News Column

CONTANGO OIL & GAS CO - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 11, 2014

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the accompanying notes and other information included elsewhere in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K/A for the year ended December 31, 2013 and Transition Report on Form 10-K for the transition period from July 1, 2013 to December 31, 2013, previously filed with the Securities and Exchange Commission ("SEC").



Overview

Contango is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development, exploitation and production of crude oil and natural gas offshore in the shallow waters of the Gulf of Mexico ("GOM") and in the Gulf Coast, Texas and Rocky Mountain regions of the United States. On October 1, 2013, we completed a merger with Crimson Exploration Inc. ("Crimson"), in an all-stock transaction (the "Merger") pursuant to which Crimson became a wholly-owned subsidiary of Contango. As a result of the Merger, each share of Crimson common stock was converted into 0.08288 shares of common stock of Contango. As a result, we issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding capital stock, resulting in Crimson stockholders owning approximately 20.3% of post-Merger Contango. We also assumed $235.4 million in debt, including accrued interest and repayment premium, and issued 135,898 options in exchange for the outstanding options held by Crimson employees. The Merger qualified as a tax-free reorganization for U.S. federal income tax purposes, so that none of Contango, Crimson, or any of their respective stockholders recognized any gain or loss in the Merger, except that Crimson's stockholders may have recognized a gain or loss with respect to cash received in lieu of fractional shares of Company common stock. On October 1, 2013 the Company's board of directors approved a change in fiscal year end from June 30 to December 31. On March 3, 2014, we filed a Form 10-K which covered the transition period of July 1, 2013 through December 31, 2013, which included six months of Contango activity (July - December) and three months of post-merger Crimson activity (October - December). We also filed the Annual Report on Form 10-K/A to present the the financial statements of the Company on a calendar year basis for each of the three years in the period ended December 31, 2013. This Form 10-Q presents our information for the three and six months ended June 30, 2014 and 2013 based on a new year-end date of December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month periods ended December 31 of each year. We have historically focused our operations in the GOM, but our recent merger with Crimson has given us access to lower risk, long life resource plays in Southeast Texas (the Woodbine oil and liquids-rich play), in South Texas (the Eagle Ford Shale and Buda oil and liquids-rich plays) and in East Texas (the James Lime liquids-rich play, and under an improved natural gas price environment, the Haynesville/Mid-Bossier gas play). We believe these plays, and other formations in the same areas, provide long-term growth potential. Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC ("Exaro") that is primarily focused on the development of proved natural gas reserves in a portion of the Jonah Field in Wyoming; (ii) non-operated producing properties in Louisiana and Mississippi targeting the Tuscaloosa Marine Shale ("TMS"); (iii) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; (iv) operated producing properties in the Denver Julesburg Basin ("DJ Basin") in Weld and Adams counties in Colorado, which we believe are prospective in the Niobrara Shale oil play; (v) approximately 93,000 net acres (80% working interest) in Wyoming, which we have the right to drill to earn, where we expect to soon initiate a horizontal drilling program, with hydraulic fractured completions, targeting multiple formations including the Mowry Shale, and approximately 18,000 newly acquired net acres (50% working interest) in Fayette, Gonzalez, Caldwell and Bastrop counties, Texas on which we expect to soon initiate a similar program targeting multiple formations and (vi) six exploratory prospects in the shallow waters of the GOM. 22 -------------------------------------------------------------------------------- On April 29, 2014, we reached total depth on our Ship Shoal 255 well, and no commercial hydrocarbons were found. As a result, for the three months ended June 30, 2014, we recognized $10.1 million in exploration expense for the cost of drilling the well and $0.5 million in impairment expense for the associated platform located in Block Ship Shoal 263. For the six months ended June 30, 2014, we recognized $36.8 million in exploration expense for the cost of drilling the well and $15.6 million in impairment expense, including $3.5 million related to leasehold costs and $12.1 million related to the platform located in Block Ship Shoal 263 which was expected to be used by the Ship Shoal 255 well had it been successful. We intend to grow reserves and production by developing our existing producing property base and by exploiting our unproved oil/liquids resource potential. We have developed a significant inventory of quality drilling opportunities on our existing property base that we believe should position us for multiyear reserve growth, and until sustained improvement is seen in natural gas prices, expect to concentrate drilling activity on further developing our oil and liquids-rich onshore assets in Southeast Texas, South Texas and the GOM. In 2014, we will focus on our inventory of crude oil and liquids-rich projects with rig programs in the Woodbine play in Madison and Grimes Counties, Texas, the Buda play in Dimmit County, Texas and the James Lime play in San Augustine County, Texas. We also currently plan to drill a number of other wells testing new formations in existing and new areas, including our newly acquired acreage. We will continue to monitor expanding industry activity in the oil-weighted TMS and in the Niobrara Shale to determine the future potential and strategy for optimizing value in each play prior to committing significant drilling capital.



Summary Production Information

Our production for the three months ended June 30, 2014 was approximately 59% offshore and 41% onshore, and 64% natural gas and 36% oil and natural gas liquids. Our production for the three months ended June 30, 2013 was 100% offshore, and approximately 78% natural gas and 22% oil and natural gas liquids.

