RADNOR, Pa.--(BUSINESS WIRE)--Penn Virginia Corporation (NYSE: PVA) today reported results for the three months ended September 30, 2012, provided updates of operations and full-year 2012 guidance and provided preliminary guidance for 2013.
Third Quarter 2012 Highlights
Third quarter 2012 results compared to the third quarter of 2011 were as follows:
- Oil and natural gas liquids (NGLs) production of 776 thousand barrels of oil (MBO), or 52 percent of total equivalent production, an increase of 19 percent compared to 649 MBO, or 33 percent of total equivalent production
- Oil production of 573 MBO, an increase of 34 percent compared to 427 MBO
- Oil and NGL revenues of $63.7 million, or 84 percent of product revenues, an increase of 33 percent compared to $47.8 million, or 58 percent of product revenues
- Product revenues from the sale of natural gas, crude oil and NGLs of $75.6 million, or $8.37 per thousand cubic feet of natural gas equivalent (Mcfe), a decrease of eight percent compared to $82.0 million, or $6.86 per Mcfe (22 percent increase in per unit revenues) due to lower gas prices and divestitures of natural gas properties
- Gross operating margin, a non-GAAP (generally accepted accounting principles) measure defined as total product revenues less total direct operating expenses, of $5.68 per Mcfe, an increase of 20 percent compared to $4.72 per Mcfe
- Adjusted EBITDAX, a non-GAAP measure, of $61.2 million, a decrease of eight percent compared to $66.3 million due to lower gas prices and production, lower NGL prices and the receipt of $2.9 million in the prior year period related to the termination of an interest rate swap, partially offset by higher oil prices and production
- Operating loss of $24.5 million, including $17.3 million of charges related to firm transportation commitments in Appalachia, compared to a loss of $9.0 million
- Net loss of $32.6 million, or $0.71 per diluted share, compared to a loss of $6.7 million, or $0.15 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 $7.3 million, or $0.16 per diluted share, compared to a loss of $6.7 million, or $0.15 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 Eagle Ford operational highlights are as follows:
-
We have completed eight (6.7 net) Eagle Ford Shale wells and acquired
one (1.0 net) Eagle Ford Shale well since early August. This brings
the total number of on-line wells to 59 (49.1 net), with one (0.9 net)
well being completed and the 61st through 63rd
wells being drilled
- The average peak gross production rate per well for the 49 wells we completed with full-length laterals was 986 barrels of oil equivalent (BOE) per day (BOEPD)
- The initial 30-day average gross production rate for the 45 of these 49 wells with a 30-day production history was 656 BOEPD
- Eagle Ford Shale oil production will begin to increase late in 2012 with the recent addition of a third drilling rig
- Our Eagle Ford Shale net production was approximately 6,300 BOEPD during the third quarter of 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent
- The results of seven wells drilled and completed to date in Lavaca County continue to meet our expectations with an average initial production of 829 BOEPD and significant back pressures, as well as 30-day average rates for five of these wells of 678 BOEPD, which exceeds our 30-day average in Gonzales County
- As previously disclosed, we have increased our Eagle Ford Shale acreage position in Gonzales and Lavaca Counties, Texas to approximately 40,000 gross (30,000 net) acres with up to approximately 285 remaining drilling locations
Management Comment
H. Baird Whitehead, President and Chief Executive Officer stated, “Our third quarter results met our expectations, with Adjusted EBITDAX at or above $60 million for the fifth consecutive quarter. We believe our cash operating margin per unit of production is among the best of our small cap peers. We have had excellent well results in the Eagle Ford Shale and are pleased with our recent Eagle Ford Shale acreage additions and increases to our drilling inventory. The recent addition of the third rig in the Eagle Ford Shale play will allow us to resume sequential crude oil as well as overall production growth, on a pro forma basis, as we enter 2013. Recent acreage additions and derisking of our Lavaca County, Texas acreage now provide a greater than six-year inventory of drilling locations for a three-rig program.
“Since July 31st, we have sold our Appalachian assets, completed concurrent offerings of $161 million of preferred and common equity and received a $32 million federal income tax refund, significantly improving the strength of our balance sheet and financial liquidity. As a result, we are well positioned to fund our 2013 Eagle Ford Shale drilling program, on which we will continue to be focused.”
Third Quarter 2012 Financial and Operational Results
Pricing
Our third quarter 2012 realized oil price of $99.45 per barrel was 14 percent higher than the $87.03 per barrel price in the prior year quarter. Our third quarter 2012 realized NGL price of $32.94 per barrel was 31 percent lower than the $48.00 per barrel price in the prior year quarter. Our third quarter 2012 realized natural gas price of $2.72 per thousand cubic feet (Mcf) was 36 percent lower than the $4.24 per Mcf price in the prior year quarter. Adjusting for oil and gas hedges, our third quarter 2012 effective oil price was $107.53 per barrel, and our effective natural gas price was $3.77 per Mcf, or increases of $8.08 per barrel and $1.05 per Mcf over the realized prices.
Overview of Financial Results
The operating loss in the third quarter of 2012 was $24.5 million, compared to the $9.0 million loss in the prior year quarter. The increase in loss of $15.5 million was due primarily to a $17.3 million increase in charges during the third quarter of 2012 related to firm transportation commitments for divested Appalachian assets and a $5.7 million decrease in total revenues, partially offset by a $7.5 million decrease in other operating expenses. Oil and NGL revenues were $63.7 million in the third quarter of 2012, 33 percent higher than the $47.8 million in the prior year quarter. Oil and NGL revenues were 84 percent of product revenues in the third quarter of 2012, compared to 58 percent in the prior year quarter.
