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CPE > SEC Filings for CPE > Form 10-Q on 8-Aug-2013All Recent SEC Filings

Show all filings for CALLON PETROLEUM CO

Form 10-Q for CALLON PETROLEUM CO


8-Aug-2013

Quarterly Report


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

General

The following management's discussion and analysis describes the principal factors affecting the Company's results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2012 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-Q.

We have been engaged in the exploration, development, acquisition and production of crude oil and natural gas properties since 1950. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both crude oil and natural gas basins. To date, a significant portion of this onshore transition has been funded by reinvesting the cash flows from our Gulf of Mexico properties. In the fourth quarter of 2012, we monetized our interest in the deepwater Habanero field in order to accelerate development of our onshore properties. In furtherance of this strategy, in April 2013, we announced our intention to evaluate alternatives with respect to a potential sale of our interests in the Medusa field, our remaining deepwater asset.

Recent key accomplishments and development progress:

In May, we successfully completed a $75 million Preferred Stock offering, which provided us with $70 million of net proceeds to accelerate the development of our Permian acreage and to retire the balance on our Credit Facility, leaving $75 million of available borrowing capacity on the Credit Facility.

In June, we expanded our acreage position in the Permian Basin with the acquisition of 2,468 gross (2,186 net) acres in the southern portion of the Midland Basin for approximately $11 million. The properties acquired were producing approximately 145 net Boe per day at the time of acquisition.

During August, we increased our capital budget by 36% to $170 million with approximately 90% of our budgeted operating expenditures (including drilling, completion, and infrastructure) allocated to our Midland Basin operations in an effort to accelerate the development of our fields in the southern and central portions of the Basin. As a result of this budget increase, we expect to increase the total number of Permian wells planned to be drilled in 2013 to 31 gross wells, including 22 horizontal wells (completion of 17 gross wells) and nine vertical wells (completion of eight gross wells) .

On August 1, 2013, we accepted delivery of an additional horizontal drilling rig under a one-year contract to support our expanded drilling program.

To date in 2013, we continue to execute our horizontal drilling program (gross production data provided):

?            Two recent Wolfcamp B shale wells in the East Bloxom field produced
             at a peak (24-hour) rate of 1,258 Boe per day and an average peak
             30-day rate of 634 Boe per day. Since commencing program development
             of this field in 2012, we have drilled seven wells with an average
             lateral length of 7,000 feet and completed four wells with
             demonstrated average peak initial (24-hour) rates of 1,031 Boe per
             day.



?            At our Taylor Draw field, we placed one well targeting the lower
             Wolfcamp B shale on production. The well produced at a 24-hour rate
             of 860 Boe per day. We also completed three additional wells in the
             upper Wolfcamp B zone that are in the process of flowing back. The
             average lateral length for these four drill wells and an additional
             well completed in the first quarter of 2013 is 4,700 feet.

Also during 2013, we continue to execute our vertical Wolfberry drilling program with positive initial results. In our Pecan Acres field, our first well to simultaneous complete multiple zones down to the Woodford shale produced at a gross peak initial (24-hour) production rate of 543 Boe per day.


Table of Contents
Item 2.  Management's Discussion and Analysis of Financial Condition and Results
of Operations (continued)

Overview and Outlook

Production and highlights of our operations include:
                                              Net Production (MBoe)
                                           Three Months Ended June 30,
                                    2013          2012      Change    % Change
Onshore - Permian Basin:
 Southern Portion                   122          85            37         44  %
 Central Portion                     48          57            (9 )      (16 )%
  Total Permian                     170         142            28         20  %

Offshore - Deepwater Properties
 Medusa                              73          90           (17 )      (19 )%
 Habanero                             -          40           (40 )     (100 )%
  Total Deepwater                    73         130           (57 )      (44 )%

Other:
 Haynesville Shale                    7          17           (10 )      (59 )%
 Gulf of Mexico shelf                79          85            (6 )       (7 )%
  Total Other                        86         102           (16 )      (16 )%

