[X]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended June 30, 2013
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Delaware
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95-4079863
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(State or other jurisdiction of
incorporation or organization)
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(IRS Employer Identification No.)
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Common Stock, Par Value $0.04 per share
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NYSE MKT
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Page
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PART I
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PART II
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PART III
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PART IV
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•
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Our financial position
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•
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Business strategy, including outsourcing
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•
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Meeting our forecasts and budgets
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•
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Anticipated capital expenditures
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•
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Drilling of wells
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•
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Natural gas and oil production and reserves
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•
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Timing and amount of future discoveries (if any) and production of natural gas and oil
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•
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Operating costs and other expenses
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•
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Cash flow and anticipated liquidity
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•
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Prospect development
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•
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Property acquisitions and sales
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•
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New governmental laws and regulations
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•
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Expectations regarding oil and gas markets in the United States
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•
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Low and/or declining prices for natural gas and oil
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•
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Natural gas and oil price volatility
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•
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Operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and gas processing facilities
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•
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The risks associated with acting as the operator in drilling deep high pressure and temperature wells in the Gulf of Mexico, including well blowouts and explosions
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•
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The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which the Company has made a large capital commitment relative to the size of the Company’s capitalization structure
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•
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The timing and successful drilling and completion of natural gas and oil wells
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•
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Availability of capital and the ability to repay indebtedness when due
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•
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Availability of rigs and other operating equipment
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•
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Ability to receive Bureau of Safety and Environmental Enforcement permits on a time schedule that permits the Company to operate efficiently
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•
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Ability to raise capital to fund capital expenditures
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•
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Timely and full receipt of sale proceeds from the sale of our production
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•
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The ability to find, acquire, market, develop and produce new natural gas and oil properties
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•
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Interest rate volatility
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•
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Zero or near-zero interest rates
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•
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Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures
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•
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Operating hazards attendant to the natural gas and oil business
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•
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Downhole drilling and completion risks that are generally not recoverable from third parties or insurance
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•
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Potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps
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•
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Weather
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•
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Availability and cost of material and equipment
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•
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Delays in anticipated start-up dates
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•
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Actions or inactions of third-party operators of our properties
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•
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Actions or inactions of third-party operators of pipelines or processing facilities
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•
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The ability to find and retain skilled personnel
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•
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Strength and financial resources of competitors
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•
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Federal and state regulatory developments and approvals
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•
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Environmental risks
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•
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Worldwide economic conditions
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•
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The ability to construct and operate offshore infrastructure, including pipeline and production facilities
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•
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The continued compliance by the Company with various pipeline and gas processing plant specifications for the gas and condensate produced by the Company
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•
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Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and state of Louisiana (“Mary Rose”) acreage
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•
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Restrictions on permitting activities
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•
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Expanded rigorous monitoring and testing requirements
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•
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Legislation that may regulate drilling activities and increase or remove liability caps for claims of damages from oil spills
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•
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Ability to obtain insurance coverage on commercially reasonable terms
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•
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Accidental spills, blowouts and pipeline ruptures
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•
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Impact of new and potential legislative and regulatory changes on Gulf of Mexico operating and safety standards
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Area/Block
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WI
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NRI
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Status
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Eugene Island 10 #D-1 (Dutch #1)
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47.05%
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38.1%
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Producing
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Eugene Island 10 #E-1 (Dutch #2)
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47.05%
|
|
38.1%
|
|
Producing
|
Eugene Island 10 #F-1 (Dutch #3)
|
|
47.05%
|
|
38.1%
|
|
Producing
|
Eugene Island 10 #G-1 (Dutch #4)
|
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47.05%
|
|
38.1%
|
|
Producing
|
Eugene Island 10 #I-1 (Dutch #5)
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47.05%
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38.1%
|
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Producing
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S-L 18640 #1 (Mary Rose #1)
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53.21%
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40.5%
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Producing
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S-L 19266 #1 (Mary Rose #2)
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53.21%
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38.7%
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Producing
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S-L 19266 #2 (Mary Rose #3)
|
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53.21%
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38.7%
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Producing
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S-L 18860 #1 (Mary Rose #4)
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34.58%
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25.5%
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Producing
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S-L 19266 #3 and S-L 19261 (Mary Rose #5)
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37.80%
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27.6%
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Intermittent
|
Ship Shoal 263
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100.00%
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80.0%
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Producing
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Vermilion 170
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87.24%
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68.0%
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Producing
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Area/Block
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WI
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Lease Date
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Expiration Date
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East Breaks 369 (Dry Hole)
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(1)
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Dec-03
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Dec-13
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South Timbalier 17
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75.00%
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(2)
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(2)
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Brazos Area 543
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100.00%
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Mar-12
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Mar-17
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East Cameron 124
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100.00%
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Sept-12
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Sept-17
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Eugene Island 31
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100.00%
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Oct-12
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Oct-17
|
Ship Shoal 83
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100.00%
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Oct-12
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(3)
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South Timbalier 110
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100.00%
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Oct-12
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Oct-17
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Eugene Island 260
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100.00%
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Nov-12
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Nov-17
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Ship Shoal 255
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100.00%
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Dec-12
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Dec-17
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Eugene Island 23
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100.00%
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Jun-13
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Jun-18
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Ship Shoal 52
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100.00%
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Jul-13
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Jul-18
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Ship Shoal 59
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100.00%
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Jul-13
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Jul-18
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(1)
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Farm-out. COI retains a 2.41% ORRI
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(2)
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Successful exploration well. Lease will be held by production.
|
•
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The domestic and foreign supply of natural gas and oil
|
•
|
Overall economic conditions
|
•
|
The level of consumer product demand
|
•
|
Adverse weather conditions and natural disasters
|
•
|
The price and availability of competitive fuels such as heating oil and coal
|
•
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Political conditions in the Middle East and other natural gas and oil producing regions
|
•
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The level of LNG imports
|
•
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Domestic and foreign governmental regulations
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•
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Special taxes on production
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•
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The loss of tax credits and deductions
|
Name
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Age
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Position
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Joseph J. Romano
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60
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Chairman, President and Chief Executive Officer
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Sergio Castro
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44
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Vice President, Chief Financial Officer, Treasurer and Secretary
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Yaroslava Makalskaya
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44
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Vice President, Chief Accounting Officer and Controller
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Marc L. Duncan
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60
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Senior Vice President - Engineering
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Charles A. Cambron (1)
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46
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Vice President - Drilling
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Michael J. Autin
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54
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|
|
Vice President - Production
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B.A. Berilgen
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|
65
|
|
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Director
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Jay D. Brehmer
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|
48
|
|
|
Director
|
Brad Juneau
|
|
53
|
|
|
Director
|
Charles M. Reimer
|
|
68
|
|
|
Director
|
Steven L. Schoonover
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|
68
|
|
|
Director
|
•
|
If a portion of the combined company's cash is applied to the payment of principal or interest on the debt, less will be available for other purposes;
|
•
|
Credit-rating agencies may change in the future with respect to the combined company, their ratings of that entity's debt and other obligations, which in turn impacts the costs, terms and conditions and availability of financing;
|
•
|
Covenants contained in the combined company's existing and future debt arrangements will require the combined company to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;
|
•
|
The combined company's ability to obtain additional financing for capital expenditures, acquisitions, general corporate and other purposes may be limited or burdened by increased costs or more restrictive covenants;
|
•
|
The combined company may be at a competitive disadvantage to similar companies that have less debt;
|
•
|
The combined company's vulnerability to adverse economic and industry conditions may increase; and
|
•
|
The combined company may face limitations on its flexibility to plan for and react to changes in its business and the industries in which it operates.
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Year Ended June 30,
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2013
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2012
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2011
|
||||||
Property acquisition costs:
|
|
|
(thousands)
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|
|
||||||
Unproved
|
$
|
16,130
|
|
|
$
|
5,404
|
|
|
$
|
2,802
|
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Proved
|
102
|
|
|
381
|
|
|
10,135
|
|
|||
Exploration costs
|
47,584
|
|
|
1,154
|
|
|
14,016
|
|
|||
Development costs
|
11,758
|
|
|
10,350
|
|
|
39,211
|
|
|||
Total costs
|
$
|
75,574
|
|
|
$
|
17,289
|
|
|
$
|
66,164
|
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
|
|
(thousands)
|
|
|
||||||
Property acquisition costs
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Exploration costs
|
—
|
|
|
—
|
|
|
—
|
|
|||
Development costs
|
46,972
|
|
|
785
|
|
|
—
|
|
|||
Company's 37% share of costs incurred
|
$
|
46,972
|
|
|
$
|
785
|
|
|
$
|
—
|
|
|
Year Ended June 30,
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive (onshore)
|
1
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Productive (offshore)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1.0
|
|
Non-productive (onshore)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Non-productive (offshore)
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1.0
|
|
Total
|
3
|
|
|
2.3
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2.0
|
|
|
Year Ended June 30,
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Developmental Wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive (onshore)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
7.5
|
|
Productive (offshore)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Non-productive (onshore)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Non-productive (offshore)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
7.5
|
|
|
Developed
Acreage (1)(2)
|
|
Undeveloped
Acreage (1)(3)
|
||||||||
|
Gross (4)
|
|
Net (5)
|
|
Gross (4)
|
|
Net (5)
|
||||
Onshore (TMS)
|
1,342
|
|
|
336
|
|
|
24,372
|
|
|
24,372
|
|
Offshore Gulf of Mexico
|
17,298
|
|
|
12,867
|
|
|
50,561
|
|
|
50,534
|
|
Total
|
18,640
|
|
|
13,203
|
|
|
74,933
|
|
|
74,906
|
|
(1)
|
Excludes any interest in acreage in which we have no working interest before payout or before initial production.
|
(2)
|
Developed acreage consists of acres spaced or assignable to productive wells.
|
(3)
|
Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
|
(4)
|
Gross acres refer to the number of acres in which we own a working interest.
|
(5)
|
Net acres represent the number of acres attributable to an owner’s proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).
