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| PVA > SEC Filings for PVA > Form 10-K on 25-Feb-2013 | All Recent SEC Filings |
25-Feb-2013
Annual Report
The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries ("Penn Virginia," "we," "us" or "our") should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, "Financial Statements and Supplemental Data." All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.
Overview of Business
We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various domestic onshore regions. We have a geographically diverse asset base with active operations in Texas, the Mid-Continent and Mississippi regions. Our operations are concentrated in the Eagle Ford Shale, the Granite Wash, Haynesville Shale, Cotton Valley and Selma Chalk plays. As discussed in the Key Developments that follow, we sold our legacy natural gas assets in West Virginia, Kentucky and Virginia in July 2012. As of December 31, 2012, we had proved oil and natural gas reserves of approximately 113.5 MMBOE. Our current operations consist primarily of drilling unconventional horizontal development wells in shale formations.
We are currently focused on development and expansion in the Eagle Ford Shale in South Texas. We also pursue select drilling opportunities in the horizontal Granite Wash play in the Mid-Continent region through participation in wells drilled by our joint venture partner.
The following table sets forth certain summary operating and financial
statistics for the periods presented:
Year Ended December 31,
2012 2011 2010
Total production (MBOE) 6,513 7,759 7,867
Daily production (BOEPD) 17,796 21,254 21,552
Product revenues, as reported $ 310,484 $ 300,046 $ 251,336
Product revenues, as adjusted for derivatives $ 338,802 $ 323,608 $ 284,816
Cash provided by operating activities $ 241,458 $ 144,741 $ 79,839
Cash paid for capital expenditures $ 370,907 $ 445,623 $ 405,994
Cash and cash equivalents at end of period $ 17,650 $ 7,512 $ 120,911
Debt outstanding, net of discounts, at end of
period $ 594,759 $ 697,307 $ 506,536
Liquidation preference of convertible preferred
stock outstanding at end of period $ 115,000 $ - $ -
Credit available under revolving credit facility
at end of period 1 $ 297,922 $ 199,600 $ 299,268
Net development wells drilled 27.8 33.4 40.0
Net exploratory wells drilled 4.9 6.5 4.4
______________________________
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Key Developments
Currently, the following general business developments and corporate actions have an important impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) drilling results in the Eagle Ford Shale and other plays, (ii) continuing to shift the focus of our production from natural gas to oil and NGLs, (iii) entering into a new five-year revolving credit facility, or the Revolver, (iv) completing an offering of common and preferred stock, (v) selling our legacy West Virginia, Kentucky and Virginia natural gas assets and related restructuring and exit activities and (vi) hedging a portion of our oil and natural gas production through calendar year 2014 to the levels permitted by the Revolver and our internal policies. We believe that these actions will provide sufficient liquidity in 2013 so that we will be able to fund our capital program.
Drilling Results and Future Development Plans
During 2012, we drilled a total of 32.7 net wells, including 29.5 net wells in the Eagle Ford Shale and 3.2 net wells in the Mid-Continent.
During 2012, we drilled 35 gross (29.5 net) operated wells in the Eagle Ford Shale, all of which were successful. Since December 2012, we have completed two gross (1.9 net) wells, bringing the total to 69 gross (56.2 net) producing wells, with three gross (2.7 net) wells being drilled. The initial 30-day average gross production rate for 59 of these wells with a 30-day production history was 651 BOEPD. Our Eagle Ford Shale production was approximately 6,377 net BOEPD during 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent. We have allocated approximately 88 percent of our anticipated capital expenditures during 2013 to activities in the Eagle Ford Shale.
Included in the totals for 2012 presented above for the Eagle Ford Shale are four gross (2.9 net) exploratory wells and nine gross (8.1 net) development wells in Lavaca County, Texas drilled under a joint exploration agreement with an industry partner that we entered into in December 2011 to jointly explore a 13,500 acre area of mutual interest, or AMI. Under the terms of the agreement, we were required to commence drilling on six wells by September 1, 2012, as well as carry our partner for its working interest share of the costs of the first three wells, to earn our entire interest in the acreage. We fulfilled this requirement during the third quarter of 2012 and as a result, earned an approximately 60 percent interest in the acreage.
In December 2012, our 40 percent industry partner in the Lavaca County Eagle Ford Shale acreage elected to not participate in the last 17 initial unit wells to be drilled on this acreage. Upon the drilling of each of the initial unit wells, our industry partner will have no participatory rights in any subsequent wells drilled in such unit. We are presently seeking a partner to acquire a 40 percent working interest in the acreage in which our industry partner has elected not to participate.
Our remaining Eagle Ford Shale wells are located in Gonzales County, Texas. We are the operator of all of our Gonzales County acreage with an average working interest of approximately 84 percent.