Total                               329         374           (45 )      (12 )%



                                           Net Production (MBoe)
                                         Six Months Ended June 30,
                                     2013      2012    Change    % Change
Onshore - Permian Basin:
 Southern Portion                   216         162       54         33  %
 Central Portion                     98          94        4          4  %
  Total Permian                     314         256       58         23  %

Offshore - Deepwater Properties
 Medusa                             178         225      (47 )      (21 )%
 Habanero                             -          81      (81 )     (100 )%
  Total Deepwater                   178         306     (128 )      (42 )%

Other:
 Haynesville Shale                   14          23       (9 )      (39 )%
 Gulf of Mexico shelf               152         181      (29 )      (16 )%
  Total Other                       166         204      (38 )      (19 )%

Total                               658         766     (108 )      (14 )%

The following table sets forth productive wells as of June 30, 2013:

                      Crude Oil Wells         Natural Gas Wells
                      Gross        Net          Gross          Net
Working interest     118          95.23       11               4.8
Royalty interest       3           0.10        2              0.08
  Total              121          95.33       13              4.88


Table of Contents
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)

Highlights of our onshore development program and offshore assets include:

Onshore - Permian Basin

We expect that our production and reserve growth initiatives will continue to focus primarily on the Permian Basin, in which we own approximately 40,275 gross (34,931 net) acres as of August 5, 2013. In order to advance our growth plans, we are directing a significant amount of our 2013 capital budget to horizontal drilling of the Wolfcamp shale formation in the Permian Basin, in addition to our ongoing vertical Wolfberry program. The following table summarizes the Company's drilling progress in the Permian Basin for the six months ended June 30, 2013:

                               Drilled          Completed (a)
                            Gross     Net       Gross       Net
Southern portion:
  Horizontal wells              9    8.22       5          4.51

Central portion:
  Vertical wells                3    1.75       4          2.29
  Horizontal wells              -       -       -             -
   Total central portion        3    1.75       4          2.29

Northern portion:
  Vertical wells                -       -       1          0.75
  Horizontal wells              -       -       1          0.75
   Total northern portion       -       -       2          1.50

Total                          12    9.97      11          8.30

(a) Completions include wells drilled prior to the first half of 2013.

Southern portion: We currently own approximately 9,971 net acres in the southern portion of the Permian Basin. Our current production in the southern portion of the Midland Basin (Crockett, Reagan and Upton Counties in Texas) is derived from vertical drilling operations in the Wolfberry play and horizontal development of the Wolfcamp shale.

During the six months ended June 30, 2013, we drilled nine gross horizontal wells, with an average lateral length of over 6,600 feet, targeting either the Wolfcamp A or Wolfcamp B formations, and we fracture stimulated five gross horizontal wells targeting the Wolfcamp formation. As of June 30, 2013, we had five gross horizontal wells awaiting fracture stimulation.

During the second quarter of 2013, we acquired 2,468 gross (2,186 net) acres and seven gross vertical wells in southern Reagan County, Texas on which we intend to initiate drilling with two gross horizontal wells and two gross vertical wells planned for 2013.

Based on our initial results and the results of other industry participants, we are planning to increase our level of horizontal drilling activity in 2013 in this portion of the Basin, drilling a total of 11 horizontal wells and two vertical wells. Given this level of sustained activity, we are drilling these wells from pads, and intend to incorporate batch completions as the year progresses in an effort to maximize capital efficiency and reduce overall drill and completion time.

Central portion: We currently own approximately 3,343 net acres in the central portion of the Permian Basin. Our current production in the central portion of the Midland Basin (Ector, Glasscock, and Midland Counties in Texas) is primarily from the Wolfberry play, which has recently been modified in this area to include deeper target zones below the Atoka formation.

