MCF-2013.6.30-10K


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended June 30, 2013
[    ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from          to         
Commission file number 001-16317
CONTANGO OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
Delaware
 
95-4079863
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer Identification No.)
3700 Buffalo Speedway, Suite 960
Houston, Texas 77098
(Address of principal executive offices)
(713) 960-1901
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, Par Value $0.04 per share
 
NYSE MKT
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  [    ]    No [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes [    ]    No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes [X]    No [    ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes [X]    No [    ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  [X]    Accelerated filer  [    ]    Non-accelerated filer  [    ]    Smaller reporting company  [    ]
(Do not check if smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes [    ]    No [X]
At December 31, 2012, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of shares of such common stock as reported on the NYSE MKT was $559,355,116. As of August 26, 2013, there were 15,194,952 shares of the registrant’s common stock outstanding.
Documents Incorporated by Reference
Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since registrant will file with the Securities and Exchange Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information required by Items 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-K.





CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 30, 2013
TABLE OF CONTENTS
 
 
Page    
 
PART I
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 

i



 
 
 
 
 
PART III
 
 
 
 
 
PART IV
 




ii



CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the statements made in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:
 
Our financial position
Business strategy, including outsourcing
Meeting our forecasts and budgets
Anticipated capital expenditures
Drilling of wells
Natural gas and oil production and reserves
Timing and amount of future discoveries (if any) and production of natural gas and oil
Operating costs and other expenses
Cash flow and anticipated liquidity
Prospect development
Property acquisitions and sales
New governmental laws and regulations
Expectations regarding oil and gas markets in the United States
Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:
 
Low and/or declining prices for natural gas and oil
Natural gas and oil price volatility
Operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and gas processing facilities
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
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
The timing and successful drilling and completion of natural gas and oil wells
Availability of capital and the ability to repay indebtedness when due
Availability of rigs and other operating equipment
Ability to receive Bureau of Safety and Environmental Enforcement permits on a time schedule that permits the Company to operate efficiently
Ability to raise capital to fund capital expenditures
Timely and full receipt of sale proceeds from the sale of our production
The ability to find, acquire, market, develop and produce new natural gas and oil properties
Interest rate volatility
Zero or near-zero interest rates
Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures
Operating hazards attendant to the natural gas and oil business
Downhole drilling and completion risks that are generally not recoverable from third parties or insurance
Potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps
Weather
Availability and cost of material and equipment
Delays in anticipated start-up dates
Actions or inactions of third-party operators of our properties
Actions or inactions of third-party operators of pipelines or processing facilities
The ability to find and retain skilled personnel
Strength and financial resources of competitors
Federal and state regulatory developments and approvals
Environmental risks
Worldwide economic conditions
The ability to construct and operate offshore infrastructure, including pipeline and production facilities
The continued compliance by the Company with various pipeline and gas processing plant specifications for the gas and condensate produced by the Company
Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and state of Louisiana (“Mary Rose”) acreage
Restrictions on permitting activities
Expanded rigorous monitoring and testing requirements
Legislation that may regulate drilling activities and increase or remove liability caps for claims of damages from oil spills
Ability to obtain insurance coverage on commercially reasonable terms
Accidental spills, blowouts and pipeline ruptures
Impact of new and potential legislative and regulatory changes on Gulf of Mexico operating and safety standards
You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” referred to on page 13 of this report for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.
 
All references in this Form 10-K to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and wholly-owned Subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to natural gas and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent engineers and are net to our interest.


iii



PART I
Item 1. Business
Overview

Contango is a Houston, Texas based, independent natural gas and oil company.  The Company's core business is to explore, develop, produce and acquire natural gas and oil properties offshore in the shallow waters of the Gulf of Mexico.  Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator of our offshore properties. Contango has additional onshore investments in i) Alta Resources Investments, LLC ("Alta"), whose primary area of focus is the liquids-rich Kaybob Duvernay in Alberta, Canada; ii) Exaro Energy III LLC ("Exaro"), which is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; and iii) the Tuscaloosa Marine Shale ("TMS") where we own approximately 24,000 acres. 

On April 19, 2013, the Company's founder and former Chairman, President and Chief Executive Officer, Mr. Kenneth R. Peak, passed away at the age of 67. The Company held a $10 million life insurance policy for Mr. Peak and received the proceeds of such policy in early May 2013.
         
On April 30, 2013, the Company announced that it had signed a merger agreement (the "Merger Agreement") with Crimson Exploration Inc. ("Crimson"), for an all-stock transaction pursuant to which Crimson will become a wholly owned subsidiary of Contango (the "Merger"). Upon consummation of the Merger, each share of Crimson stock will be converted into 0.08288 shares of Contango stock resulting in Crimson stockholders owning 20.3% of the post-merger Contango. This transaction is subject to shareholder approval of both Contango and Crimson and is expected to close in October 2013, subject to satisfaction of a number of closing conditions.
         
Crimson is a Houston, Texas-based independent energy company engaged in the exploitation, exploration, development and acquisition of crude oil and natural gas, primarily in the onshore Gulf Coast regions of the United States. Crimson currently owns approximately 95,000 net acres onshore in Texas, Louisiana, Colorado and Mississippi. Crimson refers to its four corporate areas as (i) Southeast Texas, focusing on the Woodbine, Eagle Ford and Georgetown formations, (ii) South Texas, focusing on the Eagle Ford and Buda formations, (iii) East Texas, focusing on the Haynesville, Mid-Bossier and James Lime formations, and (iv) Rockies and Other, focusing on the Niobrara and D&J Sand formations. Crimson’s strategy is to continue to increase crude oil and liquids-rich reserves and production from an extensive inventory of drilling prospects, de-risk unproved prospects in core operating areas, and opportunistically grow reserves through acquisitions complementary to its existing asset base.
As of June 30, 2013, Crimson had estimated proved reserves of 117.1 billion cubic feet equivalent ("Bcfe") of natural gas equivalents, based on SEC reporting guidelines. For the quarter ended June 30, 2013, Crimson’s average production was approximately 44.2 million cubic feet equivalent per day ("Mmcfed"). Crimson’s common stock is traded on the NASDAQ under the symbol “CXPO.”
          
On August 5, 2013, the Company announced that Alta had agreed to sell its interest in over 67,000 acres in the Kaybob Duvernay in Alberta, Canada. Proceeds from the sale are expected to be approximately $29 million, net to the Company. The sale is expected to close by October 2013 after satisfaction of a number of closing conditions.

On July 30, 2013, we spud our South Timbalier 17 prospect with the Hercules 202 rig, and on August 22, 2013 we announced a successful well. Estimated costs net to Contango to drill, complete and bring this well to full production status are $12.5 million.
Our Strategy
Our exploration strategy is predicated upon the belief that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers.
We depend primarily upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise and to review prospects submitted by third parties. JEX is experienced and has a successful track record in exploration.
We have concentrated our risk investment capital in the exploration of i) offshore Gulf of Mexico prospects and ii) conventional and unconventional onshore plays. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI drills and operates our offshore prospects. Should we be successful in any of our

1



offshore prospects, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.

Exploration Alliance with JEX
JEX is a private company formed for the purpose of generating offshore and onshore domestic natural gas and oil prospects. Additionally, JEX can generate offshore prospects through our 32.3% owned affiliated company, Republic Exploration LLC ("REX"). In addition to generating new prospects, JEX occasionally evaluates offshore and onshore exploration prospects generated by third-party independent companies for us to purchase. Once we have purchased a prospect from JEX, REX or a third-party, we have historically entered into participation agreements and joint operating agreements, which specify each participant’s working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding royalty interest of up to 3.33% to benefit employees of JEX. See Note 13 - Related Party Transactions for a detailed description of our transactions with JEX and REX.
Offshore Gulf of Mexico Activities
Contango, through its wholly-owned subsidiary, COI and its partially-owned affiliate, REX, conducts exploration activities in the Gulf of Mexico. COI drills and operates our wells in the Gulf of Mexico, as well as attends lease sales and acquires leasehold acreage. Additionally, COI may acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, under farm-out agreements, or similar agreements, with REX, JEX and/or other third parties.

As of June 30, 2013, the Company's offshore production was approximately 64.6 Mmcfed, net to Contango, which consists mainly of seven federal and five state of Louisiana wells in the shallow waters of the Gulf of Mexico. These 12 operated wells produce via the following three platforms:
Eugene Island 11 Platform
Our Company-owned and operated production platform at Eugene Island 11 was designed with a capacity of 500 million cubic feet per day ("Mmcfd") and 6,000 barrels of oil per day ("bopd"). In September 2010 the Company installed a companion platform and two pipelines adjacent to the Eugene Island 11 platform to be able to access alternate markets. These platforms service production from the Company’s five Dutch wells in federal waters and five Mary Rose wells in state of Louisiana waters. From these platforms, gas and condensate can flow to our Eugene Island 63 auxiliary platform via our 20” pipeline, which has been designed with a capacity of 330 Mmcfd and 6,000 bopd, and from there to third-party owned and operated on-shore processing facilities near Patterson, Louisiana, via an ANR pipeline.
Alternatively, gas can flow to the American Midstream pipeline via our 8” pipeline, which has been designed with a capacity of 80 Mmcfed, and from there to a third-party owned and operated on-shore processing facility at Burns Point, Louisiana. Condensate can also flow via an ExxonMobil pipeline to on-shore markets and multiple refineries. As of June 30, 2013, we were producing approximately 54.4 Mmcfed, net to Contango, from these platforms.
Based on current production and decline rates, the Company has determined the need to place its Mary Rose wells on compression in mid-2014, and place its Dutch wells on compression in late-2015. The Company is in the process of designing and building a large turbine type compressor for the platform at an estimated cost of $9.1 million, net to Contango. This compressor will be of sufficient capacity to service all ten of the Company's Dutch and Mary Rose wells. As of June 30, 2013, the Company had incurred approximately $8.3 million to design and build the compressor.