In addition to the acreage earned in Lavaca County, we acquired approximately 4,100 net acres in the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas in 2012 for approximately $10 million, increasing our net Eagle Ford Shale acreage position to approximately 32,500 net acres.
Production Focus
Since 2011, we have allocated approximately 80 percent of our capital expenditures to explore and develop oil- and NGL-rich areas in the Eagle Ford Shale. Approximately 56 percent of our total production during the quarter ended December 31, 2012 was attributable to oil and NGLs, an increase of approximately 21 percent over the corresponding prior year period. For the quarter ended December 31, 2012, approximately 83 percent of our product revenues were attributable to oil and NGLs, an increase of approximately 17 percent over the corresponding prior year period.
Completion of a New Credit Facility
In September 2012, we entered into the Revolver to replace our previous revolving credit facility that was entered into in August 2011. The Revolver provides for a $300 million revolving credit commitment and an accordion feature to expand commitment amounts by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver has an initial borrowing base of $300 million, which is $70 million higher than the borrowing base under our previous revolving credit facility at the time it was replaced by the Revolver. The applicable interest rate margin under the Revolver ranges from LIBOR plus 1.50 percent to LIBOR plus 2.50 percent, depending upon the amount drawn as a percentage of the commitment. This rate is unchanged from our previous credit facility. The maximum leverage ratio (net debt divided by EBITDAX, as defined in the Revolver) is 4.50 through December 31, 2013, 4.25 through June 30, 2014 and 4.00 through maturity in 2017. The borrowing base under the Revolver will be re-determined based on a semi-annual review of our total proved crude oil, NGL and natural gas reserves starting in the spring of 2013.
Common and Preferred Stock Offering
In October 2012, we completed a registered offering of 9.2 million shares of our common stock that provided approximately $44 million of proceeds net of underwriting fees and issuance costs. Concurrently, we completed a registered offering of 1,150,000 depositary shares each representing 1/100th interest in a share of our 6% Series A Convertible Perpetual Preferred Stock, or the 6% Preferred Stock, that provided approximately $110 million of proceeds net of underwriting fees and issuance costs. The proceeds from the combined offerings were used to fully repay outstanding borrowings under the Revolver and for general corporate purposes.
Disposition of Appalachian Assets
In July 2012, we sold our legacy natural gas assets in West Virginia, Kentucky and Virginia for approximately $100 million, excluding transaction costs and before customary purchase and sale adjustments. The assets sold included vertical and horizontal coalbed methane and vertical conventional properties, a gathering system and royalty interests. These assets had net production of approximately 20 MMcfe per day (3,333 BOEPD) and estimated proved reserves of approximately 106 Bcfe (17.7 MMBOE), of which 96 percent was proved developed and almost 100 percent was natural gas. An impairment charge of $28.6 million was recognized in the second quarter of 2012 with respect to these assets.
During 2012, we recorded certain restructuring and exit costs in connection with the sale, including those attributable to the closing of our office in Canonsburg, Pennsylvania. Furthermore, we have a contractual commitment for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale, we no longer have production to satisfy this commitment. While we intend to sell our unused firm transportation in the future to the extent possible, we recorded a charge of $17.3 million during the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.
Commodity Hedging Activities
For 2013, we have approximately 58 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $97.35 and $100.99 per barrel. For 2014, we have approximately 16 percent of our estimated oil production hedged at a weighted-average swap price of $100.33 per barrel.
For 2013, we have approximately 55 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of $3.76 and $4.19 per MMBtu. We have 5,000 MMBtu per day hedged in the first quarter of 2014 with a floor/swap and ceiling prices of $4.00 and $4.50 per MMBtu. We do not have any NGLs hedged.
Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011
The following table sets forth a summary of certain operating and financial
performance for the periods presented:
Year Ended December 31, Favorable
2012 2011 (Unfavorable) % Change
Total production:
Crude oil (MBbl) 2,252 1,283 969 76 %
NGL (MBbl) 884 907 (23 ) (3 )%
Natural gas (MMcf) 20,261 33,410 (13,149 ) (39 )%
Total production (MBOE) 6,513 7,759 (1,246 ) (16 )%
Realized prices, before derivatives:
Crude oil ($/Bbl) $ 101.95 $ 93.19 $ 8.76 9 %
NGL ($/Bbl) 35.13 47.83 (12.70 ) (27 )%
Natural gas ($/Mcf) 2.46 4.10 (1.64 ) (40 )%
Total ($/BOE) $ 47.67 $ 38.67 $ 9.00 23 %
Revenues
Crude oil $ 229,572 $ 119,582 $ 109,990 92 %
NGL 31,051 43,394 (12,343 ) (28 )%
Natural gas 49,861 137,070 (87,209 ) (64 )%
Total product revenues 310,484 300,046 10,438 3 %
Gain on sales of property and equipment 4,282 3,570 712 20 %
Other income 2,383 2,389 (6 ) - %
Total revenues 317,149 306,005 11,144 4 %
Operating expenses
Lease operating 31,266 36,988 5,722 15 %
Gathering, processing and transportation 14,196 15,157 961 6 %
Production and ad valorem taxes 10,634 13,690 3,056 22 %
General and administrative 45,900 48,328 2,428 5 %
Exploration 34,092 78,943 44,851 57 %
Depreciation, depletion and amortization 206,336 162,534 (43,802 ) (27 )%
Impairments 104,484 104,688 204 - %
Loss on firm transportation commitment 17,332 - (17,332 ) NM
Other - 1,096 1,096 100 %
Total operating expenses 464,240 461,424 (2,816 ) (1 )%
Operating loss (147,091 ) (155,419 ) 8,328 5 %
Other income (expense)
Interest expense (59,339 ) (56,216 ) (3,123 ) (6 )%
Loss on extinguishment of debt (3,164 ) (25,421 ) 22,257 88 %
Derivatives 36,187 15,651 20,536 131 %
Other 116 335 (219 ) (65 )%
Loss before income taxes (173,291 ) (221,070 ) 47,779 22 %
Income tax benefit 68,702 88,155 (19,453 ) (22 )%
Net loss (104,589 ) (132,915 ) 28,326 21 %
Preferred stock dividends (1,687 ) - (1,687 ) NM
Loss attributable to common shareholders $ (106,276 ) $ (132,915 ) $ 26,639 20 %
NM - Not meaningful
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Production
The following tables set forth a summary of our total and daily production
volumes by product and geographic region for the periods presented:
Crude Oil Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
(MBbl) (Bbl per day)
Texas
Eagle Ford Shale 1,959.6 751.2 1,208.4 5,354.1 2,058.1 3,296.0 161 %
East Texas 71.1 117.5 (46.4 ) 194.3 321.9 (127.6 ) (39 )%
Mid-Continent 206.2 395.1 (188.9 ) 563.4 1,082.6 (519.2 ) (48 )%
Mississippi 14.1 18.9 (4.8 ) 38.5 51.7 (13.2 ) (25 )%
Appalachia 1.0 0.5 0.5 2.7 1.3 1.4 105 %
2,251.9 1,283.2 968.8 6,153.0 3,515.5 2,637.4 75 %
NGLs Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
(MBbl) (Bbl per day)
Texas
Eagle Ford Shale 205.2 54.9 150.3 560.7 150.4 410.3 274 %
East Texas 280.7 440.3 (159.6 ) 766.9 1,206.3 (439.4 ) (36 )%
Mid-Continent 397.2 411.1 (13.9 ) 1,085.2 1,126.3 (41.1 ) (3 )%
Mississippi - - - - - - - %
Appalachia 0.8 0.9 (0.1 ) 2.2 2.5 (0.3 ) (11 )%
884.0 907.2 (23.3 ) 2,415.0 2,485.5 (70.5 ) (3 )%
Natural Gas Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
(MMcfe) (MMcfe per day)
Texas
Eagle Ford Shale 1,015 277 738 2.8 0.8 2.0 266 %
East Texas 5,909 9,393 (3,484 ) 16.1 25.7 (9.6 ) (37 )%
Mid-Continent 3,646 8,244 (4,598 ) 10.0 22.6 (12.6 ) (56 )%
Mississippi 4,997 6,441 (1,444 ) 13.7 17.6 (3.9 ) (22 )%
Appalachia 4,695 9,055 (4,360 ) 12.8 24.8 (12.0 ) (48 )%
20,261 33,410 (13,148 ) 55.4 91.5 (36.1 ) (39 )%
Combined
Total Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
(MBOE) (BOE per day)
Texas
Eagle Ford
Shale 2,334 852 1,482 6,377 2,334 4,043 174 %
East Texas 1,337 2,123 (786 ) 3,653 5,816 (2,163 ) (37 )%
Mid-Continent 1,211 2,180 (969 ) 3,309 5,973 (2,664 ) (44 )%
Mississippi 847 1,092 (245 ) 2,314 2,993 (678 ) (22 )%
Appalachia 784 1,511 (727 ) 2,143 4,138 (1,996 ) (48 )%
6,513 7,759 (1,245 ) 17,796 21,254 (3,458 ) (16 )%
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The decline in total production during 2012 compared to 2011 was due primarily to natural production declines as well as the effect of the sale of Appalachian and Arkoma Basin natural gas properties in July 2012 and August 2011, respectively. The effect of the sale of the Appalachian properties was approximately 4.4 Bcfe (700 MBOE) and the Arkoma Basin properties was approximately 2.0 Bcfe (333 MBOE). The natural declines in production from our remaining natural gas properties were partially offset by an increase in oil, NGL and natural gas production attributable to our drilling activity in the Eagle Ford Shale. Approximately 48% of total production in 2012 was attributable to oil and NGLs, which represents an increase of approximately 43% over the previous year. During 2012, our Eagle Ford Shale production of 2,334 MBbl represented approximately 36% of our total production. We had approximately 852 MBbls of production from this play during 2011.
