Properties

O ffshore Gulf of Mexico

As of December 31, 20 14 ,   our offshore production consisted of seven federal and six State of Louisiana Company-operated wells in the shallow waters of the G O M. These 13 wells produce from four fields. The following summary table sets forth certain information with respect to our offshore reserves as of December 31, 2014 and average daily production for the year ended December 31, 20 14 :

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 own the lease for the Eugene Island 11 block, this does not impact our ability to operate our facilities located on that block. Operators in the G O M   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 our production platform we are able to access two separate markets which minimizes downtime risk and provides the ability for us to select the best sales price for our oil and natural gas production . Oil and natural gas production can flow via a TC Offshore (formerly ANR) pipeline to third-party owned and operated onshore processing facilities near Patterson, Louisiana. Alternatively, natural 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 th ird-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.

We installed   a turbine type compressor of sufficient capacity , based on normal production decline rates, to ultimately service all ten Dutch and Mary Rose wells at the Eugene Island 11 platform in July 2014. As of December 31, 20 14 , we had incurred approximately $ 11 . 7 million to design , build and install the compressor. We started central compression at the platform during the third quarter of 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 Company -operated Dutch wells from an independent oil and gas company for approximately $1 5 million, net after   customary purchase price adjustment s.

Vermilion 170 Field

We operate one well at Vermilion 170 which flows to a Company-owned and operated production platform at the same location. This platform services natural gas and condensate production, which flow via the Sea Robin Pipeline to a third-party owned and operated onshore processing plants. Based on production and decline rates, we designed, built and installed a compressor in 2013 at a cost of approximately $1.4 million. We anticipate commencing compression in late   2015 or early   2016 .  

In January 2013, sustained casing pressure was identified between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well production was shut-in in January ,   and the original tubing and casing were successfully removed. Operations were conducted to replace the tubing and restore the well , which resumed production in June 2013. During December 2014, our Vermillion 170 well production was shut-in for fourteen days due to issues with the Sea Robin Pipeline.

Other Offshore

Our Ship Shoal 263 and South Timbalier 17 fields have been included in “Other Offshore." We operate one well at Ship Shoal 263, which produces to a Company-owned and operated production platform at the same location.

On April 29, 2014, we reached total depth on our Ship Shoal 255 prospect in the GOM, and no commercial hydrocarbons were found. As a result, for the twelve months ended December 31, 2014, we recognized $31.5 million in exploration expense for the cost of drilling the well plus $15.6 million in impairment expense associated with $3.5 million of leasehold costs and $12.1 million related to a platform located in Block Ship Shoal 263 that was expected to be used by the Ship Shoal 255 well had it been successful.

On July 30, 2013, we spud our South Timbalier 17 prospect in state of Louisiana offshore waters, and on August 22, 2013 we announced completion of a successful well at a total measured depth of approximately 11,400 feet . After we completed the well and laid flowlines to a third -party owned facility, we commenced production in July 2014. Our n et costs incurred to drill, complete and bring this well on p roduction were $15.9 million as of December 31, 20 14 . 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.   In December 2014, due to the low price environment , the net book value of our South Timbalier 17 exceeded the future undiscounted cash flows associated with its recoverable reserves , and we recognized an impairment expense of approximately $7.7 million during the year ended December 31, 2014.

During the year ended December 31, 2012, we spud our Ship Shoal 134 and South Timbalier 75 prospects, and no commercial hydrocarbons were found. The Company has plugged and abandoned both wells. We incurred approximately $50.0 million to drill, plug and abandon these wells, including approximately $6.6 million in leasehold costs.

We currently hold six untested exploratory prospects on 1 5 offshore lease blocks.   During the year ended December 31, 2014, w e recognized full impairment related to the prospects which we do not currently intend to drill. We will pursue opportunities to realize future value from these leases through farmout , a sale or a possible trade for onshore opportunities.

