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MCF > SEC Filings for MCF > Form 10-K/A on 21-Aug-2013All Recent SEC Filings

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Form 10-K/A for CONTANGO OIL & GAS CO


21-Aug-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report.

Overview

Contango is a Houston-based, independent natural gas and oil company. The Company's business is to explore, develop, produce and acquire natural gas and oil properties onshore and offshore in the Gulf of Mexico in water-depths of less than 300 feet. COI, our wholly-owned subsidiary, acts as operator on certain offshore properties.

Revenues and Profitability. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable.

Reserve Replacement. Generally, our producing properties offshore in the Gulf of Mexico have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire natural gas and oil reserves. The Company did not drill any wells during the fiscal year ended June 30, 2012, and as a result was not able to replace any reserves. Our permits to spud Ship Shoal
134 ("Eagle") and South Timbalier 75 ("Fang") were approved in September 2011 and March 2012, respectively, but a lack of rig availability prevented us from drilling these wells during fiscal year 2012. While waiting for drilling rigs to become available, we spent most of fiscal year 2012 generating new prospects. On June 20, 2012, the Company was the apparent high bidder on six lease blocks at the Central Gulf of Mexico Lease Sale 216/222. Upon approval from the BSEE, our plan is to promptly apply for permits to drill these prospects in 2013, 2014 and 2015. We therefore do not believe there will be a material impact on future sales or revenues or income from continuing operations.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold, and in the future may continue to sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to reduce debt and further our exploration activities.

Use of Estimates. The preparation of our financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oil reserves, the timing and costs of our future drilling, development and abandonment activities, and income taxes.

Related Party Transactions. The Company relies on JEX and REX to generate its offshore and onshore domestic natural gas and oil prospects. In addition to generating new prospects, JEX occasionally evaluates offshore and onshore exploration prospects generated by third-party independent companies for us to purchase. See Note 13 - Related Party Transactions for a detailed description of our transactions with JEX and REX.

See "Risk Factors" on page 13 of the Original Filing for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.

Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium

In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for another operator, sank after an apparent blowout and fire. In response, the Secretary of the Interior required all drilling operations in the Gulf of Mexico to stop until operators certify that they have adequate plans in place to quickly shut down an out-of-control well, that the blowout preventers atop the wells it drills have passed rigorous new tests, and that sufficient cleanup resources are on hand in the event of a spill.

Business Impact

We believe that the Deepwater Horizon incident will have a significant and lasting effect on the U.S. offshore energy industry, and will result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. A significant delay of planned exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on production, including a reduction in operating results and cash flows as we deplete our reserves. There may be other impacts of which we are not aware at this time.


Finally, the potential for removal of the liability cap for claims of damages from oil spills, and/or the enactment of onerous rules and regulations regarding activities in the Gulf of Mexico could significantly alter our industry. Such rules could effectively limit which companies can operate in the Gulf of Mexico. Small and medium-sized oil and gas companies may not be able to obtain insurance coverage at economically appropriate levels or meet financial responsibility requirements and would be forced to exit operations in the Gulf of Mexico. Potentially less attractive economics for exploration and development

programs going forward will require companies retaining operations in the Gulf of Mexico to review their business models. We have drilled, and believe we can continue to drill, safely in the Gulf of Mexico. However, exploration and production companies will be able to continue doing business in the Gulf of Mexico only to the extent it remains economically viable.

Delays and volatility are inherent in our business. We have maintained a capital structure with a strong liquidity position allowing us to manage during periods of uncertainty. We believe we are well-positioned to respond to the increasingly complex regulatory framework for the Gulf of Mexico.

Results of Operations

The following table shows the relationship between volumes and revenues from continuing operations.