Production
As shown in the table below, production in the third quarter of 2012 was 9.0 Bcfe, or 98.1 MMcfe per day, a 24 percent decrease compared to 11.9 Bcfe, or 129.9 MMcfe per day, in the prior year quarter. Excluding production from the Appalachian assets sold in July 2012 and the Arkoma Basin assets sold in August 2011, production in the third quarter of 2012 was 8.3 Bcfe, or 90.5 MMcfe per day, and the production in the prior year quarter was 9.2 Bcfe, or 100.0 MMcfe per day. The 0.9 Bcfe, or nine percent, decrease in pro forma production was the result of a 1.6 Bcfe, or 31 percent, decrease in natural gas production due to reduced natural gas drilling since mid-2010, partially offset by a 127 MBO (0.8 Bcfe), or 20 percent, increase in oil and NGL production due primarily to drilling in the Eagle Ford Shale since early 2011. As a percentage of total equivalent production, oil and NGL volumes were 52 percent in the third quarter of 2012 compared to 33 percent in the prior year quarter. Oil production increased 34 percent from 427 MBO in the prior year quarter to 573 MBO in the third quarter of 2012.
| Total and Daily Equivalent Production for the Three Months Ended | ||||||||||||
|
|
Sept. 30, | Sept. 30, | June 30, | Sept. 30, | Sept. 30, | June 30, | ||||||
|
Region / Play Type |
2012 | 2011 | 2012 | 2012 | 2011 | 2012 | ||||||
| (in Bcfe) | (in MMcfe per day) | |||||||||||
| Texas | 5.4 | 4.9 | 5.6 | 58.8 | 53.3 | 61.6 | ||||||
| Cotton Valley/Other | 1.3 | 1.8 | 1.3 | 14.1 | 19.9 | 14.2 | ||||||
| Haynesville Shale | 0.6 | 1.0 | 0.7 | 6.8 | 11.1 | 8.1 | ||||||
| Eagle Ford Shale | 3.5 | 2.1 | 3.6 | 37.9 | 22.4 | 39.3 | ||||||
| Appalachia(1) | 0.6 | 2.3 | 2.0 | 7.0 | 24.7 | 21.5 | ||||||
| Mid-Continent(2) | 1.7 | 3.2 | 1.8 | 18.8 | 34.8 | 19.7 | ||||||
| Granite Wash | 1.6 | 2.7 | 1.7 | 17.9 | 29.7 | 18.9 | ||||||
| Mississippi | 1.2 | 1.6 | 1.3 | 13.5 | 17.0 | 14.3 | ||||||
| Totals | 9.0 | 11.9 | 10.7 | 98.1 | 129.9 | 117.1 | ||||||
| Pro Forma Totals(3) | 8.3 | 9.2 | 8.7 | 90.5 | 100.0 | 95.4 | ||||||
|
(1) |
Includes production from the Appalachian assets sold in July 2012 | |
|
(2) |
Includes production from the Arkoma Basin assets sold in August 2011 | |
|
(3) |
Pro forma to exclude production from divested Appalachian and Arkoma Basin assets | |
|
Note - Numbers may not add due to rounding |
||
Operating Expenses
Third quarter 2012 total direct operating expenses decreased $1.3 million, or approximately five percent, to $24.3 million, or $2.69 per Mcfe produced, compared to $25.6 million, or $2.14 per Mcfe produced, in the prior year quarter.
- Lease operating expenses decreased by $2.3 million, or 27 percent, to $6.2 million, or $0.69 per Mcfe produced, from $8.5 million, or $0.71 per Mcfe produced, due primarily to lower repair and maintenance, compression and water disposal expenses, as well as reduced expenses attributable to the sale of our Appalachian properties in July 2012 and our Arkoma Basin properties in August 2011. These cost decreases were partially offset by higher chemical treatment and environmental compliance costs attributable to our expanded oil drilling program.
- Gathering, processing and transportation expenses increased by approximately $0.1 million, or six percent, to $3.1 million, or $0.35 per Mcfe produced, from $3.0 million, or $0.25 per Mcfe produced, due primarily to higher processing costs associated with NGLs in the 2012 period.
- Production and ad valorem taxes increased $1.2 million, or 35 percent, to $4.6 million, or 6.1 percent of total product revenues, from $3.4 million, or 4.1 percent of total product revenues, because we reported a property tax recovery of $1.2 million attributable to wells in West Virginia during the 2011 period.
- General and administrative (G&A) expense, excluding share-based compensation, decreased by approximately $0.4 million, or four percent, to $10.4 million, or $1.15 per Mcfe produced, from $10.8 million, or $0.91 per Mcfe produced. Excluding restructuring costs in the third quarters of both 2012 and 2011 related to the Appalachian and Arkoma asset sales, G&A expense, excluding share-based compensation, decreased by approximately $0.4 million, or four percent, to $8.9 million, or $0.99 per Mcfe produced, from $9.3 million, or $0.78 per Mcfe produced. This decrease was due primarily to lower employee headcount and lower support costs following restructuring actions taken during 2011 and 2012, with the unit cost increasing due to lower gas equivalent production volumes.
Exploration expense decreased $10.0 million, or 52 percent, to $9.3 million in the third quarter of 2012 from $19.3 million in the prior year quarter. The decrease was due primarily to a $2.7 million decrease in unproved property amortization, a $2.8 million decrease in geological and geophysical costs and a 2011 charge of $4.8 million for a contract termination.