During the six months ended June 30, 2013, we drilled three gross vertical wells, recompleted one gross vertical well, and fracture stimulated three gross vertical wells. We currently have one gross vertical well awaiting fracture stimulation. In late 2012, we modified our Wolfberry drilling program in the Pecan Acres field to target deeper intervals below the Atoka formation. Given initial results from this initiative, our future vertical drilling plans in both Pecan Acres and Carpe Diem fields will incorporate these deeper zones as part of the completion design. Our remaining 2013 drilling plans include an additional three vertical wells, though we may modify these plans based on the drilling results achieved. In addition, there has been a significant increase in horizontal Wolfcamp shale drilling in the areas surrounding our acreage position in Ector and Midland Counties. Based on the


Table of Contents
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)

results of other industry participants, our remaining 2013 drilling plans will include two horizontal Wolfcamp shale wells on our Carpe Diem acreage.

Northern portion: We currently own approximately 21,617 net acres in the northern portion of the Permian Basin, which includes the 14,653 net acres in Borden County, Texas and 6,964 net acres in Lynn County, Texas. During the six months ended June 30, 2013, we fracture stimulated one gross horizontal well targeting the Mississippian lime zone for evaluation. Due to difficulties in maintaining the drilling of the lateral in our target zone, the results from the well were inconclusive. We plan to drill a vertical well in Borden County to advance our evaluation of the acreage and provide additional information regarding the Mississippian interval.

Although the area has experienced a recent increase in drilling activity, the northern Midland Basin has had limited drilling activity compared with the southern Basin (where our current production is located), which significantly increases the risk associated with successful drilling activities in this area.

Offshore - Deepwater properties

Our net interest in the Medusa field, our remaining deepwater property, produced an average of 981 Boe per day during the six months ended June 30, 2013, approximately 88% being crude oil that receives pricing based on Mars crude. The Medusa platform was shut-in for 23 days during the second quarter of 2013 for planned construction activities on the West Delta 143 oil pipeline through which Medusa's production is transported. Production from the platform was fully restored on June 27, 2013, and as of August 5, 2013 was producing approximately 1,100 Boe, net.

As previously announced in April 2013 and in furtherance of our strategy to accelerate development of our onshore properties, we retained an advisor to assist with the potential sale of the Medusa property.

Other - Shale Gas (Haynesville shale)

We own a 69% working interest in a 429 net acre unit in the Haynesville shale play in Bossier Parish, Louisiana. As of June 30, 2013, our Haynesville well was producing approximately 477 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position.

Other - Gulf of Mexico shelf properties

During the six months ended June 30, 2013, these wells produced 152 MBoe, which accounted for 23% of our total production. We are in the process of plugging and abandoning our only remaining operated shelf property, Mobile Bay 908. Production from the East Cameron Block 257 field, which had been shut-in since November 2011, recommenced on May 9, 2013, and contributed an average of 232 Boe per day of production for the second quarter.

Liquidity and Capital Resources

Historically, our primary sources of funding have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and divestitures, such as the sale of our interest in the deepwater Habanero field.

Cash and cash equivalents of $13.4 million increased by $12.3 million at June 30, 2013 compared to $1.1 million at December 31, 2012. The increase is attributable to proceeds from the preferred stock offering previously discussed in Note 9 and summarized below. As of June 30, 2013, the Company's liquidity position approximated $88.4 million inclusive of cash and cash equivalents and available borrowing capacity under our Credit facility.

On May 30, 2013, we issued $75.0 million of 10.0% Series A Cumulative Preferred Stock (the "Preferred Stock") and received $70 million net proceeds after deducting the underwriting commissions and offering expenses. The first dividend date for the Preferred Stock was June 30, 2013, and these dividends were paid on July 1, 2013 in the amount of $0.7 million for the stub period beginning with the issuance on May 30, 2013 through the first dividend date.

As of June 30, 2013, our $200 million Credit Facility had an associated borrowing base of $75 million and a maturity of March 15, 2016. Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company's major producing fields.


Table of Contents
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)

As of June 30, 2013, no balance was outstanding on the Credit Facility as a portion of the proceeds from the Preferred Stock offering was used to repay the balance then outstanding. The Credit Facility has an interest rate calculated as the London Interbank Offered Rate ("LIBOR") plus a tiered rate ranging from 2.5% to 3.0%, which is based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly.