                                                   Fiscal Year Ended June 30,
                                                2012                       2011
                                                 (thousands, except percentage)
    Natural gas volumes (Mcf)              23,617       75.50 %       24,268       75.48 %
    Condensate and NGL volumes (Mcfe)       7,662       24.50 %        7,885       24.52 %

    Total volumes                          31,279                     32,153

    Natural gas revenues                $  73,232       40.85 %    $ 106,781       52.93 %
    Condensate and NGL revenues           106,040       59.15 %       94,940       47.07 %

    Total revenues                      $ 179,272                  $ 201,721

The table below sets forth average daily production data in Mmcfed from our offshore wells for the three months ended for each of the periods presented:

                                       September 30,         December 31,         March 31,         June 30,
                                           2011                  2011               2012              2012
Dutch and Mary Rose wells                        63.2                 66.2              59.3             67.5
Ship Shoal 263 well (Nautilus)                    7.6                 10.9               7.8              7.6
Vermilion 170 well (Swimmy)                       2.3                 17.2              15.3             15.5
Non-operated wells                                0.3                  0.2               0.3              0.2

                                                 73.4                 94.5              82.7             90.8

Dutch and Mary Rose Wells. Third-party platform and pipeline repairs, as well as third-party gas processing plant shut-ins reduced our flowrates at our Dutch #1, #2, and #3 wells during the three months ended September 2011. During the three months ended March 31, 2012 our Dutch #1, #2 and #3 wells were shut in for a total of 10 days for maintenance and to repair a small pipeline leak. As of August 24, 2012, these ten wells were flowing approximately 67.1 Mmcfed, net to Contango.

Ship Shoal 263 Well (Nautilus). For the three months ended September 30, 2011, production at Ship Shoal 263 was temporarily shut-in due to a leak on a third-party owned and operated pipeline. For the three months ended March 31, 2012 and June 30, 2012, production was intermittent due to overheating and scaling problems. As of August 24, 2012, the well was flowing at approximately
3.0 Mmcfed, net to Contango.

Vermilion 170 Well (Swimmy). Our Vermilion 170 well began production in September 2011, and as of August 24, 2012, was flowing at approximately 13.4 Mmcfed, net to Contango.

The table below sets forth revenue, production data, average sales prices and average production costs associated with our sales of natural gas, oil and natural gas liquids ("NGLs") from continuing operations for the fiscal years ended June 30,


2012, 2011 and 2010. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet ("Mcf") of natural gas. Reported lease operating expenses include property and severance taxes.

                                               Year ended June 30,                       Year ended June 30,
                                         2012           2011           %           2011           2010          %
                                                   (thousands)                               (thousands)
Revenues:
Natural gas and oil sales.             $ 179,272      $ 201,721         -11 %    $ 201,721      $ 159,010         27 %

Total revenues                         $ 179,272      $ 201,721         -11 %    $ 201,721      $ 159,010         27 %
Annual Production:
Natural gas (million cubic feet)
Dutch and Mary Rose field                 18,303         20,589         -11 %       20,589         21,019         -2 %
Vermilion 170 field                        3,098             -          100 %           -              -           0 %
Other fields                               2,216          3,679         -40 %        3,679             62       5834 %

Total natural gas                         23,617         24,268          -3 %       24,268         21,081         15 %
Oil and condensate (thousand
barrels)
Dutch and Mary Rose field                    347            456         -24 %          456            501         -9 %
Vermilion 170 field                          123             -          100 %           -              -           0 %
Other fields                                 145            217         -33 %          217              3       7133 %

Total oil and condensate.                    615            673          -9 %          673            504         34 %
Natural gas liquids (thousand
gallons)
Dutch and Mary Rose field                 21,452         25,389         -16 %       25,389         24,642          3 %
Vermilion 170 field                        5,390             -          100 %           -              -           0 %
Other fields                                 959          1,537         -38 %        1,537             48       3102 %

Total natural gas liquids.                27,801         26,926           3 %       26,926         24,690          9 %
Total (million cubic feet
equivalent)
Dutch and Mary Rose field                 23,450         26,952         -13 %       26,952         27,545         -2 %
Vermilion 170 field                        4,606             -          100 %           -              -           0 %
Other fields                               3,223          5,201         -38 %        5,201             87       5888 %

Total production                          31,279         32,153          -3 %       32,153         27,632         16 %

