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CPE > SEC Filings for CPE > Form 10-Q on 9-May-2013All Recent SEC Filings

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Form 10-Q for CALLON PETROLEUM CO


9-May-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.

Overview and Outlook

Production and highlights of our operations include:
                                               Net Production (MBoe)
                                           Three Months Ended March 31,
                                     2013          2012       Change    % Change
Onshore - Permian Basin:
 Southern Portion                     93          77             16         21  %
 Central Portion                      49          37             12         32  %
  Total Permian                      142         114             28         25  %

Offshore - Deepwater Properties
 Medusa                              105         136            (31 )      (23 )%
 Habanero                              -          42            (42 )     (100 )%
  Total Deepwater                    105         178            (73 )      (41 )%

Other:
 Haynesville Shale                     8           6              2         33  %
 Gulf of Mexico shelf                 73          94            (21 )      (22 )%
  Total Other                         81         100            (19 )      (19 )%

Total                                328         392            (64 )      (16 )%

The following table sets forth productive wells as of March 31, 2013:

                      Crude Oil Wells         Natural Gas Wells
                      Gross        Net          Gross          Net
Working interest     108          87.18       10               4.3
Royalty interest       3           0.10        2              0.08
  Total              111          87.28       12              4.38


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

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 38,127 gross
(32,962 net) acres as of May 1, 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 three months ended
March 31, 2013:
                               Drilled         Completed
                            Gross     Net    Gross     Net
Southern portion:
  Vertical wells                -       -     -          -
  Horizontal wells              4    3.95     1       1.00
   Total southern portion       4    3.95     1       1.00

Central portion:
  Vertical wells                1    0.42     2       1.39
  Horizontal wells              -       -     -          -
   Total central portion        1    0.42     2       1.39

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

Total                           5    4.37     4       3.14

Southern portion: We currently own approximately 7,785 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 three months ended March 31, 2013, we drilled three 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 two gross horizontal wells targeting the Wolfcamp formation. As of March 31, 2013, we had three gross horizontal wells awaiting fracture stimulation.

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 15 horizontal wells, an increase of 10 over the horizontal wells drilled in 2012. We also plan to drill one vertical well during the year. 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 3,560 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 three months ended March 31, 2013, we drilled one gross vertical well, recompleted one gross vertical well, and fracture stimulated two gross vertical wells. We currently have one gross vertical well awaiting fracture stimulation. In late 2012 our drilling program in the Pecan Acres and Carpe Diem fields targeted deeper intervals below the Atoka formation. Our future vertical drilling plans within the 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 seven 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. We are currently developing plans for the drilling of a horizontal evaluation well on our Carpe Diem acreage.


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

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 three months ended March 31, 2013, we fracture stimulated one gross horizontal well targeting the Mississippian lime zone. The well had a 24-hour peak oil rate of 136 barrels of oil per day (bopd) while simultaneously producing 2,000 barrels of water per day. The oil production rate quickly declined and stabilized at a rate of 10 to 15 barrels of oil per day while maintaining a high water production rate. We recently set a mechanical plug in an effort to isolate an oil producing zone in the Mississippian formation that we believe is above the source of the water production. We are continuing to evaluate the well's performance following this procedure.

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 1,163 Boe per day during the three months ended March 31, 2013, approximately 88% being crude oil that receives pricing based on Mars crude.

In furtherance of our strategy to accelerate development of our onshore properties, on April 29, 2013, we announced our retention of 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 430 net acre unit in the Haynesville shale play in Bossier Parish, Louisiana. As of March 31, 2013, our Haynesville well was producing approximately 524 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position.

Other - Gulf of Mexico shelf properties

We own interests in 14 producing wells in eight crude oil and natural gas fields in the shelf area of the Gulf of Mexico. During the three months ended March 31, 2013, these wells produced 73 MBoe, which accounted for 22% 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 contributed an average of 175 Boe per day of production prior to being shut-in in November 2011, is expected to recommence once the Stingray Pipeline is brought back online, currently anticipated to occur in the second quarter of 2013.

