | | | | | | | |
Natural gas | | $ | 10,303 | | | $ | 38,300 | | | $ | 25,189 | | | $ | 79,489 | |
Crude oil | | | 58,382 | | | | 21,548 | | | | 117,105 | | | | 38,131 | |
Natural gas liquids (NGLs) | | | 7,556 | | | | 13,161 | | | | 16,627 | | | | 23,082 | |
| | | | | | | | | | | | | | | | |
Total product revenues | | | 76,241 | | | | 73,009 | | | | 158,921 | | | | 140,702 | |
Gain (loss) on sales of property and equipment | | | 78 | | | | (28 | ) | | | 834 | | | | 452 | |
Other | | | 526 | | | | 637 | | | | 1,501 | | | | 1,047 | |
| | | | | | | | | | | | | | | | |
Total revenues | | | 76,845 | | | | 73,618 | | | | 161,256 | | | | 142,201 | |
Operating expenses | | | | | | | | | | | | | | | | |
Lease operating | | | 9,264 | | | | 10,787 | | | | 18,407 | | | | 21,064 | |
Gathering, processing and transportation | | | 4,391 | | | | 4,281 | | | | 8,545 | | | | 8,309 | |
Production and ad valorem taxes | | | (254 | ) | | | 2,834 | | | | 3,326 | | | | 7,898 | |
General and administrative (excluding equity-classified share-based compensation) (a) | | | 10,411 | | | | 10,941 | | | | 20,937 | | | | 22,497 | |
| | | | | | | | | | | | | | | | |
Total direct operating expenses | | | 23,812 | | | | 28,843 | | | | 51,215 | | | | 59,768 | |
Share-based compensation - equity classified awards (b) | | | 1,336 | | | | 2,013 | | | | 2,951 | | | | 3,809 | |
Exploration | | | 9,384 | | | | 19,368 | | | | 17,382 | | | | 48,916 | |
Depreciation, depletion and amortization | | | 51,740 | | | | 33,036 | | | | 102,557 | | | | 67,879 | |
Impairments | | | 28,616 | | | | 71,071 | | | | 28,616 | | | | 71,071 | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 114,888 | | | | 154,331 | | | | 202,721 | | | | 251,443 | |
| | | | | | | | | | | | | | | | |
| | | | |
Operating loss | | | (38,043 | ) | | | (80,713 | ) | | | (41,465 | ) | | | (109,242 | ) |
| | | | |
Other income (expense) | | | | | | | | | | | | | | | | |
Interest expense | | | (15,084 | ) | | | (14,143 | ) | | | (29,858 | ) | | | (27,627 | ) |
Loss on extinguishment of debt | | | — | | | | (24,238 | ) | | | — | | | | (24,238 | ) |
Derivatives | | | 43,826 | | | | 7,001 | | | | 43,521 | | | | 8,329 | |
Other | | | 28 | | | | 129 | | | | 29 | | | | 273 | |
| | | | | | | | | | | | | | | | |
| | | | |
Loss before income taxes | | | (9,273 | ) | | | (111,964 | ) | | | (27,773 | ) | | | (152,505 | ) |
Income tax benefit | | | 3,635 | | | | 40,046 | | | | 10,236 | | | | 54,247 | |
| | | | | | | | | | | | | | | | |
| | | | |
Net loss | | $ | (5,638 | ) | | $ | (71,918 | ) | | $ | (17,537 | ) | | $ | (98,258 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Loss per share: | | | | | | | | | | | | | | | | |
Basic | | $ | (0.12 | ) | | $ | (1.57 | ) | | $ | (0.38 | ) | | $ | (2.15 | ) |
Diluted | | $ | (0.12 | ) | | $ | (1.57 | ) | | $ | (0.38 | ) | | $ | (2.15 | ) |
| | | | |
Weighted average shares outstanding, basic | | | 46,030 | | | | 45,768 | | | | 45,988 | | | | 45,724 | |
Weighted average shares outstanding, diluted | | | 46,030 | | | | 45,768 | | | | 45,988 | | | | 45,724 | |
| | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Production | | | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | 5,859 | | | | 8,869 | | | | 12,153 | | | | 18,594 | |
Crude oil (MBbls) | | | 572 | | | | 219 | | | | 1,120 | | | | 407 | |