|
|
Total Productive
Wells (1)
|
||||
|
Gross (2)
|
|
Net (3)
|
||
Natural gas (onshore)
|
—
|
|
|
—
|
|
Natural gas (offshore)
|
12
|
|
|
6.50
|
|
Oil (onshore)
|
1
|
|
|
0.25
|
|
Oil (offshore)
|
—
|
|
|
—
|
|
Total
|
13
|
|
|
6.75
|
|
(1)
|
Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally producing wells are not considered here as a “productive” well.
|
(2)
|
A gross well is a well in which we own an interest.
|
(3)
|
The number of net wells is the sum of our fractional working interests owned in gross wells.
|
•
|
Over 30 years of practical experience in the estimation and evaluation of reserves
|
•
|
A registered professional engineer in the state of Texas
|
•
|
Bachelor of Science Degree in Petroleum Engineering
|
•
|
Member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers
|
•
|
A registered professional engineer in the state of Texas
|
•
|
Bachelor of Science Degree in Petroleum Engineering
|
•
|
Member in good standing of the Society of Petroleum Engineers
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|||
Contango Oil & Gas Reserves (1)
|
|
|
|
|
|
|||
Natural gas (MMcf)
|
146,518
|
|
|
2,489
|
|
|
149,007
|
|
Oil and condensate (MBbls)
|
2,297
|
|
|
31
|
|
|
2,328
|
|
Natural gas liquids (MBbls)
|
4,078
|
|
|
66
|
|
|
4,144
|
|
Total proved reserves (MMcfe)
|
184,768
|
|
|
3,071
|
|
|
187,839
|
|
|
|
|
|
|
|
|||
Reserves Attributable to our 37% Investment in Exaro (2)
|
|
|
|
|
|
|||
Natural gas (MMcfe)
|
30,174
|
|
|
—
|
|
|
30,174
|
|
|
|
|
|
|
|
|||
Total (Mmcfe)
|
214,942
|
|
|
3,071
|
|
|
218,013
|
|
|
Mary Rose #6
|
|
Proved undeveloped reserves as of June 30, 2012
|
6,197
|
|
Change in estimate
|
(3,126
|
)
|
Proved undeveloped reserves as of June 30, 2013
|
3,071
|
|
|
June 30, 2013
|
||
Pre-tax net present value, discounted at 10%
|
$
|
550,336
|
|
Future income taxes, discounted at 10%
|
(192,819
|
)
|
|
Standardized measure of discounted future net cash flows
|
$
|
357,517
|
|
|
High
|
|
Low
|
||||
Fiscal Year 2012:
|
|
|
|
||||
Quarter ended September 30, 2011
|
$
|
67.25
|
|
|
$
|
52.25
|
|
Quarter ended December 31, 2011
|
$
|
69.75
|
|
|
$
|
51.54
|
|
Quarter ended March 31, 2012
|
$
|
65.08
|
|
|
$
|
56.73
|
|
Quarter ended June 30, 2012
|
$
|
60.24
|
|
|
$
|
51.00
|
|
Fiscal Year 2013:
|
|
|
|
||||
Quarter ended September 30, 2012
|
$
|
61.16
|
|
|
$
|
49.11
|
|
Quarter ended December 31, 2012
|
$
|
52.64
|
|
|
$
|
38.10
|
|
Quarter ended March 31, 2013
|
$
|
46.05
|
|
|
$
|
36.27
|
|
Quarter ended June 30, 2013
|
$
|
40.49
|
|
|
$
|
33.50
|
|
Plan Category
|
|
Number of
securities to be issued upon
exercise of outstanding
options
|
|
Weighted-average
exercise price of
outstanding options
|
|
Number of securities remaining available for future
issuance under equity compensation plans (excluding securities reflected in column (b))
|
1999 Stock Incentive Plan - approved by security holders
|
|
—
|
|
$—
|
|
—
|
2009 Equity Compensation Plan - approved by security holders
|
|
—
|
|
$—
|
|
1,475,000
|
Equity compensation plans not approved by security holders
|
|
—
|
|
$—
|
|
—
|
Period
|
Total Number of
Shares Purchased
|
|
Average Price Paid Per Share
|
|
Total Number of Shares Purchased as Part of
Publicly Announced
Program
|
|
Approximate Dollar Value
of Shares that may yet be
Purchased Under Program
|
||||
October 2 - 5, 2012
|
97,496
|
|
|
$
|
50.82
|
|
|
197,877
|
|
|
$39.7 million
|
|
6/30/2008
|
|
6/30/2009
|
|
6/30/2010
|
|
6/30/2011
|
|
6/30/2012
|
|
6/30/2013
|
||||||
Contango Oil & Gas Company
|
100.00
|
|
|
45.73
|
|
|
48.16
|
|
|
62.89
|
|
|
63.71
|
|
|
38.22
|
|
S&P Smallcap 600
|
100.00
|
|
|
74.69
|
|
|
92.34
|
|
|
126.53
|
|
|
128.34
|
|
|
160.65
|
|
Old Peer Group
|
100.00
|
|
|
15.43
|
|
|
23.80
|
|
|
55.71
|
|
|
43.95
|
|
|
35.39
|
|
New Peer Group
|
100.00
|
|
|
13.69
|
|
|
14.45
|
|
|
32.03
|
|
|
23.34
|
|
|
18.16
|
|
|
||||||||||||||||||||
|
|
Year Ended June 30,
|
||||||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
Financial Data:
|
|
(Dollar amounts in thousands, except per share amounts)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas and oil sales
|
|
$
|
127,201
|
|
|
$
|
179,272
|
|
|
$
|
201,721
|
|
|
$
|
159,010
|
|
|
$
|
190,656
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from continuing operations (a)
|
|
$
|
(9,720
|
)
|
|
$
|
59,213
|
|
|
$
|
64,459
|
|
|
$
|
50,166
|
|
|
$
|
55,861
|
|
Discontinued operations, net of income taxes
|
|
—
|
|
|
(824
|
)
|
|
574
|
|
|
(480
|
)
|
|
—
|
|
|||||
Net income attributable to common stock
|
|
$
|
(9,720
|
)
|
|
$
|
58,389
|
|
|
$
|
65,033
|
|
|
$
|
49,686
|
|
|
$
|
55,861
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Continuing operations
|
|
$
|
(0.64
|
)
|
|
$
|
3.84
|
|
|
$
|
4.11
|
|
|
$
|
3.17
|
|
|
$
|
3.41
|
|
Discontinued operations
|
|
—
|
|
|
(0.05
|
)
|
|
0.04
|
|
|
(0.03
|
)
|
|
—
|
|
|||||
Total
|
|
$
|
(0.64
|
)
|
|
$
|
3.79
|
|
|
$
|
4.15
|
|
|
$
|
3.14
|
|
|
$
|
3.41
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Continuing operations
|
|
$
|
(0.64
|
)
|
|
$
|
3.84
|
|
|
$
|
4.10
|
|
|
$
|
3.11
|
|
|
$
|
3.35
|
|
Discontinued operations
|
|
—
|
|
|
(0.05
|
)
|
|
0.04
|
|
|
(0.03
|
)
|
|
—
|
|
|||||
Total
|
|
$
|
(0.64
|
)
|
|
$
|
3.79
|
|
|
$
|
4.14
|
|
|
$
|
3.08
|
|
|
$
|
3.35
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
15,221
|
|
|
15,423
|
|
|
15,665
|
|
|
15,831
|
|
|
16,363
|
|
|||||
Diluted
|
|
15,221
|
|
|
15,425
|
|
|
15,713
|
|
|
16,157
|
|
|
16,690
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Working capital
|
|
$
|
112,466
|
|
|
$
|
140,901
|
|
|
$
|
126,654
|
|
|
$
|
41,385
|
|
|
$
|
43,232
|
|
Capital expenditures
|
|
$
|
80,418
|
|
|
$
|
20,844
|
|
|
$
|
69,993
|
|
|
$
|
97,703
|
|
|
$
|
45,742
|
|
Cash dividends (b)
|
|
$
|
30,510
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Long term debt
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Shareholders’ equity
|
|
$
|
419,154
|
|
|
$
|
464,339
|
|
|
$
|
426,623
|
|
|
$
|
377,330
|
|
|
$
|
349,364
|
|
Total assets
|
|
$
|
576,461
|
|
|
$
|
624,654
|
|
|
$
|
636,930
|
|
|
$
|
592,266
|
|
|
$
|
517,042
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved Reserve Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total proved reserves (Mmcfe) (c)
|
|
187,839
|
|
|
256,567
|
|
|
296,729
|
|
|
314,027
|
|
|
355,046
|
|
|||||
Pre-tax net present value (discounted at 10%)
|
|
$
|
550,336
|
|
|
$
|
730,222
|
|
|
$
|
981,041
|
|
|
$
|
970,442
|
|
|
$
|
889,865
|
|
Standardized measure (c)
|
|
$
|
357,517
|
|
|
$
|
513,932
|
|
|
$
|
717,135
|
|
|
$
|
712,094
|
|
|
$
|
638,091
|
|
|
Three Months Ended
|
|||||||||||||
|
June 30, 2012
|
|
September 30, 2012
|
|
December 31, 2012
|
|
March 31, 2013
|
|
June 30, 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
|
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
|
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
|
)%
|
•
|
We have budgeted to invest approximately $12.5 million to drill, complete and begin production on our South Timbalier 17 well.
|
•
|
We have budgeted to invest approximately $22.5 million to drill our Ship Shoal 255 prospect. Should we be successful, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.