Depreciation, depletion and amortization (DD&A) expense increased by $4.0 million, or nine percent, to $49.3 million, or $5.47 per Mcfe produced, in the third quarter of 2012 from $45.3 million, or $3.80 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.
Capital Expenditures
During the third quarter of 2012, capital expenditures were approximately $85 million, compared to $114 million in the prior year quarter, consisting of:
- $73 million for drilling and completion activities
- $5 million for pipeline, gathering, facilities and seismic
- $6 million for leasehold acquisitions and other
Comparison of Third Quarter of 2012 to Second Quarter of 2012
As shown in the table above, production in the third quarter of 2012 of approximately 9.0 Bcfe, or 98.1 MMcfe per day, was 1.7 Bcfe, or 19.0 MMcfe per day, less than in the second quarter of 2012 due primarily to a 1.5 Bcfe decline in natural gas production as a result of the Appalachian sale and natural declines, as well as lower NGL production in the Mid-Continent associated with ethane rejection and reduced natural gas production. Crude oil production was essentially flat on a sequential basis as a result of the reduction in the rig count in the Eagle Ford Shale from three rigs to two rigs earlier in the year. We expect crude oil production to decrease slightly for the fourth quarter, after which we expect oil production to begin increasing in the first quarter of 2013 due to contributions associated with the third rig. During the third quarter of 2012, total product revenues were flat at approximately $76 million compared to the prior quarter as the decline in total production was offset by higher realized oil and gas prices. Due to flat sequential direct operating expenses of approximately $24 million in both quarters, increased cash settlements of derivatives in the third quarter and despite the sale of Appalachia at the end of July, third quarter Adjusted EBITDAX of approximately $61 million was slightly higher than the approximately $60 million in the prior quarter.
Operational Update
Eagle Ford Shale
During the third quarter of 2012, we drilled six (5.0 net) operated wells in the Eagle Ford Shale, all of which were successful. Since early August, we have completed eight (6.7 net) Eagle Ford Shale wells and acquired one (1.0 net) Eagle Ford Shale well, bringing the total to 59 (49.1 net) producing wells, with one (0.9 net) well being completed and the 61st through 63rd wells being drilled. The average peak gross production rate per well for the 49 wells we completed with full-length laterals was 986 BOEPD. The initial 30-day average gross production rate for 45 of these 49 wells with a 30-day production history was 656 BOEPD. Our Eagle Ford Shale production was approximately 6,300 net BOEPD during the third quarter of 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent.
Progress continues in reducing our drilling and completion costs. By sourcing our guar and proppant directly, we have stabilized our drilling and completion costs at $7.0 to $8.0 million per well in Gonzales County and, going forward, $8.5 to $9.5 million per well in Lavaca County, both depending on lateral length. We are also using only 100 percent high-strength white sand for proppant in Gonzales County and recently initiated the use of a mix of ceramic and high-strength white sand in Lavaca County.
Our full-year 2012 guidance anticipates the drilling of 33 (26.3 net) wells in the Eagle Ford Shale, including the wells drilled during the first nine months of 2012. As previously disclosed, we have increased our Eagle Ford Shale acreage position to approximately 40,000 gross (30,000 net) acres with a drilling inventory of up to approximately 285 locations. Efforts continue to expand our Eagle Ford Shale position through additional leasing and selective acquisitions.
| Peak Gross Daily | 30-Day Average Gross Daily | |||||||||||
|
Production Rates(4) |
Production Rates(4) |
|||||||||||
| Lateral | Frac | Oil | Equivalent | Oil | Equivalent | |||||||
| Well Name | Length | Stages | Rate | Rate | Rate | Rate | ||||||
| Feet | BOPD | BOEPD | BOPD | BOEPD | ||||||||
| New Wells On-Line | ||||||||||||
| Rock Creek Ranch #11H | 3,567 | 15 | 562 | 625 | 445 | 503 | ||||||
| McCreary #1H(5) | 4,453 | 18 | 853 | 1,036 | 572 | 709 | ||||||
| Neuse #1H | 4,650 | 19 | 633 | 667 | --- | --- | ||||||
| Henning #2H | 3,153 | 13 | 920 | 1,002 | --- | --- | ||||||
| Smith #1H(5) | 4,459 | 18 | 730 | 943 | --- | --- | ||||||
| Averages (five new wells) | 4,056 | 17 | 740 | 854 | 509 | 606 | ||||||
| Averages (49 wells) | 3,906 | 16 | 904 | 986 | 592 | 656 | ||||||
| Other New Wells On-Line | ||||||||||||
| Pavlicek #1H(5,6) | 4,870 | 20 | 574 | 662 | --- | --- | ||||||
| Bozka #1H(7) | --- | -- | 508 | 572 | --- | --- | ||||||
| Kusak #1H(8) | 4,453 | 18 | --- | --- | --- | --- | ||||||
| Leal #1H(5,8) | 4,450 | 18 | --- | --- | --- | --- | ||||||
|
(4) |
Wellhead rates only; the natural gas associated with these wells is yielding approximately 145 barrels of NGLs per million cubic feet. Barrels of oil per day (BOPD) | |
|
(5) |
Wells located in Lavaca County; all other wells are located in Gonzales County. | |
|
(6) |
The Pavlicek #1H had an operational issue which initially prevented all completed stages from producing. Subsequently, additional stages have begun to produce and the well is currently producing in excess of 500 BOPD. | |
|
(7) |
The Bozka #1H well was acquired in October 2012 and was completed in April 2011 by another operator. | |
|
(8) |
The Kusak #1H and Leal #1H have just been completed and are flowing back frac fluids. As a result, production data for these wells have been excluded. | |
Mid-Continent
During the third quarter of 2012, we drilled four (1.1 net) non-operated wells in the Granite Wash; one (0.5 net) well was successful, with final results not yet established on three (0.6 net) wells. We experienced operational problems while drilling our first horizontal Viola Lime well in Jefferson County, Oklahoma and, as a result, shortened the well’s planned lateral length by approximately 3,000 feet. We concluded that the drilled lateral length of approximately 1,100 feet was sufficient to test the concept of the prospect and we stimulated the shortened lateral with a seven-stage acid frac. The production rate is less than 10 BOPD, on pump, which is much less than anticipated. The prospect is being re-evaluated with the possibility of drilling an additional well in 2013 or attempting a recompletion in an up-hole interval in the existing well. We have an acreage position of approximately 9,600 net acres in this play.
