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Enhance our portfolio by dedicating the majority of our drilling capital to our oil and liquids-rich opportunities.  Due to the superior economics from oil production, we will allocate most of our 2014 onshore capital budget to oil and liquids-weighted opportunities as we transition from a natural gas weighted production profile to a more balanced reserve and production profile between oil/liquids and natural gas. We currently plan to develop the oil and natural gas liquids resource potential that we believe exists, from numerous formations, on our Madison and Grimes County acreage in Southeast Texas, our Zavala and Dimmit County acreage in South Texas and our San Augustine County acreage in East Texas. If warranted by market conditions, success in these areas and capital availability, we may further accelerate our drilling program in one or more areas. Until the outlook for natural gas prices for a sustained period of time improves significantly, we do not plan to further develop our acreage position in the Haynesville/Mid-Bossier natural gas play in East Texas. For the six months ended December 31, 2013, our production profile was approximately 71% natural gas and 29% oil and natural gas liquids, on an equivalent Mcfe basis. For the three months ended December 31, 2013, our production profile was approximately 66% natural gas and 34% oil and natural gas liquids.

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Complement the exploitation of our lower-risk onshore resource plays with potentially high-impact offshore exploration. We have historically depended upon Juneau Exploration, L.P. (“JEX”) for offshore prospect generation expertise and to review prospects submitted by third parties. JEX is a private company formed for the purpose of generating offshore and onshore domestic natural gas and oil prospects and is experienced and has a successful track record in exploration. We currently have seven offshore prospects and intend to continue to review and consider offshore exploration opportunities

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Pursue accretive, opportunistic acquisitions that meet our strategic and financial objectives.  We intend to continue evaluating opportunistic acquisitions of crude oil and natural gas properties, including both undeveloped and developed reserves, in areas where we currently have a presence and/or specific operating expertise, as well as new areas that we feel have significant exploration, exploitation or operational upside.

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Reduce near-term commodity price exposure through hedging.  We utilize commodity derivative instruments to minimize exposure to declining prices on our crude oil, natural gas and natural gas liquids production.  We currently use a series of swaps and costless collars to accomplish our commodity price hedging strategy. As of December 31, 2013, we have 9.5 Bcfe of equivalent production hedged between January 1, 2014 and December 31, 2014. For 2014 production we have 0.2 MMBbl of crude oil hedges at an average Brent floor price of $104.29/Bbl, 0.3 MMBbl of crude oil hedges at an average WTI floor price of $95.05/Bbl and 6.9 Bcf of natural gas hedges at an average floor price of $3.94 /MMBtu.

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Selectively exploit our existing onshore producing conventional property base to generate additional cash flows.  We believe our multi-year drilling inventory of exploitation opportunities on our existing onshore conventional producing properties provides us with a solid, dependable platform for future reserve and production growth.  We own 3D seismic data that covers substantially all of our Liberty County acreage in Southeast Texas, giving us a higher degree of confidence in the potential in this area.  However, as a result of our desire to more extensively develop our resource plays, we do not expect to allocate significant drilling capital to further develop these assets in 2014.

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Southeast Texas. As of December 31, 2013, our Southeast Texas region included approximately 42,580 gross (26,476 net) acres, proven reserves of 52.3 Bcfe, and 79 gross (44.3 net) producing wells. Crimson has actively developed this area since 2008, primarily focusing on conventional wells in the Yegua and Cook Mountain sands in Liberty County until 2012. In 2012, Crimson shifted its focus to the horizontal development of the Woodbine formation in Madison and Grimes counties, where there has recently been significant industry activity pursuing the Woodbine and Eagle Ford Shale oil plays near our leasehold positions. During 2013, Crimson, and then Contango, drilled 12 gross (eight net) wells on acreage targeting the Woodbine formation. We will continue our focus on further developing our inventory of crude oil and liquids-rich projects in the Woodbine formation with a continuous rig program planned for 2014. We currently have approximately 19,000 net acres, with a multi-year inventory of potential drilling locations, in Madison and Grimes counties, which includes the Woodbine, Eagle Ford Shale and Georgetown formations.

