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PVA > SEC Filings for PVA > Form 10-Q on 2-Nov-2012All Recent SEC Filings

Show all filings for PENN VIRGINIA CORP

Form 10-Q for PENN VIRGINIA CORP


2-Nov-2012

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries ("Penn Virginia," the "Company," "we," "us" or "our") should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Item 1. 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 and natural gas in various domestic onshore regions. We have a geographically diverse asset base with areas of operations in Texas, the Mid-Continent, Mississippi and Pennsylvania regions of the United States. As of December 31, 2011, we had proved oil and gas reserves of approximately 883 billion cubic feet equivalent, or Bcfe. As discussed in the Key Developments that follow, our total reserves were reduced by approximately106 Bcfe as a result of the sale of our Appalachian properties in July 2012. Our current operations include primarily the drilling of horizontal unconventional development wells and exploring for primarily unconventional reserves.

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 our 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:

                                      Three Months Ended               Nine Months Ended
                                         September 30,                   September 30,
                                     2012            2011            2012            2011
Total production (MMcfe)               9,024          11,947          30,551          35,817
Daily production (MMcfe per day)        98.0           129.8           111.5           131.1
Daily gas production (MMcf per
day)                                    47.5            87.5            60.3            97.5
Daily oil and NGL production
(Bbl per day)                          8,430           7,060           8,530           5,580
Product revenues, as reported    $    75,575     $    81,994     $   234,496     $   222,696
Product revenues, as adjusted
for derivatives                  $    84,812     $    87,601     $   257,279     $   239,180
Operating loss                   $   (24,485 )   $    (9,031 )   $   (65,950 )   $  (118,273 )
Interest expense                 $    14,979     $    14,206     $    44,837     $    41,833
Cash provided by operating
activities                       $    74,489     $    39,405     $   190,214     $   103,164
Cash paid for capital
expenditures                     $    68,958     $   107,193     $   257,194     $   318,274
Cash and cash equivalents at end
of period                                                        $     5,033     $     3,577
Debt outstanding, net of
discounts, at end of period                                      $   676,331     $   612,983
Credit available under revolving
credit facility at end of
period 1                                                         $   221,372     $   283,600
Net development wells drilled            6.0             9.4            18.2            23.8
Net exploratory wells drilled              -             0.1             4.8             6.5

1 As reduced by outstanding borrowings and letters of credit and limited by financial covenants, if applicable.


Table of Contents

Key Developments

Through the date of filing this Quarterly Report on Form 10-Q, the following general business developments and corporate actions had an 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 natural gas liquids, or 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 Appalachian assets and related restructuring and exit activities and (iv) hedging a portion of our oil and natural gas production for the calendar years 2012 through 2014 to the levels permitted by the Revolver and our internal policies. We believe these actions will provide sufficient liquidity in 2013 so that we will be able to fund our capital programs.

Drilling Results and Future Development

During the nine months ended September 30, 2012, we drilled a total of 30 gross (23.0 net) wells, including 20 gross (16.7 net) development wells and five gross
(4.7 net) exploratory wells in the Eagle Ford Shale and five gross (1.6 net)
development wells in the Granite Wash.

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) and acquired one (1.0 net) Eagle Ford Shale wells, 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 barrels of oil equivalent per day, or 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. We have allocated approximately 90 percent of our capital expenditures during 2012 to activities in the Eagle Ford Shale.

Included in the totals presented above for the Eagle Ford Shale are four (3.8 net) exploratory wells and three (2.5 net) development wells in Lavaca County, Texas drilled under a joint exploration agreement with an industry partner that we entered into in December 2011. Under the terms of the agreement, we were required to commence drilling on six wells by September 1, 2012 to earn our entire interest in the acreage as well as carry our partner for its working interest share of the costs of the first three wells. We fulfilled this requirement during the third quarter. Depending upon the future participation elections made by our partners, our working interest in wells drilled in the AMI is expected to be at least 57 percent.

In October 2012, we acquired approximately 4,100 net acres in the Eagle Ford Shale in Gonzales and Lavaca Counties for approximately $10 million. Under existing joint venture agreements, other non-operated working interest owners are expected to acquire approximately 17 percent of the net acreage in Gonzales County and approximately 46 percent of the net acreage in Lavaca County, increasing our net Eagle Ford Shale acreage position by approximately 3,000 net acres to a total of approximately 30,000 net acres.