|
Fiscal Year of Property Sale
|
Proceeds
Received
|
|
Reserves
Sold (Bcfe)
|
|
Reserves at end of
Fiscal Year (Bcfe)
|
|
Standardized Measure of
Discounted Future Net Cash
Flows at end of Fiscal Year (’000)
|
||||
2012
|
$10 thousand
|
|
—
|
|
|
256.6
|
|
|
$
|
513,932
|
|
2011
|
$38.7 million
|
|
17.2
|
|
|
296.7
|
|
|
$
|
717,360
|
|
|
Payment due by period (thousands)
|
||||||||||||||||||
|
Total
|
|
Less than
1 year
|
|
1 - 3 years
|
|
3 - 5 years
|
|
More than
5 years
|
||||||||||
Long term debt
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Delay rentals
|
1,302
|
|
|
318
|
|
|
636
|
|
|
348
|
|
|
—
|
|
|||||
Asset retirement obligations
|
13,345
|
|
|
623
|
|
|
—
|
|
|
—
|
|
|
12,722
|
|
|||||
Operating leases
|
871
|
|
|
328
|
|
|
543
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
$
|
15,518
|
|
|
$
|
1,269
|
|
|
$
|
1,179
|
|
|
$
|
348
|
|
|
$
|
12,722
|
|
|
|
|
|
Exhibit
Number
|
|
Description
|
|
2.1
|
|
|
Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (10)
|
2.2
|
|
|
Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (10)
|
2.3
|
|
|
Agreement and Plan of Merger, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Crimson Exploration Inc., dated as of April 29, 2013. (26)
|
3.1
|
|
|
Certificate of Incorporation of Contango Oil & Gas Company. (5)
|
3.2
|
|
|
Bylaws of Contango Oil & Gas Company. (5)
|
3.3
|
|
|
Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (5)
|
3.4
|
|
|
Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8)
|
4.1
|
|
|
Facsimile of common stock certificate of Contango Oil & Gas Company. (1)
|
4.4
|
|
|
Certificate of Designation of Series F Junior Preferred Stock of Contango Oil & Gas Company dated September 30, 2008. (16)
|
4.5
|
|
|
Rights Agreement, dated as of September 30, 2008, between Contango Oil & Gas Company and Computershare Trust Company, N.A., as Rights Agent. (16)
|
4.6
|
|
|
Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCM Crimson Holdings, LLC and OCM GW Holdings, LLC. (26)
|
10.1
|
|
|
Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and Juneau Exploration, L.L.C. (2)
|
10.2
|
|
|
Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Trust Company of the West. (3)
|
10.3
|
|
|
Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Fairfield Industries Incorporated. (3)
|
10.4
|
|
|
Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Juneau Exploration Company, L.L.C. (3)
|
10.5
|
|
|
Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration Company, LLC. dated effective as of September 1, 1999. (4)
|
10.6
|
|
|
Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002. (6)
|
10.7
|
|
|
Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust, Linda G. Ferszt, Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated January 9, 2002. (7)
|
10.8
|
|
|
Second Amended and Restated Credit Agreement dated as of October 1, 2010 among Contango Oil & Gas Company, Contango Operators, Inc. and Amegy Bank National Association, as Administrative Agent and Letter of Credit Issuer, together with First Amendment to Second Amended and Restated Credit Agreement dated October 20, 2010 among Contango Oil & Gas Company, Contango Operators, Inc. and Amegy Bank National Association. (19)
|
10.9
|
|
|
Purchase and Sale Agreement between Juneau Exploration, L.P. and Contango Operators, Inc. dated October 1, 2010. (20)
|
10.10
|
|
|
Purchase and Sale Agreement between Conterra Company as Seller, and Patara Oil & Gas LLC as Purchaser, dated April 22, 2011. (21)
|
10.11
|
|
|
Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (10)
|
10.12
|
|
|
Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC dated as of September 1, 2005. (10)
|
10.13
|
|
|
Limited Liability Company Agreement of Contango Offshore Exploration LLC dated November 1, 2000. (10)
|
10.14
|
|
|
First Amendment to Limited Liability Company Agreement and Additional Agreements of Contango Offshore Exploration LLC dated as of September 1, 2005. (10)
|
10.15
|
|
*
|
Contango Oil & Gas Company 1999 Stock Incentive Plan. (11)
|
10.16
|
|
*
|
Amendment No. 1 to Contango Oil & Gas Company 1999 Stock Incentive Plan dated as of March 1, 2001. (11)
|
10.17
|
|
|
Demand Promissory Note dated October 26, 2006 with Schedules I, II and III. (12)
|
10.18
|
|
|
Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.19
|
|
|
Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.20
|
|
|
Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.21
|
|
|
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.22
|
|
|
Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of January 3, 2008. (13)
|
10.23
|
|
|
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.24
|
|
|
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.25
|
|
|
Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.26
|
|
|
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (13)
|
10.27
|
|
|
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (14)
|
10.28
|
|
|
Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (14)
|
10.29
|
|
|
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (14)
|
10.30
|
|
|
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (14)
|
10.31
|
|
|
Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of April 3, 2008. (14)
|
10.32
|
|
|
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (14)
|
10.33
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.34
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.35
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.36
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.37
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.38
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.39
|
|
|
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (15)
|
10.40
|
|
|
Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008. (14)
|
10.41
|
|
|
Amended and Restated Limited Liability Company Agreement of Contango Offshore Exploration LLC, dated April 1, 2008. (15)
|
10.42
|
|
|
Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCM Crimson Holdings, LLC and OCM GW Holdings, LLC. (26)
|
10.43
|
|
*
|
Contango Oil & Gas Company Annual Incentive Plan. (22)
|
10.44
|
|
*
|
Contango Oil & Gas Company 2009 Equity Compensation Plan. (22)
|
10.45
|
|
|
Conterra Joint Venture Development Agreement effective October 1, 2009 between Conterra Company and Patara Oil & Gas LLC. (18)
|
10.46
|
|
|
First Amended and Restated Limited Liability Company Agreement dated as of March 31, 2012. (23)
|
10.47
|
|
|
Advisory Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., dated as of April 5, 2012. (24)
|
10.48
|
|
|
Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of October 9, 2008 between Contango Offshore Exploration LLC and Contango Operators, Inc. (25)
|
10.49
|
|
|
Amendment to Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of October 7, 2009 between Contango Offshore Exploration LLC and Contango Operators, Inc. (25)
|
10.50
|
|
|
Amendment to Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of January 29, 2010 between Contango Offshore Exploration LLC and Contango Operators, Inc. (25)
|
10.51
|
|
|
Participation Agreement covering OCS-G 33596, Vermilion 170, dated as of July 1, 2010 between Republic Exploration LLC and Contango Operators, Inc. (25)
|
10.52
|
|
|
Participation Agreement covering OCS-G 33640, Ship Shoal 121; OCS-G 33641, Ship Shoal 122; and OCS-G 22701, Ship Shoal 134, dated as of July 1, 2010 between Republic Exploration LLC and Contango Operators, Inc. (25)
|
10.53
|
|
|
Amendment to Participation Agreement covering OCS-G 33640, Ship Shoal 121; OCS-G 33641, Ship Shoal 122; and OCS-G 22701, Ship Shoal 134, dated as of June 30, 2012 between Republic Exploration LLC and Contango Operators, Inc. (25)
|
10.54
|
|
|
Participation Agreement covering OCS-G 22738, South Timbalier 75, dated as of July 26, 2011 between Republic Exploration LLC and Contango Operators, Inc. (25)
|
10.55
|
|
|
Amendment to Participation Agreement covering OCS-G 22738, South Timbalier 75, dated as of August 21, 2012 between Republic Exploration LLC and Contango Operators, Inc. (25)
|
10.56
|
|
|
Participation Agreement covering Tuscaloosa Marine Shale, dated as of August 27, 2012 between Juneau Exploration LP and Contango Operators, Inc. (25)
|
10.57
|
|
|
Letter Agreement dated as of June 8, 2012 between Juneau Exploration LP and Contango Operators, Inc. (25)
|
10.58
|
|
|
Participation Agreement covering Central Gulf of Mexico Lease Sale 216/222, dated as of August 27, 2012 between Republic Exploration LLC and Contango Operators, Inc. (25)
|
10.59
|
|
|
Participation Agreement covering Central Gulf of Mexico Lease Sale 216/222, dated as of August 27, 2012 between Juneau Exploration LP and Contango Operators, Inc. (25)
|
10.60
|
|
|
Agreement to Purchase Overriding Royalty Interest, dated March 1, 2010 between Contango Offshore Exploration LLC and Juneau Exploration LP. (25)
|
10.61
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and OCM Crimson Holdings, LLC. (26)
|
10.62
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and OCM GW Holdings, LLC. (26)
|
10.63
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Allan D. Keel. (26)
|
10.64
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and E. Joseph Grady. (26)
|
10.65
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and A. Carl Isaac. (26)
|
10.66
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Jay S. Mengle. (26)
|
10.67
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Thomas H. Atkins. (26)
|
10.68
|
|
|
Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and John A. Thomas. (26)
|
10.69
|
|
|
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and Allan D. Keel. (26)
|
10.70
|
|
|
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and E. Joseph Grady. (26)
|
10.71
|
|
|
Termination of Advisory Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., dated as of April 1, 2012. (27)
|
10.72
|
|
|
First Right of Refusal Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., entered into as of January 1, 2013. (27)
|
10.73
|
|
|
Advisory Agreement between Contaro Company and Juneau Exploration, L.P., entered into as of January 1, 2013. (27)
|
10.74
|
|
|
Employment Agreement, dated as of June 10, 2013, among Contango Oil & Gas Company and Jeffrey A. Sikora. (28)
|
10.75
|
|
|
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and A. Carl Isaac. (28)
|
10.76
|
|
|
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and John A. Thomas. (28)
|
10.77
|
|
|
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Jay S. Mengle. (28)
|
10.78
|
|
|
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Thomas H. Atkins. (28)
|
10.79
|
|
|
Transition Agreement, dated as of June 10, 2013, between Contango Oil & Gas Company and Marc Duncan. (29)
|
10.80
|
|
|
Participation Agreement covering Central Gulf of Mexico Lease Sale 227, dated as of March 21, 2013 between Republic Exploration LLC and Contango Operators, Inc. †
|
10.81
|
|
|
Participation Agreement covering Timbalier Island Prospect, South Timbalier Area Block 17, S.L. 21906, dated as of April 3, 2013 between Republic Exploration LLC, Juneau Exploration, L.P. and Contango Operators, Inc. †
|
14.1
|
|
|
Code of Ethics. (25)
|
21.1
|
|
|
List of Subsidiaries.
†
|
21.2
|
|
|
Organizational Chart.
†
|
23.1
|
|
|
Consent of William M. Cobb & Associates, Inc.
†
|
23.2
|
|
|
Consent of Lonquist & Co. LLC. †
|
23.3
|
|
|
Consent of W.D. Von Gonten & Co. †
|
23.4
|
|
|
Consent of Grant Thornton LLP.
†
|
31.1
|
|
|
Certification of Acting Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934.