Onsh ore Properties

Southeast Texas (Woodbine)

As of December 31, 20 14 , our Southeast Texas region included approximately 3 9,900 g ros s (23,000 n et) acres, proven reserves of 63.8 Bcfe, and 91 gross (50.7 net) producing wells. Crimson has been active in 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 . During 2013, Crimson, and subsequently Contango, drilled 12 gross ( 8.0 net) wells on acreage targeting the Woodbine formation. During 20 14 ,   we drilled 18 gross ( 11.6 net) wells on acreage targeting the Woodbine formation. As of December 31, 2014, eight of these wells were producing, two were being evaluated and   eight were in various stages of drilling or completion.

For 2015, our current budget includes complet ing the   six wells initiated in late 2014 utilizing a pad drilling strategy on 500 foot spacing in the Chalktown area. When drilling from pads, several wells are drilled in succession, then completed in succession, and then put on production simultaneously to maximize recovery. Our 2015 budget also includes a single well in our Chalktown area that satisfies a farm-in commitment and a horizontal test of the previously untested Lower Lewisville formation in our Grimes County area. Should commodity prices improve and/or service costs decline meaningfully, we may increase our activity in this area .   We currently have approximatel y 1 6 , 1 00  net acres in Madison and Grimes counties ( approximately 50 % of which is held by production) , with a multi-year inventory of potential drilling locations, includ ing the Woodbine, Eagle Ford Shale and Georgetown /Buda formations. As of December 31, 2014, we had 28 gross wells (17. 9 net) producing in the Woodbine formation, including 20 gross wells (12.9 net) in the Force area , four gross wells (2.2 net) in the Iola/Grimes area and four gross wells (2. 8 net) in the Chalktown area.

On December 31, 2013, we sold to an independent oil and gas company approximately 7.1% of our interest in all developed and undeveloped properties in Madison and Grimes Counties for   approximately $20.4 million, or $91,007 per flowing barrel of equivalent daily production and $47.32 per equivalent barrel of proved reserves.

South Texas (Buda /Eagle Ford )

As of December 31, 20 14 , our South Texas region included approximately 1 65 , 8 00 gross ( 83 , 2 00 net) acres , proven reserves of 53.7 Bcfe, and 273 gross (143.4 net) producing wells. Of this, approximately 41 , 3 00   gross ( 21 , 4 00 net) acres are targeting the Buda and Eagle Ford Shale plays, approximately 7 0% 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 seven gross wells ( 3.3 net) in the Buda formation in Zavala and Dimmit counties. Six of the wells were successful, while one was a mechanical failure which was side tracked in 2014 . During 20 14 ,   we drilled 14 gross wells ( 6.8 net) in the Buda formation in Zavala and Dimmit counties , all of which are currently producing .   We drilled one additional well in Zavala and Dimmit counties during the fourth quarter of 2014 as a vertical pilot well to test the viability of the Eagle Ford and other formations in the area .   We are evaluating the recovered cores before deciding on a development strategy for these areas. Our current capital program does not contemplate further drilling in Zavala and Dimmit counties in 2015 without improvement in the commodity price environment and/or service cost structure .   Our estimated net proven Buda/Eagle Ford reserves in this area were 15 . 4  Bcfe, comprised of 76 % liquids , with 2 6   gross ( 1 3.3 net) producing wells, as of December 31, 20 14 .

South Texas (Elm Hill Project)

As of December 31, 2014, we held approximately 55,900 g ross acre s (25,100 n et) in Fayette, Gonzales, Caldwell and Bastrop counties, Texas. We believe that the current acreage position, if the play is successful, could add up to 200 gross drilling locations to our drilling inventory. During 2014, we drilled four gross wells (2 . 0 net) in this area, two of which commenced production during the fourth quarter of 2014, with the other two expected to commence production in early 2015. We currently plan to drill one more well during the first quarter of 2015 and then monitor area results before determining future plans for the area.

The remaining 6 8 , 600 gross (36 , 7 00 net) acres in our South Texas region are located in our conventional fields that produce primarily from the Wilcox, Frio, and Vicksburg sands. Our estimated net proved conventional reserves in this region were 38 . 3  Bcfe, comprised of 76 % gas, with 24 5  gross (1 29 . 1  net) producing wells, as of December 31, 2014.

