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MCF > SEC Filings for MCF > Form 10-K on 29-Aug-2013All Recent SEC Filings

Show all filings for CONTANGO OIL & GAS CO

Form 10-K for CONTANGO OIL & GAS CO


29-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, Texas based, independent natural gas and oil company. The Company's core business is to explore, develop, produce and acquire natural gas and oil properties offshore in the shallow waters of the Gulf of Mexico. COI, our wholly-owned subsidiary, acts as operator on our offshore properties. Contango has additional onshore investments in i) Alta Resources Investments, LLC, whose primary area of focus is the liquids-rich Kaybob Duvernay in Alberta, Canada; ii) Exaro Energy III LLC, which is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; and iii) the Tuscaloosa Marine Shale where we own approximately 24,000 acres.
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, producing properties offshore in the Gulf of Mexico have high initial production
rates, followed by steep declines. 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 replace any offshore reserves during the fiscal year ended June 30, 2013 or 2012. During fiscal year 2013, the Company drilled two dry holes at Ship Shoal 134 ("Eagle") and South Timbalier 75 ("Fang"). During fiscal year 2012, the Company did not drill any wells. Our permits to spud Eagle and 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. In June 2012 and March 2013, the Company successfully acquired nine lease blocks at two Gulf of Mexico Lease Sales. 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.
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 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 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.
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 offshore 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 table below sets forth our average net daily production data in Mmcfed from our offshore wells for each of the periods indicated:

                                                    Three Months Ended
                             June 30,    September 30,   December 31,   March 31,    June 30,
                               2012          2012            2012          2013        2013

Dutch and Mary Rose wells       67.5            54.2           57.2         59.5        57.2
Ship Shoal 263 well              7.6             3.5            2.6          0.9         0.6
Vermilion 170 well              15.5            10.5           12.9          3.6         4.0
Non-operated wells               0.2               -              -          0.6         0.4
                                90.8            68.2           72.7         64.6        62.2

Dutch and Mary Rose Wells

Production at our Dutch and Mary Rose wells has been fairly consistent over the past year. As of June 30, 2013, the ten Dutch and Mary Rose wells were flowing approximately 54.4 Mmcfed, net to Contango.

Ship Shoal 263 Well

Production at this well has been slowly decreasing since 2011 due to overheating, scaling problems, and water production. The well has also been shut-in several times for production logging and chemical treatment. We believe that this well may be fully depleted in the next twelve months. The well reached payout during fiscal year 2012. We will continue producing this well as long as it is economical. As of June 30, 2013, the well was flowing at approximately 0.7 Mmcfed, net to Contango.

During the fiscal year ended June 30, 2013, due to the decline in production from this well, our reservoir engineer revised his estimated net proved natural gas and oil reserves from this well. As a result, the net book value of our Ship Shoal 263 well exceeded the future undiscounted cash flows associated with its reserves. Accordingly, the Company recognized an impairment expense of approximately $12.0 million for the fiscal year ended June 30, 2013.

Vermilion 170 Well

In January 2013, we identified sustained casing pressure between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well production was shut-in and the original tubing and completion assembly were successfully removed. Operations were conducted to replace the tubing and restore the well, which resumed production in June 2013. As of June 30, 2013, this well was flowing at approximately 9.5 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, 2013, 2012 and 2011. 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,
                                    2013          2012          %          2012          2011           %
Revenues:                               (thousands)                            (thousands)
 Natural gas sales               $  66,441     $  73,068        (9 )%   $  73,068     $ 106,781        (32 )%
 Condensate sales                $  39,009     $  69,547       (44 )%   $  69,547     $  61,862         12  %
 NGL sales                       $  21,751     $  36,657       (41 )%   $  36,657     $  33,078         11  %
   Total revenues                $ 127,201     $ 179,272       (29 )%   $ 179,272     $ 201,721        (11 )%

Annual Production:
 Natural gas (million cubic
feet)
   Dutch and Mary Rose field        16,152        18,303       (12 )%      18,303        20,589        (11 )%
   Vermilion 170 field               2,054         3,098       (34 )%       3,098             -        100  %
   Other fields                        452         2,216       (80 )%       2,216         3,679        (40 )%
     Total natural gas              18,658        23,617       (21 )%      23,617        24,268         (3 )%
 Oil and condensate (thousand
barrels)
   Dutch and Mary Rose field           263           347       (24 )%         347           456        (24 )%
   Vermilion 170 field                  51           123       (59 )%         123             -        100  %
   Other fields                         48           145       (67 )%         145           217        (33 )%
     Total oil and condensate          362           615       (41 )%         615           673         (9 )%
 Natural gas liquids (thousand
gallons)
   Dutch and Mary Rose field        21,568        21,452         1  %      21,452        25,389        (16 )%
   Vermilion 170 field               3,391         5,390       (37 )%       5,390             -        100  %
   Other fields                        270           959       (72 )%         959         1,537        (38 )%
     Total natural gas liquids      25,229        27,801        (9 )%      27,801        26,926          3  %
 Total (million cubic feet
equivalent)
   Dutch and Mary Rose field        20,811        23,450       (11 )%      23,450        26,952        (13 )%
   Vermilion 170 field               2,844         4,606       (38 )%       4,606             -        100  %
   Other fields                        779         3,223       (76 )%       3,223         5,201        (38 )%
     Total production               24,434        31,279       (22 )%      31,279        32,153         (3 )%

