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PVA > SEC Filings for PVA > Form 10-Q on 30-Oct-2013All Recent SEC Filings

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Form 10-Q for PENN VIRGINIA CORP


30-Oct-2013

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," "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, natural gas liquids, or NGLs, and natural gas in various onshore regions of the United States. Our current operations and capital expenditures are substantially concentrated in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma, the Haynesville Shale and Cotton Valley in East Texas and the Selma Chalk in Mississippi. As of December 31, 2012, we had proved oil and natural gas reserves of approximately 113.5 million barrels of oil equivalent, or MMBOE. In April 2013, we acquired proved reserves of approximately 12.0 MMBOE in connection the acquisition of the Eagle Ford Shale assets of Magnum Hunter Resources Corporation, or MHR. The transaction is referred to herein as the Acquisition. In connection with a mid-year review of our total proved oil and natural gas reserves, we estimate that we have approximately 114.7 MMBOE as of June 30, 2013 including those from the Acquisition and the effect of current year production, revisions, extensions, discoveries and additions. Our current operations consist primarily of the drilling of horizontal development wells in resource or unconventional plays.

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,
                                         2013            2012           2013            2012
Total production (MBOE)                    1,807          1,504           4,982          5,092
Daily production (BOEPD)                  19,638         16,348          18,249         18,584

Product revenues, as reported        $   121,648     $   75,575     $   313,606     $  234,496
Product revenues, as adjusted for
derivatives                          $   117,483     $   84,812     $   315,231     $  257,279

Cash provided by operating
activities                           $    95,083     $   74,489     $   224,834     $  190,214
Cash paid for capital expenditures,
excluding the Acquisition            $   127,645     $   68,958     $   356,964     $  257,194

Cash and cash equivalents at end of
period                                                              $    38,321     $    5,033
Debt outstanding, net of discounts,
at end of period                                                    $ 1,203,000     $  676,331
Liquidation preference of
convertible preferred stock
outstanding at end of period                                        $   115,000     $        -
Credit available under revolving
credit facility at end of period 1                                  $   218,968     $  221,372

Net development wells drilled                8.9            6.0            28.2           18.2
Net exploratory wells drilled                  -              -               -            4.8


______________________________

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


Key Developments

The following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) drilling results and future development plans in the Eagle Ford Shale, (ii) integrating the properties obtained in the Acquisition, (iii) the amendment, or Amendment, of our revolving credit facility, or the Revolver, and borrowing base re-determination, (iv) hedging a portion of our oil and natural gas production through calendar year 2015 to the levels permitted by our Revolver, and our internal policies, (v) the tender offer and the redemption, or the Tender Offer and the Redemption, of our 10.375% Senior Notes due 2016, or 2016 Senior Notes and (vi) the private placement and subsequent registration of $775 million of 8.5% Senior Notes due 2020, or 2020 Senior Notes, to finance the Acquisition, the Tender Offer and the Redemption.

Drilling Results and Future Development Plans for the Eagle Ford Shale

During the nine months ended September 30, 2013, we drilled 37 gross (24.4 net) successful wells, and our joint venture partner drilled seven (2.8 net) successful non-operated wells in the Eagle Ford Shale. We also drilled one (0.5 net) well that is currently under evaluation. We also participated in two successful non-operated gross (0.5 net) wells in the Granite Wash.

Our Eagle Ford Shale production was approximately 12,489 net BOEPD during the three months ended September 30, 2013 with oil comprising approximately 78 percent, NGLs approximately 12 percent and natural gas approximately 10 percent. In the Eagle Ford Shale, we currently have a total of 158 gross (105.4 net) producing wells, 10 gross (4.8 net) operated wells completing or waiting on completion and six gross (3.2 net) operated wells being drilled as of October 30, 2013. Despite this growth, our production and revenues increased less than expected during the three months ended September 30, 2013 due to several issues associated with the outside operated Eagle Ford Shale program. Our non-operated partner recently reduced its rig count from two to one and, as a result, we have increased our operated drilling rig count by one rig.