Daily Production:
Natural gas (million cubic feet per
day)
Dutch and Mary Rose field                   50.0           56.4         -11 %         56.4           57.6         -2 %
Vermilion 170 field                          8.5             -          100 %           -              -           0 %
Other fields                                 6.1           10.1         -40 %         10.1            0.2       5834 %

Total natural gas                           64.5           66.5          -3 %         66.5           57.8         15 %
Oil and condensate (thousand barrels
per day)
Dutch and Mary Rose field                    0.9            1.2         -24 %          1.2            1.4         -9 %
Vermilion 170 field                          0.3             -          100 %           -              -           0 %
Other fields                                 0.4            0.6         -33 %          0.6            0.0       7133 %

Total oil and condensate.                    1.7            1.8          -9 %          1.8            1.4         34 %
Natural gas liquids (thousand
gallons per day)
Dutch and Mary Rose field                   58.6           69.6         -16 %         69.6           67.5          3 %
Vermilion 170 field                         14.7             -          100 %           -              -           0 %
Other fields                                 2.6            4.2         -38 %          4.2            0.1       3102 %

Total natural gas liquids.                  76.0           73.8           3 %         73.8           67.6          9 %
Total (million cubic feet equivalent
per day)
Dutch and Mary Rose field                   64.1           73.8         -13 %         73.8           75.5         -2 %
Vermilion 170 field                         12.6             -          100 %           -              -           0 %
Other fields                                 8.8           14.2         -38 %         14.2            0.2       5888 %

Total production                            85.5           88.1          -3 %         88.1           75.7         16 %

Average Sales Price:
Natural gas (per thousand cubic
feet).                                 $    3.10      $    4.40         -30 %    $    4.40      $    4.48         -2 %
Oil and condensate (per barrel)        $  112.75      $   91.98          23 %    $   91.98      $   77.18         19 %
Natural gas liquids (per gallon)       $    1.32      $    1.23           7 %    $    1.23      $    1.04         18 %

Total (per thousand cubic feet
equivalent)                            $    5.73      $    6.27           9 %    $    6.27           5.75          9 %

Operating expenses                     $  25,183      $  25,691          -2 %    $  25,691      $  16,692         54 %
Exploration expenses                   $     346      $   9,751         -96 %    $   9,751      $  20,850        -53 %
Depreciation, depletion and
amortization.                          $  49,052      $  52,198          -6 %    $  52,198      $  34,521         51 %
Impairment of natural gas and oil
properties                             $       -      $   1,786        -100 %    $   1,786      $     952         88 %
General and administrative expenses    $  10,418      $  12,341         -16 %    $  12,341      $   4,599        168 %
Other income (expense).                $    (312 )    $    (157 )        99 %    $    (157 )    $     511       -131 %
Loss from affiliates (net of tax of
$241)                                  $    (449 )    $       -         100 %    $       -      $       -          0 %

Selected data per Mcfe:
Total lease operating expenses.        $    0.81      $    0.80           1 %    $    0.80      $    0.60         33 %
General and administrative expenses    $    0.33      $    0.38         -13 %    $    0.38      $    0.17        124 %
Depreciation, depletion and
amortization of natural gas and oil
properties.                            $    1.54      $    1.61          -4 %    $    1.61      $    1.24         30 %


Not included in the table above is production information from our discontinued operations. For the fiscal year ended June 30, 2012, our discontinued operations produced approximately 1.7 Mmcf of natural gas at an average price of $3.79 per Mcf. For the fiscal year ended June 30, 2011, our discontinued operations produced approximately 1,892 Mmcf of natural gas,



12.8 MBbls of condensate, and 2.6 million gallons of natural gas liquids at an average price of $3.45 per Mcf, $86.91 per Bbl and $0.96 per gallon, respectively. For the fiscal year ended June 30, 2010, our discontinued operations produced approximately 305 Mmcf of natural gas, 1.2 MBbls of condensate, and 428 thousand gallons of natural gas liquids at an average price of $3.72 per Mcf, $75.90 per Bbl and $1.04 per gallon, respectively.

Natural Gas, Oil and NGL Sales. All of our revenues are from the sale of our natural gas, oil and natural gas liquids production. Our revenues may vary significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our production volumes are subject to wide swings as a result of new discoveries, weather and mechanical related problems. In addition, our production declines over time as we produce our reserves.