†
|
31.2
|
|
|
Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934.
†
|
32.1
|
|
|
Certification of Acting Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†
|
32.2
|
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†
|
99.1
|
|
|
Report of William M. Cobb & Associates, Inc.
†
|
99.2
|
|
|
Report of W.D. Von Gonten and Company †
|
99.3
|
|
|
Form of Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Crimson Exploration Inc., and the following directors and executive officers of Contango Oil & Gas Company: the Estate of Kenneth R. Peak, Joseph J. Romano, Brad Juneau, Sergio Castro and Yaroslava Makalskaya. (26)
|
†
|
Filed herewith.
|
*
|
Indicates a management contract or compensatory plan or arrangement.
|
1.
|
|
Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.
|
2.
|
|
Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended September 30, 1999, as filed with the Securities and Exchange Commission on November 11, 1999.
|
3.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and Exchange Commission of September 8, 2000.
|
4.
|
|
Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed with the Securities and Exchange Commission on September 27, 2000.
|
5.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.
|
6.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and Exchange Commission on January 8, 2002.
|
7.
|
|
Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, as filed with the Securities and Exchange Commission on February 14, 2002.
|
8.
|
|
Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.
|
9.
|
|
Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as filed with the Securities and Exchange Commission on September 22, 2003.
|
10.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005.
|
11.
|
|
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2005, as filed with the Securities and Exchange Commission on September 13, 2005.
|
12.
|
|
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2006, dated November 8, 2006, as filed with the Securities and Exchange Commission.
|
13.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and Exchange Commission on January 9, 2008.
|
14.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated April 3, 2008, as filed with the Securities and Exchange Commission on April 9, 2008.
|
15.
|
|
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2008, as filed with the Securities and Exchange Commission on August 29, 2008.
|
16.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated September 30, 2008, as filed with the Securities and Exchange Commission on October 1, 2008.
|
17.
|
|
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2009, as filed with the Securities and Exchange Commission on May 11, 2009.
|
18.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated October 22, 2009, as filed with the Securities and Exchange Commission on October 28, 2009.
|
19.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated October 20, 2010 as filed with the Securities and Exchange Commission on October 25, 2010.
|
20.
|
|
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2010, as filed with the Securities and Exchange Commission on November 9, 2010.
|
21.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated May 13, 2011 as filed with the Securities and Exchange Commission on May 18, 2011.
|
22.
|
|
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2010, as filed with the Securities and Exchange Commission on September 13, 2010.
|
23.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated as of March 31, 2012, as filed with the Securities and Exchange Commission on April 5, 2012.
|
24.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated as of April 10, 2012, as filed with the Securities and Exchange Commission on April 11, 2012.
|
25.
|
|
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2012, as filed with the Securities and Exchange Commission on August 29, 2012.
|
26.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated as of April 29, 2013, as filed with the Securities and Exchange Commission on May 1, 2013.
|
27.
|
|
Filed as an exhibit to the Company's report on Form 10-Q for the quarter ended December 31, 2012, as filed with the Securities and Exchange Commission on February 11, 2013.
|
28.
|
|
Filed as an exhibit to the Company's Registration Statement on Form S-4, as filed with the Securities and Exchange Commission on June 13, 2013.
|
29.
|
|
Filed as an exhibit to the Company’s report on Form 8-K, dated as of June 7, 2013, as filed with the Securities and Exchange Commission on June 14, 2013.
|
/s/ JOSEPH J. ROMANO
|
|
/s/ SERGIO CASTRO
|
|
/s/ YAROSLAVA MAKALSKAYA
|
Joseph J. Romano
|
|
Sergio Castro
|
|
Yaroslava Makalskaya
|
Chief Executive Officer
|
|
Chief Financial Officer
|
|
Chief Accounting Officer
|
(principal executive officer)
|
|
(principal financial officer)
|
|
(principal accounting officer)
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ B.A. BERILGEN
B.A. Berilgen
|
|
Director
|
|
August 29, 2013
|
|
|
|
|
|
/s/ JAY D. BREHMER
Jay D. Brehmer
|
|
Director
|
|
August 29, 2013
|
|
|
|
|
|
/s/ BRAD. JUNEAU
Brad Juneau
|
|
Director
|
|
August 29, 2013
|
|
|
|
|
|
/s/ CHARLES M. REIMER
Charles M. Reimer
|
|
Director
|
|
August 29, 2013
|
|
|
|
|
|
/s/ STEVEN L. SCHOONOVER
Steven L. Schoonover
|
|
Director
|
|
August 29, 2013
|
|
|
Page
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
June 30,
|
||||||
|
2013
|
|
2012
|
||||
CURRENT ASSETS:
|
(thousands)
|
||||||
Cash and cash equivalents
|
$
|
101,485
|
|
|
$
|
129,983
|
|
Accounts receivable:
|
|
|
|
||||
Trade receivable
|
26,312
|
|
|
29,688
|
|
||
Joint interest billings
|
4,996
|
|
|
4,768
|
|
||
Income taxes
|
4,504
|
|
|
4,510
|
|
||
Other receivables
|
648
|
|
|
242
|
|
||
Prepaid expenses
|
4,146
|
|
|
5,762
|
|
||
Inventory and other
|
2,147
|
|
|
260
|
|
||
Total current assets
|
144,238
|
|
|
175,213
|
|
||
PROPERTY, PLANT AND EQUIPMENT:
|
|
|
|
||||
Natural gas and oil properties, successful efforts method of accounting:
|
|
|
|
||||
Proved properties
|
562,572
|
|
|
561,713
|
|
||
Unproved properties
|
24,259
|
|
|
12,485
|
|
||
Furniture and equipment
|
229
|
|
|
213
|
|
||
Accumulated depreciation, depletion and amortization
|
(218,122
|
)
|
|
(178,081
|
)
|
||
Total property, plant and equipment, net
|
368,938
|
|
|
396,330
|
|
||
OTHER ASSETS:
|
|
|
|
||||
Investment in affiliates
|
63,123
|
|
|
52,827
|
|
||
Other
|
162
|
|
|
284
|
|
||
TOTAL ASSETS
|
$
|
576,461
|
|
|
$
|
624,654
|
|
CURRENT LIABILITIES:
|
|
|
|
||||
Accounts payable
|
$
|
4,926
|
|
|
$
|
3,084
|
|
Royalties and revenue payable
|
21,651
|
|
|
22,098
|
|
||
Accrued liabilities
|
4,882
|
|
|
6,796
|
|
||
Accrued exploration and development
|
313
|
|
|
2,334
|
|
||
Total current liabilities
|
31,772
|
|
|
34,312
|
|
||
|
|
|
|
||||
DEFERRED TAX LIABILITY
|
115,923
|
|
|
118,010
|
|
||
ASSET RETIREMENT OBLIGATION
|
9,612
|
|
|
7,993
|
|
||
COMMITMENTS AND CONTINGENCIES (NOTE 10)
|
|
|
|
|
|
||
SHAREHOLDERS’ EQUITY:
|
|
|
|
||||
Common stock, $0.04 par value, 50 million shares authorized,
20,135,107 shares issued and 15,194,952 shares outstanding at June 30, 2013,
20,135,107 shares issued and 15,292,448 shares outstanding at June 30, 2012
|
805
|
|
|
805
|
|
||
Additional paid-in capital
|
79,024
|
|
|
79,024
|
|
||
Treasury stock at cost (4,940,155 shares at June 30, 2013 and 4,842,659 shares at June 30, 2012)
|
(117,162
|
)
|
|
(112,207
|
)
|
||
Retained earnings
|
456,487
|
|
|
496,717
|
|
||
Total shareholders’ equity
|
419,154
|
|
|
464,339
|
|
||
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
576,461
|
|
|
$
|
624,654
|
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
REVENUES:
|
|
|
|
|
|
||||||
Natural gas and oil sales
|
$
|
127,201
|
|
|
$
|
179,272
|
|
|
$
|
201,721
|
|
Total revenues
|
127,201
|
|
|
179,272
|
|
|
201,721
|
|
|||
|
|
|
|
|
|
||||||
EXPENSES:
|
|
|
|
|
|
||||||
Operating expenses
|
31,907
|
|
|
25,183
|
|
|
25,691
|
|
|||
Exploration expenses
|
51,748
|
|
|
346
|
|
|
9,751
|
|
|||
Depreciation, depletion and amortization
|
41,060
|
|
|
49,052
|
|
|
52,198
|
|
|||
Impairment of natural gas and oil properties
|
14,845
|
|
|
—
|
|
|
1,786
|
|
|||
General and administrative expense
|
14,364
|
|
|
10,418
|
|
|
12,341
|
|
|||
Total expenses
|
153,924
|