In late-2012, the Company suspended production to the Eugene Island 24 Platform, after installing auxiliary flowlines to enable the Company to redirect its Dutch #1, #2, and #3 wells to Eugene Island 11. In June 2013, the Company removed all remaining flowlines connected to the Eugene Island 24 Platform.
Ship Shoal 263 Platform
Our Company-owned and operated production platform at Ship Shoal 263 was designed with a capacity of 40 Mmcfd and 5,000 bopd. This platform services natural gas and condensate production from our Ship Shoal 263 well, which flows via the Transcontinental Gas Pipeline to onshore processing plants. As of June 30, 2013, we were producing approximately 0.7 Mmcfed, net to Contango, from this platform. We believe 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.
        In March 2013, due to the decline in production and high water levels from our Ship Shoal 263 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

2



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 for this well.
Should we have a discovery at our upcoming Ship Shoal 255 prospect, we will transport the new production through this platform. We have currently classified the platform as unproved properties, as its cost is expected to be recovered through Ship Shoal 255.
Vermilion 170 Platform
Our Company-owned and operated production platform at Vermilion 170 was designed with a capacity of 60 Mmcfd and 2,000 bopd. This platform services natural gas and condensate production from our Vermilion 170 well, which flow via the Sea Robin Pipeline to onshore processing plants. Based on current production and decline rates, the Company has determined the need to place its Vermilion 170 well on compression in early-2014, at a cost of $1.4 million, net to Contango. As of June 30, 2013, the Company had incurred all of the $1.4 million to design, build and install the compressor. As of June 30, 2013, we were producing approximately 9.5 Mmcfed, net to Contango, from this platform.

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. For the fiscal year ended June 30, 2013, we expended approximately $12.0 million on these workover operations, net to the Company.

Other Activities
On July 30, 2013, we spud our South Timbalier 17 prospect in state of Louisiana waters with the Hercules 202 rig, and on August 22, 2013 we announced a successful well. The well was drilled to a total measured depth of approximately 11,400 feet and the wireline logs of the well indicate the presence of hydrocarbons. Estimated reserves and production rates will be dependent upon the liquids content of the formation, which will be better defined once we complete and test the well. We are proceeding with development, including securing production facilities. Estimated costs net to Contango to drill, complete and bring this well to full production status are $12.5 million. Contango has a 75% working interest (53.25% net revenue interest) before payout of all costs, and a 59.3% working interest (42.1% net revenue interest) after payout.
In June 2013, the Company was awarded Eugene Island 23 by the Bureau of Ocean Energy Management ("BOEM"), which was bid at the Central Gulf of Mexico Lease Sale 227 held on March 20, 2013. In July 2013, the Company was awarded Ship Shoal 52 and Ship Shoal 59, representing one prospect, bid at the same Lease Sale 227. The Company bid a total of approximately $1.7 million on these three blocks. We have begun the permitting process and are hopeful to drill these new prospects in the second and third quarter of calendar year 2014.
In July 2012, we spud our Ship Shoal 134 prospect ("Eagle"). On October 19, 2012, we announced that we had reached total depth on Eagle and no commercial hydrocarbons were found. The Company has plugged and abandoned this well. For the fiscal year ended June 30, 2013, we incurred approximately $28.9 million to drill, plug and abandon this well, including approximately $6.3 million in leasehold costs. During the fiscal year ended 2013, we released two leases related to this prospect.
In July 2012, we spud our South Timbalier 75 prospect ("Fang"). On October 30, 2012, we announced that we had reached total depth on Fang and no commercial hydrocarbons were found. The Company has plugged and abandoned this well. For the fiscal year ended June 30, 2013, we incurred approximately $21.1 million to drill, plug and abandon this well, including approximately $0.3 million in leasehold costs. This prospect was a farm-in and the lease was never earned as a result of the dry hole.
Prior Year Activities
In June 2012, the Company successfully acquired six leases at the Central Gulf of Mexico Lease Sale 216/222. The Company bid an aggregate amount of approximately $11 million on East Cameron 124, Eugene Island 31, Eugene Island 260, Ship Shoal 83, Ship Shoal 255 and South Timbalier 110. The Company will have a 100% working interest in these prospects, subject to back-ins if successful. We have submitted an exploration permit for the first of these blocks, Ship Shoal 255, and have budgeted to spud this well in late-2013 at an estimated cost of $22.5 million, net to Contango.
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. As of June 30, 2013, the Company had invested approximately $0.5

3



million in Brazos Area 543, which includes seismic and leasehold costs. During the year ended June 30, 2013, we recognized an impairment expense of $0.2 million related to this lease.
In June 2011, we completed a workover of our Eloise North well at a cost of approximately $1.8 million, net to Contango, which enabled us to continue producing from the lower Rob-L sands. In October 2011, we commenced a workover of our Eloise North well to recomplete the well in the upper Rob-L sands. During the workover, the Company experienced difficulties and unexpected delays due to malfunctioning production tree valves, coiled tubing equipment failures, weather delays, and stuck equipment in the tubing. As a result, the Company plugged the Rob-L sands in January 2012 and recompleted uphole in the Cib-Op sands as our Mary Rose #5 well, at a cost of approximately $0.5 million, net to Contango, based on the new higher ownership percentage and inclusive of a required well cost adjustment. The Mary Rose #5 well began producing on January 26, 2012 and by mid-March 2012 had stopped again. We are currently flowing the well intermittently until we can install compression in 2015.

On December 21, 2011, the Company purchased an additional 3.66% working interest (2.67% net revenue interest) in
Mary Rose #5 (previously Eloise North) for approximately $0.2 million from an existing partner. This purchase brings the Company’s working interest and net revenue interest in Mary Rose #5 to 37.80% and 27.59%, respectively.
In July 2011, we recompleted our Eloise South well uphole in the Cib-Op sands as our Dutch #5 well, at a cost of approximately $5.7 million, net to Contango. The Company has a 47.05% working interest (38.1% net revenue interest) in Dutch #5. In addition to this $5.7 million, the Dutch #5 well owners purchased the Eloise South well bore from the Eloise South well owners (the “Well Cost Adjustment”). The Company invested a net of approximately $2.3 million related to this Well Cost Adjustment.
In September 2010, we drilled our Galveston Area 277L prospect, a wildcat exploration well in the Gulf of Mexico, and determined it was a dry hole. The Company invested approximately $9.5 million, including leasehold costs, to drill, plug and abandon this well.

Republic Exploration LLC
In his capacity as sole manager of the general partner of JEX, Mr. Brad Juneau controls the activities of REX, an entity owned 34.4% by JEX, 32.3% by Contango, and 33.3% by a third party. REX generates and evaluates offshore exploration prospects and has historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specify each participant’s working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding royalty interest ("ORRI") of up to 3.33% to benefit the employees of JEX. The Company proportionately consolidates the results of REX in its consolidated financial statements. In April 2013, REX sold its 25% working interest in West Delta 36 to another partner in that well.
Offshore Properties
Contango, through its wholly-owned subsidiary Contango Operators, Inc. ("COI"), and its partially-owned subsidiary REX, conducts exploration activities in the shallow waters of the Gulf of Mexico. As of June 30, 2013, Contango, through COI and REX, had an interest in 19 offshore leases.
During the fiscal year ended June 30, 2013, the Company acquired nine lease blocks at two Central Gulf of Mexico lease sales, acquired one lease block from an independent oil and gas company, relinquished four lease blocks to the BOEM, and allowed two additional lease blocks to expire in accordance with their terms. During the fiscal year ended June 30, 2012, the Company acquired one lease block at federal lease sale and allowed one lease block to expire. During the fiscal year ended June 30, 2011, the Company purchased one lease block from an independent oil and gas company, relinquished 12 lease blocks to the BOEM, and allowed two additional lease blocks to expire in accordance with their terms.
Producing Properties. The following table sets forth the interests owned by Contango through its affiliated entities in the Gulf of Mexico which were capable of producing natural gas or oil as of June 30, 2013:

4



Area/Block
 
WI    
 
NRI    
 
Status    
Eugene Island 10 #D-1 (Dutch #1)
 
47.05%
 
38.1%
 
Producing
Eugene Island 10 #E-1 (Dutch #2)
 
47.05%
 
38.1%
 
Producing
Eugene Island 10 #F-1 (Dutch #3)
 
47.05%
 
38.1%
 
Producing
Eugene Island 10 #G-1 (Dutch #4)
 
47.05%
 
38.1%
 
Producing
Eugene Island 10 #I-1 (Dutch #5)
 
47.05%
 
38.1%
 
Producing
S-L 18640 #1 (Mary Rose #1)
 
53.21%
 
40.5%
 
Producing
S-L 19266 #1 (Mary Rose #2)
 
53.21%
 
38.7%
 
Producing
S-L 19266 #2 (Mary Rose #3)
 
53.21%
 
38.7%
 
Producing
S-L 18860 #1 (Mary Rose #4)
 
34.58%
 
25.5%
 
Producing
S-L 19266 #3 and S-L 19261 (Mary Rose #5)
 
37.80%
 
27.6%
 
Intermittent
Ship Shoal 263
 
100.00%
 
80.0%
 
Producing
Vermilion 170
 
87.24%
 
68.0%
 
Producing
Leases. The following table sets forth the interests owned by Contango through its related entities in leases in the Gulf of Mexico as of June 30, 2013: 
Area/Block
 
WI    
 
Lease Date    
 
Expiration Date    
East Breaks 369 (Dry Hole)
 
(1)
 
Dec-03
 
Dec-13
South Timbalier 17
 
75.00%
 
(2)
 
(2)
Brazos Area 543
 
100.00%
 
Mar-12
 
Mar-17
East Cameron 124
 
100.00%
 
Sept-12
 
Sept-17
Eugene Island 31
 
100.00%
 
Oct-12
 
Oct-17
Ship Shoal 83
 
100.00%
 
Oct-12
 
(3)
South Timbalier 110
 
100.00%
 
Oct-12
 
Oct-17
Eugene Island 260
 
100.00%
 
Nov-12
 
Nov-17
Ship Shoal 255
 
100.00%
 
Dec-12
 
Dec-17
Eugene Island 23
 
100.00%
 
Jun-13
 
Jun-18
Ship Shoal 52
 
100.00%
 
Jul-13
 
Jul-18
Ship Shoal 59
 
100.00%
 
Jul-13
 
Jul-18
 
(1)
Farm-out. COI retains a 2.41% ORRI
(2)
Successful exploration well. Lease will be held by production.
(3) Submitted paperwork to relinquish in August 2013.

    The Company's Eugene Island 11 block expired in December 2012. This will not impact our ability to operate our facilities located on that block. Operators in the Gulf of Mexico may place platforms and facilities on any location without having to own the lease, provided that permission and proper permits from the Bureau of Safety and Environmental Enforcement (“BSEE”) have been obtained, and Contango obtained such permission and permits. We installed our facilities at Eugene Island 11 because that was the optimal gathering location in proximity to our wells and marketing pipelines, but we were not required to purchase the Eugene Island 11 block to place our facilities at this location.

