Item 1. Business
Overview
We are a Houston, Texas based independent oil and natural gas company. Our business is to maximize production and cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in various plays, and use that cash flow to explore, develop, exploit and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast 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 pursuant to which Crimson became a wholly-owned subsidiary of Contango (the “Merger"). Accordingly, 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 20.3% of the post-Merger Contango.
On October 1, 2013, our board of directors approved a change in fiscal year end from June 30 to December 31. On March 3, 2014, we filed a Transition Report on Form 10-KT 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). Also, on March 28, 2014, we filed an Annual Report on Form 10-K/A to present the financial statements of the Company on a calendar year basis which included the twelve months ended December 31, 2013 and 2012. This Annual report on Form 10-K presents our information for the twelve-month periods ended December 31, 2015, 2014 and 2013. Unless otherwise noted, all references to "years" in this report refer to the twelve-month periods ended December 31 of each year.
The following table lists our primary producing areas as of December 31, 2015:
(1)
Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production from this investment is not included in our reported production results or in our reported reserves for any periods reported herein.
Additionally, we have (i) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; (ii) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may also be prospective in the Niobrara Shale oil play; and (iii) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas.
Due to the current challenging commodity price environment, we focused our 2015 capital program on: (i) the preservation of our strong and flexible financial position, including limiting our overall capital expenditure budget; (ii) dedicating capital primarily to de-risking and/or delineating strategic projects (i.e. versus field development); (iii) the identification of opportunities for cost and production efficiencies in all areas of our operations; and (iv) continuing to identify and, when appropriate, pursue the expansion of our resource potential through opportunistic acquisitions.
The following table lists the primary areas to which we allocated capital during 2015:
			
		
			
		
Our production for the year ended December 31, 2015 was approximately 34.0 Bcfe (or 93.0 Mmcfe/d), was 63% from our offshore properties and was 67% natural gas. Our production for the three months ended December 31, 2015 was approximately 8.0 Bcfe (or 86.7 Mmcfe/d), was 65% from our offshore properties and was 68% natural gas. As of December 31, 2015, our proved reserves were approximately 84% proved developed, were 61% offshore, were 68% natural gas and were 96% attributed to wells and properties operated by us.
As of December 31, 2015, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and William M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms for our onshore and offshore properties, respectively, in accordance with reserve reporting guidelines required by the Securities and Exchange Commission (“SEC”), were approximately 187.2 Bcfe, consisting of 126.1 Bcf of natural gas, 4.8 MMBbl of crude oil and condensate and 5.4 MMBbl of natural gas liquids (“NGLs”), with a present value, discounted at a 10% rate (PV-10), of $249.4 million, and a Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) of $249.4 million. PV-10 is a non-GAAP financial measure. A reconciliation of our Standardized Measure to PV-10 is provided under “Item 2. Properties - PV-10”.
The following summary table sets forth certain information with respect to our proved reserves as of December 31, 2015 (excluding reserves attributable to our investment in Exaro), as estimated by NSAI and Cobb, and our net average daily production for the year ended December 31, 2015:
(1)
East Texas, Mississippi, Louisiana, Colorado and Wyoming
The following summary table sets forth certain information with respect to the proved reserves attributable to our investment in Exaro, as of December 31, 2015, as estimated by W.D. Von Gonten and Associates (“Von Gonten”), and our net share of Exaro’s average daily production for the year ended December 31, 2015:
Our Strategy
Due to the current low commodity price environment, and the uncertainty for improvement in commodity prices in the immediate future, our 2016 capital expenditure program is expected to be very conservative as we will limit expenditures to those which are necessary to fulfill commitments, preserve core acreage and, where determined appropriate to do so, test the geological viability of new plays or untested formations. Until we believe stability and improvement in commodity prices are likely, our priorities for 2016 will be to preserve our balance sheet strength by limiting capital expenditures to a level below cash flow, to identify new organic opportunities for growth, and to pursue stressed or distressed acquisition opportunities that may arise in this low price environment.
Specific key elements of our long-term business strategy include:
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Enhancing our portfolio by dedicating the majority of our drilling capital to our oil and liquids-rich opportunities. Due to the current superior economics of oil production, as compared to natural gas, we allocated the majority of our 2015 capital budget to oil and liquids-weighted opportunities as we strive to transition from a heavily weighted natural gas production profile to a more balanced reserve and production profile between oil/liquids and natural gas. Our long term strategy is to continue to develop the oil and natural gas liquids resource potential that we believe exists in numerous formations within our various oil/liquids weighted resource plays.
			
		
			
		
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Pursuing accretive, opportunistic acquisitions that meet our strategic and financial objectives. We intend to continue evaluating opportunistic acquisitions of crude oil and natural gas properties, both undeveloped and developed, in areas where we currently have a presence and/or specific operating expertise, and to pursue undeveloped acreage positions, at reasonable cost, in new areas that we feel have significant exploration, exploitation or operational upside. We believe that the ongoing depressed commodity price environment might provide growth opportunities for us through potential corporate combinations.
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Selectively exploiting, in a higher commodity price environment, our existing onshore producing conventional natural gas property portfolio to generate additional cash flows. We believe our multi-year drilling inventory of exploitation opportunities on our existing onshore conventional natural gas oriented producing properties provides us with a solid, dependable platform for future reserve and production growth. We will continuously monitor the commodity price environment, and if warranted, make adjustments to our investment strategy as the year progresses.
We believe that a continuing low commodity price environment could put pressure on over-leveraged or under-funded oil and natural gas exploration and production companies to consider asset sales or strategic combinations. Should a complementary and accretive opportunity materialize, our healthy financial profile, cash flow and liquidity should position us to capitalize on such an opportunity. Accordingly, we plan to closely monitor the industry to identify and evaluate appropriate acquisition opportunities. Our acquisition efforts will typically be focused on areas in which we can leverage our geographic and geological expertise, and where we can develop an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves.
Properties
Offshore Gulf of Mexico
As of December 31, 2015, our offshore assets consisted of seven federal and six State of Louisiana company-operated wells in the shallow waters of the GOM. These 13 wells are located in four fields. The following summary table sets forth certain information with respect to our offshore reserves as of December 31, 2015 and average daily offshore production for the year ended December 31, 2015:
Dutch and Mary Rose Field
We operate five federal wells located at Eugene Island 10 (“Dutch”), and five state wells located in adjacent Louisiana state waters (“Mary Rose”). All Dutch and Mary Rose wells flow 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 GOM 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 thereby minimizing downtime risk and providing the ability to select the best sales price for our oil and natural gas production. Oil and natural gas production can flow to third-party owned and operated onshore processing facilities near Patterson, Louisiana. Alternatively, natural gas can flow via our 8” pipeline, which has been designed with a capacity of 80 Mmcf/d, to a third-party owned and operated onshore processing facility at Burns Point, Louisiana. Condensate can also flow to onshore markets and multiple refineries.
			