Product Revenues and Prices
The following tables set forth a summary of our revenues and prices per unit of
volume by product and geographic region for the periods presented:
Crude Oil Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
($ per Bbl)
Texas
Eagle Ford Shale $ 202,479 $ 70,399 $ 132,080 $ 103.33 $ 93.72 $ 9.61
East Texas 6,862 11,074 (4,212 ) 96.51 94.25 2.26
Mid-Continent 18,667 36,145 (17,478 ) 90.55 91.48 (0.93 )
Mississippi 1,477 1,924 (447 ) 104.66 101.80 2.86
Appalachia 87 40 47 91.29 80.00 11.29
$ 229,572 $ 119,582 $ 109,990 $ 101.95 $ 93.19 $ 8.76
NGLs Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
($ per Bbl)
Texas
Eagle Ford Shale $ 6,451 $ 2,817 $ 3,634 $ 31.43 $ 51.22 $ (19.79 )
East Texas 10,195 21,936 (11,741 ) 36.32 49.82 (13.50 )
Mid-Continent 14,365 18,595 (4,230 ) 36.16 45.23 (9.07 )
Mississippi - - - - - -
Appalachia 40 46 (6 ) 51.61 51.11 0.50
$ 31,051 $ 43,394 $ (12,343 ) $ 35.13 $ 47.83 $ (12.70 )
Natural Gas Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
($ per Mcfe)
Texas
Eagle Ford Shale $ 2,593 $ 1,015 $ 1,578 $ 2.56 $ 3.66 $ (1.10 )
East Texas 13,607 37,057 (23,450 ) 2.30 3.95 (1.65 )
Mid-Continent 7,920 35,315 (27,395 ) 2.17 4.28 (2.11 )
Mississippi 14,387 27,047 (12,660 ) 2.88 4.20 (1.32 )
Appalachia 11,354 36,636 (25,282 ) 2.42 4.05 (1.63 )
$ 49,861 $ 137,070 $ (87,209 ) $ 2.46 $ 4.10 $ (1.64 )
Combined Total Year Ended December 31, Favorable Year Ended December 31, Favorable
2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
($ per BOE)
Texas
Eagle Ford Shale $ 211,523 $ 74,231 $ 137,292 $ 90.63 $ 87.13 $ 3.50
East Texas 30,664 70,067 (39,403 ) 22.93 33.00 (10.07 )
Mid-Continent 40,952 90,055 (49,103 ) 33.82 41.31 (7.49 )
Mississippi 15,864 28,971 (13,107 ) 18.72 26.53 (7.81 )
Appalachia 11,481 36,722 (25,241 ) 14.64 24.30 (9.66 )
$ 310,484 $ 300,046 $ 10,438 $ 47.67 $ 38.67 $ 9.00
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As illustrated below, higher oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $0.7 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in the Mid-Continent region.
The following table provides an analysis of the change in our revenues for 2012
as compared to 2011:
Volume Price Total
Crude oil $ 90,274 $ 19,716 $ 109,990
NGL (1,110 ) (11,233 ) (12,343 )
Natural gas (53,946 ) (33,263 ) (87,209 )
$ 35,218 $ (24,780 ) $ 10,438
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Effects of Derivatives
Our oil and gas revenues may change significantly from period to period as a
result of changes in commodity prices. As part of our risk management strategy,
we use derivative instruments to hedge oil and gas prices. In 2012 and 2011, we
received $28.3 million and $23.6 million, respectively, in cash settlements of
oil and gas derivatives.
The following table reconciles crude oil and natural gas revenues to realized
prices, as adjusted for derivative activities, for the periods presented:
Year Ended December 31, Favorable
2012 2011 (Unfavorable) % Change
Crude oil revenues as reported $ 229,572 $ 119,582 $ 109,990 92 %
Cash settlements on crude oil
derivatives, net 8,428 1,404 7,024 500 %
Crude oil revenues adjusted for
derivatives $ 238,000 $ 120,986 $ 117,014 97 %
Crude oil prices per Bbl, as reported $ 101.95 $ 93.19 $ 8.76 9 %
Cash settlements on crude oil per Bbl 3.74 1.09 2.65 243 %
Crude oil prices per Bbl adjusted for
derivatives $ 105.69 $ 94.28 $ 11.41 12 %
Natural gas revenues as reported $ 49,861 $ 137,070 $ (87,209 ) (64 )%
. . .
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