Full-Year 2012 Guidance
Full-year 2012 guidance highlights are as follows:
-
Full-year 2012 production of approximately 38 to 39 Bcfe (7.9 to 8.3
Bcfe in the fourth quarter of 2012), compared to previous guidance of
37 to 40 Bcfe
- Crude oil and NGLs are expected to comprise approximately 48 percent of total production during 2012, compared to previous guidance of approximately 47 percent (approximately 54 percent during the fourth quarter of 2012)
-
Full-year 2012 product revenues are expected to be approximately $301
to $307 million ($66 to $73 million in the fourth quarter of 2012),
compared to previous guidance of $284 to $303 million, excluding the
impact of our hedges
- Crude oil and NGL product revenues are expected to be approximately 84 percent of total product revenues, unchanged from previous guidance
- Full-year 2012 settlements of current commodity hedges are expected to result in cash receipts of approximately $30 million, $24 million of which was received during the first nine months of 2012
- Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be $235 to $245 million ($50 to $60 million in the fourth quarter of 2012), compared to previous guidance of $225 to $245 million
-
Full-year 2012 capital expenditures are expected to be $338 to
$350 million ($71 to $83 million in the fourth quarter of 2012),
compared to $300 to $325 million of previous guidance, due to
increased working interests in recent Lavaca County Eagle Ford Shale
wells as a result of our partner going non-consent, as well as
announced acreage additions in the Eagle Ford Shale during the third
quarter of 2012
- Approximately 90 percent of 2012 capital expenditures are expected to be allocated to the Eagle Ford Shale, approximately six percent to the Mid-Continent and four percent to other areas
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.
Preliminary Full-Year 2013 Guidance
As a result of recent equity offerings, the sale of our Appalachian assets and the receipt of a federal income tax refund, we expect to have over $300 million of available liquidity in the form of cash and equivalents and revolver availability as we enter 2013. Preliminarily, we estimate 2013 capital expenditures will range between $310 and $345 million, compared to the mid-point of 2012 capital expenditures guidance of $343 million. This range is contingent on our partner in Lavaca County participating in applicable Lavaca County wells that we plan to drill. During 2013, approximately 85 percent of our capital expenditures will be allocated to activity in Gonzales and Lavaca Counties. Preliminarily, full-year 2013 production is estimated to be approximately 34 to 37 Bcfe, compared to the mid-point of 2012 production guidance, pro forma for the sale of our Appalachian assets, of approximately 34 Bcfe. We estimate that 2013 oil and NGL production will range between 55 and 65 percent of total production. Full year crude oil production is expected to be approximately 25 percent higher in 2013 than the midpoint of 2012 production guidance, while fourth quarter 2013 oil production is expected to be approximately 40 percent higher than the midpoint of fourth quarter 2012 oil production guidance. Our expected cash flows in 2013, along with available liquidity as we enter 2013, are expected to be more than sufficient to fund 2013 capital expenditures.
Capital Resources and Liquidity
As of September 30, 2012, we had total debt with a carrying value of approximately $676 million ($682 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 $77 million of borrowings under our revolving credit facility (Revolver). Our indebtedness at September 30, 2012 was approximately 46 percent of book capitalization and 2.7 times the latest twelve months’ Adjusted EBITDAX of $248 million. As a result of the $161 million issuance of preferred and common equity in October 2012, pro forma net debt at September 30, 2012 was approximately $516 million and net debt-to-Adjusted EBITDAX was approximately 2.1 times. Currently, we have no amounts borrowed under the Revolver, approximately $298 million of availability under the Revolver and approximately $50 million of cash on hand. We have no material debt maturities until 2016.
Explanation of Non-GAAP Gross Operating Margin per Mcfe
Gross operating margin is a non-GAAP financial measure under Securities and Exchange Commission (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.
Third Quarter 2012 Financial and Operational Results Conference Call
A conference call and webcast, during which management will discuss third quarter 2012 financial and operational results, is scheduled for Thursday, November 1, 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 4295337), 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 4295337. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.