		
			
		
In July 2014, we installed a turbine type compressor capable of servicing all ten Dutch and Mary Rose wells at the Eugene Island 11 platform. We invested approximately $11.7 million to design, build and install the compressor, which began operating 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 $15 million, net after customary purchase price adjustments.
Vermilion 170 Field
We own and operate one well with a dedicated production facility at Vermilion 170. This platform services natural gas and condensate production, which flow via the Sea Robin Pipeline to a third-party owned and operated onshore processing plant. Based on production and decline rates, we designed, built and installed for later use a compressor in 2013 at a cost of approximately $1.4 million. We commenced compression in 2015.
In January 2013, production was shut-in at our Vermilion 170 well and operations were conducted to replace the tubing and casing and restore the well, which resumed production in June 2013. During December 2014, our Vermilion 170 well 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 are included in “Other Offshore." In September 2015, our Ship Shoal 263 well reached the end of its estimated useful life and was permanently shut-in. We have budgeted approximately $2.9 million to plug and abandon this well, which we expect to conclude in 2017.
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 the platform located in Block Ship Shoal 263 that was expected to be used by the Ship Shoal 255 well had it been successful. For the twelve months ended December 31, 2015, we recognized an additional $0.5 million in impairment expense for the Ship Shoal 263 platform.
On July 30, 2013, we spud a successful well on our South Timbalier 17 prospect in State of Louisiana offshore waters which commenced production in July 2014. We have a 75% working interest (53.3% net revenue interest) in this well. Due to the low price environment, the net book value of our South Timbalier 17 well exceeded the future undiscounted cash flows associated with its recoverable reserves, and we recognized an impairment expense of approximately $7.7 million and $0.5 million during the years ended December 31, 2014 and 2015, respectively.
We currently hold six untested exploratory prospects on 15 offshore lease blocks. During the year ended December 31, 2014, we recognized full impairment related to the prospects which we do not currently intend to drill.
Onshore Properties
Southeast Texas (Woodbine)
As of December 31, 2015, our Southeast Texas region included approximately 36,200 gross (21,800 net) acres, proven reserves of 32.4 Bcfe, and 86 gross (50.7 net) producing wells. During 2013, Crimson, and subsequently Contango, drilled 12 gross (8.0 net) wells on acreage targeting the Woodbine formation. During 2014, we drilled 18 gross (11.6 net) wells on acreage targeting the Woodbine formation. In 2015, we brought seven gross wells (3.9 net) on production which we initiated in late 2014 utilizing a pad drilling strategy on 500 foot spacing, plus an additional one gross well (0.9 net) in our Iola/Grimes area. We also drilled one gross (0.7 net) well in our Chalktown area to satisfy a farm-in commitment and one gross (0.7 net) horizontal well testing a more aggressive completion design in the Lower Lewisville formation in our Grimes County area, as we limited our 2015 capital expenditures to strategic projects and to stay within internally generated cash flows.
			
		
			
		
Due to the low commodity price forecasts for 2016, our current budget includes no drilling in this area, but should commodity prices improve meaningfully, we may increase our activity in this area late in the year. We currently have approximately 15,400 net acres in Madison and Grimes counties, with a multi-year inventory of potential drilling locations, including the Woodbine, Eagle Ford Shale and Georgetown/Buda formations.
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.
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. In June 2015, we announced the discovery and successful completion of the Elliot #1 well (80% working interest) in the Muddy Sandstone formation. Based on the encouraging results from this well, we spud two more wells in September 2015, the WC 45N-66W-35 1H (“Popham 1H”) and the WC 44N-66W-9 1H (“Christensen 1H”). The Popham 1H well was completed during the fourth quarter of 2015 and during February 2016 produced at an average rate of 221 BOe/d (approximately 99% liquids), while the Christensen 1H well will be completed in the first quarter of 2016. As a result of drilling these wells, we have satisfied the right to earn the 35,000 net acres (approximately 4% of which is held by production).
South Texas (Buda/Eagle Ford)
As of December 31, 2015, our South Texas region included approximately 166,600 gross (81,900 net) acres, proven reserves of 33.4 Bcfe, and 272 gross (145.6 net) producing wells. We believe approximately 20,400 gross (8,900 net) acres to be prospective for the Buda and Eagle Ford Shale plays. During 2013, Crimson, and subsequently Contango, 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 2014, we drilled 14 gross wells (6.8 net) in the Buda formation in Zavala and Dimmit counties. During the fourth quarter of 2014, we drilled one additional well in Dimmit County as a vertical pilot well to test the viability of the Eagle Ford and other formations in the area. Though core analysis indicates the viability of the Eagle Ford formation in the area, no drilling activity was conducted in this area in 2015, or is planned for 2016, because of the low commodity price environment.
Our estimated net proven Buda/Eagle Ford reserves in this area were 11.5 Bcfe, comprised of 77% liquids, with 26 gross (13.3 net) producing wells, as of December 31, 2015.
South Texas (Elm Hill Project)
As of December 31, 2015, we held approximately 57,000 gross acres (27,000 net) in Fayette, Gonzales, Caldwell and Bastrop counties, Texas. During 2014, we drilled four gross wells (2.0 net) in this area, two of which commenced production during the fourth quarter of 2014, while the other two were not commercial successes. During 2015, we drilled one gross well (0.5 net) that was not a commercial success. The Company and its partner are currently evaluating options for future testing of the Navarro, Buda and Austin Chalk, or for monetization of the acreage position.
The remaining 89,200 gross (46,000 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 21.9 Bcfe, comprised of 72% gas, with 242 gross (130.7 net) producing wells, as of December 31, 2015.
Natrona County, Wyoming (FRAMS Project)
In 2014, we acquired the right to earn approximately 119,300 gross acres (93,000 net acres with an 80% working interest) 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 acres with a 60% working interest. We spud our first well in this play, the State #1H well, during the fourth quarter of 2014 targeting the Mowry Shale. In April 2015, initial flowback began and no hydrocarbons were produced during the testing period. As a result, for the year ended December 31, 2015, we
			