Liquidity and Capital Resources

Historically, our primary sources of funding have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities and, periodically strategic divestitures.

Cash and cash equivalents of $1.4 million remained relatively flat at March 31, 2013 compared to $1.1 million at December 31, 2012.

Our $200 million Credit Facility had an associated borrowing base at March 31, 2013 of $65 million and a maturity of March 15, 2016. In April 2013, the Credit Facility's borrowing base was increased $10 million to $75 million. 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.

As of March 31, 2013, the balance outstanding on the Credit Facility was $27 million with an interest rate of 3.1%, 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. As of May 6, 2013, the balance outstanding on the Credit Facility was $38 million as the Company drew an additional $11 million in support of the Company's ongoing capital development program. Consequently, subsequent to the $10 million increase in the borrowing base net of addition draws on the Credit Facility, the Company's current liquidity position approximates $38.8 million.

At March 31, 2013, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly.


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

2013 capital expenditures

For 2013, we designed a flexible capital spending program, which we plan to fund from cash on hand and cash flows from operations, in addition to borrowings under our Credit Facility. However, depending on economic conditions or the Company's operational results, our capital budget may be adjusted up or down during the year.

Our 2013 capital budget has been established at $125.0 million with over 90% of our budgeted operating expenditures (including drilling, completion, infrastructure, and plugging and abandonment) allocated to our Midland Basin operations. The 15% decrease in total capital from 2011 reflects our primary focus on drilling and completion activities in the Permian Basin and reduced emphasis on acreage acquisitions that were budgeted in 2012 to expand the Company's presence in the basin. Our budget includes further exploration and development of our Permian Basin properties with plans to complete approximately 24 gross wells including 15 horizontal wells and nine vertical wells. Components of the 2013 capital budget include (in millions):

Midland Basin                                $  97
Gulf of Mexico                                  10
Total projected operations budget              107

Capitalized general and administrative costs    14
Capitalized interest and other                   4
Total projected capital expenditures budget  $ 125

We believe that our liquidity position, 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. In addition to cash on hand, cash flows from operations and borrowings under our Credit Facility, we may source additional capital from term debt or preferred equity offerings, as well as the potential sale of our interest in Medusa and Medusa Spar LLC, to fund the potential acceleration in our onshore growth initiatives in the future.


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

The capital expenditures for the three months ended March 31, 2013 include the
following (in millions):
Southern Midland Basin                                                    $     22
Northern Midland Basin                                                           3
Leasehold acquisitions and seismic                                               1
Capitalized interest                                                             1
Capitalized general and administrative costs allocated directly to
exploration and development projects                                             3
  Total capital expenditures                                              $     30

Summary cash flow information is provided as follows:

Operating activities. For the three months ended March 31, 2013, net cash provided by operating activities increased $2.5 million to $12.9 million, from $10.4 million for the same period in 2012. The increase relates primarily to an overall decrease in operating expenses, which were in line with our lower production. Offsetting this increase was an 8% decrease in the price received for crude oil and natural gas on an equivalent basis. Realized prices are discussed below within Results of Operations.

Investing activities. For the three months ended March 31, 2013, net cash used in investing activities was $29.6 million as compared to $44.2 million for the same period in 2012. The $14.6 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.

Financing activities. For the three months ended March 31, 2013, net cash provided by financing activities was $17 million compared to cash used in financing activities of $0.0 million during the same period of 2012. The $17 million increase relates to draws on our Credit Facility.