NGLs (MBbls) | | | 227 | | | | 253 | | | | 442 | | | | 473 | |
Total natural gas, crude oil and NGL production (MMcfe) | | | 10,653 | | | | 11,699 | | | | 21,527 | | | | 23,870 | |
| | | | |
Prices | | | | | | | | | | | | | | | | |
Natural gas ($ per Mcf) | | $ | 1.76 | | | $ | 4.32 | | | $ | 2.07 | | | $ | 4.27 | |
Crude oil ($ per Bbl) | | $ | 102.14 | | | $ | 98.45 | | | $ | 104.55 | | | $ | 93.80 | |
NGLs ($ per Bbl) | | $ | 33.23 | | | $ | 52.04 | | | $ | 37.60 | | | $ | 48.82 | |
| | | | |
Prices - Adjusted for derivative settlements | | | | | | | | | | | | | | | | |
Natural gas ($ per Mcf) | | $ | 2.72 | | | $ | 4.80 | | | $ | 3.20 | | | $ | 4.88 | |
Crude oil ($ per Bbl) | | $ | 102.03 | | | $ | 97.87 | | | $ | 104.40 | | | $ | 92.93 | |
NGLs ($ per Bbl) | | $ | 33.23 | | | $ | 52.04 | | | $ | 37.60 | | | $ | 48.82 | |
| (a) | Includes liability-classified share-based compensation expense attributable to our performance-based restricted stock units which are payable in cash upon the achievement of certain market-based performance metrics. A total of $0.6 million attributable to these awards is included in both the three and six months ended June 30, 2012. |
| (b) | Our equity-classified share-based compensation expense includes non-cash charges for our stock option expense and the amortization of common, deferred and restricted stock and restricted stock unit awards related to equity-classified employee and director compensation in accordance with accounting guidance for share-based payments. |
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
| | | | | | | | |
| | | As of | |
| | | June 30,
2012 | | | December 31,
2011 | |
Assets | | | | | | | | |
Current assets | | $ | 132,050 | | | $ | 145,346 | |
Net property and equipment | | | 1,811,553 | | | | 1,777,575 | |
Other assets | | | 33,469 | | | | 20,132 | |
| | | | | | | | |
Total assets | | $ | 1,977,072 | | | $ | 1,943,053 | |
| | | | | | | | |
| | |
Liabilities and shareholders’ equity | | | | | | | | |
Current liabilities (a) | | $ | 93,483 | | | $ | 106,607 | |
Revolving credit facility | | | 180,000 | | | | 99,000 | |
Senior notes due 2016 | | | 294,144 | | | | 293,561 | |
Senior notes due 2019 | | | 300,000 | | | | 300,000 | |
Other liabilities and deferred income taxes | | | 282,857 | | | | 297,576 | |
Total shareholders’ equity | | | 826,588 | | | | 846,309 | |
| | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 1,977,072 | | | $ | 1,943,053 | |
| | | | | | | | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Cash flows from operating activities | | | | | | | | | | | | | | | | |
Net loss | | $ | (5,638 | ) | | $ | (71,918 | ) | | $ | (17,537 | ) | | $ | (98,258 | ) |
Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | | | | | |
Non-cash portion of loss on extinguishment of debt | | | — | | | | 21,822 | | | | — | | | | 21,822 | |
Depreciation, depletion and amortization | | | 51,740 | | | | 33,036 | | | | 102,557 | | | | 67,879 | |
Impairments | | | 28,616 | | | | 71,071 | | | | 28,616 | | | | 71,071 | |
Derivative contracts: | | | | | | | | | | | | | | | | |
Net gains | | | (43,826 | ) | | | (7,001 | ) | | | (43,521 | ) | | | (8,329 | ) |
Cash settlements | | | 6,970 | | | | 5,031 | | | | 14,951 | | | | 11,775 | |