Penn Virginia Corporation (NYSE: PVA) is an independent oil and gas company engaged primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions including Texas, Oklahoma, Mississippi and Pennsylvania. 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 oil, natural gas liquids 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, natural gas liquids 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 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.
| PENN VIRGINIA CORPORATION | ||||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited | ||||||||||||||||
| (in thousands, except per share data) | ||||||||||||||||
| Three months ended | Nine months ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Revenues | ||||||||||||||||
| Natural gas | $ | 11,909 | $ | 34,171 | $ | 37,098 | $ | 113,660 | ||||||||
| Crude oil | 56,995 | 37,147 | 174,100 | 75,278 | ||||||||||||
| Natural gas liquids (NGLs) | 6,671 | 10,676 | 23,298 | 33,758 | ||||||||||||
| Total product revenues | 75,575 | 81,994 | 234,496 | 222,696 | ||||||||||||
| Gain on sales of property and equipment | 1,573 | 71 | 2,407 | 523 | ||||||||||||
| Other | 551 | 1,288 | 2,052 | 2,335 | ||||||||||||
| Total revenues | 77,699 | 83,353 | 238,955 | 225,554 | ||||||||||||
| Operating expenses | ||||||||||||||||
| Lease operating | 6,206 | 8,458 | 24,613 | 29,522 | ||||||||||||
| Gathering, processing and transportation | 3,127 | 2,952 | 11,672 | 11,261 | ||||||||||||
| Production and ad valorem taxes | 4,589 | 3,391 | 7,915 | 11,289 | ||||||||||||
| General and administrative (excluding equity-classified share-based compensation) (a) | 10,352 | 10,815 | 31,289 | 33,312 | ||||||||||||
| Total direct operating expenses | 24,274 | 25,616 | 75,489 | 85,384 | ||||||||||||
| Share-based compensation - equity classified awards (b) | 1,282 | 1,820 | 4,233 | 5,629 | ||||||||||||
| Exploration | 9,265 | 19,303 | 26,647 | 68,219 | ||||||||||||
| Depreciation, depletion and amortization | 49,331 | 45,345 | 151,888 | 113,224 | ||||||||||||
| Impairments | 700 | - | 29,316 | 71,071 | ||||||||||||
| Loss on firm transportation commitment | 17,332 | - | 17,332 | - | ||||||||||||
| Other | - | 300 | - | 300 | ||||||||||||
| Total operating expenses | 102,184 | 92,384 | 304,905 | 343,827 | ||||||||||||
| Operating loss | (24,485 | ) | (9,031 | ) | (65,950 | ) | (118,273 | ) | ||||||||
| Other income (expense) | ||||||||||||||||
| Interest expense | (14,979 | ) | (14,206 | ) | (44,837 | ) | (41,833 | ) | ||||||||
| Loss on extinguishment of debt | (3,144 | ) | (1,165 | ) | (3,144 | ) | (25,403 | ) | ||||||||
| Derivatives | (12,271 | ) | 11,498 | 31,250 | 19,827 | |||||||||||
| Other | 60 | 61 | 89 | 334 | ||||||||||||
| Loss before income taxes | (54,819 | ) | (12,843 | ) | (82,592 | ) | (165,348 | ) | ||||||||
| Income tax benefit | 22,208 | 6,125 | 32,444 | 60,372 | ||||||||||||
| Net loss | $ | (32,611 | ) | $ | (6,718 | ) | $ | (50,148 | ) | $ | (104,976 | ) | ||||
| Loss per share: | ||||||||||||||||
| Basic | $ | (0.71 | ) | $ | (0.15 | ) | $ | (1.09 | ) | $ | (2.29 | ) | ||||
| Diluted | $ | (0.71 | ) | $ | (0.15 | ) | $ | (1.09 | ) | $ | (2.29 | ) | ||||
| Weighted average shares outstanding, basic | 46,050 | 45,817 | 46,009 | 45,758 | ||||||||||||
| Weighted average shares outstanding, diluted | 46,050 | 45,817 | 46,009 | 45,758 | ||||||||||||
| Three months ended | Nine months ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Production | ||||||||||||||||
| Natural gas (MMcf) | 4,371 | 8,051 | 16,524 | 26,646 | ||||||||||||
| Crude oil (MBbls) | 573 | 427 | 1,693 | 833 | ||||||||||||
| NGLs (MBbls) | 202 | 222 | 645 | 695 | ||||||||||||
| Total natural gas, crude oil and NGL production (MMcfe) | 9,024 | 11,947 | 30,551 | 35,817 | ||||||||||||
| Prices | ||||||||||||||||
| Natural gas ($ per Mcf) | $ | 2.72 | $ | 4.24 | $ | 2.25 | $ | 4.27 | ||||||||
| Crude oil ($ per Bbl) | $ | 99.45 | $ | 87.03 | $ | 102.82 | $ | 90.33 | ||||||||
| NGLs ($ per Bbl) | $ | 32.94 | $ | 48.00 | $ | 36.14 | $ | 48.56 | ||||||||
| Prices - Adjusted for derivative settlements | ||||||||||||||||
| Natural gas ($ per Mcf) | $ | 3.77 | $ | 4.87 | $ | 3.36 | $ | 4.88 | ||||||||
| Crude oil ($ per Bbl) | $ | 107.53 | $ | 88.29 | $ | 105.45 | $ | 90.54 | ||||||||
| NGLs ($ per Bbl) | $ | 32.94 | $ | 48.00 | $ | 36.14 | $ | 48.56 | ||||||||