Onshore Exploration and Properties
Kaybob Duvernay - Alberta, Canada
In April 2011, the Company committed to invest up to $20 million in Alta, a venture that was formed to acquire, explore, develop and operate onshore unconventional oil and natural gas shale assets in North America. As of June 30, 2013, we had invested approximately $14.9 million in Alta to lease over 67,000 acres in the Kaybob Duvernay, a liquids rich shale play in Alberta, Canada. In July 2013, we invested an additional approximately $0.3 million in Alta.
In August 2013, Alta signed a contract to sell its interest in the Kaybob Duvernay. Proceeds from the sale are expected to be approximately $29 million, net to Contango. The sale is expected to close by October after satisfaction of a number of closing conditions. Contango has a 2% interest in Alta and a 5% interest in the Kaybob Duvernay project.


5



Jonah Field - Sublette County, Wyoming

In April 2012, the Company, through its wholly-owned subsidiary, Contaro Company, entered into a Limited Liability Company Agreement (as amended, the “LLC Agreement”) in connection with the formation of Exaro Energy III LLC (“Exaro”). Pursuant to the LLC Agreement, the Company has committed to invest up to $82.5 million in cash in Exaro over the next five years together with other parties for an aggregate commitment of $182.5 million, or a 45% ownership interest in Exaro.
In August 2012, one of the other investors in Exaro exercised its right to assume $15 million of the Company's commitment, which lowered the Company's commitment to $67.5 million and its ownership interest to 37%. As of June 30, 2013, the Company had invested approximately $46.9 million in Exaro.
Exaro has entered into an Earning and Development Agreement with Encana Oil & Gas (USA) Inc. (“Encana”) to provide funding of up to $380 million to continue the development drilling program in a defined area of Encana's Jonah Field asset located in Sublette County, Wyoming. This funding will be comprised of the $182.5 million investment described above, debt, and cash flow from operations. Encana will continue to be the operator of the field and upon investing the full amount of the $380 million, Exaro will have earned 32.5% of Encana's working interest in a defined joint venture area that comprises approximately 5,760 gross acres.

As of June 30, 2013, the Company had invested approximately $46.9 million in Exaro, including $13.1 million that was invested during the fiscal year ended June 30, 2013. As of June 30, 2013, the Exaro-Encana venture had 55 new wells on production, producing at a rate of approximately 10.7 Mmcfed, net to Contango, plus an additional five wells that are either in the completion or fracture stimulation phase. Exaro continues to have three drilling rigs running on this project. For the fiscal year ended June 30, 2013, the Company recognized a gain of approximately $1.2 million, net of tax benefits, as a result of its investment in Exaro. See Note 7 - Investment in Exaro Energy III LLC for a detailed description of our financial condition as a result of this investment.
    
Tuscaloosa Marine Shale
In October 2012, the Company purchased a 25% non-operating working interest in the Crosby 12H-1 well in Wilkinson County, Mississippi, targeting the Tuscaloosa Marine Shale ("TMS"), an oil-focused shale play in central Louisiana and Mississippi. As of June 30, 2013, we had invested approximately $5.8 million in this well, including leasehold costs. This well is operated by Goodrich Petroleum Company LLC ("Goodrich"). For evaluation purposes, we drilled a pilot well, performed an open-hole evaluation and obtained a conventional core over the TMS interval. As of June 30, 2013, the Crosby 12H-1 well was producing at an 8/8ths rate of approximately 350 barrels of oil per day, with cumulative production of approximately 74,000 barrels of oil through June 30, 2013. This well has approximately 6,700 feet of usable lateral and was fracked with 25 stages.

As of June 30, 2013, the Company had invested approximately $9.1 million to lease approximately 24,000 additional acres in the TMS. In July 2013, we elected to participate with less than a 1% working interest in the CMR/Foster Creek 20-7H #1 well, which is operated by Goodrich, as a result of our acreage being pooled into a unit. In August 2013, we elected to participate with approximately a 3% working interest in the Huff 18-7H #1 well, which is also operated by Goodrich, as a result of our acreage being pooled into a unit. We plan to continue to participate in third-party operated wells with a small working interest prior to initiating an operated, high interest drilling program. The data we obtain from these wells will assist us to evaluate our TMS acreage and to develop a plan for drilling and operating future wells.
Jim Hogg County, Texas

During the fiscal year ended June 30, 2013, we expended approximately $1.4 million in an exploration program with a large south Texas mineral owner involving acreage in Jim Hogg County, Texas. We have determined this program to be unsuccessful and will not invest additional funds.
Discontinued Operations
Joint Venture Assets
In October 2009, the Company entered into a joint venture with Patara Oil & Gas LLC ("Patara") to develop Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen, a member of the Company’s board of directors, was the Chief Executive Officer of Patara at the time. In May 2011, the Company sold to Patara its 90% interest and 5% overriding royalty interest in the 21 wells drilled under this joint venture for approximately $36.2 million and recognized a pre-tax loss of

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approximately $0.7 million. These 21 wells had proved reserves of approximately 16.7 Bcfe, net to Contango. The Company accounted for this sale as discontinued operations as of June 30, 2011 and has included the results of the joint venture operations in discontinued operations for all periods presented.
Rexer Assets
In May 2011, the Company sold to Patara its 100% interest in Rexer #1 and 75% interest in Rexer-Tusa #2 for approximately $2.5 million and recognized a pre-tax loss of approximately $0.3 million. The Rexer #1 well had proved reserves of approximately 0.5 Bcfe, net to Contango, while the Rexer-Tusa #2 had not been spud at the time of sale.
The remaining 25% working interest in Rexer-Tusa #2 was sold to Patara in October 2011 for $10,000. The Company has accounted for the sale of Rexer #1 and Rexer-Tusa #2 as discontinued operations as of June 30, 2012 and has included the results of these operations in discontinued operations for all periods presented.
Contango Mining Company
Contango Mining Company (“Contango Mining”), a wholly-owned subsidiary of the Company and the predecessor to Contango ORE, Inc. (“CORE”), was initially formed on October 15, 2009 as a Delaware corporation registered to do business in Alaska for the purpose of engaging in exploration in the State of Alaska for (i) gold and associated minerals and (ii) rare earth elements. Contango Mining held leasehold interests in approximately 675,000 acres from the Tetlin Village Council, the council formed by the governing body for the Native Village of Tetlin, an Alaska Native Tribe, as well as additional acres in unpatented Federal and State of Alaska mining claims for the exploration of gold deposits and associated minerals and rare earth elements (collectively, the “Properties”).
On November 29, 2010, CORE, then another wholly-owned subsidiary of the Company, acquired the assets and assumed the obligations of Contango Mining, including the Properties, in exchange for its common stock which was subsequently distributed to the Company’s stockholders of record as of October 15, 2010 on the basis of one share of common stock for each ten shares of the Company’s common stock then outstanding. No fractional shares were issued, but a cash payment was made to shareholders with less than ten shares based upon the value established for CORE. The Company also contributed $3.5 million in cash to CORE immediately prior to the distribution. The Company no longer has an ownership in CORE and has included its results of operations and gain on disposition in discontinued operations for all periods presented.
Marketing and Pricing
The Company currently derives its revenue principally from the sale of natural gas and oil. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas and oil prices. The Company currently sells its natural gas and oil on the open market at prevailing market prices. Major purchasers of our natural gas, oil and natural gas liquids for the fiscal year ended June 30, 2013 were ConocoPhillips Company (53%), Shell Trading US Company (21%), Enterprise Products Operating LLC (9%) and Exxon Mobil Oil Corporation (8%). Market prices are dictated by supply and demand, and the Company cannot predict or control the price it receives for its natural gas and oil. The Company has outsourced the marketing of its offshore natural gas and oil production volume to a privately-held third party marketing firm.
Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:
 
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
Political conditions in the Middle East and other natural gas and oil producing regions
The level of LNG imports
Domestic and foreign governmental regulations
Special taxes on production
The loss of tax credits and deductions
Competition
The Company competes with numerous other companies in all facets of its business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise.


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Governmental Regulations
Federal Income Tax. Federal income tax laws significantly affect the Company’s operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development costs” and to claim depletion on a portion of its domestic natural gas and oil properties and to claim a manufacturing deduction based on qualified production activities.
Environmental Matters. Domestic natural gas and oil operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) also known as the “Super Fund Law”. The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.
The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether financial responsibility requirements under any OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.
The Company’s operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general. Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s operations are also subject to additional federal, state and local laws and regulations relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.
Impact of Deepwater Horizon Incident. In 2010, the US Department of the Interior issued new rules designed to improve drilling and workplace safety, and various Congressional committees began pursuing legislation to greater regulate drilling activities and increase liability, in response to the Deepwater Horizon Incident. In January 2011, various legislative committees released their reports, recommending that the federal government require additional regulation and an increase in liability caps.
Additional regulatory review, slower permitting processes and increased oversight have resulted in longer development cycle time for our Gulf of Mexico projects. Cycle time is the length of time it takes for a project to progress from developing a prospect to beginning production, and longer development cycle times could result in lower rates of return on our investments.
Increased regulation impacting our activities in the Gulf of Mexico could result in extensive efforts to ensure compliance and incremental compliance costs. A significant delay or cancellation of our planned Gulf of Mexico exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on production over time. To the extent current exploration activities are significantly delayed, a gap could occur in our long-term production profile with a negative impact on our operating results and cash flows.

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Additional legislation or regulation is being discussed which could require each company doing business in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility ("COFR"), a certificate required under the Oil Pollution Act of 1990 which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill. These and/or other legislative or regulatory changes could require us to maintain a certain level of financial strength and may reduce our financial flexibility.

Future legislation or regulation is also likely to result in substantial increases in civil or criminal fines or sanctions. Such fines or sanctions could well exceed the actual cost of containment and cleanup associated with a well incident or spill.
Other Laws and Regulations. Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.
The BOEM administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The BOEM holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the BOEM changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea floor. The BOEM requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. As an operator, the Company is required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities.
The Federal Energy Regulatory Commission (the “FERC”) has embarked on wide-ranging regulatory initiatives relating to natural gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC’s rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the natural gas prices received by the Company for the sale of its production, the FERC’s actions may have an impact on the Company. However, the impact should not be substantially different for the Company than it would be for other similarly situated natural gas producers and sellers.
Risk and Insurance Program
In accordance with industry practice, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from significant losses resulting from damages to, or the loss of, physical assets or loss of human life, and liability claims of third parties, including such occurrences as well blowouts and weather events that result in oil spills and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.
We expect the future availability and cost of insurance to be impacted by the Deepwater Horizon Incident. Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor the expected regulatory and legislative response and its impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can afford considering the cost of insurance, against the potential and magnitude of disruption to our operations and cash flows.