Deferred income tax benefit | | | (3,635 | ) | | | (40,046 | ) | | | (10,236 | ) | | | (54,247 | ) |
(Gain) loss on sales of property and equipment, net | | | (78 | ) | | | 28 | | | | (834 | ) | | | (452 | ) |
Non-cash exploration expense | | | 8,284 | | | | 14,082 | | | | 16,455 | | | | 41,081 | |
Non-cash interest expense | | | 1,035 | | | | 1,478 | | | | 2,050 | | | | 4,750 | |
Share-based compensation (equity-classified awards) | | | 1,336 | | | | 2,013 | | | | 2,951 | | | | 3,809 | |
Other, net | | | 147 | | | | 29 | | | | 203 | | | | 265 | |
Changes in operating assets and liabilities | | | 73 | | | | 4,698 | | | | 20,070 | | | | 2,593 | |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 45,024 | | | | 34,323 | | | | 115,725 | | | | 63,759 | |
| | | | | | | | | | | | | | | | |
Cash flows from investing activities | | | | | | | | | | | | | | | | |
Capital expenditures - property and equipment | | | (93,767 | ) | | | (110,352 | ) | | | (188,236 | ) | | | (211,081 | ) |
Proceeds from sales of property, plant and equipment, net | | | (251 | ) | | | 336 | | | | 527 | | | | 696 | |
Other, net | | | 180 | | | | — | | | | 180 | | | | 100 | |
| | | | | | | | | | | | | | | | |
Net cash used in investing activities | | | (93,838 | ) | | | (110,016 | ) | | | (187,529 | ) | | | (210,285 | ) |
| | | | | | | | | | | | | | | | |
Cash flows from financing activities | | | | | | | | | | | | | | | | |
Dividends paid | | | (2,590 | ) | | | (2,580 | ) | | | (5,176 | ) | | | (5,156 | ) |
Proceeds from revolving credit facility borrowings | | | 61,000 | | | | — | | | | 84,000 | | | | — | |
Repayment of revolving credit facility borrowings | | | — | | | | — | | | | (3,000 | ) | | | — | |
Proceeds from the issuance of senior notes | | | — | | | | 300,000 | | | | — | | | | 300,000 | |
Repurchase of convertible notes | | | — | | | | (232,963 | ) | | | — | | | | (232,963 | ) |
Debt issuance costs paid | | | — | | | | (6,559 | ) | | | — | | | | (6,559 | ) |
Other, net | | | — | | | | 136 | | | | — | | | | 974 | |
| | | | | | | | | | | | | | | | |
Net cash provided by financing activities | | | 58,410 | | | | 58,034 | | | | 75,824 | | | | 56,296 | |
| | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 9,596 | | | | (17,659 | ) | | | 4,020 | | | | (90,230 | ) |
Cash and cash equivalents - beginning of period | | | 1,936 | | | | 48,340 | | | | 7,512 | | | | 120,911 | |
| | | | | | | | | | | | | | | | |
Cash and cash equivalents - end of period | | $ | 11,532 | | | $ | 30,681 | | | $ | 11,532 | | | $ | 30,681 | |
| | | | | | | | | | | | | | | | |
| | | | |
Supplemental disclosures of cash paid for: | | | | | | | | | | | | | | | | |
Interest (net of amounts capitalized) | | $ | 26,099 | | | $ | 19,318 | | | $ | 26,656 | | | $ | 19,705 | |
Income taxes (net of refunds received) | | $ | (10 | ) | | $ | 24 | | | $ | (311 | ) | | $ | (96 | ) |
| (a) | The $4.9 million principal balance of convertible notes are due in November 2012 and are included in current liabilities. |
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Reconciliation of GAAP “Net loss” to Non-GAAP “Net loss, as adjusted” | | | | | | | | | | | | | | | | |
Net loss | | $ | (5,638 | ) | | $ | (71,918 | ) | | $ | (17,537 | ) | | $ | (98,258 | ) |
Adjustments for derivatives: | | | | | | | | | | | | | | | | |