(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 $0.2 million and $0.8 million attributable to these awards is included in the three and nine months ended September 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 | ||||||||||||||||
| September 30, | December 31, | |||||||||||||||
| 2012 | 2011 | |||||||||||||||
| Assets | ||||||||||||||||
| Current assets | $ | 91,907 | $ | 145,346 | ||||||||||||
| Net property and equipment | 1,745,091 | 1,777,575 | ||||||||||||||
| Other assets | 25,739 | 20,132 | ||||||||||||||
| Total assets | $ | 1,862,737 | $ | 1,943,053 | ||||||||||||
| Liabilities and shareholders' equity | ||||||||||||||||
| Current liabilities (a) | $ | 121,551 | $ | 106,607 | ||||||||||||
| Revolving credit facility | 77,000 | 99,000 | ||||||||||||||
| Senior notes due 2016 | 294,447 | 293,561 | ||||||||||||||
| Senior notes due 2019 | 300,000 | 300,000 | ||||||||||||||
| Other liabilities and deferred income taxes | 274,457 | 297,576 | ||||||||||||||
| Total shareholders' equity | 795,282 | 846,309 | ||||||||||||||
| Total liabilities and shareholders' equity | $ | 1,862,737 | $ | 1,943,053 | ||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited | ||||||||||||||||
| (in thousands) | ||||||||||||||||
| Three months ended | Nine months ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Cash flows from operating activities | ||||||||||||||||
| Net loss | $ | (32,611 | ) | $ | (6,718 | ) | $ | (50,148 | ) | $ | (104,976 | ) | ||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||||||
| Non-cash portion of loss on extinguishment of debt | 3,144 | 634 | 3,144 | 22,456 | ||||||||||||
| Loss on firm transportation commitment | 17,332 | - | 17,332 | |||||||||||||
| Depreciation, depletion and amortization | 49,331 | 45,345 | 151,888 | 113,224 | ||||||||||||
| Impairments | 700 | - | 29,316 | 71,071 | ||||||||||||
| Derivative contracts: | ||||||||||||||||
| Net losses (gains) | 12,271 | (11,498 | ) | (31,250 | ) | (19,827 | ) | |||||||||
| Cash settlements | 9,238 | 8,527 | 24,189 | 20,302 | ||||||||||||
| Deferred income tax benefit | (22,208 | ) | (6,125 | ) | (32,444 | ) | (60,372 | ) | ||||||||
| (Gain) loss on the sales of assets, net | (1,573 | ) | 229 | (2,407 | ) | (223 | ) | |||||||||
| Non-cash exploration expense | 8,310 | 11,376 | 24,765 | 52,457 | ||||||||||||
| Non-cash interest expense | 1,057 | 1,062 | 3,107 | 5,812 | ||||||||||||
| Share-based compensation (equity-classified) | 1,282 | 1,820 | 4,233 | 5,629 | ||||||||||||
| Other, net | 99 | (40 | ) | 302 | 225 | |||||||||||
| Changes in operating assets and liabilities | 28,117 | (5,207 | ) | 48,187 | (2,614 | ) | ||||||||||
| Net cash provided by operating activities | 74,489 | 39,405 | 190,214 | 103,164 | ||||||||||||
| Cash flows from investing activities | ||||||||||||||||
| Capital expenditures - property and equipment | (68,958 | ) | (107,193 | ) | (257,194 | ) | (318,274 | ) | ||||||||
| Proceeds from the sales of assets, net | 92,749 | 30,381 | 93,276 | 31,077 | ||||||||||||
| Other, net | - | - | 180 | 100 | ||||||||||||
| Net cash provided by (used in) investing activities | 23,791 | (76,812 | ) | (163,738 | ) | (287,097 | ) | |||||||||
| Cash flows from financing activities | ||||||||||||||||
| Dividends paid | - | (2,580 | ) | (5,176 | ) | (7,736 | ) | |||||||||
| Proceeds from revolving credit facility borrowings | 20,000 | 30,000 | 104,000 | 30,000 | ||||||||||||
| Repayment of revolving credit facility borrowings | (123,000 | ) | (15,000 | ) | (126,000 | ) | (15,000 | ) | ||||||||
| Proceeds from the issuance of senior notes | - | - | - | 300,000 | ||||||||||||
| Repurchase of convertible notes | - | - | - | (232,963 | ) | |||||||||||
| Debt issuance costs paid | (1,779 | ) | (2,291 | ) | (1,779 | ) | (8,850 | ) | ||||||||
| Other, net | - | 174 | - | 1,148 | ||||||||||||
| Net cash (used in) provided by financing activities | (104,779 | ) | 10,303 | (28,955 | ) | 66,599 | ||||||||||
| Net decrease in cash and cash equivalents | (6,499 | ) | (27,104 | ) | (2,479 | ) | (117,334 | ) | ||||||||
| Cash and cash equivalents - beginning of period | 11,532 | 30,681 | 7,512 | 120,911 | ||||||||||||
| Cash and cash equivalents - end of period | $ | 5,033 | $ | 3,577 | $ | 5,033 | $ | 3,577 | ||||||||
| Supplemental disclosures of cash paid for: | ||||||||||||||||
| Interest (net of amounts capitalized) | $ | 1,209 | $ | (2,417 | ) | $ | 27,865 | $ | 17,288 | |||||||
| Income taxes (net of refunds received) | $ | (32,263 | ) | $ | 529 | $ | (32,574 | ) | $ | 433 | ||||||