On May 10, 2013, we entered into the second amendment to our Fourth Amended and Restated Credit Agreement dated as of June 20, 2012 to allow us to pay quarterly Senior Unsecured Debt and Preferred Equity Dividends (as defined in the Credit Facility) of $5.5 million per quarter, so long as we are not in default under the Credit Facility. The amendment became effective with the receipt of a minimum of $30.0 million of net cash proceeds from a preferred equity offering, which in turn was used to pay down the facility.

At June 30, 2013, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly.

2013 capital expenditures

Our revised 2013 capital budget (excluding acquisitions) approximates $170 million and represents a 36% increase over the previous 2013 capital development budget estimate of $125 million. The increase relates to expenditures for additional development activities on our Midland Basin acreage. Approximately 90% of our budgeted operational expenditures (including drilling, completion and infrastructure) are allocated to our Midland Basin operations. Our budget includes further exploration and development of our Permian Basin properties with plans to complete approximately 31 gross wells including 22 horizontal wells and nine vertical wells. Components of the 2013 capital budget include (in millions):

Midland Basin                                  $ 142
Gulf of Mexico                                    11
Total budgeted capital expenditures            $ 153

Capitalized general and administrative costs      13
Capitalized interest and other                     4
Total budgeted capitalized expenses            $  17

Total operational budget                         170

Acquisition - Southern Midland Basin              11
Total capital expenditures                     $ 181

We believe that our cash on hand and the availability under our Credit Facility, combined with our expected operating cash flow based on current commodity prices and forecasted production, will be adequate to meet our forecasted capital expenditures, interest payments, and operating requirements for the remainder of 2013. Depending on economic conditions or the Company's operational results, our capital budget may be adjusted up or down during the year.

The capital expenditures for the six months ended June 30, 2013 include the following (in millions):

Southern Midland Basin                         $ 43
Central Midland Basin                             4
Northern Midland Basin                            3
Total capital expenditures                     $ 50

Capitalized general and administrative costs      5
Capitalized interest and other                    2
Total capitalized expenses                     $  7

Total operational expenditures                   57

Acquisition - Southern Midland Basin             11
Total capital expenditures                     $ 68


Table of Contents
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)

Summary cash flow information is provided as follows:

Operating activities. For the six months ended June 30, 2013, net cash provided by operating activities decreased $7.2 million to $20.2 million, from $27.4 million for the same period in 2012. The decrease relates primarily to a $9.4 million decrease in revenue stemming from a 12% decrease in equivalent production, which was partially offset by a 2% increase in price per equivalent unit produced and lower operating expenses, which were in line with our lower production. Realized prices and production volumes are discussed below within Results of Operations.

Investing activities. For the six months ended June 30, 2013, net cash used in investing activities was $67.4 million as compared to $70.9 million for the same period in 2012. The $3.5 million decrease is primarily attributable to the $15 million acquisition of additional acreage in Borden County located in the northern portion of the Permian Basin during 2012 offset by the $11.0 million acreage acquisition highlighted above and discussed in Note 2.

Financing activities. For the six months ended June 30, 2013, net cash provided by financing activities was $59.4 million compared to cash used in financing activities of $0.2 million during the same period of 2012. The $59.6 million increase relates primarily to the $70.1 million net proceeds from the previously discussed preferred stock offering reduced by cash used to repay amounts outstanding on our Credit Facility.