The table below sets forth our average net daily production data in Mmcfed from our fields for each of the periods indicated:

Three Months Ended June 30, 2013 September December 31, 2013 March 31, 2014 June 30, 2014 30, 2013 Offshore GOM Dutch and Mary Rose 57.2 61.7 59.1 66.7 60.9 Vermilion 170 4.0 9.6 9.6 9.0 7.2 Other offshore (1) 1.0 0.7 0.8 0.4 0.6 Southeast Texas (2) - - 24.3 26.4 27.1 South Texas (2) - - 14.7 12.6 16.0 Other (2) (3) - - 1.7 2.4 4.2 62.2 72.0 110.2 117.5 116.0



(1) The "Other offshore" line includes Ship Shoal 263.

(2) "Southeast Texas", "South Texas" and "Other" production are not included in the table above for periods prior to the quarter ended December 31, 2013, as a result of acquiring these producing properties effective October 1, 2013 due to the Merger. (3) The "Other" line includes onshore wells in the East Texas and Rocky Mountain regions for the quarters ended December 31, 2013, March 31, 2014, and June 30, 2014. The table below sets forth our pro forma net daily production data in Mmcfed from our fields for each of the periods indicated as if Merger took place on January 1, 2013: Pro forma Three Months Ended June 30, 2013 September December 31, March 31, June 30, 30, 2013 2013 (1) 2014 (1) 2014 (1) Offshore GOM 62.2 72.0 69.5 76.1 68.7 Southeast 27.9 25.4 24.3 26.4 27.1 Texas (2) South Texas 14.2 13.0 14.7 12.6 16.0 (2) Other (2) 2.1 1.9 1.7 2.4 4.2 106.4 112.3 110.2 117.5 116.0 23

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(1) Production for the quarters ended December 31, 2013, March 31, 2014, and June 30, 2014 include historical production of the combined company post-merger.

(2) Production for Southeast Texas, South Texas and Other for the periods prior to October 1, 2013 represent historical production of Crimson Exploration Inc. as derived from its quarterly reports on Form 10-Q for the respective periods. Offshore Gulf of Mexico Dutch and Mary Rose Field We operate five federal wells located at Eugene Island 10 ("Dutch") and five state wells located in adjacent state of Louisiana waters ("Mary Rose"). These ten wells produce to a Company-owned and operated production platform at Eugene Island 11. While we do not hold a lease for the Eugene Island 11 block, this does 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. We have 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. From this platform we are able to access two separate markets which minimizes downtime risk and provides the ability to select the best sales price. Oil and gas production can flow via a TC Offshore (formerly ANR) pipeline to third-party owned and operated onshore processing facilities near Patterson, Louisiana. Alternatively, gas can flow to the American Midstream (Seacrest), LP pipeline via our 8" pipeline, which has been designed with a capacity of 80 Mmcfd, 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 Company pipeline to onshore markets and multiple refineries. Based on normal production decline, a turbine type compressor of sufficient capacity to service all ten of our Dutch and Mary Rose wells was installed at the platform in July 2014. As of June 30, 2014, we had incurred approximately $8.8 million to design and build the compressor and have budgeted an additional $1.2 million for the installation in the third quarter of 2014. We plan to place our Dutch and Mary Rose wells on central compression at the Eugene Island 11 platform in the third quarter 2014. In December 2013, we exercised a preferential right and purchased an additional 7.84% working interest and 6.53% net revenue interest in the five Contango-operated Dutch wells from an independent oil and gas company for approximately $15 million, after purchase price adjustment. Net production from our Dutch and Mary Rose wells for the quarter ended June 30, 2014 was approximately 60.9 Mmcfed, compared to 57.2 Mmcfed for the 2013 quarter. The increase in production from this field during the three months ended June 30, 2014 is mainly attributable to the additional working interest acquired in December 2013.



Vermilion 170 Field

We operate one well at Vermilion 170 which flows to a Company-owned and operated production platform at the same location. In January 2013, sustained casing pressure was identified between the production tubing and the production casing at our Vermilion 170 well. Well production was shut-in and the original tubing was successfully removed. Operations were conducted to replace the tubing and restore the well to production in June 2013. This shut-in resulted in a significantly lower production during the quarter ended June 30, 2013. Net production from this well for the quarter ended June 30, 2014 was approximately 7.2 Mmcfed, compared to 4.0 Mmcfed in the 2013 quarter.



Operating expenses for the six months ended June 30, 2013 include approximately $11.4 million related to workover expenses for this well, net to the Company.