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South Texas. As of December 31, 2013, our South Texas region included approximately 105,364 gross (55,885 net) acres, proven reserves of 63.3 Bcfe, and 274 gross (144.7 net) producing wells. Of this, approximately 25,880 gross (13,978 net) acres are targeting the Buda and Eagle Ford Shale plays, approximately 80% of which is held by production. Crimson began development of the Eagle Ford Shale in Bee County in 2010 and in Karnes, Zavala and Dimmit counties in 2011. During 2013, Contango and Crimson drilled six gross operated wells (three net) and one gross non-operated well (0.25 net) in the Buda formation in Zavala and Dimmit counties. Six of the wells were successful, while one was a mechanical failure which may be side tracked in the future. Initial thirty-day average production rates for each of the first five wells was 730 boed while the sixth well continues to clean up. We have one additional well in process at year-end 2013 and expect to have at least one rig running full-time in 2014. Our estimated net proven Buda/Eagle Ford reserves in this area were 23.5 Bcfe, comprised of 74.4% liquids, with 17 gross (8.9 net) producing wells, as of December 31, 2013.

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Other (East Texas).  As of December 31, 2013, our East Texas region included approximately 7,904 gross (4,833 net) acres primarily in San Augustine County, proven reserves of 1.5 Bcfe comprised of 99% gas, and eight gross (3.9 net) producing wells. Crimson actively developed the Haynesville and Mid-Bossier Shales in this area in 2009 through 2011 during a more favorable natural gas price environment. We believe that the further exploitation of our acreage in the Haynesville and Mid-Bossier Shale dry gas formations will provide long-term natural gas reserve and production growth in the future; however, we do not anticipate devoting drilling capital to these formations until we see a sustained improvement in the natural gas price environment. During 2014, we will initiate development of the shallower liquids rich James Lime formation on our acreage in San Augustine County. We anticipate that we will drill up to two wells in that area during 2014, where the offset operator has experienced excellent results in recent drilling. Approximately 80% of our acreage in East Texas is held by production.

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Other (Tuscaloosa Marine Shale). We own a 25% non-operated working interest in the Crosby 12H-1 well in Wilkinson County, Mississippi, targeting the TMS, an oil-focused shale play in central Louisiana and Mississippi. This well is operated by Goodrich Petroleum Company LLC ("Goodrich"). As of December 31, 2013, the Crosby 12H-1 well was producing at an 8/8ths rate of approximately 200 barrels of oil per day, with cumulative production of approximately 136,000 barrels of oil from the commencement of production through December 31, 2013.

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Other (Colorado). We hold approximately 16,080 gross (11,229 net) acres in the DJ Basin in Colorado (mostly in Adams and Weld counties). There has been increasing activity since 2011 in the vicinity of our Colorado acreage in pursuit of the Niobrara Shale oil formation. Recent industry activity in the area has proven that the application of horizontal drilling technology for oil in the shallower Niobrara Shale may provide attractive return possibilities; however, the prospect for full-scale economic development is still uncertain.  Substantially all of our net acres in the Niobrara Shale are held by production. We plan to monitor the 2014 industry activity and results of our peers in the Niobrara Shale to determine our strategy for maximizing the value of our position in the area.

•	Other. We hold approximately 3,302 gross (621 net) acres in small non-operating working interests in the Fenton field area of Calcasieu Parish, Louisiana and a minor crude oil property in Mississippi.

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Kaybob Duvernay - Alberta, Canada. In mid-2011, we began investing in Alta Resources Investments, LLC (“Alta”). On August 1, 2013, Alta sold its interest in the liquids-rich Kaybob Duvernay Play in Alberta, Canada, where we had invested approximately $15.2 million. We expect to receive approximately $30.5 million from the sales proceeds. Of this amount, $23.1 million was received in September 2013, $5.4 million was received in February 2014, and the remaining $2.0 million is expected to be received by the end of 2014.

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Jonah Field - Sublette County, Wyoming. In April 2012, we, through our wholly-owned subsidiary, Contaro Company (“Contaro”), entered into a Limited Liability Company Agreement (as amended, the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC Agreement, we have committed to invest up to $67.5 million in cash in Exaro, together with other parties for an aggregate commitment of approximately $183 million, resulting in a 37% ownership interest in Exaro. As of December 31, 2013, we had invested approximately $46.9 million in Exaro.

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•	Gulf of Mexico - We forecast capital expenditures of approximately $39 million for 2014. The largest components of this amount include $23 million to drill our Ship Shoal 255 exploratory prospect and $12 million to commence drilling an additional exploratory well in the shallow waters of the Gulf of Mexico late in the year.

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Woodbine - We forecast capital expenditures of approximately $89 million in Madison and Grimes Counties to drill 19-20 wells. We currently anticipate 11 wells in our Force area, six wells in our Chalktown area and two wells in our Iola / Grimes area, all of which will target the Woodbine formation. Additionally, we will drill one or more additional wells to test other reservoir-maximization strategies in the area.