Net losses (gains) included in net loss | | | (43,826 | ) | | | (7,001 | ) | | | (43,521 | ) | | | (8,329 | ) |
Cash settlements | | | 6,970 | | | | 5,031 | | | | 14,951 | | | | 11,775 | |
Adjustment for impairments | | | 28,616 | | | | 71,071 | | | | 28,616 | | | | 71,071 | |
Adjustment for restructuring costs | | | (148 | ) | | | 52 | | | | (148 | ) | | | 70 | |
Adjustment for net loss (gain) on sale of assets | | | (78 | ) | | | 28 | | | | (834 | ) | | | (452 | ) |
Adjustment for loss on extinguishment of debt | | | — | | | | 24,238 | | | | — | | | | 24,238 | |
Impact of adjustments on income taxes | | | 3,319 | | | | (33,413 | ) | | | 345 | | | | (34,992 | ) |
| | | | | | | | | | | | | | | | |
Net loss, as adjusted (a) | | $ | (10,785 | ) | | $ | (11,912 | ) | | $ | (18,128 | ) | | $ | (34,877 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Net loss, as adjusted, per share, diluted | | $ | (0.23 | ) | | $ | (0.26 | ) | | $ | (0.39 | ) | | $ | (0.76 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Reconciliation of GAAP “Net loss” to Non-GAAP “Adjusted EBITDAX” | | | | | | | | | | | | | | | | |
Net loss | | $ | (5,638 | ) | | $ | (71,918 | ) | | $ | (17,537 | ) | | $ | (98,258 | ) |
Income tax benefit | | | (3,635 | ) | | | (40,046 | ) | | | (10,236 | ) | | | (54,247 | ) |
Interest expense | | | 15,084 | | | | 14,143 | | | | 29,858 | | | | 27,627 | |
Depreciation, depletion and amortization | | | 51,740 | | | | 33,036 | | | | 102,557 | | | | 67,879 | |
Exploration | | | 9,384 | | | | 19,368 | | | | 17,382 | | | | 48,916 | |
Share-based compensation expense (equity-classified awards) | | | 1,336 | | | | 2,013 | | | | 2,951 | | | | 3,809 | |
| | | | | | | | | | | | | | | | |
EBITDAX | | | 68,271 | | | | (43,404 | ) | | | 124,975 | | | | (4,274 | ) |
Adjustments for derivatives: | | | | | | | | | | | | | | | | |
Net gains included in net income | | | (43,826 | ) | | | (7,001 | ) | | | (43,521 | ) | | | (8,329 | ) |
Cash settlements | | | 6,970 | | | | 5,031 | | | | 14,951 | | | | 11,775 | |
Adjustment for impairments | | | 28,616 | | | | 71,071 | | | | 28,616 | | | | 71,071 | |
Adjustment for net loss (gain) on sale of assets | | | (78 | ) | | | 28 | | | | (834 | ) | | | (452 | ) |
Adjustment for loss on extinguishment of debt | | | — | | | | 24,238 | | | | — | | | | 24,238 | |
| | | | | | | | | | | | | | | | |
Adjusted EBITDAX (b) | | $ | 59,953 | | | $ | 49,963 | | | $ | 124,187 | | | $ | 94,029 | |
| | | | | | | | | | | | | | | | |
| (a) | Net loss, as adjusted, represents the net loss adjusted to exclude the effects of non-cash changes in the fair value of derivatives, impairments, restructuring costs, net gains and losses on the sale of assets and loss on the extinguishment of debt. 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 loss, 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 loss. |
| (b) | Adjusted EBITDAX represents net loss 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, impairments, net gains and losses on the sale of assets and loss on the extinguishment of debt. 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 loss. Adjusted EBITDAX represents EBITDAX as defined in our revolving credit facility. |
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 2012. These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes.