Subsequent to the Acquisition, we have approximately 107,000 gross (67,000 net) acres, which to a large extent are contiguous and the majority of which are in the volatile oil window of the Eagle Ford Shale. Approximately 93,000 gross (61,000 net) acres are operated by us.

The average stimulation (completion) cost per frac stage for our operated Eagle Ford Shale wells was approximately $110,000 in the three months ended September 30, 2013, compared to approximately $150,000 in the three months ended June 30, 2013. The average total well cost per frac stage was approximately $350,000 in the three months ended September 30, 2013, compared to approximately $430,000 in the three months ended June 30, 2013. This decrease was due primarily to the reduced stimulation costs, as well as efficiency gains from increased use of pad drilling. A total of 16 of our recently drilled wells were drilled off of six multi-well pads, with an average effective nominal spacing of approximately 70 acres.

Acquisition of Magnum Hunter's Eagle Ford Shale Assets

On April 24, 2013, or the Date of Acquisition, we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play from MHR. The Acquisition was originally valued at $401 million with an effective date of January 1, 2013, or the Effective Date. On the Date of Acquisition, we paid approximately $380 million in cash, including approximately $19 million of initial purchase price adjustments related to the period from the Effective Date to the Date of Acquisition utilizing a portion of the proceeds from the private placement of the 2020 Senior Notes, and issued to MHR 10 million shares of our common stock, or Shares, with a fair value of $4.23 per share. Shortly after the Date of Acquisition, certain of our joint interest partners exercised preferential rights related to the Acquisition. We received approximately $21 million from the exercise of these rights, which was recorded as a decrease to our purchase price for the Acquisition. In September 2013, MHR sold the Shares to institutional investors in a series of private transactions.

The Acquisition included approximately 40,600 gross (17,700 net) mineral acres located in Gonzales and Lavaca Counties, Texas in areas adjacent to our current position in both counties. The acquired net assets also included working interests in 46 gross (22.1 net) producing wells and related accounts receivable and payable. At the time of the Acquisition, the estimated net oil and gas production for the acquired assets during 2013 was approximately 2,700 barrels of oil per day equivalent, or BOEPD. Based on MHR's third-party reserve engineering firm's year-end 2012 review of the acquired assets, proved reserves were approximately 12.0 MMBOE, 96 percent of which were oil and NGLs and 37 percent of which were proved developed.


Revolver Amendment and Borrowing Base Re-Determination

The Revolver was amended in October 2013 to increase the revolving commitment from $350 million to $400 million. Concurrently, the borrowing base under the Revolver was increased from $350 million to $425 million.The Amendment also provides for an extension of the current maximum leverage ratio of 4.5 to 1.0 for an additional six months and allows for the Revolver's administrative agent to replace any lender who fails to approve a borrowing base increase approved by lenders representing two thirds of the aggregate commitment.

Commodity Hedging Activities

For the remainder of 2013, we have approximately 79 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $94.69 and $96.99 per barrel. For 2014, we have approximately 50 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $93.49 and $94.32 per barrel. For 2015, we have approximately 13 percent of our estimated oil production hedged at a weighted-average swap price of $91.74 per barrel.

For the remainder of 2013, we have approximately 63 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of between $3.82 and $4.24 per MMBtu. Through the third quarter of 2014, we have approximately 39 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of between $4.13 and $4.19 per MMBtu. We have also hedged approximately 14 percent of our estimated natural gas production for the winter 2014 - 2015 at a weighted-average swap price of $4.50 per MMBtu.