		
			
		
recognized $6.7 million in exploration expenses for the cost of drilling the well. Though this well was not a commercial success, we did earn approximately 23,000 net acres in the prospect area under a drill-to-earn arrangement and will continue to evaluate the possibility of testing other formations on the acreage earned.
Other (East Texas)
As of December 31, 2015, our East Texas region included approximately 7,500 gross (4,500 net) acres primarily in San Augustine County, with proven reserves of 0.7 Bcfe comprised of 84% gas, and 10 gross (5.1 net) producing wells. During 2014, 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 may 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, 2015, substantially all of our acreage in our East Texas region is held by production.
Other (Colorado)
We hold approximately 16,100 gross (11,200 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 acreage in the DJ Basin is held by production.
Other
As of December 31, 2015, we held approximately 15,400 gross (4,800 net) mostly undeveloped acres under lease in the Tuscaloosa Marine Shale (“TMS”) and approximately 9,400 gross (6,400 net) acres in Southwest Louisiana, Mississippi, and North Texas.
Impairment of Long-Lived Assets
We recognized approximately $285.9 million in non-cash impairment charges in 2015 primarily related to the reduction in the estimated value of future net cash flows of the Company’s risk adjusted proved, probable and possible reserves (3P reserves) due to the recent dramatic decline in commodity prices for crude oil and natural gas. Under Financial Accounting Standards Board Accounting Codifications, an impairment charge is required when the unamortized capital cost of any individual property within the Company’s producing property base exceeds the risked estimated future net cash flows from the 3P reserves for that property. Substantially all of the impairment expense recognized during 2015 related to the onshore properties acquired via the Merger with Crimson Exploration, Inc. in October 2013. Pursuant to accounting principles generally accepted in the United States of America (“GAAP”) merger accounting rules, we were required to allocate the purchase price to the fair market value of the Crimson properties as our capitalized producing property cost for each property, i.e. rather than Crimson’s actual unamortized cash historical finding and development cost. The commodity price environment used for determining the fair market value of each property at the time of the Merger was considerably higher than it is currently; therefore, we recorded an incremental $195.7 million in asset cost in excess of Crimson’s unamortized capital cost (an upward purchase price adjustment “PPA”) for Crimson’s highest value properties, and that incremental value has been subject to amortization post-merger. Approximately $64.6 million of the PPA for those properties has been amortized post-merger through quarterly depreciation, depletion and amortization (“DD&A”), thereby reflecting a higher overall DD&A rate than would have been recognized through amortization of the actual cash cost incurred in finding and developing those assets. Substantially all of the impairment charge during 2015 is directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Approximately $235.8 million of the $285.9 million total impairment is attributable to these properties, including approximately $131.1 million of which is the unamortized PPA recorded on those properties as part of the merger accounting. Also included in the impairment charge for the year is approximately $10.0 million related to producing property impairment and $9.3 million related to unproved lease cost amortization on our Elm Hill project in Fayette and Gonzales counties, Texas.
			
		
			
		
If oil and/or natural gas prices decline further from prices at December 31, 2015, upon which the fourth quarter impairment was calculated, we may be required to record additional non-cash impairment in the future, thereby impacting our financial results for that period.
Onshore Investments
Kaybob Duvernay - Alberta, Canada
In 2011, we invested 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 $28.5 million, and we expect to receive the remaining $2.0 million once approved by Canadian regulatory officials.
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, 2015, 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, 2015, Exaro had 645 wells on production over its 5,760 gross acres (1,040 net acres), with a working interest between 14.6% and 32.5%. These wells were producing at a rate of approximately 35.5 Mmcfe/d, net to Exaro. Due to the persistent decline in natural gas prices, the operator does not expect to have any drilling rigs running on this project during 2016. For the year ended December 31, 2015, Exaro recognized an impairment of its oil and gas properties as a result of the recent dramatic decline in natural gas prices, and the Company recognized a net investment loss of approximately $30.6 million, net of tax benefit of $16.5 million, as a result of its investment in Exaro. As of December 31, 2015, reserves attributable to our investment in Exaro were 38.7 Bcfe. We do not anticipate making any additional equity contributions during 2016 as Exaro estimates that working capital will be funded through internally generated cash flow. See Note 11 to our Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.
Outlook
As a result of the dramatic downturn in crude oil, natural gas and natural gas liquids pricing in late 2014 through the present, 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 2016 will be focused on: (i) the preservation of our healthy financial position, including limiting our 2016 capital expenditure budget to a minimal amount; (ii) focusing drilling expenditures, if any, on strategic projects only; (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 2016 should allow us to meet our contractual leasehold 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 2016 capital expenditure budget is expected to be funded from internally generated cash flow and at least initially, will include the following:
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Madison/Grimes counties, Southeast Texas - We forecast capital expenditures of approximately $1.0 million for extending, leasing or re-leasing core acreage in this area.
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Wyoming - We plan to complete the Christensen 1H well drilled in late 2015 in Weston County, targeting the Muddy Sandstone formation, and estimate $2.0 million to extend a large portion of our leasehold position for an additional three to five years.
Title 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.
Marketing 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/or costless collars. As of December 31, 2015, we had no commodity price hedges in place. In January 2016, we entered into financial derivative contracts with a member of our bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and November 2016 through December 2016 and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps that provide for a fixed price of $2.53 per MMBtu on the contract volumes. Unrealized gains or losses associated with hedges 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.
Decreases to commodity prices 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:
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The domestic and foreign supply of natural gas and oil.
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Overall economic conditions.
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The level of consumer product demand.
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Adverse weather conditions and natural disasters.
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The price and availability of competitive fuels such as heating oil and coal.
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Political conditions in the Middle East and other natural gas and oil producing regions.
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The level of LNG imports/exports.
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Domestic and foreign governmental regulations.
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Special taxes on production.
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The loss of tax credits and deductions.
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, 2015, calculated on an equivalent basis, were ConocoPhillips Company (48.3%), Sunoco Inc. (22.8%), Energy Transfer Company (5.5%), Shell Trading US Company (5.2%) and Exxon Mobil Oil Corporation (5.1%). 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.
Competition
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 governments; 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.
Governmental Regulations and Industry Matters
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.
Section 1(b) of the NGA exempts gas gathering facilities from the FERC's jurisdiction. We believe that the gas gathering facilities we own meet the traditional tests the FERC has used to establish a pipeline system's status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts. While we own some gas gathering facilities, we also depend on gathering facilities owned and operated by third parties to gather production from our properties, and therefore, we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, we also may be affected by these changes. Accordingly, we do not anticipate that we would be affected any differently than similarly situated gas producers.
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, which may cause us to incur significant capital expenditures or costly actions to achieve and maintain compliance. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects 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 in environmental legislation and regulations is to place more and stringent restrictions and limitations on activities that may affect the environment, which is expected to result in increased costs of doing business and consequently affect profitability.
			