| | | | | | | | | | | | | | |
| | | First
Quarter | | | Second
Quarter | | | YTD | | | Full-Year |
| | | 2012 | | | 2012 | | | 2012 | | | 2012 Guidance |
Production: | | | | | | | | | | | | | | |
Natural gas (Bcf) | | | 6.3 | | | | 5.9 | | | | 12.2 | | | 19.8 - 21.0 |
Crude oil (MBbls) | | | 549 | | | | 572 | | | | 1,120 | | | 2,160 - 2,290 |
NGLs (MBbls) | | | 215 | | | | 227 | | | | 442 | | | 775 - 825 |
Equivalent production (Bcfe) | | | 10.9 | | | | 10.7 | | | | 21.5 | | | 37.4 - 39.7 |
Equivalent daily production (MMcfe per day) | | | 119.5 | | | | 117.1 | | | | 118.3 | | | 102.2 - 108.4 |
Equivalent production (MBOE) | | | 1,812 | | | | 1,775 | | | | 3,588 | | | 6,235 - 6,615 |
Equivalent daily production (MBOE per day) | | | 19.9 | | | | 19.5 | | | | 19.7 | | | 17.0 - 18.1 |
Percent crude oil and NGLs | | | 42.1 | % | | | 45.0 | % | | | 43.5 | % | | 43.9% - 50.1% |
| | | | |
Production revenues (a): | | | | | | | | | | | | | | |
Natural gas | | $ | 14.9 | | | | 10.3 | | | | 25.2 | | | 45.2 - 49.9 |
Crude oil | | $ | 58.7 | | | | 58.4 | | | | 117.1 | | | 211.0 - 223.7 |
NGLs | | $ | 9.1 | | | | 7.6 | | | | 16.6 | | | 27.5 - 29.0 |
Total product revenues | | $ | 82.7 | | | | 76.2 | | | | 158.9 | | | 283.7 - 302.6 |
Total product revenues ($ per Mcfe) | | $ | 7.60 | | | | 7.16 | | | | 7.38 | | | 7.58 - 7.62 |
Total product revenues ($ per BOE) | | $ | 45.62 | | | | 42.94 | | | | 44.29 | | | 45.50 - 45.74 |
Percent crude oil and NGLs | | | 82.0 | % | | | 86.5 | % | | | 84.1 | % | | 82.4% - 85.1% |
| | | | |
Operating expenses: | | | | | | | | | | | | | | |
Lease operating ($ per Mcfe) | | $ | 0.84 | | | | 0.87 | | | | 0.86 | | | 0.82 - 0.85 |
Lease operating ($ per BOE) | | $ | 5.04 | | | | 5.22 | | | | 5.13 | | | 4.92 - 5.10 |
Gathering, processing and transportation costs ($ per Mcfe) | | $ | 0.38 | | | | 0.41 | | | | 0.40 | | | 0.34 - 0.38 |
Gathering, processing and transportation costs ($ per BOE) | | $ | 2.29 | | | | 2.47 | | | | 2.38 | | | 2.04 - 2.28 |
Production and ad valorem taxes (percent of oil and gas revenues) | | | 4.3 | % | | | -0.3 | % | | | 2.1 | % | | 3.5% - 4.0% |
| | | | |
General and administrative: | | | | | | | | | | | | | | |
Recurring general and administrative | | $ | 10.5 | | | | 10.4 | | | | 20.9 | | | 38.5 - 40.0 |
Share-based compensation | | $ | 1.6 | | | | 1.3 | | | | 3.0 | | | 6.0 - 6.5 |
Restructuring | | $ | — | | | | (0.1 | ) | | | (0.1 | ) | | 2.0 - 3.0 |
Total reported G&A | | $ | 12.1 | | | | 11.7 | | | | 23.8 | | | 46.5 - 49.5 |
| | | | |
Exploration: | | | | | | | | | | | | | | |
Total reported exploration | | $ | 8.0 | | | | 9.4 | | | | 17.4 | | | 36.0 - 40.0 |
Unproved property amortization | | $ | 8.2 | | | | 8.3 | | | | 16.5 | | | 30.0 - 32.0 |
| | | | |
Depreciation, depletion and amortization ($ per Mcfe) | | $ | 4.67 | | | | 4.86 | | | | 4.76 | | | 4.90 - 5.10 |
Depreciation, depletion and amortization ($ per BOE) | | $ | 28.02 | | | | 29.14 | | | | 28.58 | | | 29.40 - 30.60 |
| | | | |
Adjusted EBITDAX (b) | | $ | 64.2 | | | | 60.0 | | | | 124.2 | | | 225.0 - 245.0 |
| | | | |
Capital expenditures: | | | | | | | | | | | | | | |
Drilling and completion | | $ | 82.6 | | | | 79.8 | | | | 162.4 | | | 275.0 - 285.0 |
Pipeline, gathering, facilities | | $ | 3.9 | | | | 4.4 | | | | 8.3 | | | 10.0 - 15.0 |
Seismic (c) | | $ | (0.4 | ) | | | 0.7 | | | | 0.3 | | | 3.0 - 5.0 |
Lease acquisitions, field projects and other | | $ | 4.3 | | | | 6.6 | | | | 10.9 | | | 12.0 - 20.0 |
Total oil and gas capital expenditures | | $ | 90.4 | | | | 91.5 | | | | 181.9 | | | 300.0 - 325.0 |
| | | | |
End of period debt outstanding | | $ | 717.6 | | | | 779.0 | | | | 779.0 | | | |
Effective interest rate | | | 8.5 | % | | | 8.5 | % | | | 8.5 | % | | |
Income tax benefit rate | | | 35.7 | % | | | 39.2 | % | | | 36.9 | % | | 38.0% - 39.0% |
| (a) | Assumes average benchmark prices of $92.20 per barrel for crude oil, $35.31 per barrel for NGLs and $2.58 per MMBtu for natural gas, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments. |
| (b) | Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income from continuing operations. |
| (c) | Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities from continuing operations. |
PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited - (continued)
Note to Guidance Table:
The following table shows our current derivative positions.