(a) The 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 | Nine months ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
|
Reconciliation of GAAP "Net loss" to Non-GAAP "Net loss, as adjusted" |
||||||||||||||||
| Net loss | $ | (32,611 | ) | $ | (6,718 | ) | $ | (50,148 | ) | $ | (104,976 | ) | ||||
| Adjustments for derivatives: | ||||||||||||||||
| Net losses (gains) included in net loss | 12,271 | (11,498 | ) | (31,250 | ) | (19,827 | ) | |||||||||
| Cash settlements | 9,238 | 8,527 | 24,189 | 20,302 | ||||||||||||
| Adjustment for impairments | 700 | - | 29,316 | 71,071 | ||||||||||||
| Adjustment for restructuring costs | 1,432 | 1,553 | 1,284 | 1,623 | ||||||||||||
| Adjustment for net loss (gain) on sale of assets | (1,573 | ) | 229 | (2,407 | ) | (223 | ) | |||||||||
| Adjustment for loss on extinguishment of debt | 3,144 | 1,165 | 3,144 | 25,403 | ||||||||||||
| Adjustment for loss on firm transportation commitment | 17,332 | - | 17,332 | - | ||||||||||||
| Impact of adjustments on income taxes | (17,235 | ) | 11 | (16,345 | ) | (35,909 | ) | |||||||||
| Net loss, as adjusted (a) | $ | (7,302 | ) | $ | (6,731 | ) | $ | (24,885 | ) | $ | (42,536 | ) | ||||
| Net loss, as adjusted, per share, diluted | $ | (0.16 | ) | $ | (0.15 | ) | $ | (0.54 | ) | $ | (0.93 | ) | ||||
|
Reconciliation of GAAP "Net loss" to Non-GAAP "Adjusted EBITDAX" |
||||||||||||||||
| Net loss | $ | (32,611 | ) | $ | (6,718 | ) | $ | (50,148 | ) | $ | (104,976 | ) | ||||
| Income tax benefit | (22,208 | ) | (6,125 | ) | (32,444 | ) | (60,372 | ) | ||||||||
| Interest expense | 14,979 | 14,206 | 44,837 | 41,833 | ||||||||||||
| Depreciation, depletion and amortization | 49,331 | 45,345 | 151,888 | 113,224 | ||||||||||||
| Exploration | 9,265 | 19,303 | 26,647 | 68,219 | ||||||||||||
| Share-based compensation expense (equity-classified awards) | 1,282 | 1,820 | 4,233 | 5,629 | ||||||||||||
| EBITDAX | 20,038 | 67,831 | 145,013 | 63,557 | ||||||||||||
| Adjustments for derivatives: | ||||||||||||||||
| Net gains included in net income | 12,271 | (11,498 | ) | (31,250 | ) | (19,827 | ) | |||||||||
| Cash settlements | 9,238 | 8,527 | 24,189 | 20,302 | ||||||||||||
| Adjustment for loss on firm transportation commitment | 17,332 | - | 17,332 | - | ||||||||||||
| Adjustment for impairments | 700 | - | 29,316 | 71,071 | ||||||||||||
| Adjustment for net loss (gain) on sale of assets | (1,573 | ) | 229 | (2,407 | ) | (223 | ) | |||||||||
| Adjustment for loss on extinguishment of debt | 3,144 | 1,165 | 3,144 | 25,403 | ||||||||||||
| Adjusted EBITDAX (b) | $ | 61,150 | $ | 66,254 | $ | 185,337 | $ | 160,283 | ||||||||
(a) Net loss, as adjusted, represents the net loss adjusted to exclude the effects of non-cash changes in the fair value of derivatives, restructuring costs, and net gains and losses on the sale of assets. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. 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, and net gains and losses on the sale of assets. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net 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 | Second | Third | |||||||||||||||||
| Quarter | Quarter | Quarter | YTD | Full-Year | |||||||||||||||
| 2012 | 2012 | 2012 | 2012 | 2012 Guidance | |||||||||||||||
| Production: | |||||||||||||||||||
| Natural gas (Bcf) | 6.3 | 5.9 | 4.4 | 16.5 | 20.1 | - | 20.3 | ||||||||||||
| Crude oil (MBbls) | 549 | 572 | 573 | 1,693 | 2,220 | - | 2,250 | ||||||||||||
| NGLs (MBbls) | 215 | 227 | 202 | 645 | 835 | - | 845 | ||||||||||||
| Equivalent production (Bcfe) | 10.9 | 10.7 | 9.0 | 30.6 | 38.4 | - | 38.9 | ||||||||||||
| Equivalent daily production (MMcfe per day) | 119.5 | 117.1 | 98.1 | 111.5 | 105.0 | - | 106.2 | ||||||||||||
| Equivalent production (MBOE) | 1,812 | 1,775 | 1,504 | 5,092 | 6,405 | - | 6,478 | ||||||||||||
| Equivalent daily production (MBOE per day) | 19.9 | 19.5 | 16.5 | 18.6 | 17.5 | - | 17.7 | ||||||||||||
| Percent crude oil and NGLs | 42.1% | 45.0% | 51.6% | 45.9% | 47.2% | - | 48.3% | ||||||||||||
| Production revenues (a): | |||||||||||||||||||
| Natural gas | $ | 14.9 | $ | 10.3 | $ | 11.9 | $ | 37.1 | 49.0 | - | 50.0 | ||||||||
| Crude oil | $ | 58.7 | $ | 58.4 | $ | 57.0 | $ | 174.1 | 223.0 | - | 228.0 | ||||||||
| NGLs | $ | 9.1 | $ | 7.6 | $ | 6.7 | $ | 23.3 | 28.7 | - | 29.2 | ||||||||
| Total product revenues | $ | 82.7 | $ | 76.2 | $ | 75.6 | $ | 234.5 | 300.7 | - | 307.2 | ||||||||