Natrona County, Wyoming (FRAMS Project )

In 2014, we acquired the right to earn approximately 119, 3 00 gross acres (93,000 net acres with an   80% working interes t) in Natrona County, Wyoming. During the fourth quarter of 2014, we sold a 20% working interest in this prospect to an independent oil and gas company, reducing our potential ownership to approximately 69,900 net acre s with a 60% working interest. We spud our first well in this play during the fourth quarter of 2014 targeting the Mowry Shale, and expect to complete that well late in the first quarter

or early second quarter of 2015. W e will evaluate results from the first well for a number of months and determ ine future drilling plans for this area.

Weston County, Wyoming (N. Cheyenne Project)

In 2014, we acquired the right to earn approximately 49,000 gross acres (44,000 net acres with a 90% to 100% working interest ) in Weston County, Wyoming. During the fourth quarter of 2014, we sold a 20% working interest in this prospect to an independent oil and gas company, reducing our potential ownership to approximately   35,000 net acres with a 72% to 80% working interest. We spud our first well in this play during the first quarter of 2015 targeting the Muddy Sandstone formation, and currently plan to complete that well early in the second quarter of 2015. W e will evaluate results from the first well for a number of months and determine future drilling plans for th is area. This acreage is approximately 125 miles to the northeast of our Natrona County acreage.

Other (East Texas)

As of December 31, 20 14 , our East Texas region included approximate ly 7,400 gross (4,300 n et) acres primarily in San Augustine County, with proven reserves of 8.3 Bcfe comprised of 65 % gas, and ten gross (5.1 net) p roducing wells. Crimson actively developed the dry gas Haynesville and Mid-Bossier Shales in this area in 2009 through 2011 during a more favorable natural gas price environment. During 20 14 , we drilled two gross (1.2 net) wells targeting the shallower , liquids - rich James Lime formation on our acreage in San Augustine County. We believe that the further exploitation of our acreage in the Haynesville , Mid-Bossier and James Lime formations will provide long-term natural gas reserve and production growth potential in the future; however, we do not anticipate devoting drilling capital to these formations until we see a sustained meaningful improvement in the natural gas price environment .   As of December 31, 20 14 ,   approximately 69 % of our acreage in our East Texas region is held by production.

Other (Colorado)

We hold approximately 16, 10 0 gross (11,2 00 net) acres in the DJ Basin in Colorado (mostly in Adams and Weld counties). There has been sporadic 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 established 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 of this play is still uncertain due to the limited activity in the area and the current commodity price environment .  Substantially all of our acre age in the DJ Basin   is held by production. We plan to monitor the 20 15 industry activity and results of our peers in the Niobrara Shale to determine our future strategy for maximizing the value of our position in the area.

Other (Tuscaloosa Marine Shale “TMS” )

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 less than 2.0% in three other wells in Mississippi, all targeting the TMS, an oil-focused shale play in central Louisiana and Mississippi. The Crosby 12H-1 well is operated by Goodrich Petroleum Company LLC ("Goodrich ”).

In addition, as of December 31, 20 14 , we have   approximately 40, 8 00 gross (29,000 net) undeveloped acres under lease in the TMS. To date, we have elected to participate in three non-operated wells (excluding the Crosby 12H-1 discussed above) where our acreage has been pooled into units: (i) the Goodrich-operated CMR   Foster Creek 20-7H #1 well, where we own less than a 1% working interest; (ii) the Goodrich-operated Huff 18-7H #1 well, where we own approximately a 3% working interest; and (iii) the Goodrich -operated CMR Foster Creek 24-13H #1 well, where we own less than a 2% working interest. Due to the poor economics we have experienced in the area related to high drilling and completion costs and the current low oil price environment, we do not expect to drill TMS wells in the near future. Given the low likelihood that we will devote any capital to this area prior to lease expirations in 2015 and 2016, we recognized impairment of certain unproved properties in the third and fourth quarters of 2014. We plan to continue to evaluate participation in third- party operated wells with a small working interest as a means to obtain data from these wells to assist us in evaluating , and maximizing value, from our TMS acreage.