We reported revenues of approximately $29.8 million for the year ended June 30, 2012, compared to revenues of approximately $201.7 million for the year ended June 30, 2011. This decrease in sales was principally attributable to lower equivalent production for the period (discussed below) as well as a lower average equivalent sales price received for the period.

We reported revenues of approximately $201.7 million for the year ended June 30, 2011, up from approximately $159.0 million reported for the year ended June 30, 2010. This increase in sales was primarily attributable to increased natural gas, oil and NGL production for the period (discussed below) as well as higher oil and NGL prices for the period, slightly offset by lower natural gas prices.

Average Sales Prices. For the year ended June 30, 2012, the price of natural gas was $3.10 per Mcf while the price for oil and NGLs was $112.75 per barrel and $1.32 per gallon, respectively. For the year ended June 30, 2011, the price of natural gas was $4.40 per Mcf while the price for oil and NGLs was $91.98 per barrel and $1.23 per gallon, respectively. For the year ended June 30, 2010, the price of natural gas was $4.48 per Mcf while the price for oil and NGLs was $77.18 per barrel and $1.04 per gallon, respectively.

Natural Gas, Oil and NGL Production. Our net natural gas production for the year ended June 30, 2012 was approximately 64.5 Mmcfd, down from approximately 66.5 Mmcfd for the year ended June 30, 2011. Net oil and condensate production for the comparable periods also decreased from approximately 1,800 barrels per day to approximately 1,700 barrels per day, and our NGL production increased from approximately 73,800 gallons per day to approximately 76,000 gallons per day. In total, equivalent production decreased from 88.1 Mmcfed to 85.5 Mmcfed, principally attributable to our Eloise North well which stopped producing in October 2011 and was subsequently recompleted as our Mary Rose #5 well in January 2012. Since recompletion, this well has only produced intermittently. Partially offsetting this decrease in production is our Vermilion 170 well which began producing in fiscal year 2012.

Our net natural gas production for the year ended June 30, 2011 was approximately 66.5 Mmcfd, up from approximately 57.8 Mmcfd for the year ended June 30, 2010. Net oil production and NGL production also increased for the comparable periods. Net oil production increased from 1,400 barrels per day to 1,800 barrels per day, while NGL production increased from approximately 67,600 gallons per day to 73,800 gallons per day. In total, equivalent production increased from 75.7 Mmcfed to 88.1 Mmcfed. This increase in natural gas, oil and NGL production was principally attributable to our Ship Shoal 263 well which began producing in June 2010 and our Eloise South well (now our Dutch #5 well) which began producing in July 2010. Also contributing to the increase in production was increased production from our four Mary Rose wells, Dutch #4 and our Eloise North well (now our Mary Rose #5 well), which had been shut-in for approximately 35 days during fiscal year 2010 due to our ruptured 20" pipeline. This increase in production was partially offset by temporarily shutting in our Eloise South well in October 2010 and our Eloise North well in February 2011 for remedial work.

Operating Expenses. Operating expenses for the year ended June 30, 2012 were approximately $6.5 million, which included approximately $4.1 million in Louisiana state severance taxes, $1.6 million in workover costs, and $4.4 million of well insurance. The remaining $15.1 million related to lease operating expenses for 12 offshore wells. Operating expenses for the year ended June 30, 2011 were approximately $5.9 million, which included approximately $4.6 million in Louisiana state severance taxes, $1.7 million in workover costs, and $4.6 million of well insurance. The remaining $14.8 million related to lease operating expenses for 11 offshore wells. Operating expenses for the year ended June 30, 2010 were approximately $16.7 million, which included approximately $5.3 million of Louisiana state severance taxes, $0.7 million in workover costs and $10.7 million related to lease operating expenses for nine offshore wells.

Exploration Expenses. We reported approximately $45.0 million of exploration expenses for the year ended June 30, 2012, related to various geological and geophysical activities, seismic data and delay rentals.