| | | | | | | | | | | | | | |
| | | | | | | | Weighted Average Price | |
| | | Instrument Type | | Average Volume
Per Day | | | Floor/Swap | | | Ceiling | |
| | | |
Natural gas: | | | | | (MMBtu | ) | | | ($ / MMBtu) | |
Third quarter 2012 | | Swaps | | | 20,000 | | | | 5.31 | | | | | |
Fourth quarter 2012 | | Swaps | | | 10,000 | | | | 5.10 | | | | | |
| | | |
Crude oil: | | | | | (barrels | ) | | | ($ / barrel) | |
Third quarter 2012 | | Collars | | | 1,000 | | | | 90.00 | | | | 97.00 | |
Fourth quarter 2012 | | Collars | | | 1,000 | | | | 90.00 | | | | 97.00 | |
First quarter 2013 | | Collars | | | 1,000 | | | | 90.00 | | | | 100.00 | |
Second quarter 2013 | | Collars | | | 1,000 | | | | 90.00 | | | | 100.00 | |
Third quarter 2013 | | Collars | | | 1,000 | | | | 90.00 | | | | 100.00 | |
Fourth quarter 2013 | | Collars | | | 1,000 | | | | 90.00 | | | | 100.00 | |
Third quarter 2012 | | Swaps | | | 3,000 | | | | 104.40 | | | | | |
Fourth quarter 2012 | | Swaps | | | 3,000 | | | | 104.40 | | | | | |
First quarter 2013 | | Swaps | | | 2,250 | | | | 103.51 | | | | | |
Second quarter 2013 | | Swaps | | | 2,250 | | | | 103.51 | | | | | |
Third quarter 2013 | | Swaps | | | 1,500 | | | | 102.77 | | | | | |
Fourth quarter 2013 | | Swaps | | | 1,500 | | | | 102.77 | | | | | |
First quarter 2014 | | Swaps | | | 2,000 | | | | 100.44 | | | | | |
Second quarter 2014 | | Swaps | | | 2,000 | | | | 100.44 | | | | | |
Third quarter 2014 | | Swaps | | | 1,500 | | | | 100.20 | | | | | |
Fourth quarter 2014 | | Swaps | | | 1,500 | | | | 100.20 | | | | | |
First quarter 2013 | | Swaption | | | 1,100 | | | | 100.00 | | | | | |
Second quarter 2013 | | Swaption | | | 1,000 | | | | 100.00 | | | | | |
Third quarter 2013 | | Swaption | | | 900 | | | | 100.00 | | | | | |
Fourth quarter 2013 | | Swaption | | | 750 | | | | 100.00 | | | | | |
First quarter 2014 | | Swaption | | | 812 | | | | 100.00 | | | | | |
Second quarter 2014 | | Swaption | | | 812 | | | | 100.00 | | | | | |
Third quarter 2014 | | Swaption | | | 812 | | | | 100.00 | | | | | |
Fourth quarter 2014 | | Swaption | | | 812 | | | | 100.00 | | | | | |
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 2012 would increase or decrease by approximately $9 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 2012 would increase or decrease by approximately $11 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.