Other

As of December 31, 20 14 , we held approxim ately 3, 3 00 gross (6 2 0 net ) acres in small non-operated working interests in the Fenton field area of Calcasieu Parish, Louisiana and a minor operated crude oil property in Mississippi.

Ons hore Investments

Kaybob Duvernay – Alberta, Canada

In 2011, we invest ed 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 , for approximately $30.5 million net to us . Of this amount, we have received $2 8 . 5  million , and we expect to receive   the remaining $ 2.0  million within the next twelve months .

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 for a 37% ownership interest. As of December 31, 20 14 , we had invested approximately $46.9 million in Exaro. We account for Contaro ’s ownership in Exaro using the equity method of accounting, and therefore, do not include its share of individual operating results, reserves or production in those reported for our consolidated results.

As of December 31, 20 14, Exaro   had 6 25 wells on production over its 1,040 net acres, with a working int erest between 14.4% and 32.5%. These wells were producing at a rate of approximately 41 Mmcfed, net to Exaro, plus an additional four wells that are either in the completion or fracture s timulation phase. The operator expect s to have two drilling rigs running on this project during 20 15 . For the year ended December 31, 20 14 , the Company recognized a net investment gain of approximately $ 6 . 9  million, net of tax expense of $ 3 . 8  million, as a result of its investment in Exaro. As of December 31, 2014, reserves attributable to our investment in Exaro were 70 . 2 Bcfe . We do not anticipate making any additional equity contributions during 20 15 as Exaro estimates that drilling capital will be funded through internally generated cash flow and borrowings under its revolving credit facility . See Note 11 to our Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.

Ou tlook

As a result of the dramatic downturn in crude oil, natural gas and natural gas liquids pricing in late 2014 and early in 2015, the negative impact of those price declines on the economics of most domestic resource plays, and the continuing uncertainty as to when, or how much, the price environment might improve, our capital expenditure program for 2015 will be focused on: (i) the preservation of our strong and flexible financial position, including limiting our 2015 capital expenditure budget to no more than internally generated cash flow; (ii) focusing drilling expenditures on strategic projects ; (iii) identification of opportunities for cost efficiencies in all areas of our operations; and (iv) continuing to identify new resource potential opportunities, internally and through acquisition. Our current capital budget for 2015 should allow us to meet our contractual requirements, remain in position to preserve our term acreage where appropriate and maintain our strong financial profile. We will continuously monitor the commodity price environment, stability and forecast, and if warranted, make adjustments to that strategy as the year progresses. Our capital expenditure budget is currently forecasted at approximately $ 50 . 6 million ; a decrease of over 7 3 % compared to our 2014 capital expenditures , and is expected to be funded from internally generated cash flow .   Primary drilling activity is currently planned as follows:

Ti tle to Properties

From time to time, we are involved in legal proceedings relating to claims associated with ownership interests in our properties. We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, and liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. As

is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Detailed investigations, including a title opinion rendered by a licensed independent third party attorney, are typically made before commencement of drilling operations.

We have granted mortgage liens on substantially all of our natural gas and crude oil properties to secure our senior secured revolving credit facility. These mortgages and the related credit agreement contain substantial restrictions and operating covenants that are customarily found in credit agreements of this type. See Note 13 to our Financial Statements ‑ “Long-Term Debt” for further information.

Ma rketing and Pricing

We derive our revenue principally from the sale of natural gas and oil. As a result, our revenues are determined, to a large degree, by prevailing natural gas and oil prices. We sell a portion of our natural gas production to purchasers pursuant to sales agreements which contain a primary term of up to three years and crude oil and condensate production to purchasers under sales agreements with primary terms of up to one year. The sales prices for natural gas are tied to industry standard published index prices, subject to negotiated price adjustments, while the sale prices for crude oil are tied to industry standard posted prices subject to negotiated price adjustments.