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

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 March 31,
                                                     2013         2012        Change       % Change
Net production:
Crude oil (MBbls)                                      206          241          (35 )       (15 )%   *
Natural gas (MMcf)                                     738          904         (166 )       (18 )%   *
Total production (MBoe)                                328          392          (64 )       (16 )%
Average daily production (MBoe)                        3.6          4.3         (0.7 )       (16 )%

Average realized sales price (a):
Crude oil (Bbl)                                   $  94.85     $ 106.84     $ (11.99 )       (11 )%
Natural gas (Mcf)                                 $   4.07     $   3.92     $   0.15           4  %
Total on an equivalent basis (Boe)                $  68.72     $  74.73     $  (6.01 )        (8 )%

Crude oil and natural gas revenues (in
thousands):
Crude oil revenue                                 $ 19,540     $ 25,749     $ (6,209 )       (24 )%
Natural gas revenue                                  3,001        3,545         (544 )       (15 )%
Total                                             $ 22,541     $ 29,294     $ (6,753 )       (23 )%

Additional per Boe data:
Sales price                                       $  68.72     $  74.73     $  (6.01 )        (8 )%
Lease operating expense                              17.55        21.02        (3.47 )       (17 )%
Production taxes                                      1.64         1.40         0.24          17  %
Operating margin                                  $  49.53     $  52.31     $  (2.78 )        (5 )%

Other expenses per Boe:
Depletion, depreciation and amortization          $  33.66     $  31.09     $   2.57           8  %
General and administrative                           11.40        12.83        (1.43 )       (11 )%

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

Average NYMEX price per barrel of crude oil       $  94.37     $ 102.93     $  (8.56 )        (8 )%
Basis differential and quality adjustments            1.12         4.78        (3.66 )       (77 )%
Transportation                                       (0.64 )      (0.87 )       0.23         (26 )%
Average realized price per barrel of crude oil    $  94.85     $ 106.84     $ (11.99 )       (11 )%

Average NYMEX price per million British thermal
units ("MMBtu")                                   $   3.48     $   2.51     $   0.97          39  %
Basis differential, quality and Btu adjustments       0.59         1.41        (0.82 )       (58 )%
Average realized price per Mcf of natural gas     $   4.07     $   3.92     $   0.15           4  %

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


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

Revenues

The following table is intended to reconcile the change in crude oil, natural
gas and total revenue for the respective periods presented by reflecting the
effect of changes in volume, changes in the underlying commodity prices and the
impact of our hedge program.

 (in thousands)                                       Crude Oil      Natural Gas        Total
Revenues for the three-months ended March 31, 2011   $   18,804     $      6,645     $  25,449

Volume increase (decrease)                           $    3,841     $     (2,170 )   $   1,671
Price increase (decrease)                                 3,104             (930 )       2,174
Impact of hedges                                              -                -             -
Net increase (decrease) in 2012                           6,945           (3,100 )       3,845

Revenues for the three-months ended March 31, 2012   $   25,749     $      3,545     $  29,294

Volume decrease                                      $   (3,739 )   $       (651 )   $  (4,390 )
Price decrease (increase)                                (2,470 )            107        (2,363 )
Impact of hedges                                              -                -             -
Net decrease in 2013                                     (6,209 )           (544 )      (6,753 )

Revenues for the three-months ended March 31, 2013   $   19,540     $      3,001     $  22,541

Crude oil revenue

Crude oil revenues decreased 24% to $19.5 million for the three months ended March 31, 2013 compared to revenues of $25.7 million for the same period of 2012. Contributing to the decrease in crude oil revenue was an 11% decrease in commodity prices compounded by a 15% decrease in production. The average price realized decreased to $94.85 per barrel compared to $106.84 for the same period of 2012. Production decreased to 206 thousand barrels ("MBbls") during the first quarter of 2013 compared to production of 241 MBbls during the same period in 2012. The decrease in production was primarily attributable to the sale of our deepwater Habanero field in the fourth quarter of 2012, which produced 33 MBbls during the first quarter of 2012. Additionally, normal and expected declines further reduced oil production. Partially offsetting these decreases in our Gulf of Mexico and other properties was a 23 MBbls increase in production from newly producing wells on our Permian properties.