Other (Offshore)

Our Ship Shoal 263 and South Timbalier 17 fields have been included in "Other Offshore". The Company operates one well at Ship Shoal 263, which produces to a Company-owned and operated production platform at the same location. On July 30, 2013, we spud our South Timbalier 17 prospect in state of Louisiana waters, and on August 22, 2013, we announced a successful well at a total measured depth of 11,400 feet. We completed the well, installed production facilities and commenced production in July 2014. Net costs incurred to drill, complete and bring this well to full production status were $13.5 million as of June 30, 2014. We have a 75% working interest (53.3% net revenue interest) before payout and a 59.3% working interest (42.1% net revenue interest) after payout. On April 29, 2014, we reached total depth on our Ship Shoal 255 well, and no commercial hydrocarbons were found. As a result, for the three months ended June 30, 2014, we recognized $10.1 million in exploration expense for the cost of drilling the well and $0.5 million in impairment expense for the associated platform located at Block Ship Shoal 263. For the six months ended June 30, 2014, we recognized $36.8 million in exploration expense for the cost of drilling the well and $15.6 million in impairment expense, including $3.5 million related to leasehold costs and $12.1 million related to the platform located at Block Ship Shoal 263 which was expected to be used by the Ship Shoal 255 well had it been successful. 24 -------------------------------------------------------------------------------- The interests above include our ownership interest in Republic Exploration LLC ("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. In his capacity as sole manager of the general partner of JEX, Mr. Brad Juneau also controls the activities of REX. The Company proportionately consolidates its interest in REX in its consolidated financial statements.



Other Offshore Activities

During the year ended December 31, 2013, the Company was awarded three lease blocks, Eugene Island 23, Ship Shoal 52 and Ship Shoal 59, by the Bureau of Ocean Energy Management ("BOEM"), which were bid at the Central Gulf of Mexico Lease Sale 227 held on March 20, 2013. We currently hold 16 offshore lease blocks.



Onshore Properties

Our onshore areas of operations are concentrated on oil and liquids-rich unconventional plays, with year-to-date activity for 2014 consisting primarily of:

Southeast Texas (Woodbine) During the quarter ended June 30, 2014, we brought two operated gross wells (1.5 net) on production that were spud in the first quarter of 2014, and an additional two gross wells (1.4 net) that were spud and completed during the second quarter. In total, seven wells were brought on production in the Woodbine formation for the six months ended June 30, 2014. We will continue our focus on further developing our inventory of crude oil and liquids-rich projects in the Woodbine formation with a continuous one to two rig program planned for the rest of 2014. We have a multi-year inventory of potential drilling locations on our approximate 19,000 net acre position in Madison and Grimes counties, which we believe include the Woodbine, Eagle Ford Shale and Georgetown formations. As of June 30, 2014, we had 23 gross operated wells (16.7 net) producing in the Woodbine formation, consisting of 17 gross wells (12.8 net) in the Force area, three gross wells (1.8 net) in the Iola/Grimes area and three gross wells (2.1 net) in the Chalktown area.



South Texas (Buda)

During the quarter ended June 30, 2014, we brought three operated gross wells (1.7 net) on production that were spud during the first quarter of 2014, and an additional two gross wells (1.0 net) that were spud and completed during the second quarter. In total, eight wells were brought on production in the Buda formation for the six months ended June 30, 2014. We expect to continue having one to two rigs running full-time in 2014 as we continue to delineate the play over our 8,700 net acre position. As of June 30, 2014, we had twelve gross operated wells (6.2 net) producing from our Buda acreage.



Other (East Texas)

During the quarter ended June 30, 2014, we brought one gross (0.5 net) well on production that was spud during the first quarter of 2014, targeting the James Lime formation. In total, two wells were brought on production in the James Lime formation for the six months ended June 30, 2014. We will continue to monitor the production decline rate and liquids yield from our two wells in this region for several months, and if results support it, we could drill additional James Lime wells later in the year or in 2015. We have approximately 4,800 net acres in the area prospective for the James Lime.



We also 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.

Other (Tuscaloosa Marine Shale)

We own a 25% non-operated working interest in the Crosby 12H-1 well in Wilkinson County, Mississippi, and an average non-operated working interest of 1.4% in four other wells in Mississippi, all targeting the TMS, an oil-focused shale play in central Louisiana and Mississippi. We own approximately 29,000 net acres in what is considered the TMS play.



Other (Colorado)

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. 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. 25 --------------------------------------------------------------------------------



New Frontiers and Resource Plays

We continue to make preparations to spud our first well under our previously announced Exploration Agreement with a private company targeting multiple formations in Fayette County, Texas. To date, we have purchased approximately 42,000 gross acres in this play (18,000 net to Contango). We believe that the current acreage position, if the play is successful, could add up to 200 gross drilling locations of resource potential to our drilling inventory, based on 150 acre spacing. The drilling of an initial well is expected to commence in mid-to-late third quarter. We have the right to drill to earn approximately 119,500 gross acres (93,000 net acres with 80% working interest) in Wyoming on which we expect to soon test the application of horizontal drilling and hydraulic fractured completions on the Mowry Shale, a tight formation that has historically been produced thorugh vertical completions. We believe that our current acreage position, if the play is successful, could add up to 1,200 gross drilling locations of resource potential to our drilling inventory, based on 80 acre spacing. We expect to commence our initial operated well by the end of 2014.



Onshore Investments and Joint Ventures

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, $28.5 million has been received, and the remaining $2.0 million is expected to be received by the end of 2014.