We typically utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural gas and natural gas liquids production , by using a series of swaps and costless collars. As of December 31, 2014, however, we had no co mmodity price hedges in place. Unrealized gains or losses vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities and interest rates being hedged.

Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:

Historically, we have been dependent upon a few purchasers for a significant portion of our revenue. Major purchasers of our natural gas, oil and natural gas liquids for the year ended December 31, 20 14 , calculated on an equivalent basis, were ConocoPhillips Company ( 31 % ),   Sunoco Inc. (2 7 %), Shell Trading US Company ( 10 % ), Exxon Mobil Oil Corporation ( 7 %), and Enterprise Products Operating LLC ( 5 % ) . This concentration of purchasers may increase our overall exposure to credit risk, and our purchasers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations could be materially adversely affected if one or more of our significant purchasers fails to pay us or ceases to acquire our production on terms that are favorable to us. However, we believe our current purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Com petition

The oil and gas industry is highly competitive and we compete with numerous other companies. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independent companies, including many that have significantly greater financial resources.

The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining purchasers and transporters for the natural gas and crude oil we produce. There is also competition between producers of natural gas and crude oil and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state and local g overnment s ; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing natural gas and crude oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Gove rnmental Regulations and Industry Matters

Federal Income Tax

Federal income tax laws significantly affect our operations. The principal provisions affecting us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic natural gas and oil properties and to claim a manufacturing deduction based on qualified production activities.

Industry Regulations

The availability of a ready market for crude oil, natural gas and natural gas liquids production depends upon numerous factors beyond our control. These factors include regulation of crude oil, natural gas, and natural gas liquids production, federal ,   state and local regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of crude oil, natural gas and natural gas liquids available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the area in which the well is located. State and federal regulations generally are intended to prevent waste of crude oil, natural gas, and natural gas liquids, protect rights to produce crude oil, natural gas and natural gas liquids between owners in a common reservoir, control the amount of crude oil, natural gas and natural gas liquids produced by assigning allowable rates of production, and protect the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.

The following discussion summarizes the regulation of the U.S. oil and gas industry. We believe that we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

Regulation of Crude Oil, Natural Gas and Natural Gas Liquids Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of crude oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project, if the operator owns less than 100% of the leasehold. In addition, state conservation laws, which establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and

impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of crude oil, natural gas and natural gas liquids we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability. Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price of natural gas produced by us, and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938 (the “NGA”), the Federal Energy Regulatory Commission (the “FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all sales by us of our own production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. However, the Decontrol Act did not affect the FERC’s jurisdiction over natural gas transportation.

Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit market manipulation by any person, including marketers, in connection with the purchase or sale of natural gas, and the FERC has issued regulations to implement this prohibition. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation.

Under the 2005 Act, the FERC has also established regulations that are intended to increase natural gas pricing transparency through, among other things, new reporting requirements and expanded dissemination of information about the availability and prices of gas sold. For example, on December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704 as clarified in orders on clarification and rehearing. In addition, to the extent that we enter into transportation contracts with interstate pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such interstate capacity. Any failure on our part to comply with the FERC’s regulations could result in the imposition of civil and criminal penalties.

Our natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional passage of the Natural Gas Policy Act of 1978 (the “NGPA”), the FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas. Beginning with the adoption of Order No. 436, issued in October 1985, the FERC has implemented a series of major restructuring orders that have required interstate pipelines, among other things, to perform “open access” transportation of gas for others, “unbundle” their sales and transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained direct access to the particular interstate pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. We do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural gas with which we compete.

In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation, or “lighter handed” regulation, and the promotion of competition in the gas industry. There regularly are other legislative proposals pending in the federal and state legislatures that, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas. Again, we do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas with which we compete.

Oil Price Controls and Transportation Rates

Sales prices of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (the “FTC”) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of up to $1 million per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.

The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of the transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC’s regulation of crude oil and natural gas liquids transportation rates may tend to increase the cost of transporting crude oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.