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 barrels of oil per day, 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 acres in this play.

Production Focus

Since 2011, we have allocated approximately 90 percent of our capital expenditures to explore and develop primarily oil and NGL-rich areas, primarily in the Eagle Ford Shale. Accordingly, we are continuing to transform our production profile away from natural gas to oil and NGLs. Approximately 52 percent of our total production on an equivalent basis during the quarter ended September 30, 2012 was attributable to oil and NGLs, an increase of approximately 19 percent over the prior year period. For the quarter ended September 30, 2012, approximately 84 percent of our product revenues were attributable to oil and NGLs, an increase of approximately 33 percent over the corresponding prior year period.


Table of Contents

Completion of a New Credit Facility

In September 2012, we entered into the Revolver which replaced our previous revolving credit facility that was entered into in August 2011. The Revolver provides for a $300 million revolving 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. The applicable interest rate margin under the Revolver ranges from the London Interbank Offered Rate, or LIBOR, plus 1.50 percent to LIBOR plus 2.50 percent, depending upon the amount drawn at any given time. This rate is unchanged from our previous credit facility. The maximum leverage ratio (net debt divided by Adjusted 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 net proceeds before 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 6% Preferred Stock, that provided approximately $111 million of net proceeds before issuance costs. The proceeds from the combined offerings were used to fully repay outstanding borrowings under our Revolver and for general corporate purposes.

Disposition of Appalachian Assets

On July 31, 2012, we sold all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for $100 million, prior to deducting transaction costs and purchase and sale adjustments. Certain leases subject to the sale, representing approximately $4 million of value, are awaiting consent by the underlying property or mineral owners to be transferred. Such consents are expected to be obtained by the end of 2012. Through September 30, 2012, we received proceeds of $92.2 million, net of transaction costs and customary closing adjustments, and recognized a gain of $1.7 million in connection with the transaction. The sold assets included vertical and horizontal coalbed methane and vertical conventional properties, a gathering system and royalty interests. The sold assets had net production of approximately 20 million cubic feet of dry natural gas equivalent per day during June 2012, almost 100 percent of which was natural gas. As a result of the divestiture, our 2012 production will decrease by an estimated 2.9 Bcfe. Estimated proved reserves associated with the sold assets, as determined by our third party reserve engineer as of December 31, 2011, were approximately 106 Bcfe, of which 96 percent were proved developed. An impairment charge of $28.6 million was recognized in the second quarter of 2012 with respect to these assets.

During the quarter ended September 30, 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 contractual commitments for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we recorded a charge of $17.3 million representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

Commodity Hedging Activities

As of October 26, 2012, we have hedged the maximum volume of oil production as permitted under the terms of the Revolver for calendar years 2013 and 2014. For the remainder of 2012, we have hedged approximately 68 percent of our estimated oil production at weighted-average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel. For 2013, we have approximately 31 to 48 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $97.66 and $102.43 per barrel. For 2014, we have approximately 15 to 24 percent of our estimated oil production hedged at a weighted-average floor/swap and ceiling prices of $100.20 and $100.44 per barrel. Our natural gas hedges represent approximately 24 percent of our estimated production for the balance of the year at a weighted-average swap price of $5.10 per MMBtu. For 2013, we have approximately 36 to 40 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of $3.68 and $4.21 per MMBtu.


Table of Contents

Results of Operations

Three Months Ended September 30, 2012 Compared to the Three Months Ended
September 30, 2011