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 June 30, 2014, we had invested approximately $46.9 million in Exaro. In April 2012, Exaro entered into an Earning and Development Agreement with Encana to provide funding of up to $380 million to continue the development drilling program in a defined area of Encana's Jonah Field located in Sublette County, Wyoming. This funding was to be comprised of the $182.5 million investment described above, debt and cash flow from operations. Upon investing the full amount of the $380 million, Exaro would have earned 32.5% of Encana's working interest in a defined joint venture area that comprises approximately 5,760 gross acres. In May 2014, Encana, the operator of the field, completed the sale of its Jonah Field operations to an independent third-party. In connection with this sale, the Earning and Development Agreement with Encana was terminated, with Exaro having earned 1,040 acres in the defined joint venture area. For all future wells to be drilled in this area, Exaro will have between a 14.4% and 32.5% working interest, depending on the location of the well. As of June 30, 2014, the Exaro venture had 113 new wells on production, producing at a rate of approximately 40 Mmcfed, net to Exaro, plus an additional 8 wells that are either in the completion or fracture stimulation phase. Exaro has indicated that they expect to have two drilling rigs running on this project during 2014. For the quarters ended June 30, 2014 and 2013, we recognized a gain of approximately $1.5 million and $1.9 million, net of tax expense of $(0.8) million and $(1.0) million, respectively, as a result of our investment in Exaro. For the six months ended June 30, 2014 and 2013, we recognized a gain of approximately $3.1 million and $0.7 million, net of tax expense of $(1.7) million and $(0.4) million, respectively, as a result of our investment in Exaro. We do not anticipate making any additional equity contributions in 2014. See Note 8 to our Financial Statements - "Investment in Exaro Energy III LLC" for additional details related to this investment. We intend to continue to evaluate potential acquisition opportunities to expand our presence in our resource plays, to exploit our oil and liquids-rich positions and to continue to develop exploration and exploitation opportunities where commodity price-justified. Acquisition efforts will typically be focused on areas in which we can leverage our geographic and geological expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves. 26

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Results of Operations for the Three and Six Months Ended June 30, 2014 and 2013

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 three and six months ended June 30, 2014 and 2013. 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 production taxes, such as ad valorem and severance taxes. Information for the three and six months ended June 30, 2013 includes results of operations of Contango prior to its merger with Crimson. Three Months Ended June 30, Six Months Ended June 30, 2014 2013 % 2014 2013 % Revenues: (thousands except prices) (thousands except prices) Oil and condensate sales $ 38,340$ 7,743 395.2 % $ 73,440$ 17,917 309.9 % Natural gas sales 31,244 18,381 70.0 % 65,871 34,394 91.5 % NGL sales 8,835 4,584 92.7 % 19,365 10,184 90.2 % Total revenues $ 78,419$ 30,708 155.4 % $ 158,676$ 62,495 153.9 % Production: Oil and condensate (thousand barrels) Offshore GOM 74 73 1.4 % 155 164 (5.5) % Southeast Texas 192 - n/a 378 - n/a South Texas 91 - n/a 168 - n/a Other 24 - n/a 37 - n/a Total oil and condensate 381 73 421.9 % 738 164 350.0 % Natural gas (million cubic feet) Offshore GOM 4,893 4,428 10.5 % 10,263 8,795 16.7 % Southeast Texas 888 - n/a 1,702 - n/a South Texas 729 - n/a 1,247 - n/a Other 220 - n/a 349 - n/a Total natural gas 6,730 4,428 52.0 % 13,561 8,795 54.2 % Natural gas liquids (thousand barrels) Offshore GOM 152 133 14.3 % 318 283 12.4 % Southeast Texas 72 - n/a 146 - n/a South Texas 31 - n/a 56 - n/a Other 2 - n/a 5 - n/a Total natural gas liquids 257 133 93.2 % 525 283 85.5 % Total (million cubic feet equivalent) Offshore GOM 6,250 5,662 10.4 % 13,098 11,477 14.1 % Southeast Texas 2,468 - n/a 4,846 - n/a South Texas 1,456 - n/a 2,594 - n/a Other 386 - n/a 598 - n/a Total production 10,560 5,662 86.5 % 21,136 11,477 84.2 % Daily Production: Oil and condensate (thousand barrels per day) Offshore GOM 0.8 0.8 1.4 % 0.9 0.9 (5.5) % Southeast Texas 2.1 - n/a 2.1 - n/a South Texas 1.0 - n/a 0.9 - n/a Other 0.3 - n/a 0.2 - n/a Total oil and condensate 4.2 0.8 421.9 % 4.1 0.9 350.0 % Natural gas (million cubic feet per day) Offshore GOM 53.8 48.7 10.5 % 56.7 48.6 16.7 % Southeast Texas 9.8 - n/a 9.4 - n/a South Texas 8.0 - n/a 6.9 - n/a Other 2.4 - n/a 1.9 - n/a Total natural gas 74.0 48.7 52.0 % 74.9 48.6 54.2 % 27