|
|
84,999
|
|
|
101,767
|
|
|||
|
|
|
|
|
|
||||||
Gain (loss) from investment in affiliates (net of income taxes)
|
1,241
|
|
|
(449
|
)
|
|
—
|
|
|||
Other income (expense)
|
9,665
|
|
|
(312
|
)
|
|
(157
|
)
|
|||
|
|
|
|
|
|
||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
|
|
|
|
|
|
||||||
BEFORE INCOME TAXES
|
(15,817
|
)
|
|
93,512
|
|
|
99,797
|
|
|||
Benefit (provision) for income taxes
|
6,097
|
|
|
(34,299
|
)
|
|
(35,338
|
)
|
|||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
|
(9,720
|
)
|
|
59,213
|
|
|
64,459
|
|
|||
|
|
|
|
|
|
||||||
DISCONTINUED OPERATIONS (NOTE 5)
|
|
|
|
|
|
||||||
Discontinued operations, net of income taxes
|
—
|
|
|
(824
|
)
|
|
574
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
|
$
|
(9,720
|
)
|
|
$
|
58,389
|
|
|
$
|
65,033
|
|
|
|
|
|
|
|
||||||
NET INCOME (LOSS) PER SHARE:
|
|
|
|
|
|
||||||
Basic
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
(0.64
|
)
|
|
$
|
3.84
|
|
|
$
|
4.11
|
|
Discontinued operations
|
—
|
|
|
(0.05
|
)
|
|
0.04
|
|
|||
Total
|
$
|
(0.64
|
)
|
|
$
|
3.79
|
|
|
$
|
4.15
|
|
Diluted
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
(0.64
|
)
|
|
$
|
3.84
|
|
|
$
|
4.10
|
|
Discontinued operations
|
—
|
|
|
(0.05
|
)
|
|
0.04
|
|
|||
Total
|
$
|
(0.64
|
)
|
|
$
|
3.79
|
|
|
$
|
4.14
|
|
|
|
|
|
|
|
||||||
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
|
|
|
|
|
|
||||||
Basic
|
15,221
|
|
|
15,423
|
|
|
15,665
|
|
|||
Diluted
|
15,221
|
|
|
15,425
|
|
|
15,713
|
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(9,720
|
)
|
|
$
|
59,213
|
|
|
$
|
64,459
|
|
Plus income (loss) from discontinued operations, net of income taxes
|
—
|
|
|
(824
|
)
|
|
574
|
|
|||
Net income
|
(9,720
|
)
|
|
58,389
|
|
|
65,033
|
|
|||
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
41,060
|
|
|
49,052
|
|
|
59,337
|
|
|||
Impairment of natural gas and oil properties
|
14,845
|
|
|
1,031
|
|
|
2,315
|
|
|||
Exploration expenses
|
51,350
|
|
|
—
|
|
|
9,657
|
|
|||
Deferred income taxes
|
(2,087
|
)
|
|
(5,716
|
)
|
|
(7,819
|
)
|
|||
Loss (gain) on sale of assets
|
—
|
|
|
169
|
|
|
(1,813
|
)
|
|||
Loss (gain) from investment in affiliates
|
(1,910
|
)
|
|
690
|
|
|
—
|
|
|||
Stock-based compensation
|
—
|
|
|
3
|
|
|
1,276
|
|
|||
Tax benefit from exercise of stock options
|
—
|
|
|
(254
|
)
|
|
(502
|
)
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Decrease (increase) in accounts receivable and other
|
2,969
|
|
|
14,280
|
|
|
(2,029
|
)
|
|||
Decrease (increase) in inventory
|
(1,887
|
)
|
|
—
|
|
|
—
|
|
|||
Decrease (increase) in prepaids and other receivables
|
1,894
|
|
|
(1,840
|
)
|
|
1,671
|
|
|||
Increase (decrease) in accounts payable and advances from joint owners
|
1,166
|
|
|
(27,842
|
)
|
|
(5,718
|
)
|
|||
Increase (decrease) in other accrued liabilities
|
(1,914
|
)
|
|
(3,413
|
)
|
|
7,142
|
|
|||
Increase (decrease) in income taxes payable, net
|
5
|
|
|
(11,357
|
)
|
|
11,917
|
|
|||
Other
|
(116
|
)
|
|
379
|
|
|
91
|
|
|||
Net cash provided by operating activities
|
95,655
|
|
|
73,571
|
|
|
140,558
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Natural gas and oil exploration and development expenditures
|
(80,418
|
)
|
|
(20,847
|
)
|
|
(69,993
|
)
|
|||
Advance under note receivable
|
—
|
|
|
(500
|
)
|
|
—
|
|
|||
Repayment of note receivable
|
—
|
|
|
500
|
|
|
2,028
|
|
|||
Investments in affiliates
|
(16,416
|
)
|
|
(53,406
|
)
|
|
(3,959
|
)
|
|||
Distributions from affiliates
|
8,146
|
|
|
823
|
|
|
—
|
|
|||
Proceeds from the sale of assets
|
—
|
|
|
—
|
|
|
38,671
|
|
|||
Net cash used in investing activities
|
(88,688
|
)
|
|
(73,430
|
)
|
|
(33,253
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Dividends
|
(30,510
|
)
|
|
—
|
|
|
(6
|
)
|
|||
Purchase of common stock
|
(4,955
|
)
|
|
(20,419
|
)
|
|
(9,769
|
)
|
|||
Tax benefit from exercise/cancellation of stock options
|
—
|
|
|
254
|
|
|
502
|
|
|||
Debt issuance costs
|
—
|
|
|
—
|
|
|
(494
|
)
|
|||
Net cash used in financing activities
|
(35,465
|
)
|
|
(20,165
|
)
|
|
(9,767
|
)
|
|||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
(28,498
|
)
|
|
(20,024
|
)
|
|
97,538
|
|
|||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
|
129,983
|
|
|
150,007
|
|
|
52,469
|
|
|||
CASH AND CASH EQUIVALENTS, END OF PERIOD
|
$
|
101,485
|
|
|
$
|
129,983
|
|
|
$
|
150,007
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
|
|
|
|
|
|
||||||
Cash paid (received) for taxes, net
|
$
|
(2,453
|
)
|
|
$
|
50,687
|
|
|
$
|
31,876
|
|
Cash paid for interest
|
$
|
50
|
|
|
$
|
121
|
|
|
$
|
60
|
|
|
|
|
Additional
Paid-in
Capital
|
|
Treasury
Stock
|
|
Retained
Earnings
|
|
Total
Shareholders’
Equity
|
|||||||||||||
|
Common Stock
|
|
||||||||||||||||||||
|
Shares
|
|
Amount
|
|
||||||||||||||||||
Balance at June 30, 2010
|
15,684
|
|
|
$
|
799
|
|
|
$
|
77,968
|
|
|
$
|
(82,019
|
)
|
|
$
|
380,582
|
|
|
$
|
377,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Exercise of stock options
|
153
|
|
|
6
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Tax benefit from exercise of stock options
|
—
|
|
|
—
|
|
|
502
|
|
|
—
|
|
|
—
|
|
|
502
|
|
|||||
Treasury shares at cost
|
(173
|
)
|
|
—
|
|
|
—
|
|
|
(9,769
|
)
|
|
—
|
|
|
(9,769
|
)
|
|||||
Stock option expense
|
—
|
|
|
—
|
|
|
814
|
|
|
—
|
|
|
—
|
|
|
814
|
|
|||||
Dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,287
|
)
|
|
(7,287
|
)
|
|||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65,033
|
|
|
65,033
|
|
|||||
Balance at June 30, 2011
|
15,664
|
|
|
$
|
805
|
|
|
$
|
79,278
|
|
|
$
|
(91,788
|
)
|
|
$
|
438,328
|
|
|
$
|
426,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Tax benefit from exercise of stock options
|
—
|
|
|
—
|
|
|
(254
|
)
|
|
—
|
|
|
—
|
|
|
(254
|
)
|
|||||
Treasury shares at cost
|
(372
|
)
|
|
—
|
|
|
—
|
|
|
(20,419
|
)
|
|
—
|
|
|
(20,419
|
)
|
|||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58,389
|
|
|
58,389
|
|
|||||
Balance at June 30, 2012
|
15,292
|
|
|
$
|
805
|
|
|
$
|
79,024
|
|
|
$
|
(112,207
|
)
|
|
$
|
496,717
|
|
|
$
|
464,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Treasury shares at cost
|
(97
|
)
|
|
—
|
|
|
—
|
|
|
(4,955
|
)
|
|
—
|
|
|
(4,955
|
)
|
|||||
Dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(30,510
|
)
|
|
(30,510
|
)
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
(9,720
|
)
|
|
(9,720
|
)
|
||||
Balance at June 30, 2013
|
15,195
|
|
|
$
|
805
|
|
|
$
|
79,024
|
|
|
$
|
(117,162
|
)
|
|
$
|
456,487
|
|
|
$
|
419,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
||||||
|
2012
|
|
2011
|
||||
|
(thousands)
|
||||||
Revenues
|
$
|
—
|
|
|
$
|
8,055
|
|
Operating expenses
|
(40
|
)
|
|
(1,613
|
)
|
||
Depletion expenses
|
—
|
|
|
(4,106
|
)
|
||
Impairment and other expenses
|
—
|
|
|
(527
|
)
|
||
Loss on sale
|
—
|
|
|
(651
|
)
|
||
Income (loss) before income taxes
|
$
|
(40
|
)
|
|
$
|
1,158
|
|
Benefit (provision) for income taxes
|
14
|
|
|
(618
|
)
|
||
Income (loss) from discontinued operations, net of income taxes
|
$
|
(26
|
)
|
|
540
|
|
|
June 30,
|
||||||
|
2012
|
|
2011
|
||||
|
(thousands)
|
||||||
Revenues
|
$
|
6
|
|
|
$
|
2,056
|
|
Operating expenses
|
(16
|
)
|
|
(298
|
)
|
||
Depletion expenses
|
(11
|
)
|
|
(3,033
|
)
|
||
Impairment of natural gas and oil properties
|
(1,031
|
)
|
|
—
|
|
||
Exploration expenses
|
(7
|
)
|
|
—
|
|
||
Loss on sale
|
(169
|
)
|
|
$
|
(273
|
)
|
|
Loss before income taxes
|
$
|
(1,228
|
)
|
|
$
|
(1,548
|
)
|
Benefit for income taxes
|
430
|
|
|
542
|
|
||
Loss from discontinued operations, net of income taxes
|
$
|
(798
|
)
|
|
$
|
(1,006
|
)
|
|
June 30, 2011
|
||
|
(thousands)
|
||
Revenues
|
$
|
—
|
|
Exploration expenses
|
(983
|
)
|
|
General and administrative expenses
|
(154
|
)
|
|
Gain on sale
|
2,737
|
|
|
Income before income taxes
|
$
|
1,600
|
|
Benefit (provision) for income taxes
|
(560
|
)
|
|
Income from discontinued operations, net of income taxes
|
$
|
1,040
|
|
|
Year Ended June 30, 2013
|
|||||||||
(thousands, except per share amounts)
|
Net Loss
|
|
Shares
|
|
Per Share
|
|||||
Basic Earnings per Share:
|
|
|
|
|
|
|||||
Net loss attributable to common stock
|
$
|
(9,720
|
)
|
|
15,221
|
|
|
$
|
(0.64
|
)
|
Diluted Earnings per Share:
|
|
|
|
|
|
|||||
Net loss attributable to common stock
|
$
|
(9,720
|
)
|