Table of Contents
Item 2.  Management's Discussion and Analysis of Financial Condition and Results
of Operations (continued)

Results of Operations

The following table sets forth certain unaudited operating information with
respect to the Company's crude oil and natural gas operations for the periods
indicated:
                                                             Three Months Ended June 30,
                                                     2013         2012        Change      % Change
Net production:
Crude oil (MBbls)                                      198          223          (25 )       (11 )% *
Natural gas (MMcf)                                     787          902         (115 )       (13 )% *
Total production (MBoe)                                329          374          (45 )       (12 )%
Average daily production (MBoe)                        3.6          4.1         (0.5 )       (12 )%

Average realized sales price (a):
Crude oil (Bbl)                                   $  96.27     $  98.78     $  (2.51 )        (3 )%
Natural gas (Mcf)                                 $   4.70     $   3.65     $   1.05          29  %
Average realized sales price on an equivalent
basis (Boe)                                       $  69.18     $  67.85     $   1.33           2  %

Crude oil and natural gas revenues (in
thousands):
Crude oil revenue                                 $ 19,061     $ 22,073     $ (3,012 )       (14 )%
Natural gas revenue                                  3,699        3,287          411          13  %
Total                                             $ 22,760     $ 25,360     $ (2,600 )       (10 )%

Additional per Boe data:
Average realized sales price                      $  69.18     $  67.85     $   1.33           2  %
Lease operating expense                              16.36        14.03         2.33          17  %
Production taxes                                      2.09         1.54         0.55          36  %
Operating margin                                  $  50.73     $  52.28     $  (1.55 )        (3 )%

Other expenses per Boe:
Depletion, depreciation and amortization          $  32.38     $  31.69     $   0.69           2  %
General and administrative                           13.81        11.70         2.11          18  %

(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:

Average NYMEX price per barrel ("Bbl") of crude
oil                                               $  94.22     $  93.49     $   0.73           1  %
Basis differential and quality adjustments            2.52         3.68        (1.16 )       (32 )%
Transportation                                       (0.47 )      (0.68 )       0.21         (31 )%
Hedging                                                  -         2.29        (2.29 )      (100 )%
Average realized price per Bbl of crude oil       $  96.27     $  98.78        (2.51 )        (3 )%

Average NYMEX price per million British thermal
units ("MMBtu")                                   $   4.01     $   2.35     $   1.66          71  %
Basis differential, quality and Btu adjustments       0.69         1.30        (0.61 )       (47 )%
Average realized price per Mcf of natural gas     $   4.70     $   3.65     $   1.05          29  %

* Please refer to the Crude oil and Natural gas revenue discussions included below for an explanation of the production declines.


Table of Contents
Item 2.  Management's Discussion and Analysis of Financial Condition and Results
of Operations (continued)

                                                              Six Months Ended June 30,
                                                     2013         2012        Change      % Change
Net production:
Crude oil (MBbls)                                      404          465          (61 )       (13 )% *
Natural gas (MMcf)                                   1,525        1,806         (281 )       (16 )% *
Total production (MBoe)                                658          766         (108 )       (14 )%
Average daily production (MBoe)                        3.6          4.2         (0.6 )       (14 )%

Average realized sales price (a):
Crude oil (Bbl)                                   $  95.55     $ 102.86     $  (7.31 )        (7 )%
Natural gas (Mcf)                                 $   4.39     $   3.78     $   0.61          16  %
Average realized sales price on an equivalent
basis (Boe)                                       $  68.85     $  71.36     $  (2.51 )        (4 )%

Crude oil and natural gas revenues (in
thousands):
Crude oil revenue                                 $ 38,601     $ 47,822     $ (9,221 )       (19 )%
Natural gas revenue                                  6,700        6,833         (133 )        (2 )%
Total                                             $ 45,301     $ 54,655     $ (9,354 )       (17 )%

Additional per Boe data:
Average realized sales price                      $  68.85     $  71.36     $  (2.51 )        (4 )%
Lease operating expense                              16.93        19.07        (2.14 )       (11 )%
Production taxes                                      1.86         1.46         0.40          27  %
Operating margin                                  $  50.06     $  50.83     $  (0.77 )        (2 )%

Other expenses per Boe:
Depletion, depreciation and amortization          $  32.97     $  31.38     $   1.59           5  %
General and administrative                           12.59        12.28         0.31           3  %

(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:

. . .

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