Tender Offer and Redemption for the 2016 Senior Notes

In April 2013, we initiated the Tender Offer for any and all of the $300 million principal amount of the 2016 Senior Notes. Holders of approximately 58% of the 2016 Senior Notes outstanding tendered their notes. The total consideration payable for each $1,000 principal amount of those 2016 Senior Notes tendered was $1,065.34, which included a consent payment of $30.00 per $1,000 principal amount of 2016 Senior Notes tendered. In April 2013, we paid approximately $191 million, including accrued interest of $6.5 million for the 2016 Senior Notes tendered. In May 2013, we made an irrevocable election in connection with the Redemption to redeem the remaining 42% of the 2016 Senior Notes outstanding in accordance with the 2016 Senior Notes indenture. We paid a total of $1,061.31 per $1,000 principal amount of the 2016 Senior Notes, or approximately $140 million, including accrued interest of $5.3 million, in connection with the Redemption. We recognized a loss on the extinguishment of debt of $29.2 million during the three months ended June 30, 2013 in connection with the Tender Offer and the Redemption, including non-cash charges of $10.0 million attributable to the write-off of unamortized debt issuance costs and the remaining debt discount associated with the 2016 Senior Notes.

Issuance of 2020 Senior Notes

On April 24, 2013, we completed a private placement of $775 million of the 2020 Senior Notes. In July 2013, we completed an exchange offer that resulted in the registration of all of the 2020 Senior Notes. The 2020 Senior Notes were priced at par and interest will be payable on June 15 and December 15 of each year. The 2020 Senior Notes are fully and unconditionally guaranteed by all of our material subsidiaries, or Guarantor Subsidiaries. Approximately $380 million of the net proceeds from the private placement were used to finance the cash consideration for the Acquisition, including initial purchase price adjustments. The remaining net proceeds were used to pay down borrowings under the revolving credit facility, or the Revolver, and to fund a portion of the Tender Offer and the Redemption.


 Results of Operations

Three Months Ended September 30, 2013 Compared to the Three Months Ended
September 30, 2012

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        Three Months Ended                          Three Months Ended
                   September 30,           Favorable            September 30,           Favorable
                 2013          2012      (Unfavorable)        2013          2012      (Unfavorable)     % Change
                       (MBbl)                                   (Bbl per day)
Texas
South Texas       897.9        489.8            408.0       9,759.4       5,324.1          4,435.2           83  %
East Texas         15.5         13.1              2.4         168.1         142.5             25.7           18  %
Mid-Continent      37.8         66.3            (28.5 )       410.8         720.5           (309.7 )        (43 )%
Mississippi         3.2          3.5             (0.3 )        35.1          38.2             (3.1 )         (8 )%
Appalachia            -          0.4             (0.4 )           -           4.1             (4.1 )       (100 )%
                  954.4        573.1            381.3      10,373.5       6,229.4          4,144.0           67  %


NGLs             Three Months Ended                           Three Months Ended
                   September 30,           Favorable            September 30,            Favorable
                 2013          2012      (Unfavorable)        2013           2012      (Unfavorable)     % Change
                       (MBbl)                                   (Bbl per day)
Texas
South Texas       142.1         49.6             92.4       1,544.0          539.2          1,004.9          186  %
East Texas         42.5         69.2            (26.7 )       462.4          752.7           (290.3 )        (39 )%
Mid-Continent      69.3         83.4            (14.1 )       753.3          906.8           (153.5 )        (17 )%
Mississippi           -            -                -             -              -                -            -  %
Appalachia            -          0.2             (0.2 )           -            2.3             (2.3 )       (100 )%
                  253.9        202.4             51.4       2,759.7        2,201.0            558.7           25  %



Natural gas      Three Months Ended                         Three Months Ended
                   September 30,           Favorable           September 30,          Favorable
                 2013          2012      (Unfavorable)       2013         2012      (Unfavorable)      % Change
                       (MMcf)                                 (MMcf per day)
Texas
South Texas         693          250              443          7.5          2.7              4.8          177  %
East Texas        1,129        1,424             (295 )       12.3         15.5             (3.2 )        (21 )%
Mid-Continent       674          833             (159 )        7.3          9.1             (1.7 )        (19 )%
Mississippi       1,057        1,224             (167 )       11.5         13.3             (1.8 )        (14 )%
Appalachia           37          639             (602 )        0.4          6.9             (6.5 )        (94 )%
                  3,591        4,371             (780 )       39.0         47.5             (8.5 )        (18 )%