|
15,221
|
|
|
$
|
(0.64
|
)
|
|
Year Ended June 30, 2012
|
|||||||||
(thousands, except per share amounts)
|
Net Income
|
|
Shares
|
|
Per Share
|
|||||
Income from continuing operations
|
$
|
59,213
|
|
|
15,423
|
|
|
$
|
3.84
|
|
Discontinued operations, net of income taxes
|
(824
|
)
|
|
15,423
|
|
|
(0.05
|
)
|
||
Basic Earnings per Share:
|
|
|
|
|
|
|||||
Net income attributable to common stock
|
$
|
58,389
|
|
|
15,423
|
|
|
$
|
3.79
|
|
Effect of potential dilutive securities:
|
|
|
|
|
|
|||||
Stock options, net of shares assumed purchased
|
—
|
|
|
2
|
|
|
|
|||
Income from continuing operations
|
$
|
59,213
|
|
|
15,425
|
|
|
$
|
3.84
|
|
Discontinued operations, net of income taxes
|
(824
|
)
|
|
15,425
|
|
|
(0.05
|
)
|
||
Diluted Earnings per Share:
|
|
|
|
|
|
|||||
Net income attributable to common stock
|
$
|
58,389
|
|
|
15,425
|
|
|
$
|
3.79
|
|
|
Year Ended June 30, 2011
|
|||||||||
(thousands, except per share amounts)
|
Net Income
|
|
Shares
|
|
Per Share
|
|||||
Income from continuing operations
|
$
|
64,459
|
|
|
15,665
|
|
|
$
|
4.11
|
|
Discontinued operations, net of income taxes
|
574
|
|
|
15,665
|
|
|
0.04
|
|
||
Basic Earnings per Share:
|
|
|
|
|
|
|||||
Net income attributable to common stock
|
$
|
65,033
|
|
|
15,665
|
|
|
$
|
4.15
|
|
Effect of potential dilutive securities:
|
|
|
|
|
|
|||||
Stock options, net of shares assumed purchased
|
—
|
|
|
48
|
|
|
|
|||
Income from continuing operations
|
$
|
64,459
|
|
|
15,713
|
|
|
$
|
4.10
|
|
Discontinued operations, net of income taxes
|
574
|
|
|
15,713
|
|
|
0.04
|
|
||
Diluted Earnings per Share:
|
|
|
|
|
|
|||||
Net income attributable to common stock
|
$
|
65,033
|
|
|
15,713
|
|
|
$
|
4.14
|
|
|
|
June 30,
|
||||||
|
|
2013
|
|
2012
|
||||
Current assets
|
|
$
|
24,038
|
|
|
$
|
43,607
|
|
Non-current assets:
|
|
|
|
|
||||
Net property and equipment
|
|
128,147
|
|
|
2,125
|
|
||
Restricted cash escrow account
|
|
40,022
|
|
|
40,004
|
|
||
Other non-current assets
|
|
3,684
|
|
|
5,540
|
|
||
Total non-current assets
|
|
171,853
|
|
|
47,669
|
|
||
Total assets
|
|
$
|
195,891
|
|
|
$
|
91,276
|
|
|
|
|
|
|
||||
Current liabilities
|
|
$
|
19,107
|
|
|
$
|
303
|
|
Non-current liabilities:
|
|
|
|
|
||||
Long-term debt
|
|
45,000
|
|
|
—
|
|
||
Other non-current liabilities
|
|
824
|
|
|
—
|
|
||
Total non-current liabilities
|
|
45,824
|
|
|
—
|
|
||
Member's equity
|
|
130,960
|
|
|
90,973
|
|
||
Total liabilities & member's equity
|
|
$
|
195,891
|
|
|
$
|
91,276
|
|
|
|
Year Ended June 30,
|
||||||
|
|
2013
|
|
2012
|
||||
Oil and natural gas sales
|
|
$
|
27,932
|
|
|
$
|
68
|
|
Other loss
|
|
(2,720
|
)
|
|
—
|
|
||
Less:
|
|
|
|
|
||||
Lease operating expenses
|
|
8,157
|
|
|
23
|
|
||
Depreciation, depletion, amortization & accretion
|
|
8,178
|
|
|
—
|
|
||
General & administrative expense
|
|
3,227
|
|
|
1,536
|
|
||
Income/(loss) from continuing operations
|
|
5,650
|
|
|
(1,491
|
)
|
||
Net interest income/(expense)
|
|
(604
|
)
|
|
9
|
|
||
Net income (loss)
|
|
$
|
5,046
|
|
|
$
|
(1,482
|
)
|
|
Year Ended June 30,
|
|||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||
|
(thousands)
|
|||||||||||||||||||
Provision/(benefit) at statutory tax rate
|
$
|
(5,302
|
)
|
|
(0.35
|
)%
|
|
$
|
32,644
|
|
|
35.00
|
%
|
|
$
|
34,929
|
|
|
35.00
|
%
|
State income tax provision, net of federal benefit
|
2,293
|
|
|
15.13
|
%
|
|
1,712
|
|
|
1.84
|
%
|
|
2,985
|
|
|
3.04
|
%
|
|||
Permanent differences
|
(2,424
|
)
|
|
(16.00
|
)%
|
|
(746
|
)
|
|
(0.80
|
)%
|
|
(2,678
|
)
|
|
(2.73
|
)%
|
|||
Other
|
4
|
|
|
0.03
|
%
|
|
447
|
|
|
0.48
|
%
|
|
102
|
|
|
0.10
|
%
|
|||
Income tax provision /(benefit)
|
$
|
(5,429
|
)
|
|
(35.84
|
)%
|
|
$
|
34,057
|
|
|
36.52
|
%
|
|
$
|
35,338
|
|
|
35.41
|
%
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Deferred tax liability:
|
(thousands)
|
||||||||||
Temporary basis differences in natural gas and oil properties and other
|
$
|
(115,923
|
)
|
|
$
|
(118,010
|
)
|
|
$
|
(123,472
|
)
|
Net deferred tax liability
|
$
|
(115,923
|
)
|
|
$
|
(118,010
|
)
|
|
$
|
(123,472
|
)
|
|
Year Ended June 30,
|
||||||
|
2013
|
|
2012
|
||||
|
(thousands)
|
||||||
Balance as of July 1
|
$
|
7,993
|
|
|
$
|
8,611
|
|
Liabilities incurred during period
|
2,023
|
|
|
53
|
|
||
Liabilities settled during period
|
(2,037
|
)
|
|
(238
|
)
|
||
Accretion
|
491
|
|
|
507
|
|
||
Change in estimate
|
1,142
|
|
|
(940
|
)
|
||
Balance as of June 30
|
$
|
9,612
|
|
|
$
|
7,993
|
|
|
Year Ended June 30,
|
|||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||||
|
Shares
Under Options |
|
Weighted
Average Exercise Price |
|
Shares
Under
Options
|
|
Weighted
Average
Exercise
Price
|
|
Shares
Under
Options
|
|
Weighted
Average
Exercise
Price
|
|||||||||||
Outstanding, beginning of year
|
—
|
|
|
—
|
|
|
45,000
|
|
|
$
|
54.21
|
|
|
305,334
|
|
|
$
|
28.61
|
|
|||
Granted
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|||
Exercised
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
(152,544
|
)
|
|
$
|
21.38
|
|
|||
Forfeited (1)
|
—
|
|
|
—
|
|
|
(45,000
|
)
|
|
$
|
54.21
|
|
|
(107,790
|
)
|
|
$
|
28.14
|
|
|||
Outstanding, end of year
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
45,000
|
|
|
$
|
54.21
|
|
|||
Aggregate intrinsic value ($000)
|
$
|
—
|
|
|
|
|
|
$
|
—
|
|
|
|
|
$
|
190
|
|
|
|
||||
Exercisable, end of year
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
45,000
|
|
|
$
|
54.21
|
|
|||
Aggregate intrinsic value ($000)
|
$
|
—
|
|
|
|
|
|
$
|
—
|
|
|
|
|
$
|
190
|
|
|
|
||||
Available for grant, end of year
|
1,475,000
|
|
|
|
|
|
1,475,000
|
|
|
|
|
1,475,000
|
|
|
|
|||||||
Weighted average fair value of options granted during the year
|
$
|
—
|
|
|
|
|
|
$
|
—
|
|
|
|
|
$
|
—
|
|
|
|
(1)
|
For the fiscal year ended June 30, 2012, forfeited options consist of options that were net-settled for cash with the Company. For the fiscal year ended June 30, 2011, forfeited options relate to options surrendered under a cashless exercise, with immediate sale to the Company.
|
•
|
In March 2010 the Company spud the Eloise South well. All owners paid for their proportionate share of drilling and completion costs based on their ownership percentage. The Company had a
23.8%
working interest in this well, Olympic had a
3.33%
working interest, and REX had a
9.6%
working interest. Once production began, JEX employees received an ORRI of
1.33%
.
|
•
|
In June 2010 the Company spud its Rexer #1 well. Under the terms of the applicable participation agreement, the Company had a
100%
working interest through payout of all costs. In May 2011, the Company sold Rexer #1 (See Note 5 - Discontinued Operations) prior to reaching payout. Once payout is reached with the new operator, JEX will have an option to back-in for a
10%
working interest (
7.25%
net revenue interest). Other third-parties own the remaining working interests. JEX employees maintained a
2.5%
ORRI in this well. The Company paid JEX a prospect fee of
$250,000
for generating this prospect.
|
•
|
In October 2010, the Company purchased JEX's
7.5%
working interest in Ship Shoal 263 for
$7.5 million
, based on a reserve valuation as of the purchase date.
|
•
|
Prior to its dissolution, Contango Offshore Exploration LLC owed the Company
$5.9 million
in principal and interest under a promissory note (the “COE Note”) payable on demand. In connection with the dissolution, the Company assumed its
65.63%
share of the obligation under the COE Note, while JEX assumed the remaining
34.37%
, or approximately
$2 million
. This
$2 million
was paid to the Company in October 2010.
|
•
|
In February 2011 the Company spud Vermilion 170 which was owned
100%
by the Company. Under the terms of the applicable participation agreement, Contango had a
100%
working interest through casing point. Once casing point was reached, JEX and REX each exercised their option to back-in for a
2.6%
and
7.5%
working interest, respectively. Once production began, JEX and REX each received their carried working interest of
1.7%
and
5.0%
, respectively, resulting in JEX having a final working interest of
4.3%
and REX having a final working interest of
12.5%
. The Company owns the remaining working interests in this well. The Company paid JEX a prospect fee of
$250,000
for generating this prospect.