•	Buda - We forecast capital expenditures of approximately $33 million in Zavala and Dimmit Counties to drill 14 operated and five non-operated wells targeting the Buda formation.

•	James Lime - We forecast capital expenditures of approximately $9 million in St. Augustine County to drill two wells targeting the James Lime formation.

•	Other - We also forecast spending an additional $46 million in 2014 on the acquisition of undeveloped acreage in existing and new areas, initial test wells on other formations in current areas or new acreage, on seismic data and for potential completion/facility costs on Gulf of Mexico prospects.

•	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/exports

•	Domestic and foreign governmental regulations

•	Special taxes on production

•	The loss of tax credits and deductions

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•	The Environmental NTL, which imposes 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; and

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The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system, known as “SEMS,” to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended in April 2013 to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.

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•	Our proved reserves.

•	The level of crude oil, natural gas and natural gas liquids we are able to produce from existing wells.

•	The prices at which crude oil, natural gas and natural gas liquids are sold.

•	Our ability to acquire, locate and produce new reserves.

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·	unusual or unexpected geological formations and miscalculations;

·	pressures;

·	fires;

·	explosions and blowouts;

·	pipe or cement failures;

·	environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and discharges of toxic gases, brine, well stimulation and completion fluids, or other pollutants into the surface and subsurface environment;

·	loss of drilling fluid circulation;

·	title problems;

·	facility or equipment malfunctions;

·	unexpected operational events;

·	shortages of skilled personnel;

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·	shortages or delivery delays of equipment and services or of water used in hydraulic fracturing activities;

·	compliance with environmental and other regulatory requirements;

·	natural disasters; and

·	adverse weather conditions.

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•	The Environmental NTL, which imposes 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; and

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The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system, often referred to as SEMS, to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the “SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.

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•	our operating and financial performance and prospects;

•	our quarterly or annual earnings or those of other companies in our industry;

•	conditions that impact demand for crude oil, natural gas and natural gas liquids;

•	future announcements concerning our business;

•	changes in financial estimates and recommendations by securities analysts;

•	actions of competitors;

•	market and industry perception of our success, or lack thereof, in pursuing our growth strategy;

•	strategic actions by us or our competitors, such as acquisitions or restructurings;

•	changes in government and environmental regulation;

•	general market, economic and political conditions;

•	changes in accounting standards, policies, guidance, interpretations or principles;

•	sales of common stock by us, our significant stockholders or members of our management team; and

•	natural disasters, terrorist attacks and acts of war.

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permit us to issue, without any further vote or action by the stockholders, shares of preferred stock in one or more series and, with respect to each such series, to fix the number of shares constituting the series and the designation of the series, the voting powers (if any) of the shares of the series, and the preferences and relative, participating, optional, and other special rights, if any, and any qualification, limitations or restrictions of the shares of such series;

•	require special meetings of the stockholders to be called by the Chairman of the Board, the Chief Executive Officer, the President, or by resolution of a majority of the board of directors;

•	require business at special meetings to be limited to the stated purpose or purposes of that meeting;

•	require that stockholder action be taken at a meeting rather than by written consent, unless approved by our board of directors;

•	require that stockholders follow certain procedures, including advance notice procedures, to bring certain matters before an annual meeting or to nominate a director for election; and

•	permit directors to fill vacancies in our board of directors.

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•	our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status;

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upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or

•	the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.

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•	If a portion of the combined company's cash is applied to the payment of principal or interest on the debt, less will be available for other purposes;

•	Credit-rating agencies may change in the future with respect to the combined company, their ratings of that entity's debt and other obligations, which in turn impacts the costs, terms and conditions and availability of financing;

•	Covenants contained in the combined company's existing and future debt arrangements will require the combined company to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;

•	The combined company's ability to obtain additional financing for capital expenditures, acquisitions, general corporate and other purposes may be limited or burdened by increased costs or more restrictive covenants;

•	The combined company may be at a competitive disadvantage to similar companies that have less debt;

•	The combined company's vulnerability to adverse economic and industry conditions may increase; and

•	The combined company may face limitations on its flexibility to plan for and react to changes in its business and the industries in which it operates.

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(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).

(6)	Other includes acreage in Louisiana, Colorado, Mississippi and East Texas.

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(1)	A gross well is a well in which we own an interest.

(2)	The number of net wells is the sum of our fractional working interests owned in gross wells.