We reported approximately $0.0 million of exploration expenses for the year ended June 30, 2011. Of this amount, approximately $9.5 million related to our dry hole at Galveston Area 277L, and the remaining $0.3 million related to various geological and geophysical activities, seismic data, and delay rentals.


We reported approximately $20.9 million of exploration expenses for the year ended June 30, 2010. Of this amount, approximately $14.9 million related to the dry hole the Company drilled at Matagorda Island 617, $5.3 million related to the dry hole the Company drilled at Vermillion 155, and the remaining $0.7 million related to various geological and geophysical activities, seismic data and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended June 30, 2012 was approximately $9.6 million. This compares to approximately $11.0 million for the year ended June 30, 2011. The decrease in depreciation, depletion and amortization was primarily attributable to an overall decrease in production due to our Eloise North well which stopped producing in October 2011 and was subsequently recompleted as our Mary Rose #5 well in

January 2012. Since recompletion, this well has only produced intermittently. Partially offsetting this decreased production is our Vermilion 170 well which began producing in fiscal year 2012.

Depreciation, depletion and amortization for the year ended June 30, 2011 was approximately $11.0 million. This compares to approximately $34.5 million for the year ended June 30, 2010. The increase in depreciation, depletion and amortization was primarily attributable to an overall increase in production and increase in capitalized costs as a result of our Ship Shoal 263 and Eloise South discoveries. Also contributing to the increase in depreciation, depletion and amortization were increased produced volumes from our four Mary Rose wells, Dutch #4 and our Eloise North wells, which had been shut-in for approximately 35 days in 2010 due to our ruptured 20" pipeline. This increase in depreciation, depletion and amortization was partially offset by temporarily shutting in our Eloise South well in October 2010 and our Eloise North well in February 2011 for remedial work.

Impairment of Natural Gas and Oil Properties. No impairment expense was recorded for the year ended June 30, 2012. For the year ended June 30, 2011, the Company recorded impairment expense of approximately $1.8 million related to the relinquishment of 14 lease blocks owned by Contango and REX. For the year ended June 30, 2010, the Company recorded impairment expense of approximately $1.0 million, related to the relinquishment of six lease blocks owned by REX and COE.

General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2012 were approximately $2.6 million, compared to approximately $2.2 million for the year ended June 30, 2011. Major components of general and administrative expenses for the year ended June 30, 2012 included approximately $6.6 million in salaries, bonuses, stock-based compensation, benefits and board compensation, $0.4 million in insurance costs, $0.7 million in accounting and tax services, $0.9 million in legal and consulting expenses, $0.7 million in franchise taxes, and $1.1 million in office administration and other expenses.

General and administrative expenses for the year ended June 30, 2011 were approximately $2.2 million, up from approximately $4.6 million for the year ended June 30, 2010. The increase is principally attributable to higher bonus payments and stock option expenses in the year ended June 30, 2011. Major components of general and administrative expenses for the year ended June 30, 2011 included approximately $9.6 million in salaries, bonuses, stock-based compensation, benefits and board compensation (includes $1.3 million in non-cash expenses related to option awards), $0.9 million in office administration and other expenses, $0.5 million in insurance costs, $0.5 million in accounting and tax services, and $0.8 million in legal, consulting and other administrative expenses.

General and administrative expenses for the year ended June 30, 2010 were approximately $4.6 million. Major components of general and administrative expenses for the year ended June 30, 2010 included approximately $3.0 million in salaries, stock-based compensation, benefits and board compensation (includes $0.7 million in non-cash expenses related to restricted stock and option awards), $0.5 million in office administration and other expenses, $0.5 million in insurance costs, $0.2 million in accounting and tax services, and $0.4 million in legal, consulting and other administrative expenses.

Discontinued Operations. The table and discussions above, along with our financial statements, discuss only continuing operations for all fiscal years presented. Not reflected are the Company's sold producing properties which generated approximately 0%, 5% and 1% of combined revenues for the fiscal year ended June 30, 2012, 2011 and 2010, respectively. See Note 5 - Discontinued Operations of Notes to Consolidated Financial Statements included as part of this Form 10-K, for a discussion of our discontinued operations.

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