|
•
|
In May 2011 the Company spud its Rexer-Tusa #2 well. Under the terms of the applicable participation agreement, the Company had a
25%
working interest through payout of all costs. In October 2011, the Company completed selling Rexer-Tusa #2 (See Note 5 - Discontinued Operations) prior to reaching payout. Once payout is reached with the new operator, JEX will have an option to back-in for a
10%
working interest (
7.36%
net revenue interest). Other third-parties own the remaining working interests. JEX employees maintained a
2.92%
ORRI in this well.
|
•
|
In July 2011, the Company recompleted its Eloise South well uphole in the Cib-Op sands as our Dutch #5 well. Under the terms of the applicable joint operating agreement, all Dutch #5 well owners were required to purchase the Eloise South well bore from the Eloise South owners (the "Dutch Well Cost Adjustment"). All Eloise South and Dutch #5 well owners paid and/or received their proportionate share of the Dutch Well Cost Adjustment based on their ownership percentage in each well. JEX had a
1.6%
working interest in Dutch #5; Olympic had a
3.02%
working interest in Dutch #5 and a
3.33%
working interest in Eloise South; REX had a
9.6%
working interest in Eloise South; and Contango had a
47.05%
working interest in Dutch #5 and a
23.8%
working interest in Eloise South.
|
•
|
In December 2011, the Company purchased an additional working interest in Mary Rose #5 (see below) from an existing partner. The Company then sold to Olympic and JEX its proportionate share of the existing partner's interest, based on Olympic and JEX's ownership percentage in the well.
|
•
|
In January 2012, the Company recompleted its Eloise North well uphole in the Cib-Op sands as our Mary Rose #5 well. Under the terms of the applicable joint operating agreement, all Mary Rose #5 well owners were required to purchase the Eloise North well bore from the Eloise North owners. (the "Mary Rose Well Cost Adjustment"). All Eloise North and Mary Rose #5 well owners paid and/or received their proportionate share of the Mary Rose Well Cost Adjustment based on their ownership percentage in each well. JEX had a
1.4%
working interest in Mary Rose #5 and a
0.1%
working interest in Eloise North; Olympic had a
2.56%
working interest in Mary Rose #5 and a
4.79%
working interest in Eloise North; REX had a
13.2%
working interest in Eloise North; and the Company had a
37.8%
working interest in Mary Rose #5 and a
35.8%
working interest in Eloise North.
|
•
|
In March 2012, the Company was awarded Brazos Area 543 by the BOEM, which was bid on at the Western Gulf of Mexico Lease Sale No. 218 held on December 14, 2011. Under the terms of the applicable participation agreement, if
|
•
|
In July 2012 the Company spud the Ship Shoal 134 prospect which was owned
100%
by the Company. The Company paid
100%
of the costs to drill, plug and abandon this well. The Company paid JEX a prospect fee of
$250,000
for generating this prospect.
|
•
|
In July 2012 the Company spud the South Timbalier 75 prospect which was farmed-in
100%
by the Company and REX. Under the terms of the applicable participation agreement, the Company paid
100%
of the costs to drill, plug and abandon this well. The Company paid JEX a prospect fee of
$250,000
for generating this prospect.
|
•
|
For the
five
REX-generated lease blocks that the Company purchased at the June 20, 2012 lease sale, the Company will have a
100%
working interest through first production. At first production (if successful), REX will receive a carried working interest of
10%
. Once payout of post casing point costs has been reached, REX will have an option to back-in for up to
12.5%
working interest, resulting in REX having a final working interest of up to
22.5%
(
17.5%
net revenue interest) and the Company owning the remaining working interests. JEX employees will receive an ORRI of
3.33%
in these prospects.
|
•
|
For the
one
JEX-generated lease block that the Company purchased at the June 20, 2012 lease sale, the Company will carry JEX for
10%
through first production and JEX employees will receive an ORRI of
3.33%
.
|
•
|
For the
three
REX-generated lease blocks that the Company purchased at the March 20, 2013 lease sale, the Company will have a
100%
working interest through first production. At first production (if successful), REX will receive a carried working interest of
10%
. Once payout of post casing point costs has been reached, REX will have an option to back-in for up to
12.5%
working interest, resulting in REX having a final working interest of up to
22.5%
(
17.5%
net revenue interest) and the Company owning the remaining working interests. JEX employees will receive an ORRI of
3.33%
in these prospects.
|
•
|
In June 2013, the Company purchased South Timbalier 17 from an independent oil and gas company. Under the terms of the applicable participation agreement, the Company will have a
75%
working interest in this well, with several other owners owning the remainder, until payout of all costs is reached. Once payout of all costs has been reached, REX will have an option to back-in for up to a
9.4%
working interest, (
6.7%
net revenue interest), resulting in the Company owning a
56.3%
working interests (
39.9%
net revenue interest). The Company paid JEX a prospect fee of
$250,000
for evaluating this prospect. There are no JEX employee ORRIs on this prospect.
|
•
|
In the Tuscaloosa Marine Shale ("TMS"), a shale play in central Louisiana and Mississippi, the Company has a
100%
working interest through first production. At first production of the existing acreage (if successful), JEX will receive a carried working interest of
10%
and JEX employees will receive an ORRI of
2%
, of which Mr. Juneau receives
0.75%
, due to fees to third parties paid by JEX in order to get into the prospect, that were not billed to Contango. An additional
2%
was granted to the geologist who is responsible for the generation of the TMS prospect. The geologist has subsequently been employed by JEX.
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||||||||||||||
|
Olympic
|
JEX
|
REX
|
|
Olympic
|
JEX
|
REX
|
|
Olympic
|
JEX
|
REX
|
||||||||||||||||||
Revenue payments as well owners
|
$
|
(6,455
|
)
|
$
|
(4,380
|
)
|
$
|
(2,449
|
)
|
|
$
|
(8,453
|
)
|
$
|
(5,719
|
)
|
$
|
(3,166
|
)
|
|
$
|
(10,406
|
)
|
$
|
(6,089
|
)
|
$
|
(1,908
|
)
|
Joint interest billing receipts
|
1,122
|
|
1,170
|
|
1,430
|
|
|
1,223
|
|
928
|
|
2,422
|
|
|
1,480
|
|
1,437
|
|
2,068
|
|
|||||||||
Dutch well cost adjustment
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
(389
|
)
|
161
|
|
(957
|
)
|
|||||||||
Mary Rose well cost adjustment
|
—
|
|
—
|
|
—
|
|
|
(201
|
)
|
118
|
|
(1,185
|
)
|
|
—
|
|
—
|
|
—
|
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||||||||||||||
|
Olympic
|
JEX
|
REX
|
|
Olympic
|
JEX
|
REX
|
|
Olympic
|
JEX
|
REX
|
||||||||||||||||||
Sale of interest in Mary Rose #5
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
8
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Reimbursement of certain costs
|
—
|
|
(546
|
)
|
(5
|
)
|
|
—
|
|
(325
|
)
|
(17
|
)
|
|
—
|
|
(206
|
)
|
(302
|
)
|
|||||||||
Prospect fees
|
—
|
|
(750
|
)
|
—
|
|
|
—
|
|
(250
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||||||
Advisory Agreement
|
—
|
|
(1,000
|
)
|
—
|
|
|
—
|
|
(500
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||||||
First Right Agreement
|
—
|
|
(125
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||||||
Contaro Advisory Agreement
|
—
|
|
(50
|
)
|
—
|
|
|
—
|
|
(30
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||||||
Purchase of Ship Shoal 263
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
(7,512
|
)
|
—
|
|
|||||||||
REX distribution to members
|
—
|
|
—
|
|
646
|
|
|
—
|
|
—
|
|
823
|
|
|
—
|
|
—
|
|
—
|
|
|||||||||
Repayment of COE Note
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
2,028
|
—
|
|||||||||||
Exploration costs in Alaska
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
(906)
|
—
|
|
2013
|
|
2012
|
||||||||||
|
Olympic
|
JEX
|
REX
|
|
Olympic
|
JEX
|
REX
|
||||||
Accounts receivable:
|
|
|
|
|
|
|
|
||||||
Trade receivable
|
16
|
|
21
|
|
—
|
|
|
26
|
|
20
|
|
18
|
|
Joint interest billing
|
178
|
|
358
|
|
922
|
|
|
193
|
|
158
|
|
92
|
|
|
|
|
|
|
|
|
|
||||||
Accounts payable:
|
|
|
|
|
|
|
|
||||||
Royalties and revenue payable
|
(609
|
)
|
(425
|
)
|
(221
|
)
|
|
(611
|
)
|
(813
|
)
|
(682
|
)
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Property acquisition costs:
|
|
|
(thousands)