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Natural gas liquids (thousand barrels per day) Offshore GOM 1.7 1.5 14.3 % 1.8 1.6 12.4 % Southeast Texas 0.8 - n/a 0.8 - n/a South Texas 0.3 - n/a 0.3 - n/a Other - - n/a - - n/a Total natural gas liquids 2.8 1.5 93.2 % 2.9 1.6 85.5 % Total (million cubic feet equivalent per day) Offshore GOM 68.7 62.2 10.4 % 72.4 63.4 14.1 % Southeast Texas 27.1 - n/a 26.8 - n/a South Texas 16.0 - n/a 14.3 - n/a Other 4.2 - n/a 3.3 - n/a Total production 116.0 62.2 86.5 % 116.8 63.4 84.2 % Average Sales Price: Oil and condensate (per barrel) $ 100.53$ 106.07 (5.2) % $ 99.52$ 109.25 (8.9) % Natural gas (per thousand cubic $ 4.64$ 4.15 11.8 % $ 4.86$ 3.91 24.2 % feet) Natural gas liquids (per barrel) $ 34.40$ 34.47 (0.2) % $ 36.91$ 35.99 2.6 % Total (per thousand cubic feet $ 7.43$ 5.42 36.9 % $ 7.51$ 5.45 37.9 % equivalent) Expenses: Operating expenses $ 11,576$ 10,687 8.3 % $ 22,629$ 20,472 10.5 % Exploration expenses $ 10,853$ 5 ** $ 37,784$ 134 ** Depreciation, depletion and $ 39,901$ 10,230 290.0 % $ 74,303$ 20,724 258.5 % amortization Impairment and abandonment of oil $ 1,371$ 767 78.7 % $ 16,566$ 767 ** and gas properties General and administrative $ 9,207$ 5,757 59.9 % $ 19,664$ 8,965 119.3 % expenses Gain from investment in affiliates $ 1,478$ 1,880 (21.4) % $ 3,100$ 733 322.9 % (net of taxes) Selected data per Mcfe: Operating expenses $ 1.10$ 1.89 (41.8) % $ 1.07$ 1.78 (39.9) % General and administrative $ 0.87$ 1.02 (14.7) % $ 0.93$ 0.78 19.2 % expenses Depreciation, depletion and $ 3.78$ 1.81 108.8 % $ 3.52$ 1.81 94.5 % amortization ** Greater than 1,000%



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Natural Gas, Oil and NGL Sales and Production

All of our revenues are from the sale of our natural gas, oil and natural gas liquids production. Our revenues may vary significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our production volumes are subject to wide swings as a result of new discoveries, weather events, transportation and processing constraints, and mechanical problems. In addition, our production naturally declines over time as we produce our reserves. We reported revenues of approximately $78.4 million for the three months ended June 30, 2014, compared to revenues of approximately $30.7 million for the three months ended June 30, 2013. The increase in revenues was primarily attributable to: our merger with Crimson, which contributed approximately $41.3 million of revenues; approximately $2.9 million primarily due to a higher average realized price from our Dutch and Mary Rose field; approximately $2.3 million due to the increase in our working interest in Dutch wells in December 2013; and approximately $1.7 million more from production from our Vermilion 170 well. Total equivalent production increased from 62.2 Mmcfed to 116.0 Mmcfed, an increase of which 88% is attributable to our merger with Crimson. Our net natural gas production for the three months ended June 30, 2014 was approximately 74.0 Mmcfd, compared to approximately 48.7 Mmcfd for the three months ended June 30, 2013. This increase primarily resulted from a 3.7 Mmcfd increase due to the December 2013 purchase of an additional interest in our Dutch wells, 2.5 Mmcfd higher production at Vermillion 170, which was shut-in for a portion of the 2013 quarter, and 20.2 Mmcfd contributed by Crimson. Net oil production increased from 797 barrels per day to 4,191 barrels per day, and NGL production increased from approximately 1,458 barrels per day to 2,823 barrels per day, almost all of which is attributable to our merger with Crimson. 28

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Average Sales Prices The average equivalent sales price realized for the three months ended June 30, 2014 was $7.43 compared to $5.42 for the three months ended June 30, 2013. This increase was attributable primarily to a higher percentage of oil and liquids to total production and to the increase in the price of natural gas to $4.64 per Mcf, compared to $4.15 per Mcf for the three months ended June 30, 2013, offset in part by an approximate $5.50 per barrel decrease in oil prices.



Operating Expenses

Operating expenses for the three months ended June 30, 2014 were approximately $11.6 million, or $1.10 per Mcfe, compared to $10.7 million, or $1.89 per Mcfe, for the three months ended June 30, 2013. Operating expenses for the three months ended June 30, 2014 included approximately $6.5 million of lease operating expenses, $3.1 million of production and ad valorem taxes, $1.6 million related to transportation and processing costs and $0.4 million of workover costs. For the three months ended June 30, 2013, operating expenses included approximately $3.1 million in lease operating expenses, $0.7 million of production taxes, $0.8 million in transportation and processing costs and $6.1 million in workover costs related primarily to our Vermilion 170 well. The increase in lease operating expenses from $3.1 million to $6.5 million is primarily related to our merger with Crimson, which incurred approximately $4.7 million of lease operating expenses for the three months ended June 30, 2014, and the incremental cost related to several additional wells brought to production.



Exploration Expenses

Exploration expenses for the three months ended June 30, 2014 included $10.1 million in dry-hole costs related to our Ship Shoal 255 well finalized early in the second quarter. Impairment Expenses Impairment expenses for the three months ended June 30, 2014 included a $0.5 million impairment of an existing platform that was expected to be used by the Ship Shoal 255 well.



Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended June 30, 2014 was approximately $39.9 million or $3.78 per Mcfe. This compares to approximately $10.2 million or $1.81 per Mcfe for the three months ended June 30, 2013. The increase in depreciation, depletion and amortization was primarily attributable to increased production as a result of our merger with Crimson which contributed $29.0 million to the depreciation, depletion and amortization for the three months ended June 30, 2014. The higher depletion rate reflects the addition of the Crimson properties as a result of the Merger.



General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2014 were approximately $9.2 million, compared to $5.8 million for the three months ended June 30, 2013. This increase was primarily due to a $2.4 million increase in salaries and benefits as a result of the Merger ($1.3 million of which was an accrued merger-related bonus paid to Mr. Romano in July 2014) and $1.0 million in non-cash stock-based compensation.



Gain from Affiliates

For the three months ended June 30, 2014, the Company recorded a gain from affiliates of approximately $1.5 million, net of tax expense of $(0.8) million, related to our investment in Exaro, compared to a gain of $1.9 million, net of tax expense of $(1.0) million, for the three months ended June 30, 2013.



Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Natural Gas, Oil and NGL Sales and Production

All of our revenues are from the sale of our natural gas, oil and natural gas liquids production. Our revenues may vary significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our production volumes are subject to wide swings as a result of new discoveries, weather events, transportation and processing constraints, and mechanical problems. In addition, our production declines over time as we produce our reserves. We reported revenues of approximately $158.7 million for the six months ended June 30, 2014, compared to revenues of approximately $62.5 million for the six months ended June 30, 2013. The increase in revenues was primarily attributable to: our merger with Crimson, which contributed approximately $78.4 million of revenues; approximately $9.1 million primarily due to a higher average realized price from our Dutch and Mary Rose field; approximately $4.6 million due to the acquisition of an additional working interest in December 2013; approximately $5.4 million more from production from our Vermilion 170 well, 29 --------------------------------------------------------------------------------



which was shut-in for a substantial portion of the first quarter of 2013; and a higher average equivalent sales price realized for the period.

Total equivalent production increased from 63.4 Mmcfed to 116.8 Mmcfed, an increase of which 83% is attributable to our merger with Crimson. Our net natural gas production for the six months ended June 30, 2014 was approximately 74.9 Mmcfd, compared to approximately 48.6 Mmcfd for the six months ended June 30, 2013. This increase was primarily associated with a 3.6 Mmcfd increase due to the increase in ownership in the Dutch wells, a 3.3 Mmcfd increase due to reinstatement of production at Vermillion 170 and 18.2 Mmcfd was contributed by Crimson. Net oil production increased from 903 barrels per day to 4,077 barrels per day, and NGL production increased from approximately 1,563 barrels per day to 2,899 barrels per day, almost all of which was attributable to our merger with Crimson. Average Sales Prices The average equivalent sales price realized for the six months ended June 30, 2014 was $7.51 compared to $5.45 for the six months ended June 30, 2013. This increase resulted primarily from the higher percentage of oil and liquids production to total production and to the increase in the price of natural gas to $4.86 per Mcf, compared to $3.91 per Mcf for the six months ended June 30, 2013. Additionally, NGL prices increased to $36.91 per barrel, compared to $35.99 per barrel for the six months ended June 30, 2013. The price for oil decreased from $109.25 per barrel for the six months ended June 30, 2013 to $99.52 per barrel for the six months ended June 30, 2014.



Operating Expenses

Operating expenses for the six months ended June 30, 2014 were approximately $22.6 million, or $1.07 per Mcfe, compared to $20.5 million, or $1.78 per Mcfe, for the six months ended June 30, 2013. Operating expenses for the six months ended June 30, 2014 included approximately $12.9 million of lease operating expenses, $6.1 million of production and ad valorem taxes, $2.7 million related to transportation and processing costs and $0.9 million of workover costs. For the six months ending June 30, 2013, operating expenses included approximately $5.6 million in lease operating expenses, $1.7 million of production taxes, $1.8 million in transportation and processing costs and $11.4 million in workover costs related primarily to our Vermilion 170 well. The increase in lease operating expenses from $5.6 million to $12.9 million was primarily related to our merger with Crimson, which incurred approximately $8.8 million of lease operating expenses for the six months ended June 30, 2014, and to the incremental cost related to several additional wells being brought to production. Exploration Expenses



Exploration expenses for the six months ended June 30, 2014 included $36.8 million in dry-hole costs related to our Ship Shoal 255 well.

Impairment Expenses

Impairment expenses for the six months ended June 30, 2014 included a $3.5 million impairment of leasehold cost related to the Ship Shoal 255 block and $12.1 million for impairment of an existing platform, that was expected to be used by the Ship Shoal 255 well if it had been successful.



Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the six months ended June 30, 2014 was approximately $74.3 million or $3.52 per Mcfe compared to approximately $20.7 million or $1.81 per Mcfe for the six months ended June 30, 2013. The increase in depreciation, depletion and amortization was primarily attributable our merger with Crimson which contributed $51.7 million to this expense for the six months ended June 30, 2014. The higher depletion rate reflects the addition of the Crimson properties as a result of the Merger.