The following table sets forth a summary of certain operating and financial
performance for the periods presented:
                                        Three Months Ended
                                           September 30,              Favorable
                                       2012            2011         (Unfavorable)      % Change
Total production:
 Natural gas (MMcf)                      4,371           8,051             (3,680 )        (46 )%
 Crude oil (MBbl)                          573             427                146           34  %
 NGLs (MBbl)                               202             222                (20 )         (9 )%
   Total production (MMcfe)              9,024          11,947             (2,923 )        (24 )%
Realized prices, before
derivatives:
 Natural gas ($/Mcf)               $      2.72     $      4.24     $        (1.52 )        (36 )%
 Crude oil ($/Bbl)                       99.45           87.04              12.41           14  %
 NGLs ($/Bbl)                            32.96           48.00             (15.04 )        (31 )%
   Total ($/Mcfe)                  $      8.37     $      6.86     $         1.51           22  %
Revenues
Natural gas                        $    11,909     $    34,171     $      (22,262 )        (65 )%
Crude oil                               56,995          37,147             19,848           53  %
Natural gas liquids (NGLs)               6,671          10,676             (4,005 )        (38 )%
Total product revenues                  75,575          81,994             (6,419 )         (8 )%
Gain on sales of property and
equipment, net                           1,573              71              1,502           NM
Other                                      551           1,288               (737 )        (57 )%
Total revenues                          77,699          83,353             (5,654 )         (7 )%
Operating expenses
Lease operating                          6,206           8,458              2,252           27  %
Gathering, processing and
transportation                           3,127           2,952               (175 )         (6 )%
Production and ad valorem taxes          4,589           3,391             (1,198 )        (35 )%
General and administrative              11,634          12,635              1,001            8  %
Exploration                              9,265          19,303             10,038           52  %
Depreciation, depletion and
amortization                            49,331          45,345             (3,986 )         (9 )%
Impairments                                700               -               (700 )         NM
Loss on firm transportation
commitment                              17,332               -            (17,332 )         NM
Other                                        -             300                300           NM
Total operating expenses               102,184          92,384             (9,800 )        (11 )%
Operating loss                         (24,485 )        (9,031 )          (15,454 )       (171 )%
Other income (expense)
Interest expense                       (14,979 )       (14,206 )             (773 )         (5 )%
Loss on extinguishment of debt          (3,144 )        (1,165 )           (1,979 )         NM
Derivatives                            (12,271 )        11,498            (23,769 )         NM
Other                                       60              61                 (1 )         (2 )%
Loss before income taxes               (54,819 )       (12,843 )          (41,976 )       (327 )%
Income tax benefit                      22,208           6,125             16,083          263  %
Net loss                           $   (32,611 )   $    (6,718 )   $      (25,893 )       (385 )%
NM - Not meaningful


Table of Contents

 Production

The following tables set forth a summary of our total and daily production
volumes by product and geographical region for the periods presented:
                 Three Months Ended                           Three Months Ended
Natural gas         September 30,           Favorable            September 30,           Favorable
                 2012          2011       (Unfavorable)       2012          2011       (Unfavorable)     % Change
                        (MMcf)                                   (MMcf per day)
Texas             1,674         2,154             (479 )        18.2          23.4             (5.2 )      (22 )%
Appalachia          639         2,273           (1,633 )         6.9          24.7            (17.8 )      (72 )%
Mid-Continent       833         2,090           (1,257 )         9.1          22.7            (13.6 )      (60 )%
Mississippi       1,224         1,535             (311 )        13.3          16.7             (3.4 )      (20 )%
                  4,371         8,051           (3,681 )        47.5          87.5              (40 )      (46 )%



                 Three Months Ended                           Three Months Ended
Crude oil           September 30,           Favorable            September 30,           Favorable
                 2012          2011       (Unfavorable)       2012          2011       (Unfavorable)     % Change
                       (MBbl)                                   (MBbl per day)
Texas             502.9         323.7            179.2          5.47          3.52             1.95         55  %
Appalachia          0.4           0.5             (0.1 )           -          0.01            (0.01 )      100  %
Mid-Continent      66.3          98.4            (32.1 )        0.72          1.07            (0.35 )      (33 )%
Mississippi         3.5           4.2             (0.7 )        0.04          0.05            (0.01 )      (20 )%
                  573.1         426.8            146.3          6.23          4.65             1.58         34  %



NGLs           Three Months Ended June 30,      Favorable      Three Months Ended June 30,      Favorable
                   2012            2011       (Unfavorable)         2012           2011       (Unfavorable)     % Change
                         (MBbl)                                       (MBbl per day)
Texas                 118.8         135.3            (16.5 )           1.29          1.47            (0.18 )      (12 )%
Appalachia              0.2           0.2                -                -             -                -         NM
Mid-Continent          83.4          86.9             (3.5 )           0.91          0.94            (0.03 )       (3 )%
                      202.4         222.4            (20.0 )           2.20          2.41            (0.21 )       (9 )%



                  Three Months Ended                        Three Months Ended September
Combined             September 30,           Favorable                   30,                  Favorable
                  2012          2011       (Unfavorable)         2012            2011       (Unfavorable)     % Change
                        (MMcfe)                                    (MMcfe per day)
Texas              5,405         4,908              497              58.7          53.3              5.4         10  %
Appalachia           643         2,277           (1,634 )             7.0          24.7            (17.7 )      (72 )%
Mid-Continent      1,731         3,201           (1,470 )            18.8          34.8              (16 )      (46 )%
Mississippi        1,245         1,560             (315 )            13.5          17.0             (3.5 )      (21 )%
                   9,024        11,947           (2,922 )            98.0         129.8            (31.8 )      (24 )%

Certain results in the tables above may not calculate due to rounding.