		
			
		
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund Law”, and similar state laws, impose strict joint and several 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 substance” 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 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, allowing us to manage these wastes under RCRA’s less stringent non-hazardous waste requirements, we can provide no assurance that this exemption will be preserved in the future. For example, in August 2015, several non-governmental organizations filed notice of intent to sue the EPA under RCRA for, among other things, the agency’s alleged failure to reconsider whether such RCRA exclusion should continue to apply. Any removal of this exclusion 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.
The Clean Air Act, as amended (the “CAA”), and comparable state laws 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.
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 restrict emissions of GHGs from certain sources. These EPA regulations could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. 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 and reporting on GHG emissions from certain of our operations.
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.
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 an issued permit. 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 (the “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. Furthermore, 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, 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. 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.
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, including a suite of proposed rulemakings and final rules issued by the EPA and the federal Bureau of Land Management (the “BLM”), which legal requirements, to the extent in effect, may impose more stringent requirements relating to emissions and discharges from hydraulic fracturing, chemical disclosures, and performances of fracturing activities on federal and Indian lands.
Congress has from time to time considered, but not enacted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process while, at the state level, several states, including Texas and Wyoming, 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 hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, following the lead of the State of New York. 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. 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 including the EPA and the White House Council on Environmental Quality. 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.
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. Governmental permits or authorizations that are subject to the requirements of NEPA are required for exploration and development projects on federal and Indian lands. 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. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. 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, on September 1, 2015, the U.S. District Court for the Western District of Texas vacated the FWS’ rule listing the lesser prairie chicken in its entirety, concluding that the decision to list the species was arbitrary and capricious. Whether the lesser prairie chicken or other species will be listed in the future under the ESA is currently unknown but the 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.
In response to the Deepwater Horizon drilling rig explosive incident and resulting oil spill in the United States Gulf of Mexico in 2010, the Bureau of Ocean Energy Management (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. 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 more stringent regulatory restrictions, together with any uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans could adversely affect or delay new drilling and ongoing development efforts. In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional delays, restrictions or
			
		
			
		
obligations with respect to oil and natural gas exploration and production operations conducted offshore. Any new rules, regulations or legal initiatives 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 limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If the BOEM determines that increased financial assurance is required in connection with our offshore facilities but we are unable to provide the necessary supplemental bonds or other forms of financial assurance, the BOEM could impose monetary penalties or require our operations on federal leases to be suspended or cancelled. Also, 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. Any one or more of the offshore-related matters described above could have a material adverse effect on our business, financial condition and results of operations.
See “Item 1A.
Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss.
RISK FACTORS RELATING TO OUR BUSINESS
We have no ability to control the market price for natural gas and oil. Natural gas and oil prices fluctuate widely, and a continued substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on the business, the results of operations and financial condition of the Company.
Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Natural gas and crude oil prices declined severely during 2015 and have declined even further through 2016 to date. The markets for these commodities are volatile and prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital. Lower prices also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:
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Overall economic conditions, domestic and global.
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The domestic and foreign supply of natural gas and oil.
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The level of consumer product demand.
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Adverse weather conditions and natural disasters.
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The price and availability of competitive fuels such as LNG, heating oil and coal.
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Political conditions in the Middle East and other natural gas and oil producing regions.
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The level of LNG imports and any LNG exports.
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Domestic and foreign governmental regulations.
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Special taxes on production.
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Access to pipelines and gas processing plants.
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The loss of tax credits and deductions.
A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us. The Company may utilize financial derivative contracts, such as swaps, costless collars and puts on commodity prices, to reduce exposure to potential declines in commodity prices. As of December 31, 2015, we did not have derivative arrangements in place on any post-2015 production. During January 2016, we entered into financial derivative contracts with a member of our bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016, and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps that provide for a fixed price of $2.53 per MMBtu on the contract volumes.
Part of our strategy involves drilling in new or emerging plays; therefore, our drilling results in these areas are not certain.
The results of our drilling in new or emerging plays, such as in our South Texas and Wyoming resource plays, are more uncertain than drilling results in areas that are more developed and with longer production history. Since new or emerging plays and new formations have limited production history, we are less able to use past drilling results in those areas to help predict our future drilling results. The ultimate success of these drilling and completion strategies and techniques in these formations will be better evaluated over time as more wells are drilled and production profiles are better established. Accordingly, our drilling results are subject to greater risks in these areas and could be unsuccessful. We may be unable to execute our expected drilling program in these areas because of disappointing drilling results, capital constraints, lease expirations, access to adequate gathering systems or pipeline
			