General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2014 were approximately $19.7 million, compared to $9.0 million for the six months ended June 30, 2013. This increase was primarily due to a $6.5 million increase in salaries and benefits as a result of the Merger ($2.6 million of which was an accrued merger-related bonus paid to Mr. Romano in July 2014) and $2.1 million in non-cash stock-based compensation. Other changes to general and administrative expenses include a $1.3 million increase in office and other related costs. 30

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Gain from Affiliates For the six months ended June 30, 2014, the Company recorded a gain from affiliates of approximately $3.1 million, net of tax expense of $(1.7) million, related to our investment in Exaro, compared to a gain of $0.7 million, net of tax expense of $(0.4) million, for the six months ended June 30, 2013.



Capital Resources and Liquidity

During the three months ended June 30, 2014, we incurred $56.2 million for capital projects. This includes $23.5 million related to drilling of the Woodbine formation in our Madison and Grimes counties area, $11.4 million for drilling of our Ship Shoal 255 well, $10.0 million in drilling the Buda formation in South Texas and $9.4 million for leased acreage in new areas.

During the six months ended June 30, 2014, we incurred $117.2 million for capital projects. This includes $38.2 million related to drilling of the Woodbine formation in our Madison and Grimes counties area, $33.3 million for drilling of our Ship Shoal 255 well, $19.1 million in drilling the Buda formation in South Texas, $8.9 million in East Texas, $11.0 million for leases in new areas and $3.3 million for facilities at our South Timbalier 17 well. Our capital expenditure budget for 2014 is currently forecasted to be between $215 and $225 million, including the amounts spent during the six months ended June 30, 2014, and is expected to be funded primarily from internally generated cash flow. Additionally, the Company often reviews acquisitions and prospects presented to us by third parties, and we may decide to invest in one or more of these opportunities. There can be no assurance that we will invest or that any investment we enter into will be successful. These potential investments are not part of our current capital budget and would require us to invest additional capital. Natural gas and oil prices continue to be volatile and our resources may be insufficient to fund any of these opportunities.



Cash From Operating Activities

Cash flows from operating activities provided approximately $127.8 million in cash for the six months ended June 30, 2014 compared to $48.7 million for the same period in 2013. For the six months ended June 30, 2014 and 2013, cash flows from operating activities, exclusive of changes in working capital accounts, were $112.0 million and $35.6 million, respectively.



Cash From Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2014 were approximately $103.9 million, including approximately $109.3 million used for capital expenditures related to drilling and developing wells, offset by $5.4 million in Alta distributions received during the period. Cash used in investing activities for the six months ended June 30, 2013 were approximately $26.7 million, including an $11.8 million outflow for capital expenditures related to drilling and developing wells and additional equity investments of $1.8 million in Alta and $13.1 million in Exaro.



Cash From Financing Activities

Cash flows used in financing activities for the six months ended June 30, 2014 were approximately $23.9 million, primarily all related to partial repayment of short-term borrowings outstanding under our RBC Credit Facility. The Company did not have any cash flows from financing activities for the six months ended June 30, 2013. RBC Credit Facility In October 2013, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders (the "RBC Credit Facility") with an initial hydrocarbon supported borrowing base of $275 million, which was reaffirmed as of May 1, 2014. This facility replaced the Company's $40 million secured revolving Credit Agreement with Amegy Bank ("Amegy Credit Agreement"). The Company incurred $2.2 million of arrangement and upfront fees for the RBC Credit Facility. Proceeds of the RBC Credit Facility will also be used (i) to finance working capital and for general corporate purposes (including requisitions), (ii) for permitted acquisitions and (iii) to finance transaction expenses in connection with the RBC Credit Facility and the Merger. The RBC Credit Facility is collateralized by substantially all of the assets of the Company and its subsidiaries. Borrowings under the RBC Credit Facility bear interest at a rate that is dependent upon LIBOR or the U.S. prime rate of interest, plus a margin dependent upon the amount outstanding under the facility.



As of August 7, 2014, the Company had outstanding debt of approximately $77.4 million under the RBC Credit Facility, and had no cash on hand.

Application of Critical Accounting Policies and Management's Estimates

The discussion and analysis of the Company's financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. 31

-------------------------------------------------------------------------------- The preparation of these consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company's significant accounting policies are described in Note 2 of Notes to Consolidated Financial Statements included in our Form 10-K/A for the year ended December 31, 2013. We have identified below the policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. The Company analyzes its estimates, including those related to natural gas and oil reserve estimates, on a periodic basis and bases its estimates on historical experience, independent third party reservoir engineers and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company's consolidated financial statements:



Oil and Gas Properties - Successful Efforts

Our application of the successful efforts method of accounting for our natural gas and oil exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.



Reserve Estimates

While we are reasonably certain of recovering our reported reserves, the Company's estimates of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future development costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's natural gas and oil properties and/or the rate of depletion of such natural gas and oil properties.