Daily Production:
 Natural gas (million cubic feet
per day)
   Dutch and Mary Rose field          44.3          50.0       (12 )%        50.0          56.4        (11 )%
   Vermilion 170 field                 5.6           8.4       (34 )%         8.4             -        100  %
   Other fields                        1.2           6.1       (80 )%         6.1          10.1        (40 )%
     Total natural gas                51.1          64.5       (21 )%        64.5          66.5         (3 )%
 Oil and condensate (thousand
barrels per day)
   Dutch and Mary Rose field           0.7           0.9       (24 )%         0.9           1.2        (24 )%
   Vermilion 170 field                 0.2           0.4       (59 )%         0.4             -        100  %
   Other fields                        0.1           0.4       (67 )%         0.4           0.6        (33 )%
     Total oil and condensate          1.0           1.7       (41 )%         1.7           1.8         (9 )%


                                        Year Ended June 30,                   Year Ended June 30,
                                    2013         2012         %          2012         2011          %
Daily Production (continued):
 Natural gas liquids (thousand
gallons per day)
   Dutch and Mary Rose field         59.1         58.6         1  %       58.6         69.6        (16 )%
   Vermilion 170 field                9.3         14.8       (37 )%       14.8            -        100  %
   Other fields                       0.7          2.6       (72 )%        2.6          4.2        (38 )%
     Total natural gas liquids       69.1         76.0        (9 )%       76.0         73.8          3  %
 Total (million cubic feet
equivalent per day)
   Dutch and Mary Rose field           56.9       63.8       (11 )%       63.8         73.6        (13 )%
   Vermilion 170 field                8.1         12.8       (38 )%       12.8            -        100  %
   Other fields                       1.9          8.9       (76 )%        8.9         14.5        (38 )%
     Total production                66.9         85.5       (22 )%       85.5         88.1         (3 )%

Average Sales Price:
 Natural gas (per thousand cubic
feet)                            $   3.56     $   3.10        15  %   $   3.10     $   4.40        (30 )%
 Oil and condensate (per barrel) $ 107.75     $ 112.75        (4 )%   $ 112.75     $  91.98         23  %
 Natural gas liquids (per
gallon)                          $   0.86     $   1.32       (35 )%   $   1.32     $   1.23          7  %
     Total (per thousand cubic
feet equivalent)                 $   5.21     $   5.73        (9 )%   $   5.73     $   6.27         (9 )%

Expenses (thousands):
Operating expenses               $ 31,907     $ 25,183        27  %   $ 25,183     $ 25,691         (2 )%
Exploration expenses             $ 51,748     $    346        *       $    346     $  9,751        (96 )%
Depreciation, depletion and
amortization                     $ 41,060     $ 49,052       (16 )%   $ 49,052     $ 52,198         (6 )%
Impairment of natural gas and
oil properties                   $ 14,845     $      -       100  %   $      -     $  1,786       (100 )%
General and administrative
expenses                         $ 14,364     $ 10,418        38  %   $ 10,418     $ 12,341        (16 )%
Other income (expense), net      $  9,665     $   (312 )      *       $   (312 )   $   (157 )       99  %
Gain (loss) from affiliates (net
of taxes)                        $  1,241     $   (449 )    (376 )%   $   (449 )   $      -        100  %

Selected data per Mcfe:
Operating expenses               $   1.30     $   0.81        60  %   $   0.81     $   0.80          1  %
General and administrative
expenses                         $   0.59     $   0.33        79  %   $   0.33     $   0.38        (13 )%
Depreciation, depletion and
amortization of natural gas and
oil properties                   $   1.65     $   1.54         7  %   $   1.54     $   1.61         (4 )%