Natural gas revenue

Natural gas revenues of $3.0 million decreased 15% during the three months ended March 31, 2013 as compared to natural gas revenues of $3.5 million for the same period of 2012. The decline primarily relates to an 18% decrease in natural gas production, primarily attributable to the sale of our deepwater Habanero field in the fourth quarter of 2012, which produced 54 MMcf of natural gas during the first quarter of 2012 as well as other normal and expected declines in our Gulf of Mexico properties. These production decreases were partially offset by a 14 MMcf increase in natural gas production from our Haynesville well, which was shut-in for 70 days during the first quarter of 2012 due to well interference from an offsetting well, and to a 30 MMcf increase in the Permian. Also offsetting these production declines was a 4% increase in the average price realized, which rose to $4.07 per thousand cubic feet of natural gas ("Mcf") from $3.92 per Mcf.

Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream from our Permian Basin and offshore production.


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

Operating Expenses
(in thousands except per
unit data)                                                  Three Months Ended March 31,
                                                                                  Total Change           Boe Change
                              2013       Per Boe       2012       Per Boe         $           %          $          %
Lease operating expenses    $ 5,758     $  17.55     $ 8,237     $  21.01     $ (2,479 )    (30 )%   $ (3.46 )    (16 )%
Production taxes                539         1.64         547         1.40           (8 )     (1 )%      0.24       17  %
Depreciation, depletion
and amortization             11,042        33.66      12,189        31.09       (1,147 )     (9 )%      2.57        8  %
General and
administrative                3,739        11.40       5,031        12.83       (1,292 )    (26 )%     (1.43 )    (11 )%
Accretion expense               565         1.72         574         1.46           (9 )     (2 )%      0.26       18  %

Lease operating expenses ("LOE")

Lease operating expenses for the three months ended March 31, 2013 decreased by 30% to $5.8 million compared to $8.2 million for the same period in 2012, which was primarily due to $2.9 million of workover costs in the prior year associated with our Haynesville well for which we had no similar costs in the current period. The additional LOE from our growing Permian operations was partially offset by a reduction in LOE associated with the sale of our Habanero deepwater property in December 2012.

Production taxes

Production taxes remained relatively flat for the three months ended March 31, 2013 as compared to the same period of 2012, though increased 17% on a per Boe basis. The increase relates to an increase of onshore production subject to these taxes while our offshore production is exempt from production taxes.

Depreciation, depletion and amortization

Depreciation, depletion and amortization ("DD&A") for the three months ended March 31, 2013 and compared to the same period of 2012 decreased 9% to $11.0 million compared to $12.2 million. The overall decrease is primarily related to the 16% drop in total production in the first quarter of 2013 compared to the same quarter of 2012. The decrease in DD&A related to production was partially offset by an 8% increase in the DD&A rate on an equivalent basis. Partially contributing to the increase per Boe is that prior period DD&A rates were effectively reduced by the impact of a $486 million 2008 impairment charge following a ceiling test writedown, which resulted in a lower, prospective DD&A rate for the then existing reserves. Subsequent increases in the rate are attributable to our exploration and development expenditures related to our onshore reserve development including the ongoing onshore development cost increases in the Permian Basin area.

General and administrative

General and administrative expenses, net of amounts capitalized, decreased to $3.7 million for the three months ended March 31, 2013 from $5.0 million for the same period of 2012. The decrease primarily consists of a $0.9 million downward revision for the mark-to-market adjustment of certain liability-based incentive compensation instruments. We also recorded a $0.4 million reduction to our performance-based incentive compensation accrual during the first quarter of 2013.

Accretion expense

Accretion expense related to our asset retirement obligation decreased 2% for the three months ended March 31, 2013 compared to the same period of 2012. See Note 8 for additional information regarding the Company's ARO.


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

Other Income and Expenses
(in thousands)                                   Three Months Ended March 31,
. . .
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