		
			
		
take-away capacity, availability of drilling rigs and other services or otherwise, and/or crude oil, natural gas and natural gas liquids price declines. To the extent we are unable to execute our expected drilling program in these areas, our return on investment may not be as attractive as we anticipate and our common stock price may decrease. We could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future if our drilling results are unsuccessful.
Initial production rates in shale plays tend to decline steeply in the first twelve months of production and are not necessarily indicative of sustained production rates.
Our future cash flows are subject to a number of variables, including the level of production from existing wells. Initial production rates in shale plays tend to decline steeply in the first twelve months of production and are not necessarily indicative of sustained production rates. As a result, we generally must locate and develop or acquire new crude oil or natural gas reserves to offset declines in these initial production rates. If we are unable to do so, these declines in initial production rates may result in a decrease in our overall production and revenue over time.
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of undeveloped acreage and/or a decline in our crude oil, natural gas and natural gas liquids reserves.
The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas and natural gas liquids reserves. We intend to finance our future capital expenditures primarily with cash flow from operations and borrowings under our senior secured revolving credit agreement. Our cash flow from operations and access to capital is subject to a number of variables, including:
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Our proved reserves.
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The level of crude oil, natural gas and natural gas liquids we are able to produce from existing wells.
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The prices at which crude oil, natural gas and natural gas liquids are sold.
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Our ability to acquire, locate and produce new reserves.
If our revenues decrease as a result of lower crude oil, natural gas and natural gas liquids prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, to further develop and exploit our current properties, or to conduct exploratory activity. In order to fund our capital expenditures, we may need to seek additional financing. Our credit agreements contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold this consent in their sole discretion. In addition, if our borrowing base redetermination results in a lower borrowing base under our senior secured revolving credit agreement, we may be unable to obtain financing otherwise currently available under our senior secured revolving credit agreement. As part of the regular redetermination schedule, the borrowing base on our revolving credit agreement was redetermined at $225 million effective May 8, 2015, and $190 million effective November 13, 2015 due primarily to lower commodity prices and the impact of the significant reduction in the Company’s drilling program in 2015. Since the last regularly scheduled redetermination of our borrowing base, effective through May 1, 2016, commodity prices have continued to decline. The decline in prices will likely negatively impact the price decks utilized by banks in their calculation of the Company’s borrowing base at May 1, 2016. It is not possible to forecast what that adjustment to the borrowing base might be at that time, and because of that uncertainty, the Company has currently limited its planned 2016 capital expenditure budget to a level that is below our projected internally generated cash flows, thereby allowing for the repayment of a portion of the outstanding debt under our revolving credit facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity.”
In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness is unceratain and will be affected by our future performance and events or circumstances beyond our control. Failure to comply with these covenants could result in an event of default under such indebtedness and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under any of our other outstanding indebtedness.
Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets
			
		
			
		
generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our crude oil, natural gas and natural gas liquids reserves.
We rely on third-party operators to operate and maintain some of our wells, production platforms, pipelines and processing facilities and, as a result, we have limited control over the operations of such facilities. The interests of an operator may differ from our interests.
We depend upon the services of third-party operators to operate some production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and financial condition. Also, the interest of an operator may differ from our interests.
Failure of our working interest partners to fund their share of development costs could result in the delay or cancellation of future projects, which could have a materially adverse effect on our financial condition and results of operations.
Natural gas and crude oil prices declined significantly during 2015 and have declined even further through 2016 to date. An extended or more severe downturn could have material adverse effects on the liquidity of our working interest partners. Our working interest partners must be able to fund their share of investment costs through cash flow from operations, external credit facilities, or other sources. If our partners are not able to fund their share of costs, it could result in the delay or cancellation of future projects, resulting in a reduction of our reserves and production, which could have a materially adverse effect on our financial condition and results of operations.
We are exposed to the credit risks of our customers and derivative counterparties, and any material nonpayment or nonperformance by our customers or derivative counterparties could have a materially adverse effect on our financial condition and results of operations.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers, which risks may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of our significant customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could have a materially adverse effect on our financial condition and results of operations.
Repeated offshore production shut-ins can possibly damage our well bores.
Our offshore well bores are required to be shut-in from time to time due to a variety of issues, including a combination of weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with our condensate production, as well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessary from time to time to upgrade and improve the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to negatively impacting our near term revenues and cash flow, repeated production shut-ins may damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells.
			
		
			
		
Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.
Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows will be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities of our reserves.
There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves shown in this report.
In order to prepare these estimates, our independent third-party petroleum engineers must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in a reserve report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control and may prove to be incorrect over time. As a result, our estimates may require substantial upward or downward revisions if subsequent drilling, testing and production reveal different results. Furthermore, some of the producing wells included in our reserve report have produced for a relatively short period of time. Accordingly, some of our reserve estimates are not based on a multi-year production decline curve and are calculated using a reservoir simulation model together with volumetric analysis. Any downward adjustment could indicate lower future production and thus adversely affect our financial condition, future prospects and market value.
Approximately 16% of our total estimated proved reserves at December 31, 2015 were proved undeveloped reserves. The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures that we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. Although cost and reserve estimates attributable to our crude oil, natural gas and natural gas liquids reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
			
		
			
		
The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil, natural gas and natural gas liquids reserves.
You should not assume that the present value of future net revenues from our proved reserves referred to in this report is the current market value of our estimated crude oil, natural gas and natural gas liquids reserves. In accordance with the requirements of the SEC, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the estimate, held flat for the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate. The present value of future net revenues from our proved reserves as of December 31, 2015 was based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2015. For our condensate and natural gas liquids, the average West Texas Intermediate (Cushing) posted price was $50.28 per barrel for offshore volumes and the average West Texas Intermediate (Plains) posted price was $46.79 per barrel for onshore volumes. For our natural gas, the average Henry Hub spot price was $2.587 per MMBtu for offshore volumes and the average Henry Hub spot price was $2.587 per MMBtu for onshore volumes. Assuming strip pricing as of March 1, 2016 through 2020 and keeping pricing flat thereafter, instead of 2015 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserves would have been 185.4 Bcfe and the PV-10 value of proved reserves would have been $226.3 million. Any adjustments to the estimates of proved reserves or decreases in the price of crude oil or natural gas may decrease the value of our common stock. A reconciliation of our Standardized Measure to PV-10 is provided under "Item 2. Properties - PV-10".
Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses in connection with the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.
Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of crude oil, natural gas and natural gas liquids. In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the results of our drilling operations.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are uncertain. For example, we have over 4,000 square miles of 3D data in the South Texas and Gulf Coast regions. However, even when used and properly interpreted, 3D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know if hydrocarbons are present or producible economically. Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our professionals.
In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses due to such expenditures. As a result, our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve.
Drilling for and producing crude oil, natural gas and natural gas liquids are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our drilling and operating activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for crude oil, natural gas and natural gas liquids can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
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unusual or unexpected geological formations and miscalculations;
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pressures;
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fires;
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explosions and blowouts;
			