* Greater than 1,000%

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. The Company did not have any discontinued operations for the fiscal year ended June 30, 2013.
Natural Gas, Oil and NGL Sales and Production. 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 $127.2 million for the year ended June 30, 2013, compared to revenues of approximately $179.3 million for the year ended June 30, 2012. This decrease in revenues was primarily attributable to a decrease in natural gas, condensate and NGL production, further compounded by a lower average equivalent sales price received for the period. Our net natural gas production for the year ended June 30, 2013 was approximately 51.1 Mmcfd, down from approximately 64.5 Mmcfd for the year ended June 30, 2012. Additionally, net oil production decreased from 1,700 barrels per day to 1,000 barrels per day, while NGL production decreased from approximately 76,000 gallons per day to 69,100 gallons per day. In total, equivalent production decreased from 85.5 Mmcfed to 66.9 Mmcfed. This decrease in natural gas, oil and NGL production was principally attributable to our Vermilion 170 well which was shut-in for approximately six months this fiscal year for workover operations, our Ship Shoal 263 well which has been quickly depleting over the past year, and our Mary Rose #5 well which has been producing intermittently during most of the year.
We reported revenues of approximately $179.3 million for the year ended June 30, 2012, down from approximately $201.7 million reported for the year ended June 30, 2011. This decrease in sales was principally attributable to lower equivalent production for the period as well as a lower average equivalent sales price received for the period.
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.
Average Sales Prices. For the fiscal year ended June 30, 2013, the price of natural gas was $3.56 per Mcf while the price for oil and NGLs was $107.75 per barrel and $0.86 per gallon, respectively. 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. Operating Expenses. Lease operating expenses ("LOE") for the fiscal year ended June 30, 2013 were approximately $31.9 million, which included approximately $3.3 million of Louisiana state severance taxes, $12.0 million in workover costs for Vermilion 170, $0.4 million in workover costs for other wells and $4.7 million of well insurance. The remaining $11.4 million related to recurring lease operating expenses.
Operating expenses for the year ended June 30, 2012 were approximately $25.2 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 $25.7 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 recurring lease operating expenses for 11 offshore wells.
Exploration Expenses. We reported approximately $51.7 million of exploration expenses for the fiscal year ended June 30, 2013, which consists of $50.0 million for our dry holes at Ship Shoal 134 ("Eagle") and South Timbalier 75 ("Fang"), $1.4 million related to an unsuccessful drilling program at Jim Hogg County, Texas and $0.3 million for geological and geophysical activities, seismic data and delay rentals.
We reported approximately $0.3 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 $9.8 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.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the fiscal year ended June 30, 2013 was approximately $41.1 million. This compares to approximately $49.1 million for the year ended June 30, 2012. The decrease in depreciation, depletion and amortization was primarily attributable to a decrease in overall production.
Depreciation, depletion and amortization for the year ended June 30, 2012 was approximately $49.1 million. This compares to approximately $52.2 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.
Impairment of Natural Gas and Oil Properties. For the fiscal year ended June 30, 2013, the Company recorded impairment expense of approximately $14.8 million. Of this amount, approximately $12.0 million related to our Ship Shoal 263 well; $2.1 million related to the Eugene Island 24 platform and other properties, $0.5 million related to leasehold costs on our Ship Shoal 83 prospect which we relinquished in August 2013, and $0.2 million related to leasehold costs on our Brazos Area 543 prospect.
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.
General and Administrative Expenses. General and administrative expenses for the fiscal year ended June 30, 2013 were approximately $14.4 million, compared to $10.4 million for the year ended June 30, 2012. Major components of general and administrative expenses for the year ended June 30, 2013 included approximately $6.2 million in salaries and benefits, $1.2 million in office administration and other expenses, $0.6 million in board compensation, $0.6 million in accounting and tax services, $1.0 million in franchise taxes, and $4.8 million in legal, professional and other administrative expenses, which includes $3.0 million attributable to the proposed Merger.
General and administrative expenses for the year ended June 30, 2012 were approximately $10.4 million, compared to approximately $12.3 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 $12.3 million. 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.
Other Income (Expense). Other income for the fiscal year ended June 30, 2013 included the proceeds of a $10 million life insurance policy for the Company's former Chairman, President and Chief Executive Officer, Mr. Peak, who passed away on April 19, 2013.
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%, 0% and 5% of combined revenues for the fiscal year ended June 30, 2013, 2012 and 2011, 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. Capital Resources and Liquidity
Cash From Operating Activities. Cash flow from operating activities provided approximately $95.7 million in cash for the year ended June 30, 2013 compared to $73.6 million for the same period in 2012. This increase in cash provided by operating activities was primarily attributable to the timing of payments of the Company's obligations.
Cash flow from operating activities provided approximately $73.6 million in cash for the year ended June 30, 2012 compared to $140.6 million for the same period in 2011. This decrease in cash provided by operating activities was primarily attributable to decreased natural gas, oil and NGL sales and production as well as higher amounts of taxes paid due to reduced drilling activities in 2012. Cash From Investing Activities. Cash used in investing activities for the fiscal year ended June 30, 2013 was approximately $88.7 million, which consisted mainly of $80.4 million in capital expenditures for drilling and developing wells ($50.0 million of this was Eagle and Fang), investing $16.4 million in Alta and Exaro, partially offset by receiving $7.5 million as a return of capital related to our Exaro investment and $0.6 million as a distribution from REX to its partners.
Cash flows used in investing activities for the year ended June 30, 2012 were approximately $73.4 million, which consisted mainly of $20.8 million in capital expenditures for developing our wells and facilities and $53.4 million in equity


investments in Alta and Exaro. Cash flows used in investing activities for the year ended June 30, 2011 were approximately $33.3 million, which consisted mainly of $70.0 million in capital expenditures, offset by receiving approximately $38.7 million in proceeds from the sale of assets. . . .

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