Environmental and Occupational Health and Safety Matters

Our crude oil and natural gas exploration, development and production operations are subject to stringent federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment, or otherwise relating to environmental protection. Numerous governmental authorities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may require the acquisition of a permit to conduct drilling and other regulated activities, restrict the types, quantities and concentration of various substances that may be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from current or former operations; impose specific health and safety criteria addressing worker protection; and impose substantial liabilities for pollution resulting from production and drilling operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of orders enjoining some or all of our operations in affected areas. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue in the future, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental actions are taken that result in more stringent and costly well drilling, construction, completion, water management activities, waste handling, storage, transport, disposal or remediation requirements, our business and prospects could be materially and adversely affected.

Our domestic natural gas and oil operations, including those involving federal and state leases in the U.S. Gulf of Mexico, are subject to extensive federal and state regulation and imposition of environmental liabilities or possible interruption or termination of leasing activities by governmental authorities. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund Law”, and similar state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous su bstance” into the environment.  These potentially responsible persons include the current or past owner or

operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances released at the site.  Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (the “RCRA”), and comparable state statutes. The RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous wastes, and the EPA and analogous state agencies stringently enforce the approved methods of management and disposal of these wastes. While the RCRA currently exempts certain drilling fluids, produced waters, and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes, we can provide no assurance that this exemption will be preserved in the future. Repeal or modification of this exclusion or similar exemptions under federal or state law could increase the amount of waste we are required to manage and dispose of as hazardous waste rather than non-hazardous waste, and could cause us to incur increased operating costs, which could have a significant impact on us as well as the natural gas and oil industry in general. In any event, these excluded wastes are subject to regulation as nonhazardous wastes.

We currently own, lease or operate numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we believe that we have used good operating and waste disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the petroleum hydrocarbons or wastes disposed thereon may be subject to the CERCLA, RCRA and analogous state laws as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, which may impose strict, joint and several liability, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

The Clean Air Act, as amended (the “CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of crude oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in December 20 14 , the EPA published a proposed rule making that it expects to finalize by October 1, 2015, which rulemaking proposes to revise the National Ambient Air Quality Standard for ozone between 65 to 70 parts per billion (“ppb”) for both the 8-hour primary and secondary standards. Compliance with this or other regulatory initiatives could directly impact us by requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines and significantly increasing our capital expenditures and operation costs, which could adversely impact our business.

Based on findings made by the EPA that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions . Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources, should such sources exceed threshold emission levels. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, which include the majority of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

While Congress has, from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future federal laws or regulations that impose reporting obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce. For example, on January 14, 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our assets and operations.

The Federal Water Pollution Control Act, as amended (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. Any such discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The disposal of oil and natural gas wastes into underground injection wells are subject to the Safe Drinking Water Act, as amended, or SDWA, and analogous state laws. The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities that may be injected, and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for alternative water supplies, property damages and personal injuries. While we believe that we have obtained the necessary permits from the applicable regulatory agencies for our underground injection wells and that we are in substantial compliance with applicable permit conditions and federal and state rules, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into belowground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission (“TRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs. .

The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA applies to vessels, onshore facilities, and offshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities and lessees and permittees of offshore leases may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. In December 2014, the Bureau of Ocean Energy Management (the “BOEM”) issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including preparation of oil spill response plans for responding to a worst-case discharge of oil into waters of the U.S., and proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility in the form of a Certificate of Financial Responsibility ("COFR") for its offshore facilities. However, the Company cannot predict whether significantly higher COFR amounts under any future OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives under pressure into targeted subsurface formations to stimulate production. We routinely use hydraulic fracturing techniques in many of our completion programs. Hydraulic fracturing typically is regulated by state oil and gas commissions, or other similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process . For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”) issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hy draulic fracturing activities.  States could elect to prohibit hydraulic fracturing altogether, such as the State of New York announced in December 2014. Local government may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or completing wells.

In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review the first half of 2015 . These ongoing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing .

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party pollution claims in accordance with, and subject to the terms of such policies.

Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the BLM , are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Environmental laws such as the Endangered Species Act, as amended (“ESA”), may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (the “FWS”) is required to make a determination on listing of numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in March 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, where we conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. T he designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures , time delays or limitations on our drilling program activities, which costs delays or limitation could have an adverse impact on our ability to develop and produce reserves.

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

In response to the Deepwater Horizon drilling rig explosive incident and resulting oil spill in the United States Gulf of Mexico in 2010, the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”), each agencies of the U.S. Department of the Interior, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters.  These governmental agencies have implemented and enforced new rules, Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities.  In addition, states may adopt and implement similar or more stringent legal requirements applicable to exploration and production activities in state waters.  Compliance with these added and more stringent regulatory restrictions, in addition to any

uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development and oil spill-response plans could adversely affect or delay new drilling and ongoing development efforts, which could have a material adverse impact on our business.  Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, developing and implementing new, more restrictive requirements.  One example is the 2013 amendments to the federal Workplace Safety Rule regarding the utilization of a more comprehensive safety and environmental management system (“SEMS”), which amended rule is sometimes referred to as SEMS II.  A second, and more recent, example is the August 2014 Advanced Notice of Proposed Rulemaking that ultimately seeks to bolster the offshore financial assurance and bonding program.  Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production.  If material spill incidents similar to the Deepwater Horizon incident were to occur in the future, the United States could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which developments could have a material adverse effect on our business.

Other Laws and Regulations

Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.

The BOEM administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The BOEM holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the BOEM changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea floor. The BOEM requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. As an operator, the Company is required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities. However, in August 2014, BOEM published an Advance Notice of Proposed Rulemaking, pursuant to which it seeks to bolster its current bonding requirements for offshore oil and gas operations.

R isk and Insurance Program

In accordance with industry practice, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from significant losses resulting from damages to, or the loss of, physical assets or loss of human life, and liability claims of third parties, including such occurrences as well blowouts and weather events that result in oil spills and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can afford considering the cost of insurance, against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico could lead to tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases in liability caps for cla ims of damages from oil spills.

We maintain significant insurance coverage attributable to our net share of any potential financial losses occurring as a result of potential perils, including well control coverage of $ 75  million, which covers control of well, pollution cleanup and consequential damages. We also maintain $150 million of general liability coverage, which covers pollution cleanup, consequential damages coverage, and third party personal injury and death, and $35  million of Oil Spill Financial Responsibility coverage, which covers additional pollution cleanup and third party claims coverage.

Health, Safety and Environmental Program

Our Health, Safety and Environmental (“HS&E”) Program is supervised by an operating committee of senior management to insure compliance with all state and federal regulations. In support of the operating committee, we have contracted with J. Connor Consulting (“JCC”) to coordinate the regulatory process relati ve to our offshore assets. JCC is a regulatory consulting firm specializing in the offshore Gulf of Mexico . They provide preparation of incident response plans, safety and environmental services and facilitation of comprehensive oil spill response training and drills on behalf of oil and gas companies and pipeline operators.

A ddition ally ,   in support of our Gulf of Mexico operations, we have established a Regional Oil Spill Plan which has been approved by the BOEM. Our response team is trained annually and is tested through in-house spill drills. We have also contract ed with O’Brien’s Response Management (“O’Brien’s”) , who maintains a n incident command center on 24 hour alert in Slidell, LA. In the event of an oil spill, the Company’s response program is initiated by notifying O’Brien’s any   incident while the Company   response team is mobilized to focus on source control and containment of the spill .   O’Brien’s would coordinate communication s with state and federal agencies and would provide subject matter expertise in support of the response team.

W e have also contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs in the event of a spill . CGA specializes in onsite control and cleanup and is on 24 hour alert with equipment currently stored at six bases along the gulf coast (Ingleside and Galveston, TX; Lake Charles, Houma, and Venice, LA; and Pascagoula, MS) . CGA is opening new sites in Leeville, Morgan City and Harvey, LA. The CGA equipment stockpile is available to serve member oil spill response needs and includes open seas   skimm ers, and shoreline protection boom, communications equipment, dispersants with application systems, wildlife rehabilitation and a forward command center. CGA has retainers with aerial dispersant and mechanical recovery equipment contractors for spill response .