The decline in total production during the quarter ended September 30, 2012 compared to the corresponding quarter of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Appalachian properties in July 2012 and Arkoma Basin properties in August 2011. The effect of the sale of the Appalachian properties was approximately 1.5 Bcfe while the effect of the Arkoma Basin properties was 0.4 Bcfe during the quarter. The natural declines in production were partially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 52% of total production on an equivalent basis in the quarter ended September 30, 2012 was attributable to oil and NGLs, a 19% increase over the prior year quarter. The shift in production mix reflects our focus on oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the quarter ended September 30, 2012, our Eagle Ford Shale production of 3.5 Bcfe represented 39% of our total production. We had approximately 2.1 Bcfe of production from this play during the corresponding 2011 quarter.


Table of Contents

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of
volume by product and geographical region for the periods presented:
Natural gas      Three Months Ended September 30,       Favorable       Three Months Ended September 30,       Favorable
                       2012               2011        (Unfavorable)            2012              2011        (Unfavorable)
                                                                                   ($ per Mcf)
Texas           $           3,386     $    8,284     $       (4,898 )   $           2.02     $     3.85     $        (1.83 )
Appalachia                  1,831          9,478             (7,647 )               2.86           4.17              (1.31 )
Mid-Continent               3,109          9,726             (6,617 )               3.73           4.65              (0.92 )
Mississippi                 3,583          6,683             (3,100 )               2.93           4.35              (1.42 )
                $          11,909     $   34,171     $      (22,262 )   $           2.72     $     4.24     $        (1.52 )



Crude oil        Three Months Ended September 30,       Favorable        Three Months Ended June 30,          Favorable
                       2012               2011        (Unfavorable)          2012              2011         (Unfavorable)
                                                                                 ($ per Bbl)
Texas           $          50,498     $   28,215     $      22,283     $        100.41     $    87.16     $         13.25
Appalachia                     34             29                 5               85.00          58.00               27.00
Mid-Continent               6,104          8,481            (2,377 )             92.07          86.19                5.88
Mississippi                   359            422               (63 )            102.57         100.48                2.09
                $          56,995     $   37,147     $      19,848     $         99.45     $    87.04     $         12.41



NGLs            Three Months Ended September 30,       Favorable        Three Months Ended June 30,         Favorable
                       2012              2011        (Unfavorable)          2012              2011        (Unfavorable)
                                                                                ($ per Bbl)
Texas           $          3,838     $    6,881     $      (3,043 )   $         32.31     $    50.86     $      (18.55 )
Appalachia                    10             10                 -               50.00          50.00                 -
Mid-Continent              2,823          3,785              (962 )             33.85          43.56             (9.71 )
                $          6,671     $   10,676     $      (4,005 )   $         32.96     $    48.00     $      (15.04 )



Combined         Three Months Ended September 30,       Favorable         Three Months Ended June 30,         Favorable
                       2012               2011        (Unfavorable)           2012              2011        (Unfavorable)
                                                                                  ($ per Mcfe)
Texas           $          57,722     $   43,380     $      14,342     $          10.68     $     8.84     $        1.84
Appalachia                  1,875          9,517            (7,642 )               2.92           4.18             (1.26 )
Mid-Continent              12,036         21,992            (9,956 )               6.95           6.87              0.08
Mississippi                 3,942          7,105            (3,163 )               3.17           4.55             (1.38 )
                $          75,575     $   81,994     $      (6,419 )   $           8.37     $     6.86     $        1.51

As illustrated below, 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 favorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in our Mid-Continent region. In addition, the sale of our Appalachian assets resulted in a reduction to total revenues of $5.8 million during the three month period. The following table provides an analysis of the change in our revenues for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011:

Revenue Variance Due to
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