		
			
		
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pipe or cement failures;
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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of toxic gases, brine, well stimulation and completion fluids, or other pollutants into the surface and subsurface environment;
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loss of drilling fluid circulation;
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title problems;
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facility or equipment malfunctions;
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unexpected operational events;
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shortages of skilled personnel;
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shortages or delivery delays of equipment and services or of water used in hydraulic fracturing activities;
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compliance with environmental and other regulatory requirements;
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natural disasters; and
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adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life; severe damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, clean-up responsibilities, loss of wells, repairs to resume operations; and regulatory fines or penalties.
Insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. We carry limited environmental insurance, thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not covered in full or in part by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
The potential lack of availability of, or high cost of, drilling rigs, equipment, supplies, personnel and crude oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.
When the prices of crude oil, natural gas and natural gas liquids increase, or the demand for equipment and services is greater than the supply in certain areas, we typically encounter an increase in the cost of securing drilling rigs, equipment and supplies. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our results of operations and financial condition.
Our hedging activities could result in financial losses or reduce our income.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of crude oil, natural gas and natural gas liquids, as well as interest rates, we have, and may in the future, enter into derivative arrangements for a portion of our crude oil, natural gas and/or natural gas liquids production and our debt that could result in both realized and unrealized hedging losses. We typically utilize financial instruments to hedge commodity price exposure to declining prices on our crude oil, natural gas and natural gas liquids production. We typically use a combination of puts, swaps and costless collars. As of December 31, 2015, we did not have any derivatives in place. In January 2016, we entered into financial derivative contracts with a member of our bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016, and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps that provide for a fixed price of $2.53 per MMBtu on the contract volumes.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the
			
		
			
		
underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate, and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.
In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
If prices remain at current levels or decline further, we will likely incur substantial further impairment of proved properties.
If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and/or natural gas prices decline further in 2016 as they have done in 2014 and 2015, we will likely be required to record further non-cash impairment write-downs in the future, which would result in a negative impact to our financial results. Furthermore, any sustained decline in oil and/or natural gas prices may require us to make further impairments. We review our proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we
			
		
			
		
compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and natural gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis.
Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, and amortization to reduce our recorded cost basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value.
Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.
Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.
A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. All of the Company’s operations in the Gulf of Mexico shelf are in water depths of less than 300 feet and less than 50 miles from the coast. Such proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system in the event of released condensate.
Climate change legislation and regulatory initiatives restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
Based on findings that emissions of GHGs present an endangerment to public health and the environment, the EPA has 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 also will be required to meet “best available control technology” standards that typically will be established by the states. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations.
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. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. For example, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although it is not possible at this time to predict how new methane restrictions would impact our business or how or when the United State might impose restrictions on GHGs as a result of the international agreement agreed to in Paris, any new legal requirements that impose more stringent requirements on the emission of GHGs from our operations could result in increased compliance costs or additional
			
		
			
		
operating restrictions, which could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs 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 financial condition and results of operations.
Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, or the FTC, we could be subject to substantial penalties and fines.
Section 1(b) of the NGA exempts natural gas gathering facilities from FERC’s jurisdiction. We believe that the gas gathering facilities we own meet the traditional tests the FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. Under the 2005 Act and implementing regulations, the FERC prohibits market manipulation in connection with the purchase or sale of natural gas. The CFTC has similar authority under the Commodity Exchange Act and regulations it has promulgated thereunder with respect to certain segments of the physical and futures energy commodities market including oil and natural gas. The FTC also prohibits manipulative or fraudulent conduct in the wholesale petroleum market with respect to sales of commodities, including crude oil, condensate and natural gas liquids. These agencies have substantial enforcement authority, including the ability to impose penalties for current violations of up to $1 million per day for each violation. The FERC has also imposed requirements related to reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to these and other matters may be considered or adopted from time to time. Our failure to comply with these or other laws and regulations administered by these agencies could subject us to criminal and civil penalties, as described in Part I, Item 1: “Business-Governmental Regulations and Industry Matters.”
The natural gas and oil business involves many operating risks that can cause substantial losses and our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.
The natural gas and oil business involves a variety of operating risks, including:
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Blowouts, fires and explosions.
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Surface cratering.
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Uncontrollable flows of underground natural gas, oil or formation water.
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Natural disasters.
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Pipe and cement failures.
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Casing collapses.
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Stuck drilling and service tools.
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Reservoir compaction.
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Abnormal pressure formations.
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Environmental hazards such as natural gas leaks, oil spills, pipeline and tank ruptures or unauthorized discharges of brine, toxic gases or well fluids.
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Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelines and gas processing plants over which we have no control.
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Repeated shut-ins of our well bores could significantly damage our well bores.
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Required workovers of existing wells that may not be successful.
If any of the above events occur, we could incur substantial losses as a result of:
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Injury or loss of life.
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Reservoir damage.
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Severe damage to and destruction of property or equipment.
			