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We carry insurance protection for our net share of any potential financial losses occurring as a result of events such as the Deepwater Horizon Incident. As a result of the incident, we have increased our well control coverage to $100 million on certain wells, which covers control of well, pollution cleanup and consequential damages. We have increased our general liability coverage to $150 million, which covers pollution cleanup, consequential damages coverage, and third party personal injury and death. We have also increased our Oil Spill Financial Responsibility coverage to $150 million, which covers additional pollution cleanup and third party claims coverage.
Health, Safety and Environmental Program. The Company’s Health, Safety and Environmental (“HS&E”) Program is supervised by an operating committee of senior management to insure compliance with all state and federal regulations. In addition, to support the operating committee, we have contracted with J. Connors Consulting (“JCC”) to manage our regulatory process. JCC is a regulatory consulting firm specializing in the offshore Gulf of Mexico regulatory process, preparation of incident response plans, safety and environmental services and facilitation of comprehensive oil spill response training and drills to oil and gas companies and pipeline operators.
For our Gulf of Mexico operations, we have a Regional Oil Spill Plan in place with the BOEM. Our response team is trained annually and is tested through annual spill drills given by the BOEM. In addition, we have in place a contract with O’Brien’s Response Management (“O’Brien’s”). O’Brien’s maintains a 24/7 manned incident command center located in Slidell, LA. Upon the occurrence of an oil spill, the Company’s spill program is initiated by notifying O’Brien’s that we have an emergency. While the Company would focus on source control of the spill, O’Brien’s would handle all communication with state and federal agencies as well as U.S. Coast Guard notifications.
If a spill were to occur, we have contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs. CGA specializes in onsite control and cleanup and is on 24 hour alert with equipment currently stored at six bases (Ingleside and Galveston, TX and Lake Charles, Houma, Venice and Pascagoula, LA), and is opening new sites in Leeville, Morgan City and Harvey, LA. The CGA equipment stockpile is available to serve member oil spill response needs including blowouts; open seas, near shore and shallow water skimming; open seas and shoreline booming; communications; dispersants; boat spray systems to apply dispersants; wildlife rehabilitation; and a forward command center. CGA has retainers with an aerial dispersant company and a company that provides mechanical recovery equipment for spill responses.
In addition to being a member of CGA, the Company has contracted with Wild Well Control for source control at the wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting, well control, engineering, and training services.
Safety and Environmental Management System. The Company has developed and implemented a Safety and Environmental Management System (“SEMS”) to address oil and gas operations in the Outer Continental Shelf (“OCS”), as required by the BSEE. Our SEMS program identifies, addresses, and manages safety, environmental hazards, and its impacts during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. The Company has established goals, performance measures, training, accountability for its implementation, and provides necessary resources for an effective SEMS, as well as reviews the adequacy and effectiveness of the SEMS program. Facilities must be designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes, consensus standards, and all applicable governmental regulations. We have contracted with Island Technologies Inc. to manage our SEMS program for production operations.
The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may force us to shut-in our Gulf of Mexico operations.
Employees
We have ten employees, all of whom are full time. The Company outsources its human resources function to Insperity, Inc. and all of the Company’s employees are co-employees of Insperity, Inc. In addition to our employees, we use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We are dependent on JEX for prospect generation, evaluation and prospect leasing. As a working interest owner, we rely on outside operators to drill, produce and market our natural gas and oil for our onshore prospects and certain offshore prospects where we are a non-operator. In the offshore prospects where we are the operator, we currently rely on drilling contractors to drill and rely on independent contractors to produce and market our natural gas and oil. In addition, we utilize the services of independent contractors to perform field and on-site drilling and production operation services and independent third party engineering firms to evaluate our reserves.



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Directors and Executive Officers
The following table sets forth the names, ages and positions of our directors and executive officers:
 
Name
 
Age    
 
Position
Joseph J. Romano
 
60

 
Chairman, President and Chief Executive Officer
Sergio Castro
 
44

 
Vice President, Chief Financial Officer, Treasurer and Secretary
Yaroslava Makalskaya
 
44

 
Vice President, Chief Accounting Officer and Controller
Marc L. Duncan
 
60

 
Senior Vice President - Engineering
Charles A. Cambron (1)
 
46

 
Vice President - Drilling
Michael J. Autin
 
54

 
Vice President - Production
B.A. Berilgen
 
65

 
Director
Jay D. Brehmer
 
48

 
Director
Brad Juneau
 
53

 
Director
Charles M. Reimer
 
68

 
Director
Steven L. Schoonover
 
68

 
Director
(1) Resigned effective August 22, 2013
Joseph J. Romano. Mr. Romano was elected Director, President and Chief Executive Officer of Contango in November 2012, a few months after the Company's founder, Mr. Kenneth R. Peak, received a medical leave of absence. Upon Mr. Peak's passing in April 2013, Mr. Romano was also elected Chairman. Mr. Romano assisted Mr. Peak in founding the Company in 1999. Mr. Romano has worked in the energy industry since 1977. Mr. Romano served as Senior Vice President and Chief Financial Officer of Zilkha Energy Company until its sale in 1998 and served as President and Chief Executive Officer of Zilkha Renewable Company until its sale in 2005. He currently also serves in various capacities in Zilkha-affiliated companies. He has been President and Chief Executive Officer of Olympic Energy Partners since 2005, which owns working interests in Contango's Dutch and Mary Rose fields, has been President and Chief Executive Officer of ZZ Biotech since 2006, and has been Vice President and Director of Laetitia Vineyards and Winery since 2000. Mr. Romano also served as Chief Financial Officer, Treasurer and Controller of Texas International Company from 1986 through 1988 and its Treasurer and Controller from 1982 through 1985. Prior to 1982, Mr. Romano spent five years working in the Worldwide Energy Group of the First National Bank of Chicago. He earned his BA in Economics from the University of Wisconsin in Eau Claire and an MBA from the University of Northern Illinois.
Sergio Castro. Mr. Castro joined Contango in March 2006 as Treasurer and was appointed Vice President, Treasurer and Secretary in April 2006 and Chief Financial Officer in June 2010. Prior to joining Contango, Mr. Castro spent two years (April 2004 to March 2006) as a consultant for UHY Advisors TX, LP. From January 2001 to April 2004, Mr. Castro was a lead credit analyst for Dynegy Inc. From August 1997 to January 2001, Mr. Castro worked as an auditor for Arthur Andersen LLP, where he specialized in energy companies. Mr. Castro was honorably discharged from the U.S. Navy in 1993 as an E-6, where he served onboard a nuclear powered submarine. Mr. Castro received a BBA in Accounting in 1997 from the University of Houston, graduating summa cum laude. Mr. Castro is a CPA and a Certified Fraud Examiner.
Yaroslava Makalskaya. Ms. Makalskaya joined Contango in March 2010 and was appointed Vice President, Chief Accounting Officer and Controller in June 2010. Ms. Makalskaya has over 20 years of experience in accounting and finance, including 13 years in public accounting. Prior to joining Contango, Ms. Makalskaya was a director in the Transaction Services practice at PricewaterhouseCoopers, where she assisted clients with M&A transactions as well as advised clients with complex accounting and financial reporting issues. Prior to July 2008 Ms. Makalskaya was a Senior Manager in the audit practices of PricewaterhouseCoopers and Arthur Andersen, where her clients included many US and international companies in energy, utilities, mining and other sectors. Ms. Makalskaya holds a MS degree in Economics from Novosibirsk State University in Russia. Ms. Makalskaya is a CPA.  
Marc L. Duncan. Mr. Duncan joined Contango in June 2005 as President and Chief Operating Officer of Contango Operators, Inc. and was appointed President and Chief Operating Officer of Contango Oil & Gas Company in October 2006 until December 2010. In December 2010 Mr. Duncan was appointed as the Company’s Safety, Environmental and Regulatory Compliance Officer (“SEARCO”) and Vice Chairman of the Operating Committee. In December 2012, Mr. Duncan was appointed Senior Vice President - Engineering. Mr. Duncan has approximately 40 years of experience in the energy industry and has held a variety of domestic and international engineering and senior-level operations management positions relating to

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natural gas and oil exploration, project development, and drilling and production operations. Prior to joining Contango, Mr. Duncan served as Chief Operating Officer of USENCO International, Inc. and its subsidiaries and affiliates in China and Ukraine from February 2000 to July 2004 and as a senior project and drilling engineer for Hunt Oil Company from July 2004 to June 2005. He holds an MBA in Engineering Management from the University of Dallas, an MEd from the University of North Texas and a BS in Science and Education from Stephen F. Austin University.
Charles A. Cambron. Mr. Cambron joined Contango in August 2010 as Vice President of Drilling. Mr. Cambron has over 20 years of experience in the Gulf of Mexico oil and gas industry. Most recently he was employed by Applied Drilling Technology, Inc. (ADTI) as an Operations Manager from August 1995 until August 2010. He also held various positions in engineering and offshore supervision over a 15 year period. Prior to ADTI, Mr. Cambron began his career with Rowan Petroleum, Inc. as a Drilling Engineer working in both the Gulf of Mexico and North Sea. Mr. Cambron received a BS degree in Petroleum Engineering from the University of Oklahoma in 1991.
Michael J. Autin. Mr. Autin joined Contango in May 2012 as Vice President of Production. Mr. Autin has approximately 35 years of experience in the petroleum industry including the Gulf of Mexico and U.S onshore shale. He has held various positions including Production Manager, HSE Manager and Offshore Installation Manager. Prior to joining Contango, Mr. Autin was employed by BHP Billiton since October 2000, where most recently he was Gulf of Mexico Operations Manager, Field Manager and Operations Advisor. Mr. Autin attended Nicholls State University where he studied petroleum, safety and business. He received a BS degree in 1986.
B.A. Berilgen. Mr. Berilgen was appointed a director of Contango in July 2007. Mr. Berilgen has served in a variety of senior positions during his 40 year career. In February 2013 he became the managing director Most recently, he became Chief Executive Officer of Patara Oil & Gas LLC in April 2008. Prior to that he was Chairman, Chief Executive Officer and President of Rosetta Resources Inc., a company he founded in June 2005, until his resignation in July 2007, and then he was an independent consultant from July 2007 through April 2008. Mr. Berilgen was also previously the Executive Vice President of Calpine Corp. and President of Calpine Natural Gas L.P. from October 1999 through June 2005. In June 1997, Mr. Berilgen joined Sheridan Energy, a public oil and gas company, as its President and Chief Executive Officer. Mr. Berilgen attended the University of Oklahoma, receiving a BS in Petroleum Engineering in 1970 and a MS in Industrial Engineering / Management Science.
Jay D. Brehmer. Mr. Brehmer has been a director of Contango since October 2000. Mr. Brehmer is a co-founding partner of Southplace, LLC, a provider of private-company middle-market corporate finance advisory services. Mr. Brehmer founded Southplace, LLC in November 2002. In August 2004, Mr. Brehmer became Managing Director of Houston Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank, while still retaining his membership in Southplace, LLC. Mr. Brehmer resigned from Houston Capital Advisors LP in January 2008 and is currently associated with Southplace, LLC in a full-time capacity. From May 1998 until November 2002, Mr. Brehmer was responsible for structured-finance energy related transactions at Aquila Energy Capital Corporation. Prior to joining Aquila, Mr. Brehmer founded Capital Financial Services, which provided mid-cap companies with strategic merger and acquisition advice coupled with prudent financial capitalization structures. Mr. Brehmer holds a BBA from Drake University in Des Moines, Iowa.