In addition to our membership in CGA, the Company has contracted with Wild Well Control for source control at the wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting and well control services.

We also have a full time health, safety and environmental professional who supports our operations and oversees the implementation of our onshore HS&E policies.

Safety and Environmental Management System

We have developed and implemented a Safety and Environmental Management System (“SEMS”) to address oil and gas operations in the Outer Continental Shelf (“OCS”), as required by the BSEE. Our SEMS identifies and mitigates safety and environmental hazards and the impacts of these hazards on design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. The Company has established goals, performance measures, training and accountability for SEMS implementation . We also provide the necessary resources to maintain an effective SEMS and we review the adequacy and effectiveness of the SEMS program annually .   Company f acilities are designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes, consensus standards, and all applicable governmental regulations. We have contracted with Island Technologies Inc. to coordinate our SEMS program and to track compliance for production operations.

The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may result in an Incident of Non-Compliance and could ultimately require a shut-in our Gulf of Mexico operations if not resolved within the required time.

E mployees

On December 31, 20 14 , we had 92 full time employees, of which 23 were field personnel. We have been able to attract and retain a talented team of industry professionals that have been successful in achieving significant growth and success in the past. As such, we are well-positioned to adequately manage and develop our existing assets and also to increase our proved reserves and

production through exploitation of our existing asset base, as well as the continuing identification, acquisition, and development of new growth opportunities. None of our employees are covered by collective bargaining agreements. We believe our relationship with our employees is good.

In addition to our employees, we use the services of independent consultants and contractors to perform various professional services. As a working interest owner, we rely on certain outside operators to drill, produce and market our natural gas and oil where we are a non-operator. In prospects where we are the operator, we rely on drilling contractors to drill and sometimes rely on independent contractors to produce and market our natural gas and oil. In addition, we frequently utilize the services of independent contractors to perform field and on-site drilling and production operation services and independent third party engineering firms to evaluate our reserves.

Dire ctors and Executive Officers

See “Item 10. Directors , Executive Officers and Corporate Governance ” , which information is incorporated herein by reference.

Co rporate Offices

Effective October 1, 2013, we moved our corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease that expires March 31, 2019. Rent, including parking, related to this office space for the year ended December 31, 20 14 was approximately $ 2 . 1 million. We remain responsible for the rent at our previous corporate office at 3700 Buffalo Speedway in Houston, Texas, through February 29, 2016. Effective January 1, 2014, we subleased our previous corporate offices through February 29, 2016 and expect to recover the substantial majority of the r ent we pay at that location.

Co de of Ethics

We adopted a Code of Ethics for senior management in December 2002. In January 2014, our board of directors adopted a new Code of Business Conduct and Ethics ("Code of Conduct") that applies to all directors, officers and employees of the Company. Our Code of Conduct is available on the Company's website at www.contango.com. Any shareholder who so requests may obtain a copy of the Code of Conduct by submitting a request to the Company's corporate secretary at the address on the cover of this Form 10-K . Changes in and waivers to the Code of Conduct for the Company's directors, chief executive officer and certain senior financial officers will be posted on the Company's website within five business days and maintained for at least 12 months. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Report on Form 10-K.

Ava ilable Information

You may read and copy all or any porti on of this report on Form 10-K , our quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, without charge at the office of the Securities and Exchange Commission (the “SEC”) in Public Reference Room, 100 F Street NE, Washington, DC, 20549. Information regarding the operation of the public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330. In addition, filings made with the SEC electronically are publicly available through the SEC's website at http://www.sec.gov, and at our website at http://www.contango .com. This report on Form 10-K , including all exhibits and amendments, has been filed electronically with the SEC.

Seas onal Nature of Business

The demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.