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(1)

Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.

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(1)

Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices, using SEC rules, are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.

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(1)	The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro does not include the effect of income taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or expense for tax purposes to its partners.

(2)

Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.

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(1)	Average volume per month for the remaining contract term

(2)	Average price per unit for the remaining contract term

(3)	Commodity derivative based on NYMEX West Texas Intermediate crude oil prices

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(4)	Commodity derivative based on Brent crude oil prices

(5)	Commodity derivative based on Henry Hub NYMEX natural gas prices

(1)	Represents counterparty netting under agreements governing such derivatives

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(1)	The aggregate intrinsic value of stock options exercised during the six months ended December 31, 2013 and the fiscal year ended June 30, 2011 was $7,721 and $8.9 million, respectively.

(2)	For the fiscal year ended June 30, 2012, forfeited options consist of options that were net-settled for cash with the Company. For the fiscal year ended June 30, 2011, forfeited options relate to options surrendered under a cashless exercise, with immediate sale to the Company.

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•	In March 2010 the Company spud the Eloise South well. All owners paid for their proportionate share of drilling and completion costs based on their ownership percentage. The Company had a 23.8% working interest in this well, Olympic had a 3.33% working interest, and REX had a 9.6% working interest. Once production began, JEX employees received an ORRI of 1.33%.

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In June 2010 the Company spud its Rexer #1 well. Under the terms of the applicable participation agreement, the Company had a 100% working interest through payout of all costs. In May 2011, the Company sold Rexer #1 (See Note 18 - "Discontinued Operations") prior to reaching payout. Once payout is reached with the new operator, JEX will have an option to back-in for a 10% working interest (7.25% net revenue interest). Other third-parties own the remaining working interests. JEX employees maintained a 2.5% ORRI in this well. The Company paid JEX a prospect fee of $250,000 for generating this prospect.

•	In October 2010, the Company purchased JEX's 7.5% working interest in Ship Shoal 263 for $7.5 million, based on a reserve valuation as of the purchase date.

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Prior to its dissolution, Contango Offshore Exploration LLC owed the Company $5.9 million in principal and interest under a promissory note (the “COE Note”) payable on demand. In connection with the dissolution, the Company assumed its 65.63% share of the obligation under the COE Note, while JEX assumed the remaining 34.37%, or approximately $2 million. This $2 million was paid to the Company in October 2010.

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In February 2011 the Company spud Vermilion 170 which was owned 100% by the Company. Under the terms of the applicable participation agreement, Contango had a 100% working interest through casing point. Once casing point was reached, JEX and REX each exercised their option to back-in for a 2.6% and 7.5% working interest, respectively. Once production began, JEX and REX each received their carried working interest of 1.7% and 5.0%, respectively, resulting in JEX having a final working interest of 4.3% and REX having a final working interest of 12.5%. The Company owns the remaining working interests in this well. The Company paid JEX a prospect fee of $250,000 for generating this prospect.

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In May 2011 the Company spud its Rexer-Tusa #2 well. Under the terms of the applicable participation agreement, the Company had a 25% working interest through payout of all costs. In October 2011, the Company completed selling Rexer-Tusa #2 (See Note 18 - "Discontinued Operations") prior to reaching payout. Once payout is reached with the new operator, JEX will have an option to back-in for a 10% working interest (7.36% net revenue interest). Other third-parties own the remaining working interests. JEX employees maintained a 2.92% ORRI in this well.

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In July 2011, the Company recompleted its Eloise South well uphole in the Cib-Op sands as our Dutch #5 well. Under the terms of the applicable joint operating agreement, all Dutch #5 well owners were required to purchase the Eloise South well bore from the Eloise South owners (the "Dutch Well Cost Adjustment"). All Eloise South and Dutch #5 well owners paid and/or received their proportionate share of the Dutch Well Cost Adjustment based on their ownership percentage in each well. JEX had a 1.6% working interest in Dutch #5; Olympic had a 3.02% working interest in Dutch #5 and a 3.33% working interest in Eloise South; REX had a 9.6% working interest in Eloise South; and Contango had a 47.05% working interest in Dutch #5 and a 23.8% working interest in Eloise South.

•	In December 2011, the Company purchased an additional working interest in Mary Rose #5 (see below) from an existing partner. The Company then sold to Olympic and JEX its proportionate share of the existing partner's interest, based on Olympic and JEX's ownership percentage in the well.