Combined
total              Three Months Ended                             Three Months Ended
                      September 30,             Favorable           September 30,           Favorable
                   2013             2012      (Unfavorable)       2013          2012      (Unfavorable)      % Change
                         (MBOE)                                     (BOE per day)
Texas
South Texas           1,155           581              574      12,558.9      6,316.7          6,242.2           99  %
East Texas              246           320              (73 )     2,676.1      3,474.9           (798.9 )        (23 )%
Mid-Continent           219           289              (69 )     2,385.5      3,136.4           (750.9 )        (24 )%
Mississippi             179           208              (28 )     1,950.5      2,255.7           (305.2 )        (14 )%
Appalachia                6           107             (101 )        67.5      1,164.6         (1,097.1 )        (94 )%
                      1,807         1,504              303      19,638.5     16,348.4          3,290.1           20  %

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

Total production increased during the three months ended September 30, 2013 compared to the corresponding period of 2012 due primarily to the Acquisition and the continued expansion of our development program in South Texas, both of which were concentrated in the Eagle Ford Shale. The increase was partially offset by the effect of the sale of our Appalachian natural


gas properties in July 2012 along with natural production declines in our East Texas and Mid-Continent regions. The effect of the sale of the Appalachian properties was approximately 102 thousand barrels of oil equivalent, or MBOE. Approximately 67% of total production during the three months ended September 30, 2013 was attributable to oil and NGLs, which represents an increase of approximately 56% over the prior year period. During the three months ended September 30, 2013, our Eagle Ford Shale production represented approximately 64% of our total production as compared to approximately 39% from this play during the corresponding period of 2012.

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        Three Months Ended                           Three Months Ended
                   September 30,            Favorable           September 30,            Favorable
                  2013         2012       (Unfavorable)        2013         2012       (Unfavorable)
                                                                 ($ per Bbl)
Texas
South Texas   $    94,794    $ 49,266    $      45,528     $    105.58    $ 100.58    $          5.00
East Texas          1,629       1,232              397          105.31       94.00              11.31
Mid-Continent       3,789       6,104           (2,315 )        100.24       92.09               8.16
Mississippi           352         359               (7 )        109.05      102.10               6.94
Appalachia              -          34              (34 )            NM       89.95                 NM
              $   100,564    $ 56,995    $      43,569     $    105.37    $  99.45    $          5.92


NGLs                     Three Months Ended                                    Three Months Ended
                           September 30,                Favorable                September 30,                Favorable
                        2013              2012        (Unfavorable)           2013              2012        (Unfavorable)
                                                                                  ($ per Bbl)
Texas
South Texas       $     3,919         $    1,419     $        2,500     $     27.59         $    28.61     $        (1.02 )
East Texas              1,858              2,419               (561 )         43.68              34.93               8.75
Mid-Continent           2,435              2,823               (388 )         35.14              33.84               1.30
Mississippi                 -                  -                  -               -                  -                  -
Appalachia                  -                 10                (10 )             -              47.17                 NM
                  $     8,212         $    6,671     $        1,541     $     32.34         $    32.94     $        (0.60 )


Natural gas            Three Months Ended                                Three Months Ended
                         September 30,              Favorable              September 30,              Favorable
                      2013            2012        (Unfavorable)         2013            2012        (Unfavorable)
                                                                            ($ per Mcfe)
Texas
South Texas       $     2,560     $      662     $        1,898     $      3.69     $     2.64     $        1.05
East Texas              4,001          2,724              1,277            3.54           1.91              1.63
Mid-Continent           2,367          3,109               (742 )          3.51           3.73             (0.22 )
Mississippi             3,824          3,583                241            3.62           2.93              0.69
Appalachia                120          1,831             (1,711 )          3.22           2.86                NM
                  $    12,872     $   11,909     $          963     $      3.58     $     2.72     $        0.86