|
|
|
||||||
Unproved
|
$
|
16,130
|
|
|
$
|
5,404
|
|
|
$
|
2,802
|
|
Proved
|
102
|
|
|
381
|
|
|
10,135
|
|
|||
Exploration costs
|
47,584
|
|
|
1,154
|
|
|
14,016
|
|
|||
Development costs
|
11,758
|
|
|
10,350
|
|
|
39,211
|
|
|||
Total costs incurred
|
$
|
75,574
|
|
|
$
|
17,289
|
|
|
$
|
66,164
|
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
|
|
(thousands)
|
|
|
||||||
Property acquisition costs
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Exploration costs
|
—
|
|
|
—
|
|
|
—
|
|
|||
Development costs
|
46,972
|
|
|
785
|
|
|
—
|
|
|||
Company's 37% share of costs incurred
|
$
|
46,972
|
|
|
$
|
785
|
|
|
$
|
—
|
|
|
Oil and
Condensate
|
|
NGLs
|
|
Natural
Gas
|
|||
|
(MBbls)
|
|
(MBbls)
|
|
(MMcf)
|
|||
Proved Developed and Undeveloped Reserves as of:
|
|
|
|
|
|
|||
June 30, 2010
|
4,598
|
|
|
6,738
|
|
|
246,011
|
|
Sale of minerals in place
|
(126
|
)
|
|
(648
|
)
|
|
(16,804
|
)
|
Extensions and discoveries
|
565
|
|
|
191
|
|
|
31,585
|
|
Purchases of minerals in place
|
53
|
|
|
9
|
|
|
929
|
|
Revisions of previous estimates
|
73
|
|
|
(302
|
)
|
|
2,584
|
|
Production
|
(685
|
)
|
|
(702
|
)
|
|
(26,160
|
)
|
June 30, 2011
|
4,478
|
|
|
5,286
|
|
|
238,145
|
|
Sale of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
(551
|
)
|
|
1,262
|
|
|
(13,149
|
)
|
Production
|
(615
|
)
|
|
(662
|
)
|
|
(23,617
|
)
|
June 30, 2012
|
3,312
|
|
|
5,886
|
|
|
201,379
|
|
Sale of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
81
|
|
|
—
|
|
|
—
|
|
Purchases of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
(703
|
)
|
|
(1,141
|
)
|
|
(33,714
|
)
|
Production
|
(362
|
)
|
|
(601
|
)
|
|
(18,658
|
)
|
June 30, 2013
|
2,328
|
|
|
4,144
|
|
|
149,007
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|||
June 30, 2010
|
4,328
|
|
|
6,167
|
|
|
231,260
|
|
June 30, 2011
|
3,738
|
|
|
5,037
|
|
|
205,085
|
|
June 30, 2012
|
3,353
|
|
|
5,664
|
|
|
196,268
|
|
June 30, 2013
|
2,297
|
|
|
4,078
|
|
|
146,518
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|||
June 30, 2010
|
270
|
|
|
571
|
|
|
14,751
|
|
June 30, 2011
|
740
|
|
|
249
|
|
|
33,060
|
|
June 30, 2012
|
(41
|
)
|
|
222
|
|
|
5,111
|
|
June 30, 2013
|
31
|
|
|
66
|
|
|
2,489
|
|
|
|
|
|
|
|
|||
Company's Share of Proved Developed Reserves attributable to our 37% investment in Exaro:
|
|
|
|
|
|
|||
June 30, 2012
|
20
|
|
|
—
|
|
|
1,683
|
|
June 30, 2013
|
309
|
|
|
—
|
|
|
28,320
|
|
|
As of June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(thousands)
|
||||||||||
Future cash inflows
|
$
|
956,886
|
|
|
$
|
1,378,910
|
|
|
$
|
1,801,236
|
|
Future production costs
|
(170,159
|
)
|
|
(301,137
|
)
|
|
(313,688
|
)
|
|||
Future development costs
|
(22,507
|
)
|
|
(31,214
|
)
|
|
(52,053
|
)
|
|||
Future income tax expenses
|
(268,290
|
)
|
|
(312,211
|
)
|
|
(406,306
|
)
|
|||
Future net cash flows
|
495,930
|
|
|
734,348
|
|
|
1,029,189
|
|
|||
10% annual discount for estimated timing of cash flows
|
(138,413
|
)
|
|
(220,416
|
)
|
|
(312,054
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
357,517
|
|
|
$
|
513,932
|
|
|
$
|
717,135
|
|
|
|
|
|
|
|
||||||
Contango's share of standardized measure of discounted future net cash flows attributable to our 37% investment in Exaro
|
$
|
42,464
|
|
|
$
|
2,733
|
|
|
$
|
—
|
|
|
Year Ended June 30,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Changes in standardized measure due to current year operation:
|
(thousands)
|
||||||||||
Sales of natural gas and oil produced during the period, net of production expenses
|
$
|
(112,469
|
)
|
|
$
|
(160,111
|
)
|
|
$
|
(188,810
|
)
|
Extensions and discoveries
|
2,956
|
|
|
—
|
|
|
160,712
|
|
|||
Net change in prices and production costs
|
8,186
|
|
|
(144,533
|
)
|
|
5,401
|
|
|||
Changes in estimated future development costs
|
9,399
|
|
|
17,322
|
|
|
41,989
|
|
|||
Revisions in quantity estimates
|
(131,245
|
)
|
|
(25,486
|
)
|
|
4,078
|
|
|||
Purchase of reserves
|
—
|
|
|
—
|
|
|
6,556
|
|
|||
Sale of reserves
|
—
|
|
|
—
|
|
|
(20,031
|
)
|
|||
Accretion of discount
|
73,022
|
|
|
98,104
|
|
|
97,044
|
|
|||
Changes in income taxes
|
23,470
|
|
|
47,616
|
|
|
(5,558
|
)
|
|||
Change in the timing of production rates and other
|
(29,734
|
)
|
|
(36,115
|
)
|
|
(96,340
|
)
|
|||
Net change
|
(156,415
|
)
|
|
(203,203
|
)
|
|
5,041
|
|
|||
Beginning of year
|
513,932
|
|
|
717,135
|
|
|
712,094
|
|
|||
End of year
|
$
|
357,517
|
|
|
$
|
513,932
|
|
|
$
|
717,135
|
|
|
|
Quarter Ended
|
||||||||||||||
|
|
September 30, 2012
|
|
December 31, 2012
|
|
March 31, 2013
|
|
June 30, 2013
|
||||||||
|
|
(thousands, except per share amounts)
|
||||||||||||||
Fiscal Year 2013:
|
|
|
|
|
|
|
|
|
||||||||
Revenues from continuing operations
|
|
$
|
29,765
|
|
|
$
|
34,940
|
|
|
$
|
31,787
|
|
|
$
|
30,709
|
|
Net income (loss) from continuing operations (1)
|
|
$
|
(27,549
|
)
|
|
$
|
2,604
|
|
|
$
|
3,869
|
|
|
$
|
11,356
|
|
Net income (loss) attributable to common stock
|
|
$
|
(27,549
|
)
|
|
$
|
2,604
|
|
|
$
|
3,869
|
|
|
$
|
11,356
|
|
Net income (loss) per share (2):
|
|
|
|
|
|
|
|
|
||||||||
Basic:
|
|
$
|
(1.80
|
)
|
|
$
|
0.17
|
|
|
$
|
0.25
|
|
|
$
|
0.75
|
|
Diluted:.
|
|
$
|
(1.80
|
)
|
|
$
|
0.17
|
|
|
$
|
0.25
|
|
|
$
|
0.75
|
|
Fiscal Year 2012:
|
|
|
|
|
|
|
|
|
||||||||
Revenues from continuing operations
|
|
$
|
44,203
|
|
|
$
|
53,907
|
|
|
$
|
41,339
|
|
|
$
|
39,823
|
|
Income from continuing operations (1)
|
|
15,586
|
|
|
19,589
|
|
|
14,699
|
|
|
9,339
|
|
||||
Net loss from discontinued operations, net of taxes
|
|
(682
|
)
|
|
(114
|
)
|
|
(26
|
)
|
|
(2
|
)
|
||||
Net income attributable to common stock
|
|
14,904
|
|
|
19,475
|
|
|
14,673
|
|
|
9,337
|
|
||||
Net income per share (2):
|
|
|
|
|
|
|
|
|
||||||||
Basic:
|
|
$
|
0.95
|
|
|
$
|
1.27
|
|
|
$
|
0.96
|
|
|
$
|
0.61
|
|
Diluted:.
|
|
$
|
0.95
|
|
|
$
|
1.27
|
|
|
$
|
0.96
|
|
|
$
|
0.61
|
|
(1)
|
Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of natural gas and oil properties, general and administrative expense, and other income and expense before income taxes.
|
(2)
|
The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income for that quarter and the weighted average number of common shares outstanding during that quarter.
|
•
|
Eugene Island Area Block 23 , Lease Number OCS-G 34813
|
•
|
Ship Shoal Area Block 52 , Lease Number OCS-G 34826
|
•
|
Ship Shoal Area Block 59, Lease Number OCS-G 34827
|
•
|
a map or plat depicting the outline of the lands included in the Prospect; and
|
•
|
the minimum depth interval to be drilled and tested with respect to the Test Well for the Prospect (“
Objective Depth
”).
|
1.
|
COI shall pay to JEX, the sole manager of REX, a prospect fee of $250,000 upon execution of the Participation Agreement and the Joint Operating Agreement with Houston Energy, L.P. et al pursuant to the terms and conditions of the LOI.
|
2.
|
REX shall be entitled to an election to own a proportionately reduced 12.5% back-in working interest after Prospect Payout upon the same terms in the LOI such that REX will have the option to own a 9.375% working interest and 6.65625% net revenue interest after Prospect Payout.
|
Re:
|
Contango Oil & Gas Company, 2013 Annual Report on Form 10-K
|
|
Yours very truly,
|
|
WILLIAM M. COBB & ASSOCIATES, INC.
|
|
/s/ F.J. MAREK
|
F.J. Marek, P.E.
|
Senior Vice President
|
Re:
|
Contango Oil & Gas Company, Annual Report on Form 10-K
|
|
Yours very truly,
|
|
W.D. VON GONTEN & CO.
|
|
/s/ W.D. VON GONTEN JR
|
Name: W.D. Von Gonten JR
|
Title: President
|
1.
|
I have reviewed this Annual Report on Form 10-K of the Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;
|
4.
|
I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:
|
5.
|
I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.
|
1.
|
I have reviewed this Annual Report on Form 10-K of the Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;
|
4.
|
I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:
|
5.
|
I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.
|
1.
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.
|
1.
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.
|
|
|
|
|
|
|
Future Net Pre-Tax
Income – M$
|
|
Reserve
Category
|
|
Net Gas
(MMCF)
|
Net NGL
(MBBL)
|
Net Oil
(MBBL)
|
|
Undiscounted
|
Discounted
at 10%
|
Proved
|
|
|
|
|
|
|
|
Producing
|
|
98,510
|
2,764
|
1,608
|
|
517,815
|
403,233
|
Non-Producing
|
|
48,008
|
1,314
|
689
|
|
230,147
|
120,537
|
Undeveloped
|
|
2,489
|
66
|
31
|
|
16,258
|
26,566
|
Total Proved
|
|
149,007
|
4,144
|
2,328
|
|
764,220
|
550,336
|