		
			
		
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Pollution and other environmental and natural resources damage.
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Restoration, decommissioning or clean-up responsibilities.
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Regulatory investigations and penalties.
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Suspension of our operations or repairs necessary to resume operations.
Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.
If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.
All of our natural gas and oil is transported through gathering systems, pipelines and processing plants. Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.
If our access to sales markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.
Market conditions or the unavailability of satisfactory crude oil, natural gas and natural gas liquids transportation arrangements may hinder our access to crude oil, natural gas and natural gas liquids markets or delay our production. The availability of a ready market for our crude oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for and supply of crude oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our crude oil, natural gas and natural gas liquids may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production.
We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our exploration and development of the lease site.
Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of consultants and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well
			
		
			
		
the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However, such deficiencies may not have been cured by the operator of such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.
Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than many of our competitors.
We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Many of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future depends on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.
Proposed U.S. federal budgets and pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.
The federal administration has released repeated budget proposals over the past few years which include numerous proposed tax changes. The proposed budgets and legislation would repeal many tax incentives and deductions that are currently used by oil and gas companies in the United States and impose new taxes. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law, taxes on the E&P industry would increase, which could have a negative impact on our results of operations and cash flows. Although these proposals initially were made in 2009, none have become law. It is still, however, the federal administration’s stated intention to enact legislation to repeal tax incentives and deductions and impose new taxes on oil and gas companies.
We are subject to stringent laws and regulations, including environmental requirements that can adversely affect the cost, manner or feasibility of doing business.
Our oil and natural gas exploration, development and production operations are subject to stringent federal, regional, state and local laws and regulations governing the operation and maintenance of our facilities, the discharge of materials into the environment and environmental protection. Failure to comply with such rules and regulations could result in the assessment of sanctions, including administrative, civil and criminal penalties, investigatory, remedial and corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects and the issuance of orders limiting or prohibiting some or all of our operations in affected areas. These laws and regulations:
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Require that we obtain permits before commencing drilling or other regulated activities.
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Restrict the substances that can be released into the environment in connection with drilling and production activities.
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Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas.
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Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.
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Impose substantial penalties for pollution resulting from drilling and production operations.
			
		
			
		
Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental natural resource and property damages. We maintain insurance coverage for sudden and accidental environmental damages; however, it is possible that coverage might not be sufficient in a catastrophic event. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. The trend in environmental laws and regulations is to place more stringent restrictions and limitations on activities that may affect the environment. For example, in October 2015, the EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. With EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations, which could apply to our operations and require the installation of , resulting in a need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures. In another example, the EPA issued a final rule in May 2015 that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, we can provided no assurance that our future compliance with existing laws and regulations, these recently adopted rulemakings, or any new or amended legal requirements will not have a material adverse effect on our business, financial condition and results of operations.
An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.
We may incur significant environmental costs liabilities in our business as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and waste water discharges related to our operations, and due to historical industry operations and waste disposal practices. We currently own, operate or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. 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. An accidental release such, for example, while drilling a well, could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property and natural resource damages as well as monetary fines or penalties for related violations of environmental laws or regulations. Moreover, certain environmental statutes impose strict, joint and several liability for these costs and liabilities without regard to fault or the legality of our conduct. Under these environmental laws and regulations, we could be required to remove 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 or other decommissioning activities to prevent future contamination. We may not be able to recover some or any of these costs from insurance.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production.
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 chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural 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 issued CAA final regulations in 2012 and proposed additional CAA regulations in August 2015 governing performance standards for the oil and natural gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural gas extraction operations must meet before discharging to a treatment plant; and issued in 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 BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups. Moreover, from time to time, Congress has considered, but not enacted, legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the
			
		
			
		
hydraulic fracturing process. In addition, certain states, including Texas and Wyoming, where we conduct operations, have adopted and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, and well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, following the approach of the State of New York in 2015. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we currently or in the future plan to 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 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. Also, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study, indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.
We may be subject to increased supplemental bonding under the BOEM financial assurance requirements.
Energy companies conducting oil and natural gas lease operations offshore on the OCS are required by the BOEM, among other obligations, to conduct decommissioning within specified times following cessation of offshore producing activities, which decommissioning includes the plugging of wells, removal of platforms and other facilities, and the clearing of obstacles from the lease site sea floor. To cover a lease operator’s decommissioning obligations, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or otherwise post bonds or other acceptable financial assurances that such future obligations will be satisfied. As an operator, we are required to post surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities as part of our general bonding requirements, as well as the posting of additional supplemental bonds to cover, among other things, our decommissioning obligations. We typically post surety bonds with the BOEM to satisfy our general and supplemental bonding requirements.
In recent years, the BOEM has sought to bolster its financial assurance requirements imposed on offshore operators on the OCS. For example, in August 2014, the BOEM published an Advance Notice of Proposed Rulemaking (“ANPR”), pursuant to which it seeks to bolster its current bonding requirements established under its rules. While the BOEM is yet to propose rules pursuant to the ANPR, in September 2015, it issued draft guidance (“Draft Guidance”) describing revised supplemental bonding procedures the agency plans to use to impose financial assurance obligations for decommissioning activities on the OCS. Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a revised notice to lessees (“NTL”) that will replace an existing 2008 NTL that covers supplemental bonding requirements and related exemptions regarding such external financial assurances. Among other things, the Draft Guidance proposes to eliminate a “waiver” exemption currently allowed by the BOEM, whereby operators on the OCS meeting certain relatively large net worth and other criteria have the option of being exempted from posting supplemental bonds or other acceptable financial assurances for such operator’s decommissioning obligations. Under the existing 2008 NTL, qualifying operators may self-insure to meet supplemental bonding requirements, but only to the extent the estimated cumulative decommissioning liability is no more than 50% of the operator’s net worth. Under the Draft Guidance, this waiver option would be eliminated and qualifying operators would only be able to self-insure for an amount that is no more than 10% of their tangible net worth. In addition, the Draft Guidance would implement a phase-in period for establishing compliance with supplemental bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored plan” that is approved by the BOEM and would require payment of the supplemental bonding amount in three approximately equal installments during a one year period from the date of BOEM approval of the tailored plan. It is expected that the revised NTL will be issued by the BOEM by summer 2016. While we have satisfied past secondary bonding obligations imposed by the BOEM, the
			