Brad Juneau. Mr. Juneau, was elected a director of the Company in April 2012. Mr. Juneau is the sole manager of the general partner of JEX. Prior to forming JEX in 1998, Mr. Juneau served as senior vice president of exploration for Zilkha Energy Company from 1987 to 1998. Prior to joining Zilkha Energy Company, Mr. Juneau served as staff petroleum engineer with Texas International Company for three years, where his principal responsibilities included reservoir engineering, as well as acquisitions and evaluations. Prior to that, he was a production engineer with Enserch Corporation in Oklahoma City. Additionally, as a co-founder of CORE, Mr. Juneau was elected President and Chief Executive Officer of CORE in December 2012, and appointed Chairman of CORE in April 2013. Mr. Juneau holds a BS degree in petroleum engineering from Louisiana State University.

Charles M. Reimer. Mr. Reimer was elected a director of Contango in November 2005. Mr. Reimer is President of Freeport LNG Development, L.P., and has experience in exploration, production, liquefied natural gas (“LNG”) and business development ventures, both domestically and abroad. From 1986 until 1998, Mr. Reimer served as the senior executive responsible for the VICO joint venture that operated in Indonesia, and provided LNG technical support to P. T. Badak. Additionally, during these years he served, along with Pertamina executives, on the board of directors of the P.T. Badak LNG plant in Bontang, Indonesia. Mr. Reimer began his career with Exxon Company USA in 1967 and held various professional and management positions in Texas and Louisiana. Mr. Reimer was named President of Phoenix Resources Company in 1985 and relocated to Cairo, Egypt, to begin eight years of international assignments in both Egypt and Indonesia. Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President and Chief Executive Officer of Cheniere Energy, Inc.

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Steven L. Schoonover. Mr. Schoonover was elected a director of Contango in November 2005. Mr. Schoonover was most recently Chief Executive Officer of Cellxion, L.L.C., a company he founded in September 1996 and sold in September 2007, which specialized in construction and installation of telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. Since the sale in September 2007, Mr. Schoonover continues to serve as a consultant to the current management team of Cellxion, L.L.C. From 1990 until its sale in November 1997 to Telephone Data Systems, Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-service cellular telephone company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with two different companies, Entrepreneur of the Year, sponsored by Ernst & Young, Inc Magazine and USA Today.
Mr. Kenneth R. Peak, the Company's founder, was Chairman of the Board, Chief Executive Officer and a director of the Company since its inception in 1999. In August 2012, Mr. Peak received a medical leave of absence from his responsibilities at the Company. Mr. Peak passed away in April 2013. Mr. Peak also co-founded Contango ORE, Inc. in 2010, and from its inception until August 2012 was its Chairman and Chief Executive Officer. Mr. Peak entered the energy industry in 1973 as a commercial banker and held a variety of financial and executive positions in the oil and gas industry prior to founding Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University in 1967, and an MBA from Columbia University in 1972. He was also a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to exploration and production companies in North America.
Directors of Contango serve as members of the board of directors until the next annual stockholders meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of Contango are elected by the board of directors and hold office until their successors are chosen and qualified, until their death or until they resign or have been removed from office. All corporate officers serve at the discretion of the board of directors. Each non-employee director of the Company receives a quarterly retainer of $28,000 payable in cash, with no stock option or common stock grants. There are no additional payments for meetings attended or being chairman of a committee. During fiscal year 2011, each outside director of the Company received a quarterly retainer of $20,000 payable in cash, with no stock option or common stock grants. There were no additional payments for meetings attended or being chairman of a committee. There are no family relationships between any of our directors or executive officers.
Corporate Offices
We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. In November 2010, the Company expanded its office space and extended its office lease agreement through February 29, 2016.
Code of Ethics
We adopted a Code of Ethics for senior management in December 2002, which was updated and adopted by the Company's Board of Directors in May 2012. A copy of our Code of Ethics is filed as an exhibit to this Form 10-K and is also available on our website at www.contango.com.
Available Information
You may read and copy all or any portion of this annual report on Form 10-K, our quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, without charge at the office of the Securities and Exchange Commission (the “SEC”) in Public Reference Room, 100 F Street NE, Washington, DC, 20549. Information regarding the operation of the public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330. In addition, filings made with the SEC electronically are publicly available through the SEC's website at http://www.sec.gov, and at our website at http://www.contango.com. This annual report on Form 10-K, including all exhibits and amendments, has been filed electronically with the SEC.
Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss.



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RISK FACTORS RELATING TO CONTANGO
We have no ability to control the market price for natural gas and oil. Natural gas and oil prices fluctuate widely, and a substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on the business, the results of operations and financial condition of the Company.

Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital. We do not expect to hedge our production to protect against price decreases. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:

• Overall economic conditions.
• The domestic and foreign supply of natural gas and oil.
• The level of consumer product demand.
• Adverse weather conditions and natural disasters.
• The price and availability of competitive fuels such as LNG, heating oil and coal.
• Political conditions in the Middle East and other natural gas and oil producing regions.
• The level of LNG imports and any LNG exports.
• Domestic and foreign governmental regulations.
• Special taxes on production.
• Access to pipelines and gas processing plants.
• The loss of tax credits and deductions.

A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period would negatively affect us.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and is expected to continue to require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, additional financing may not be available to us on acceptable terms, if at all. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

It is difficult to quantify the amount of financing we may need to fund our planned growth. The amount of funding we may need in the future depends on various factors such as:

• Our financial condition.
• The prevailing market price of natural gas and oil.
• The type of projects in which we are engaging.
• The lead time required to bring any discoveries to production.

We assume additional risk as operator in drilling high pressure and high temperature wells in the Gulf of Mexico.

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. Drilling activities are subject to numerous risks, including the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs,
drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and

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fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or we may not recover all or any of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

We rely on third-party operators to operate and maintain some of our production platforms, pipelines and processing facilities and, as a result, we have limited control over the operations of such facilities. The interests of an operator may differ from our interests.

We depend upon the services of third-party operators to operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and financial condition. Also, the interest of an operator may differ from our interests.

Repeated production shut-ins can possibly damage our well bores.

Our well bores are required to be shut-in from time to time due to a variety of issues, including a combination of weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with our condensate production at our Eugene Island 11 platform, as well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessary from time to time to upgrade and improve the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to negatively impacting our near term revenues and cash flow, repeated production shut-ins may damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells.

Concentrating our capital investment in the Gulf of Mexico increases our exposure to risk.

The vast majority of our capital investments is primarily focused in offshore Gulf of Mexico exploration prospects, which may result in a total loss of our investment. Furthermore, even our productive wells may not result in profitable operations. Gulf of Mexico exploration efforts have been undertaken for over 60 years and remaining prospects are at deeper horizons that are more expensive to drill and often in much deeper water depths. Accordingly, as a result, a number of companies have shifted their focus to onshore “shale plays.” The Company’s continuing focus on the Gulf of Mexico will result in significant dry hole costs, perhaps in excess of $30 million for one well, which significantly concentrates and increases our risk profile.

Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows will be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities of our reserves.

There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves shown in this report.


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In order to prepare these estimates, our independent third-party petroleum engineers must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in a reserve report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control and may prove to be incorrect over time. As a result, our estimates may require substantial upward or downward revisions if subsequent drilling, testing and production reveal different results. Furthermore, some of the producing wells included in our reserve report have produced for a relatively short period of time. Accordingly, some of our reserve estimates are not based on a multi-year production decline curve and are calculated using a reservoir simulation model together with volumetric analysis. Any downward adjustment could indicate lower future production and thus adversely affect our financial condition, future prospects and market value.

The Company’s reserves and revenues are primarily concentrated in one field.

Approximately 89.6% of our reserves are assigned to our Dutch and Mary Rose field which has ten producing well bores concentrated primarily in one reservoir and is producing through one production platform. Reserve assessments based on only ten well bores in one reservoir are subject to significantly greater risk of being shut-in for a variety of weather, platform and pipeline difficulties. In addition, the risk of a downward revision in our reserve estimates is also greater.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineer.

We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to us by our independent third-party reservoir engineer. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineer in our financial planning. If the reports of the outside reservoir engineer prove to be inaccurate, we may make misjudgments in our financial planning.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success largely depends on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the significant risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• Unexpected drilling conditions.
• Blowouts, fires or explosions with resultant injury, death or environmental damage.
• Pressure, temperature or other irregularities in formations.
• Equipment failures and/or accidents caused by human error.
• Tropical storms, hurricanes and other adverse weather conditions.
• Compliance with governmental requirements and laws, present and future.
• Shortages or delays in the availability of drilling rigs and the delivery of equipment.
• Our turnkey drilling contracts reverting to a day rate contract or our turnkey contractor electing to terminate the
turnkey contract would significantly increase the cost and risk to the Company.
• Problems at third-party operated platforms, pipelines and gas processing facilities over which we have no control.
Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations. In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.

Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.

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A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. All of the Company’s operations in the Gulf of Mexico shelf are in water depths of less than 300 feet and less than 50 miles from the coast. Such proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system in the event of released condensate.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.
Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions in the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries including countries in the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.
The Environmental Protection Agency (the “EPA”) has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules at a subsequent date.
Several decisions have been issued by courts that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the natural gas and condensate that we produce.

The natural gas and oil business involves many operating risks that can cause substantial losses and our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

The natural gas and oil business involves a variety of operating risks, including:

• Blowouts, fires and explosions.
• Surface cratering.
• Uncontrollable flows of underground natural gas, oil or formation water.
• Natural disasters.
• Pipe and cement failures.
• Casing collapses.
• Stuck drilling and service tools.
• Reservoir compaction.
• Abnormal pressure formations.
• Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.
• Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelines and gas
processing plants over which we have no control.
• Repeated shut-ins of our well bores could significantly damage our well bores.
• Required workovers of existing wells that may not be successful.

If any of the above events occur, we could incur substantial losses as a result of:


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• Injury or loss of life.
• Reservoir damage.
• Severe damage to and destruction of property or equipment.
• Pollution and other environmental damage.
• Clean-up responsibilities.
• Regulatory investigations and penalties.
• Suspension of our operations or repairs necessary to resume operations.

Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.

If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Not hedging our production may result in losses.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if our production should be shut-in during a period when NYMEX natural gas prices increase, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.

All of our natural gas and oil is transported through gathering systems, pipelines and processing plants. Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.

We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our exploration and development of the lease site.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of JEX and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However, such deficiencies may not have been cured by the operator of such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than many of our competitors.


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We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Many of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future depends on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.

Proposed United States federal budgets and pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

The federal administration has released repeated budget proposals over the past few years which include numerous proposed tax changes. The proposed budgets and legislation would repeal many tax incentives and deductions that are currently used by oil and gas companies in the United States and impose new taxes. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law, taxes on the E&P industry would increase, which could have a negative impact on our results of operations and cash flows. Although these proposals initially were made in 2009, none have become law. It is still, however, the federal administration’s stated intention to enact legislation to repeal tax incentives and deductions and impose new taxes on oil and gas companies.

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment. Failure to comply with such rules and regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations:

• Require that we obtain permits before commencing drilling.
• Restrict the substances that can be released into the environment in connection with drilling and production
activities.
• Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas.
• Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could
be changed and any such changes could have an adverse effect on our business and results of operations.

Our operations in the Gulf of Mexico have been and may continue to be adversely affected by changes in laws and regulations which have occurred and are expected to continue to occur as a result of the Deepwater Horizon Incident.

As a result of the Deepwater Horizon Incident in 2010, the Department of the Interior issued additional safety and performance standards as well as rigorous monitoring and testing requirements for offshore drilling. In addition, various Congressional committees began pursuing legislation to regulate drilling activities, establish safety requirements and increase liability for oil spills.

We continue to monitor legislative and regulatory developments. However, the full legislative and regulatory response to the incident is not fully known. An expansion of safety and performance regulations or an increase in liability for drilling activities will have one or more of the following impacts on our business:

• Increase the costs of drilling exploratory and development wells.

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• Cause delays in, or preclude, the development of projects in the Gulf of Mexico.
• Result in longer time periods to obtain permits.
• Result in higher operating costs.
• Increase or remove liability caps for claims of damages from oil spills.
• Limit our ability to obtain additional insurance coverage on commercially reasonable terms to protect against any
increase in liability.

Any of the above factors may result in a reduction of our cash flows, profitability, and the fair value of our properties.

Current regulatory requirements and permitting procedures have significantly delayed our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the Deepwater Horizon Incident in the Gulf of Mexico, a series of Notices to Lessees (“NTLs”) were issued which imposed new regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new regulatory requirements include the following:

• The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental
impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response
requirements.
• The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well
design, construction and flow intervention processes, and also requires certifications of compliance from senior
corporate officers.
• The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of
drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and
their components, including shear and pipe rams.
The Workplace Safety Rule, which requires operators to have a comprehensive SEMS in order to reduce human and
organizational errors as root causes of work-related accidents and offshore spills.

Since the adoption of these new regulatory requirements, BOEM has been taking much longer periods of time to review and approve permits for new wells. Due to the extremely slow pace of permit review and approval, the BOEM may now take four months or longer to approve applications for drilling permits that were previously approved in less than 30 days. The new rules also increase the cost of preparing each permit application and will increase the cost of each new well.

The BSEE has implemented much more stringent controls and reporting requirements that if not followed, could result in significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.

The BSEE is the federal agency responsible for overseeing the safe and environmentally responsible development of energy and mineral resources on the OCS. They are responsible for leading the most aggressive and comprehensive reforms to offshore oil and gas regulation and oversight in U.S. history. Their reforms have tightened requirements for everything from well design and workplace safety to corporate accountability. One of the many reforms includes implementing a SEMS program. This program requires operators to identify, address, and manage safety and environmental hazards during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. Facilities must be designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes, consensus standards, and all
applicable governmental regulations. Failure to comply with the SEMS program may force us to cease operations in the Gulf of Mexico.

Additionally, the OCS Lands Act authorizes and requires the BSEE to provide for both an annual scheduled inspection and a periodic unscheduled (unannounced) inspection of all oil and gas operations on the OCS. In addition to examining all safety equipment designed to prevent blowouts, fires, spills, or other major accidents, the inspections focus on pollution, drilling operations, completions, workovers, production, and pipeline safety. Upon detecting a violation, the inspector issues an Incident of Noncompliance ("INC") to the operator and uses one of two main enforcement actions (warning or shut-in), depending on the severity of the violation. If the violation is not severe or threatening, a warning INC is issued. The warning INC must be corrected within a reasonable amount of time specified on the INC. The shut-in INC may be for a single component (a portion of the facility) or the entire facility. The violation must be corrected before the operator is allowed to resume the activity in question.

In addition to the enforcement actions specified above, the BSEE can assess a civil penalty of up to $35,000 per violation per day if: 1) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or 2)

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the violation resulted in a threat of serious harm or damage to human life or the environment. Operators with excessive INCs may be required to cease operations in the Gulf of Mexico.


Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

It is customary in our industry to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. We intend to use hydraulic fracturing as a means to increase the productivity of the onshore wells that we drill and complete.

The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states, including Pennsylvania, Texas, Colorado, Montana, New Mexico and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Additionally, the EPA has asserted federal regulatory authority over hydraulic fracturing activities involving diesel fuel (specifically, when diesel fuel is utilized in the stimulation fluid) under the Safe Drinking Water Act and is completing the process of drafting guidance documents related to this newly asserted regulatory authority. There are also certain governmental reviews either underway or being proposed that focus on shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate such activities. The EPA has published proposed New Source Performance Standards ("NSPS") and National Emissions Standards for Hazardous Air Pollutants ("NESHAP") that, if adopted as proposed, would amend existing NSPS and NESHAP standards for oil and gas facilities as well as create new NSPS standards for oil and gas production, transmission
and distribution facilities. The EPA has also proposed regulations focused on reducing emissions of certain air pollutants by the oil and gas industry, including volatile organic compounds, sulfur dioxide and certain air toxics.

Certain environmental and other groups have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or local laws or regulations will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

We do not control the activities on properties we do not operate.

Other companies may from time to time drill, complete and operate properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

• Timing and amount of capital expenditures.
• The operator’s expertise and financial resources.
• Approval of other participants in drilling wells.
• Selection of technology.

We are highly dependent on our management team, JEX, our exploration partners and third-party consultants and engineers, and any failure to retain the services of such parties could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies.

The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineers and other professionals engaged by us. We are highly dependent on the services provided by JEX. The loss of key members of our management team, JEX or other highly qualified technical professionals could adversely affect our ability to effectively

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manage our overall operations or successfully execute current or future business strategies which may have a material adverse effect on our business, financial condition and operating results.


Acquisition prospects are difficult to assess and may pose additional risks to our operations.
We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:

• Recoverable reserves.
• Exploration potential.
• Future natural gas and oil prices.
• Operating costs.
• Potential environmental and other liabilities and other factors.
• Permitting and other environmental authorizations required for our operations.
In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:

• Problems integrating the purchased operations, personnel or technologies.
• Unanticipated costs.
• Diversion of resources and management attention from our exploration business.
• Entry into regions or markets in which we have limited or no prior experience.
• Potential loss of key employees of the acquired organization.

Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely affect a potential acquisition by third-parties that may ultimately be in the financial interests of our stockholders.

Our Certificate of Incorporation, Bylaws and the Delaware General Corporation Law contain provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of inhibiting fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts, preventing changes in our management or limiting the price that investors may be willing to pay for shares of common stock.

RISK FACTORS RELATED TO THE MERGER
The transactions contemplated by the Merger Agreement are subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all.
The Merger is subject to a number of conditions beyond Contango's and Crimson's control that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether and when these other conditions will be satisfied. Any delay in completing the Merger could cause us not to realize some or all of the synergies that we expect to achieve if the Merger is successfully completed within its expected time frame.
Failure to complete the Merger could negatively impact our future business and financial results.
We cannot make any assurances that we will be able to satisfy all of the conditions to the Merger or succeed in any litigation brought in connection with the Merger. If the Merger is not completed, our financial results may be adversely affected and we will be subject to several risks, including but not limited to:
Being required to pay a termination fee of $28 million under certain circumstances provided in the Merger Agreement;
Payment of costs relating to the Merger, such as legal, accounting, financial advisor and printing fees, whether or not
the Merger is completed;
Having had the focus of our management on the Merger instead of on pursuing other opportunities that could have

22



been beneficial to the Company; and
Being subject to litigation related to any failure to complete the Merger.

If the Merger is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock prices.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees.
We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. The combined company's success after the Merger will depend in part upon the ability of Contango and Crimson to retain key management personnel and other key employees. Current and prospective employees of Contango and Crimson may experience uncertainty about their roles within the combined company following the Merger, which may have an adverse effect on the ability of each of Contango and Crimson to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees of Contango and Crimson to the same extent that Contango and Crimson have previously been able to attract or retain their own employees.

The failure to integrate successfully the businesses of Contango and Crimson in the expected time frame would adversely affect the combined company's future results following the Merger.
The Merger involves the integration of two companies that have previously operated independently. The success of the Merger will depend, in large part, on the ability of the combined company following the Merger to realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from combining the businesses of Contango and Crimson. To realize these anticipated benefits, the businesses of Contango and Crimson must be successfully integrated. This integration will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company not achieving the anticipated benefits of the Merger.
Our stockholders will have a reduced ownership and voting interest in the combined company after the Merger.
If the Merger occurs, each Contango stockholder will remain a stockholder of Contango with a percentage ownership of the combined company that will be smaller than the stockholder's percentage of Contango prior to the Merger. As a result of these reduced ownership percentages, Contango stockholders will have less voting power in the combined company than they now have with respect to Contango.

The future results of the combined company could suffer if the combined company does not effectively manage its expanded operations following the Merger.

Following the Merger, the size of the business of the combined company will increase significantly beyond the current size of either Contango's or Crimson's business. The combined company's future success depends, in part, upon its ability to manage this expanded business, which could pose challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements and other benefits currently anticipated from the Merger.

The combined company's debt may limit its financial flexibility.
Contango currently has no amounts outstanding under its credit facility and traditionally has carried minimal balances of long-term debt. Following the Merger, it is expected that the combined company will have more long-term debt. In addition, the combined company may incur additional debt from time to time in connection with the financing of operations, acquisitions, recapitalizations and refinancings. The level of the combined company's debt could have several important effects on future operations, including, among others:
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;

23



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.