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In January 2012, the Company recompleted its Eloise North well uphole in the Cib-Op sands as our Mary Rose #5 well. Under the terms of the applicable joint operating agreement, all Mary Rose #5 well owners were required to purchase the Eloise North well bore from the Eloise North owners. (the "Mary Rose Well Cost Adjustment"). All Eloise North and Mary Rose #5 well owners paid and/or received their proportionate share of the Mary Rose Well Cost Adjustment based on their ownership percentage in each well. JEX had a 1.4% working interest in Mary Rose #5 and a 0.1% working interest in Eloise North; Olympic had a 2.56% working interest in Mary Rose #5 and a 4.79% working interest in Eloise North; REX had a 13.2% working interest in Eloise North; and the Company had a 37.8% working interest in Mary Rose #5 and a 35.8% working interest in Eloise North.

•	In July 2012 the Company spud the Ship Shoal 134 prospect which was owned 100% by the Company. The Company paid 100% of the costs to drill, plug and abandon this well. The Company paid JEX a prospect fee of $250,000 for generating this prospect.

•	In July 2012 the Company spud the South Timbalier 75 prospect which was farmed-in 100% by the Company and REX. Under the terms of the applicable participation agreement, the Company paid 100% of the costs to drill, plug and abandon this well. The Company paid JEX a prospect fee of $250,000 for generating this prospect.

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For the five REX-generated lease blocks that the Company purchased at the June 20, 2012 lease sale, the Company will have a 100% working interest through first production. At first production (if successful), REX will receive a carried working interest of 10%. Once payout of post casing point costs has been reached, REX will have an option to back-in for up to 12.5% working interest, resulting in REX having a final working interest of up to 22.5% (17.5% net revenue interest) and the Company owning the remaining working interests. JEX employees will receive an ORRI of 3.33% in these prospects. The Company will pay JEX a prospect fee of $250,000 for each prospect the Company drills. Should the Company not drill these prospects within 48 months of the effective date of each lease, the Company shall assign such lease to REX.

•	For the one JEX-generated lease block that the Company purchased at the June 20, 2012 lease sale, the Company will carry JEX for 10% through first production and JEX employees will receive an ORRI of 3.33%. The Company paid JEX a prospect fee of $250,000 in December 2013 upon spudding this prospect.

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For the three REX-generated lease blocks that the Company purchased at the March 20, 2013 lease sale, the Company will have a 100% working interest through first production. At first production (if successful), REX will receive a carried working interest of 10%. Once payout of post casing point costs has been reached, REX will have an option to back-in for up to 12.5% working interest, resulting in REX having a final working interest of up to 22.5% (17.5% net revenue interest) and the Company owning the remaining working interests. JEX employees will receive an ORRI of 3.33% in these prospects. The Company paid JEX two prospect fees of $250,000 each, for evaluating these two prospects located on three leases. Should the Company not drill these prospects within 48 months of the effective date of each lease, the Company shall assign such lease to REX.

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In June 2013, the Company purchased South Timbalier 17 from an independent oil and gas company. Under the terms of the applicable participation agreement, the Company will have a 75% working interest in this well, with several other owners owning the remainder, until payout of all costs is reached. Once payout of all costs has been reached, REX will have an option to back-in for up to a 9.4% working interest, (6.7% net revenue interest), resulting in the Company owning a 56.3% working interests (39.9% net revenue interest). The Company paid JEX a prospect fee of $250,000 for evaluating this prospect. There are no JEX employee ORRIs on this prospect.

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In the Tuscaloosa Marine Shale ("TMS"), a shale play in central Louisiana and Mississippi, the Company has a 100% working interest through first production. Beginning with production from the fourth well on the existing acreage (if successful), JEX will receive a carried working interest of 10% and JEX employees will receive an ORRI of 2%, of which Mr. Juneau receives 0.75%, to reimburse Mr. Juneau for out-of-pocket costs incurred in order for Contango to participate in the prospect. An additional 2% was granted to the geologist who generated the TMS prospect for us. The geologist has subsequently been employed by Contango. Should the Company not drill on its TMS acreage within six months of the leases expiring, the Company shall assign such leases to JEX.

•	Effective January 1, 2014, the Company subleased to JEX a portion of its previous office space at 3700 Buffalo Speedway, Houston, Texas for approximately $0.1 million per year, which approximates our rental liability for that space.

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(1)	Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of natural gas and oil properties, general and administrative expense, and other income and expense before income taxes.

(2)	The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income for that quarter and the weighted average number of common shares outstanding during that quarter.