Combined total           Three Months Ended                                 Three Months Ended
                           September 30,              Favorable               September 30,                Favorable
                        2013            2012        (Unfavorable)          2013              2012        (Unfavorable)
                                                                               ($ per BOE)
Texas
South Texas         $   101,273     $   51,347     $      49,926     $     87.65         $    88.36     $        (0.71 )
East Texas                7,488          6,375             1,113           30.41              19.94              10.47
Mid-Continent             8,591         12,036            (3,445 )         39.15              41.71              (2.57 )
Mississippi               4,176          3,942               234           23.27              19.00               4.28
Appalachia                  120          1,875            (1,755 )            NM              17.50                 NM
                    $   121,648     $   75,575     $      46,073     $     67.33         $    50.25     $        17.08
NM - Not meaningful


The following table provides an analysis of the change in our revenues for the three months ended September 30, 2013 as compared to the three months ended September 30, 2012:

Revenue Variance Due to
              Volume       Price       Total
Crude oil   $ 37,920     $ 5,649     $ 43,569
NGL            1,693        (152 )      1,541
Natural gas   (2,125 )     3,088          963
            $ 37,488     $ 8,585     $ 46,073

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 the three months
ended September 30, 2013 and 2012, we paid $4.2 million and received $9.2
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:
                                             Three Months Ended
                                               September 30,              Favorable
                                            2013            2012        (Unfavorable)      % Change
Crude oil revenues as reported          $   100,564     $   56,995     $      43,569           76  %
Cash settlements on crude oil
derivatives, net                             (4,649 )        4,633            (9,282 )         NM
Crude oil revenues adjusted for
derivatives                             $    95,915     $   61,628     $      34,287           56  %

Crude oil prices per Bbl, as reported   $    105.37     $    99.45     $        5.92            6  %
Cash settlements on crude oil
derivatives per Bbl                           (4.87 )         8.08            (12.95 )         NM
Crude oil prices per Bbl adjusted for
derivatives                             $    100.50     $   107.53     $       (7.03 )         (7 )%

Natural gas revenues as reported        $    12,872     $   11,909     $         963            8  %
Cash settlements on natural gas
derivatives, net                                484          4,604            (4,120 )        (89 )%
Natural gas revenues adjusted for
derivatives                             $    13,356     $   16,513     $      (3,157 )        (19 )%

Natural gas prices per Mcf, as reported $      3.58     $     2.72     $        0.86           32  %
Cash settlements on natural gas
derivatives per Mcf                            0.13           1.05             (0.92 )        (88 )%
Natural gas prices per Mcf adjusted for
derivatives                             $      3.71     $     3.77     $       (0.06 )         (2 )%

(Loss) Gain on Sales of Property and Equipment

In the three months ended September 30, 2013, we recognized several individually insignificant losses on the sale of property, equipment, tubular inventory and well materials, and we recognized a gain of $1.7 million during the corresponding period of 2012 related primarily to the sale of our Appalachian natural gas assets.

Other Income

Other income, which includes gathering, transportation, compression and water disposal fees and other miscellaneous operating income, net of marketing and related expenses, decreased during the three months ended September 30, 2013 due primarily to accretion expense attributable to our stranded firm transportation obligation in the Appalachian region.


Production and Lifting Costs
                                   Three Months Ended
                                      September 30,             Favorable
                                     2013           2012      (Unfavorable)     % Change
Lease operating                $    8,457         $ 6,206    $      (2,251 )     (36 )%
Per unit of production ($/BOE) $     4.68         $  4.13    $       (0.55 )     (13 )%

Lease operating expense increased during the three months ended September 30, 2013 due primarily to higher chemical and water disposal costs associated with our increased oil production as well as higher downhole repairs and maintenance costs, particularly in our East Texas region. These increases were partially offset by lower compression charges.

                                                Three Months Ended
                                                  September 30,                 Favorable
                                               2013              2012         (Unfavorable)       % Change
Gathering, processing and transportation $     3,039         $    3,127     $            88            3 %
Per unit of production ($/BOE)           $      1.68         $     2.08     $          0.40           19 %
. . .
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