| Total product revenues ($ per Mcfe) | $ | 7.60 | $ | 7.16 | $ | 8.37 | $ | 7.68 | 7.82 | - | 7.90 | ||||||||
| Total product revenues ($ per BOE) | $ | 45.62 | $ | 42.94 | $ | 50.25 | $ | 46.05 | 46.95 | - | 47.42 | ||||||||
| Percent crude oil and NGLs | $ | 82.0% | $ | 86.5% | $ | 84.2% | $ | 84.2% | 83.4% | - | 84.0% | ||||||||
| Operating expenses: | |||||||||||||||||||
| Lease operating ($ per Mcfe) | $ | 0.84 | $ | 0.87 | $ | 0.69 | $ | 0.81 | 0.81 | - | 0.82 | ||||||||
| Lease operating ($ per BOE) | $ | 5.04 | $ | 5.22 | $ | 4.13 | $ | 4.83 | 4.86 | - | 4.92 | ||||||||
| Gathering, processing and transportation costs ($ per Mcfe) | $ | 0.38 | $ | 0.41 | $ | 0.35 | $ | 0.38 | 0.36 | - | 0.37 | ||||||||
| Gathering, processing and transportation costs ($ per BOE) | $ | 2.29 | $ | 2.47 | $ | 2.08 | $ | 2.29 | 2.16 | - | 2.22 | ||||||||
| Production and ad valorem taxes (percent of oil and gas revenues) | 4.3% | -0.3% | 6.1% | 3.4% | 3.7% | - | 3.8% | ||||||||||||
| General and administrative: | |||||||||||||||||||
| Recurring general and administrative | $ | 10.5 | $ | 10.6 | $ | 8.9 | $ | 30.0 | 38.5 | - | 39.0 | ||||||||
| Share-based compensation | $ | 1.6 | $ | 1.3 | $ | 1.3 | $ | 4.2 | 5.3 | - | 5.5 | ||||||||
| Restructuring | $ | - | $ | (0.1) | $ | 1.4 | $ | 1.3 | 1.3 | - | 1.3 | ||||||||
| Total reported G&A | $ | 12.1 | $ | 11.7 | $ | 11.6 | $ | 35.5 | 45.1 | - | 45.8 | ||||||||
| Exploration: | |||||||||||||||||||
| Total reported exploration | $ | 8.0 | $ | 9.4 | $ | 9.3 | $ | 26.6 | 38.0 | - | 39.0 | ||||||||
| Unproved property amortization | $ | 8.2 | $ | 8.3 | $ | 8.3 | $ | 24.8 | 33.5 | - | 34.0 | ||||||||
| Depreciation, depletion and amortization ($ per Mcfe) | $ | 4.67 | $ | 4.86 | $ | 5.47 | $ | 4.97 | 5.00 | - | 5.05 | ||||||||
| Depreciation, depletion and amortization ($ per BOE) | $ | 28.02 | $ | 29.14 | $ | 32.80 | $ | 29.83 | 30.00 | - | 30.30 | ||||||||
| Adjusted EBITDAX (b) | $ | 64.2 | $ | 60.0 | $ | 61.2 | $ | 185.3 | 235.0 | - | 245.0 | ||||||||
| Capital expenditures: | |||||||||||||||||||
| Drilling and completion | $ | 82.6 | $ | 79.8 | $ | 73.1 | $ | 235.5 | 291.0 | - | 301.0 | ||||||||
| Pipeline, gathering, facilities | $ | 3.9 | $ | 4.4 | $ | 5.0 | $ | 13.3 | 16.0 | - | 17.0 | ||||||||
| Seismic (c) | $ | (0.4) | $ | 0.7 | $ | 0.1 | $ | 0.4 | 3.0 | - | 4.0 | ||||||||
| Lease acquisitions, field projects and other | $ | 4.3 | $ | 6.6 | $ | 6.4 | $ | 17.3 | 27.5 | - | 28.0 | ||||||||
| Total oil and gas capital expenditures | $ | 90.4 | $ | 91.5 | $ | 84.6 | $ | 266.6 | 337.5 | - | 350.0 | ||||||||
| End of period debt outstanding | $ | 717.6 | $ | 779.0 | $ | 671.4 | $ | 671.4 | |||||||||||
| Effective interest rate | 8.5% | 8.5% | 8.5% | 8.5% | |||||||||||||||
| Income tax benefit rate | 35.7% | 39.2% | 40.5% | 39.3% | 39.0% | - | 39.5% | ||||||||||||
(a) Assumes average benchmark prices of $90 per barrel for crude oil, $31.50 per barrel for NGLs and $3.51 per MMBtu for natural gas during the fourth quarter of 2012, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments.
(b) Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.
(c) Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities.
| PENN VIRGINIA CORPORATION | ||||||||
| GUIDANCE TABLE - unaudited - (continued) | ||||||||
|
Note to Guidance Table: |
||||||||
| The following table shows our current derivative positions. | ||||||||
| Weighted Average Price | ||||||||
|
|
Average Volume |
|
|
|||||
|
Instrument Type |
Per Day |
Floor/ Swap |
Ceiling |
|||||
| Natural gas: | (MMBtu) | ($ / MMBtu) | ||||||
| First quarter 2013 | Collars | 10,000 | 3.50 | 4.30 | ||||
| Second quarter 2013 | Collars | 10,000 | 3.50 | 4.30 | ||||
| Third quarter 2013 | Collars | 10,000 | 3.50 | 4.30 | ||||
| Fourth quarter 2013 | Collars | 10,000 | 3.50 | 4.30 | ||||
| Fourth quarter 2012 | Swaps | 10,000 | 5.10 | |||||
| First quarter 2013 | Swaps | 5,000 | 4.04 | |||||
| Second quarter 2013 | Swaps | 5,000 | 4.04 | |||||
| Third quarter 2013 | Swaps | 5,000 | 4.04 | |||||
| Fourth quarter 2013 | Swaps | 5,000 | 4.04 | |||||
| Crude oil: | (barrels) | ($ / barrel) | ||||||
| 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 | ||||
| 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 fourth quarter of 2012 would increase or decrease by approximately $2.5 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the fourth quarter of 2012 would increase or decrease by approximately $5.4 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.