Item 1B. Unresolved Staff Comments
None
Item 2. Properties

Development, Exploration and Acquisition Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:
 
 
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
$
75,574


$
17,289


$
66,164


The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:
 
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

 
$

Drilling Activity
The following table shows our exploratory and developmental drilling activity for the periods indicated. The Company did not drill any wells during the fiscal year ended June 30, 2012. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells.
 
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


24



 
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

For the fiscal year ended June 30, 2011, of the nine productive onshore development wells listed above, one relates to the Rexer-Tusa #2 well and eight relate to our joint venture wells with Patara. The Rexer #1 well and joint venture wells with Patara were sold in May 2011 while the sale of the Rexer-Tusa #2 was completed in October 2011. These wells are classified as discontinued operations in our financial statements for all periods presented.
Exploration and Development Acreage
Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2013:
 
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).
Included in the Offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango has in the offshore acreage owned by REX. The above table includes our 32.3% interest in REX’s 625 net developed acres.
Productive Wells
The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2013: 
 
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.

25



Natural Gas and Oil Reserves
The following table presents our estimated net proved natural gas and oil reserves at June 30, 2013, based on reserve reports generated by William M. Cobb & Associates, Inc. (“Cobb”) and W.D. Von Gonten and Company ("Von Gonten"). The Company believes that having independent and well respected third-party engineering firms prepare its reserve report enhances the credibility of its reported reserve estimates.

Management is responsible for the reserve estimate disclosures in this filing, and members of the Company’s management meet regularly with our independent third-party engineer to review these reserve estimates. Mr. Joseph J. Romano, the Company’s Chief Executive Officer, has primary responsibility for the preparation of the reserve report. Mr. Romano has been in the energy industry for over 35 years, but also relies on others with technical backgrounds in a collaborative effort, all of who provide input to the independent third-party engineers. Mr. Brad Juneau, one of the Company’s directors, monitors production and pressure data daily and provides the majority of the input. Mr. Juneau holds a BS degree in petroleum engineering from Louisiana State University. Mr. Juneau has over 30 years of experience in the oil and gas industry and was a former registered petroleum engineer in the State of Texas. Other executives in accounting and production have advanced degrees and specialty licenses and also provide input to the independent third-party engineers and assist in reviewing the reports.
The qualifications of the technical individuals at Cobb and Von Gonten responsible for overseeing the preparation of our reserve estimates are set forth below.
William M. Cobb & Associates, Inc.
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
W.D.Von Gonten and Company
Over 13 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
Each of Cobb and Von Gonten has informed us that the technical person primarily responsible for the reserve estimates meets or exceeds the education, training, and experience requirements set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.
We maintain adequate and effective internal controls over the underlying data upon which reserves estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is communicated to our reservoir engineers quarterly, is confirmed when our third-party reservoir engineers hold technical meetings with geologists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Controls – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All data such as commodity prices, lease operating expenses, production taxes, field level commodity price differentials, ownership percentages, and well production data are updated in the reserve database by our third-party reservoir engineers and then analyzed by management to ensure that they have been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, our independent engineering firms prepare their independent reserve estimates and final report.




26



The following table sets forth our offshore proved reserves as of June 30, 2013:
 
 
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


(1) Reserves prepared by William M. Cobb & Associates, Inc.
(2) Reserves prepared by W.D. Von Gonten and Company
Prior Year Reserves
Our estimated net proved natural gas, oil and natural gas liquids reserves as of June 30, 2010, 2011, 2012 and 2013 are disclosed on page F-26 and were based on reserve reports generated by Cobb, while the reserves associated with our 37% investment in Exaro were prepared by Von Gonten. The reserve estimates as of June 30, 2010 also include the reserves associated with the Joint Venture Assets which were prepared exclusively by Lonquist & Co. LLC (“Lonquist”). These Joint Venture Asset reserves account for approximately 8% of our total reserves as of June 30, 2010 and were sold on May 13, 2011. The technical person at Lonquist responsible for overseeing the preparation of our Joint Venture Asset reserve estimates had over 23 years of practical experience in the estimation and evaluation of reserves, is a registered professional engineer in the state of Texas, has a BS in Petroleum Engineering, and is a member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. This individual meets or exceeds the education, training, and experience requirements set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.

Proved Undeveloped Reserves

The Company annually reviews any proved undeveloped reserves (“PUDs”) to ensure their development within five years or less. As of June 30, 2013, the Company had approximately 3.1 Bcfe of PUDs related to Mary Rose #6, a rate acceleration well on state of Louisiana acreage. Our plan is to develop this PUD reserve prior to December 31, 2016, which is five years from the initial date of disclosure of this PUD reserve.

The Mary Rose #6 rate acceleration well will be drilled in the main Cib Op reservoir. This well provides significant
acceleration benefits but minimal incremental reserves. The incremental net PV-10 for this well, as of June 30, 2013, is approximately $26.6 million. However, the incremental net reserves are only approximately 2,489 MMcf and 97 MBbls of condensate and liquids. The incremental net reserves are modest because the main Cib Op reservoir is a depletion drive retrograde gas reservoir. The condensate yield declines as reservoir pressure declines. Our reservoir engineer’s simulation model indicates that the timing of the pressure depletion, and the distribution of that depletion across the field, will have an effect on all of the wells in communication with the Mary Rose #6. The effect of accelerating the pressure depletion, and changing the take points in the reservoir, is that more of the condensate “condenses” in the reservoir before it can be produced into the wellbores.

The Mary Rose #6 PUD reserves are calculated incrementally. The field-wide simulation model is run first without the
Mary Rose #6 well to generate a total field gas and condensate projection. The model is then run again with the Mary Rose #6 well included. The difference between these two cases is the incremental PUD reserve case. Of the gas volumes the Mary Rose #6 well is projected to produce, the majority comes from other wells in the field, such that the incremental gas recovery for the Mary Rose #6 well is much less.

    


27




The following table presents the changes in our total proved undeveloped reserves for the fiscal year ended June 30, 2013 (MMcfe):
 
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

Pre-Tax Net Present Value
The Company's pre-tax net present value, discounted at 10%, for its reserves is approximately $550.3 million. This figure is not intended to represent the current market value of the estimated natural gas and oil reserves we own. The pre-tax net present value of future cash flows attributable to our proved reserves as of June 30, 2013 was based on $3.44 per million British thermal units (“MMbtu”) for natural gas at the NYMEX, $91.57 per barrel of oil at the West Texas Intermediate Posting, and $39.50 per barrel of NGLs, in each case before adjusting for basis, transportation costs and British thermal unit (“BTU”) content. The pre-tax net present value is a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. The table below reconciles our calculation of pre-tax net present value to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that pre-tax net present value is an important non-GAAP financial measure used by analysts, investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The reconciliation of the pre-tax net present value to the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at June 30, 2013 is as follows (in thousands):
 
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

While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all of this data may vary. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
Item 3. Legal Proceedings
Several class action lawsuits have been brought by Crimson stockholders challenging the proposed Merger and seeking, among other things, injunctive relief to enjoin the defendants from completing the Merger on the agreed-upon terms, compensatory damages, and costs and disbursements relating to the lawsuits. Various combinations of Crimson, Contango, members of Crimson’s board of directors, and members of Crimson management have been named as defendants in these lawsuits. It is possible that additional similar lawsuits may be filed.
The known plaintiffs in these lawsuits, based on the most current information provided by Crimson, collectively own a very small percentage of the total outstanding shares of Crimson common stock. The lawsuits allege, among other things, that Crimson’s board of directors failed to take steps to obtain a fair price, failed to properly value Crimson, failed to protect against alleged conflicts of interest, failed to conduct a reasonably informed evaluation of whether the transaction was in the best interests of stockholders, failed to fully disclose all material information to stockholders, acted in bad faith and for improper motives, engaged in self-dealing, discouraged other strategic alternatives, took steps to avoid competitive bidding, and agreed to allegedly unreasonable deal protection mechanisms, including the no-shop and fiduciary-out provisions and termination fee. The lawsuits also allege that Contango aided and abetted the other defendants in violating duties to the Crimson stockholders. The lawsuits seek damages and injunctive relief.
Contango and Crimson believe that these lawsuits are without merit and intend to contest them vigorously.

28




Item 4. Mine Safety Disclosures
Not applicable.


29



PART II
Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock was listed on the NYSE MKT (previously the American Stock Exchange) in January 2001 under the symbol “MCF”. The table below shows the high and low prices of our common stock for the periods indicated.
 
 
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

On June 30, 2013, we had 69 registered shareholders. In November 2012, the Board of the Company declared a special dividend of $2.00 per share of common stock to be paid on December 17, 2012 to each holder of record of the Company's common stock as of the close of business on December 10, 2012. We have not declared any further cash dividends on our shares of common stock. Any future decision to pay dividends on our common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital requirements, and other factors our board may deem relevant.
The following table sets forth information about our equity compensation plans at June 30, 2013:
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
 
 
$—
 
The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. The final remaining outstanding options were net-settled with the Company in February 2012 and no options remain outstanding.

On September 15, 2009, the Company’s Board of Directors (the “Board”) adopted the Contango Oil & Gas Company Equity Compensation Plan (the “2009 Plan”), which was approved by shareholders on November 19, 2009. Under the 2009 Plan, the Board may grant restricted stock and option awards to officers, directors, employees or consultants of the Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. As of June 30, 2013, all options issued under the 2009 Plan had been exercised. The Company has not issued any restricted stock under the 2009 Plan.
In February 2012, the Company net-settled 45,000 stock options from two officers for a total of approximately $465,000. During the fiscal year ended June 30, 2011, the Company purchased 172,544 shares of its common stock. Of this amount, 152,544 shares were purchased from three officers of the Company, one member of the Board, one employee, and one consultant for a total of approximately $8.9 million. All purchases were approved by the Board under the Company’s share repurchase programs described below and were completed at the closing price of the Company’s common stock on the date of purchase.


30



Share Repurchase Programs
$100 Million Share Repurchase Program
In September 2008, the Company’s board of directors approved a $100 million share repurchase program which concluded in October 2011. Under this share repurchase program, the Company purchased a total of 2,157,278 shares of common stock at an average price of $46.35 per share. All shares were purchased in the open market or through privately negotiated transactions when we believed the Company's stock price to be undervalued. The purchases were made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. Repurchased shares of common stock became authorized but unissued shares, and may be issued in the future for general corporate and other purposes.

$50 Million Share Repurchase Program

In September 2011, the Company’s board of directors approved a $50 million share repurchase program, effective upon completion of purchases under the Company’s $100 million share repurchase program. The repurchases are subject to the same terms and conditions as repurchases made under the $100 million share repurchase program. During the fiscal year ended June 30, 2013, the Company purchased the below listed shares under its $50 million share repurchase program:
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

In addition to the above, in February 2012 the Company net-settled 45,000 stock options from two officers for a
total of approximately $465,000. In total, under both share repurchase programs combined as of June 30, 2013, the Company had invested approximately $110.8 million to purchase 2,355,155 shares of its common stock at an average cost per share of $46.84, and 45,000 stock options. As of June 30, 2013, the Company had 15,194,952 shares of common stock outstanding and no options.