Impairment of Natural Gas and Oil Properties

The Company reviews its proved natural gas and oil properties for impairment whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows from each field to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company's estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates and anticipated capital expenditures. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that will require the Company to record an impairment of its natural gas and oil properties, and there can be no assurance that such impairments will not be required in the future nor that they will not be material.



Derivative Instruments

At the end of each reporting period, we record on our balance sheet the mark-to-market valuation of our derivative

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instruments. The estimated change in fair value of the derivatives is reported in Other Income and Expense as Loss on derivatives, net.

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. We are subject to taxation in several jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Estimating the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income and changes in shareholder ownership that limit the use of net operating losses under the Internal Revenue Code Section 382. Our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we used and actual amounts we reported are recorded in the period in which we file our income tax returns. We have a significant deferred tax asset associated with the net tax operating losses acquired in the Merger. The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. We expect we will be able to utilize all deferred tax assets despite the limitations of Internal Revenue Code Section 382, except those for which valuation allowance was provided. We will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods. Any adjustments or changes in our estimates of asset recovery could have an impact on our results of operations. See Note 10 - "Income Taxes" to our consolidated financial statements. The effective tax rate for the three and six months ended June 30, 2014 varies from the statutory rate primarily due to the effect of state income taxes, offset by the permanent differences related to deductible Merger transaction costs and additional depletion deductions for state taxes resulteing from the return to provision adjustments for federal and state taxes. The effective tax rate for the three and six months ended June 30, 2013 varied from the statutory rate due to non-taxable income related to life insurance proceeds partially offset by state income taxes and non-deductible merger related expenses.



Business Combinations

Accounting for business combinations requires that the various assets acquired and liabilities assumed in a business combination be recorded at their respective acquisition date fair values. The most significant estimates to us typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. Deferred taxes are recorded for any differences between fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value assigned to recoverable oil and gas reserves is subject to the impairment test when facts or circumstances indicate that the value of the properties may be impaired, and the value assigned to unproved properties is assessed at least annually to ascertain whether impairment has occurred. Our consolidated balance sheet presented as of June 30, 2014 reflects the purchase price allocations based on available information. If the initial accounting for the business combination is not complete, the amounts recognized for assets acquired and liabilities assumed in the financial statements may be adjusted during the measurement period of up to one year as specified by ASC 805, Business Combinations.



Recent Accounting Pronouncements

In May 2014, the FASB and the International Accounting Standards Board ("IASB") jointly issued new accounting guidance for recognition of revenue. This new guidance replaces virtually all existing US GAAP and IFRS guidance on revenue recognition. The new guidance is effective for fiscal years beginning after December 15, 2016. This new guidance applies to all 33 -------------------------------------------------------------------------------- periods presented. Therefore, when the Company issues its financial statements on Forms 10-Q and 10-K for periods included in its year ended December 31, 2017, its comparative periods that are presented from the years ended December 31, 2015 and 2016, must be retrospectively presented in compliance with this new guidance. Early adoption is not allowed for US GAAP. The new guidance requires companies to make more estimates and use more judgment than under current accounting guidance. The Company is currently evaluating (i) the two allowed adoption methods to determine which method it plans to use for retrospective presentation of comparative periods and (ii) whether the implementation of this new guidance will have a material impact on the Company's consolidated financial position or results of operations for the periods presented. In April 2014, the FASB issued amendments to guidance for reporting discontinued operations and disposals of components of an entity. The amended guidance requires that a disposal representing a strategic shift that has (or will have) a major effect on an entity's financial results or a business activity classified as held for sale should be reported as discontinued operations. The amendments also expand the disclosure requirements for discontinued operations and add new disclosures for individually significant dispositions that do not qualify as discontinued operations. The amendments are effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2014 (early adoption is permitted only for disposals that have not been previously reported). The implementation of the amended guidance is not expected to have a material impact on the Company's consolidated financial position or results of operations. In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. We are currently evaluating the provisions of ASU 2014-08 and assessing the impact, if any, it may have on our financial position and results of operations. In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), revised its criteria related to internal controls over financial reporting from the originally established 1992 Internal Control - Integrated Framework with 2013 Internal Control - Integrated Framework. The modified framework provides enhanced guidance that ties control objectives to the related risk, enhancement of governance concepts, increased emphasis on globalization of markets and operations, increased recognition of use and reliance on information technology, increased discussion of fraud as it relates to internal control, changes of control deficiency descriptions, and that internal reporting is included in both financial and nonfinancial objectives. The revised framework is effective for interim and annual periods beginning after December 15, 2013. We plan to implement any changes required by the new COSO framework during the year ended December 31, 2014. Currently, we are evaluating the provisions of the revised framework and continue to assess the impact, if any, it may have on our internal control structure. In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2013-04 Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU 2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice. The accounting update is effective for interim and annual periods beginning after December 15, 2013. The provisions of this accounting update did not have a material impact on our financial position or results of operations.



Off Balance Sheet Arrangements

We may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of June 30, 2014, the primary off-balance sheet arrangements that we have entered into included short-term drilling rig contracts and operating lease agreements, all of which are customary in the oil and gas industry. Other than the off-balance sheet arrangements shown under operating leases in the commitments and contingencies table included in our Annual Report on Form 10-K/A for the year ended December 31, 2013, we have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.


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