The following graph compares the yearly percentage change from June 30, 2008 until June 30, 2013 in the cumulative total stockholder return on our common stock to the cumulative total return on the S&P Smallcap 600 Index and a peer group of five independent oil and gas exploration companies selected by us. In previous years, the companies in our selected peer group included ATP Oil & Gas Corp., McMoRan Exploration Company, Callon Petroleum, Energy XXI (Bermuda) Limited, and W&T Offshore, Inc. ("Old Peer Group").

In August 2012, ATP Oil & Gas Corp. filed for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas, and in June 2013 McMoRan Exploration Company ceased trading on the NYSE as a result of their merger with Freeport-McMoRan Copper & Gold, Inc. As a result, we deleted these two companies from our Old Peer Group and replaced them with two new companies. The companies in our selected peer group now include Stone Energy Corporation, SandRidge Energy Inc., Callon Petroleum, Energy XXI (Bermuda) Limited and W&T Offshore, Inc. ("New Peer Group").

Our common stock began trading on the NYSE MKT (previously American Stock Exchange) on January 19, 2001 and before that had traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in our common stock and each index on June 30, 2008, adjusted for stock splits and dividends. The stock performance for our common stock is not necessarily indicative of future performance.





31




 
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



Item 6. Selected Financial Data
The following selected financial data for the years ended June 30, 2013, 2012, 2011, 2010 and 2009 have been derived from the audited consolidated financial statements of Contango contained in our Annual Report on Form 10-K for the applicable fiscal year. The selected consolidated financial data (not including proved reserve information) set forth below is for continuing operations and should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this Form 10-K.

32



 

 
 
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

(a) During the fiscal year ended June 30, 2013, the Company drilled two dry holes resulting in exploration expenses of
approximately $50 million, including leasehold costs. Also during the fiscal year ended June 30, 2013, Contango revised
estimated proved reserves at Ship Shoal 263, resulting in non-cash impairment expenses of approximately $12.0 million.
Additionally, the Company completed a workover on its Vermilion 170 well at a cost of approximately $12.0 million.

(b) On November 29, 2012, the board of directors declared a one-time special dividend of $2.00 per share of common stock
which was paid on December 17, 2002.

(c) During the fiscal year ended June 30, 2013, the Company's proved reserves decreased by approximately 68.7 Bcfe and its
standardized measure decreased by approximately $156.4 million. This decrease is attributable to production of 24.4 Bcfe
during the period, and a decrease of approximately 44.8 Bcfe in the estimated reserves at our Dutch, Mary Rose, Vermilion
170, and Ship Shoal 263 wells due to new information obtained by our reservoir engineer, offset by an increase of
0.5 Bcfe due to our onshore discovery at Crosby 12H-1 in the TMS. During the fiscal year ended June 30, 2012, the
Company's proved reserves decreased by approximately 40.2 Bcfe and its standardized measure decreased by
approximately $203.2 million. This decrease is attributable to production of 31.3 Bcfe during the period, and a decrease of

33



approximately 8.9 Bcfe in the estimated reserves at our Dutch, Mary Rose, and Vermilion 170 wells due to
new information obtained.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report.

Overview

Contango is a Houston, Texas based, independent natural gas and oil company.  The Company's core business is to explore, develop, produce and acquire natural gas and oil properties offshore in the shallow waters of the Gulf of Mexico.  COI, our wholly-owned subsidiary, acts as operator on our offshore properties. Contango has additional onshore investments in i) Alta Resources Investments, LLC, whose primary area of focus is the liquids-rich Kaybob Duvernay in Alberta, Canada; ii) Exaro Energy III LLC, which is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; and iii) the Tuscaloosa Marine Shale where we own approximately 24,000 acres. 
Revenues and Profitability. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable.

Reserve Replacement. Generally, producing properties offshore in the Gulf of Mexico have high initial production
rates, followed by steep declines. We must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire natural gas and oil reserves. The Company did not replace any offshore reserves during the fiscal year ended June 30, 2013 or 2012. During fiscal year 2013, the Company drilled two dry holes at Ship Shoal 134 ("Eagle") and South Timbalier 75 ("Fang"). During fiscal year 2012, the Company did not drill any wells. Our permits to spud Eagle and Fang were approved in September 2011 and March 2012, respectively, but a lack of rig availability prevented us from drilling these wells during fiscal year 2012. While waiting for drilling rigs to become available, we spent most of fiscal year 2012 generating new prospects. In June 2012 and March 2013, the Company successfully acquired nine lease blocks at two Gulf of Mexico Lease Sales. Our plan is to promptly apply for permits to drill these prospects in 2013, 2014 and 2015. We therefore do not believe there will be a material impact on future sales or revenues or income from continuing operations.
Use of Estimates. The preparation of our financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oil reserves, the timing and costs of our future drilling, development and abandonment activities, and income taxes.
Related Party Transactions. The Company relies on JEX and REX to generate its offshore and onshore domestic natural gas and oil prospects. In addition to generating new prospects, JEX occasionally evaluates offshore and onshore exploration prospects generated by third-party independent companies for us to purchase. See Note 13 - Related Party Transactions for a detailed description of our transactions with JEX and REX.
See “Risk Factors” on page 13 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.
Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium
We believe that the Deepwater Horizon incident will have a significant and lasting effect on the U.S. offshore energy industry, and will result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. A significant delay of planned exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on production, including a reduction in operating results and cash flows as we deplete our reserves. There may be other impacts of which we are not aware at this time.
The potential for removal of the liability cap for claims of damages from oil spills, and/or the enactment of onerous rules and regulations regarding activities in the Gulf of Mexico could significantly alter our industry. Such rules could effectively limit which companies can operate in the Gulf of Mexico. Small and medium-sized oil and gas companies may not be able to obtain insurance coverage at economically appropriate levels or meet financial responsibility requirements and would be forced to exit operations in the Gulf of Mexico. Potentially less attractive economics for offshore exploration and development programs going forward will require companies retaining operations in the Gulf of Mexico to review their

34



business models. We have drilled, and believe we can continue to drill, safely in the Gulf of Mexico. However, exploration and production companies will be able to continue doing business in the Gulf of Mexico only to the extent it remains economically viable.
Delays and volatility are inherent in our business. We have maintained a capital structure with a strong liquidity position allowing us to manage during periods of uncertainty. We believe we are well-positioned to respond to the increasingly complex regulatory framework for the Gulf of Mexico.
Results of Operations

The table below sets forth our average net daily production data in Mmcfed from our offshore wells for each of the periods indicated:
 
Three Months Ended
 
June 30, 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


Dutch and Mary Rose Wells

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

Ship Shoal 263 Well

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

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

Vermilion 170 Well

In January 2013, we identified sustained casing pressure between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well production was shut-in and the original tubing and completion assembly were successfully removed. Operations were conducted to replace the tubing and restore the well, which resumed production in June 2013. As of June 30, 2013, this well was flowing at approximately 9.5 Mmcfed, net to Contango.





35




The table below sets forth revenue, production data, average sales prices and average production costs associated with our sales of natural gas, oil and natural gas liquids ("NGLs") from continuing operations for the fiscal years ended June 30, 2013, 2012 and 2011. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported lease operating expenses include property and severance taxes.
 
Year Ended June 30,

Year Ended June 30,
 
2013

2012

%

2012

2011

%
Revenues:
(thousands)



(thousands)


  Natural gas sales
$
66,441


$
73,068


(9
)%

$
73,068


$
106,781


(32
)%
  Condensate sales
$
39,009


$
69,547


(44
)%

$
69,547


$
61,862


12
 %
  NGL sales
$
21,751


$
36,657


(41
)%

$
36,657


$
33,078


11
 %
     Total revenues
$
127,201


$
179,272


(29
)%

$
179,272


$
201,721


(11
)%




Annual Production:

 












  Natural gas (million cubic feet)

















      Dutch and Mary Rose field
16,152


18,303


(12
)%

18,303


20,589


(11
)%
      Vermilion 170 field
2,054


3,098


(34
)%

3,098




100
 %
      Other fields
452


2,216


(80
)%

2,216


3,679


(40
)%
          Total natural gas
18,658


23,617


(21
)%

23,617


24,268


(3
)%
  Oil and condensate (thousand barrels)

















      Dutch and Mary Rose field
263


347


(24
)%

347


456


(24
)%
      Vermilion 170 field
51


123


(59
)%

123




100
 %
      Other fields
48


145


(67
)%

145


217


(33
)%
          Total oil and condensate
362


615


(41
)%

615


673


(9
)%
  Natural gas liquids (thousand gallons)

















      Dutch and Mary Rose field
21,568


21,452


1
 %

21,452


25,389


(16
)%
      Vermilion 170 field
3,391


5,390


(37
)%

5,390




100
 %
      Other fields
270


959


(72
)%

959


1,537


(38
)%
          Total natural gas liquids
25,229


27,801


(9
)%

27,801


26,926


3
 %
  Total (million cubic feet equivalent)

















      Dutch and Mary Rose field
20,811


23,450


(11
)%

23,450


26,952


(13
)%
      Vermilion 170 field
2,844


4,606


(38
)%

4,606




100
 %
      Other fields
779


3,223


(76
)%

3,223


5,201


(38
)%
          Total production
24,434


31,279


(22
)%

31,279


32,153


(3
)%
 
 
 
 
 
 
 
 
 
 
 
 
Daily Production:

















  Natural gas (million cubic feet per day)

















      Dutch and Mary Rose field
44.3

 
50.0

 
(12
)%

50.0


56.4


(11
)%
      Vermilion 170 field
5.6

 
8.4

 
(34
)%

8.4




100
 %
      Other fields
1.2

 
6.1

 
(80
)%

6.1


10.1


(40
)%
          Total natural gas
51.1

 
64.5

 
(21
)%

64.5


66.5


(3
)%
  Oil and condensate (thousand barrels per day)


 


 











      Dutch and Mary Rose field
0.7

 
0.9

 
(24
)%

0.9


1.2


(24
)%
      Vermilion 170 field
0.2

 
0.4

 
(59
)%

0.4




100
 %
      Other fields
0.1

 
0.4

 
(67
)%

0.4


0.6


(33
)%
          Total oil and condensate
1.0

 
1.7

 
(41
)%

1.7


1.8


(9
)%

36



 
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