		
			
		
revised NTL, once it is issued and implemented by the BOEM, could result in our having to post additional supplemental bonds to the extent that we no longer have the opportunity to obtain waivers from supplemental bonding. The cost of posting additional supplemental bonds or other financial assurances can be substantial, and there is no assurance that they can be obtained in all cases. Obtaining such bonds may require us to provide other financial assurances to the surety company, such as bank letters of credit, which can limit available liquidity.
Moreover, notwithstanding any issuance of a revised NTL, the effect of the significant reduction in oil and natural gas pricing since mid-2014 on operators of, and other owners of interests in, offshore federal leases has impacted the BOEM’s financial assurance determinations with respect to such operators and owners. In those cases where the BOEM determines that a company can no longer demonstrate the requisite financial strength and reliability to maintain a waiver from supplemental bonding, the BOEM may direct such operator to relinquish such waiver and instead post increased supplemental bonding amounts. In the event any such increases in supplemental bonding were required of us, such increases could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. A failure by an operator to post required supplemental bonding or other financial assurances required by the BOEM could result in the BOEM assessing monetary penalties or requiring any on an operator’s federal lease to be suspended or cancelled or otherwise subject an operator to monetary penalties. Any one or more such actions imposed on us could materially adversely affect our financial condition and results of operations.
The BSEE has implemented much more stringent controls and reporting requirements that if not followed, could result in significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.
The BSEE is the federal agency responsible for overseeing the safe and environmentally responsible development of energy and mineral resources on the OCS. They are responsible for leading the most aggressive and comprehensive reforms to offshore oil and gas regulation and oversight in U.S. history. Their reforms have tightened requirements for everything from well design and workplace safety to corporate accountability.
Additionally, the OCS Lands Act authorizes and requires the BSEE to provide for both an annual scheduled inspection and a periodic unscheduled (unannounced) inspection of all oil and gas operations on the OCS. In addition to examining all safety equipment designed to prevent blowouts, fires, spills, or other major accidents, the inspections focus on pollution, drilling operations, completions, workovers, production, and pipeline safety. Upon detecting a violation, the inspector issues an Incident of Noncompliance ("INC") to the operator and uses one of two main enforcement actions (warning or shut-in), depending on the severity of the violation. If the violation is not severe or threatening, a warning INC is issued. The warning INC must be corrected within a reasonable amount of time specified on the INC. The shut-in INC may be for a single component (a portion of the facility) or the entire facility. The violation must be corrected before the operator is allowed to resume the activity in question.
In addition to the enforcement actions specified above, the BSEE can assess a civil penalty of up to $40,000 per violation per day if: (i) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or (ii) the violation resulted in a threat of serious harm or damage to human life or the environment. Operators with excessive INCs may be required to cease operations in the Gulf of Mexico.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, oil spill-response and decommissioning plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In response to the Deepwater Horizon explosive incident and resulting oil spill in the United States Gulf of Mexico in 2010, the BOEM and the BSEE have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory restrictions, in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts. Moreover, new regulatory initiatives may be adopted or enforced by the BOEM and/or the BSEE in the future that could result in additional delays, restrictions or obligations with respect to oil and natural gas exploration and production operations conducted offshore. For example, in April 2015, the BSEE issued a notice of proposed rulemaking, expected to be finalized in 2016, that focuses on well blowout preventer systems and well control with respect to operations on the OCS. The proposed rule requires, among other things, incorporation of the latest industry standards
			
		
			
		
establishing minimum baseline standards for the design, manufacture, repair, and maintenance of blowout preventers, as well as more controls over the maintenance and repair of blowout preventers. These recent or any new rules, regulations or legal initiatives 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 and costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities, any one or more of which developments could have a material adverse effect on our business, financial condition and results of operations.. Also, if material spill events similar to the Deepwater Horizon incident were to occur in the future, the United States or other countries could elect to 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 gas exploration and development, any of which developments could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws, regulations or legal initiatives on our drilling operations or on the cost or availability of insurance to cover the risks associated with such operations.
We are highly dependent on our senior management team, our exploration partners, third-party consultants and engineers, and other key personnel and any failure to retain the services of such parties could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies.
The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineers and other professionals engaged by us. The loss of key members of our management team or other highly qualified technical professionals could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies which may have a material adverse effect on our business, financial condition and operating results. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.
Acquisition prospects are difficult to assess and may pose additional risks to our operations.
We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:
·
Recoverable reserves.
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Exploration potential.
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Future natural gas and oil prices.
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Operating costs.
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Potential environmental and other liabilities and other factors.
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Permitting and other authorizations, including environmental permits and authorizations, required for our operations.
In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:
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Problems integrating the purchased operations, personnel or technologies.
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Unanticipated costs.
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Diversion of resources and management attention from our exploration business.
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Entry into regions or markets in which we have limited or no prior experience.
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Potential loss of key employees of the acquired organization.
			
		
			
		
We may be unable to successfully integrate the properties and assets we acquire with our existing operations.
Integration of the properties and assets we acquire may be a complex, time consuming and costly process. Failure to timely and successfully integrate these assets and properties with our operations may have a material adverse effect on our business, financial condition and result of operations. The difficulties of integrating these assets and properties present numerous risks, including:
·
Acquisitions may prove unprofitable and fail to generate anticipated cash flows.
·
We may need to (i) recruit additional personnel and we cannot be certain that any of our recruiting efforts will succeed and (ii) expand corporate infrastructure to facilitate the integration of our operations with those associated with the acquired properties, and failure to do so may lead to disruptions in our ongoing businesses or distract our management.
·
Our management’s attention may be diverted from other business concerns.
We are also exposed to risks that are commonly associated with acquisitions of this type, such as unanticipated liabilities and costs, some of which may be material. As a result, the anticipated benefits of acquiring assets and properties may not be fully realized, if at all.
When we acquire properties, in most cases, we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities.
We generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties, and in these situations we cannot assure you that we will identify all areas of existing or potential exposure. In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, we cannot assure you that the seller will be able to fulfill its contractual obligations. In addition, the competition to acquire producing crude oil, natural gas and natural gas liquids properties is intense and many of our larger competitors have financial and other resources substantially greater than ours. We cannot assure you that we will be able to acquire producing crude oil, natural gas and natural gas liquids properties that have economically recoverable reserves for acceptable prices.
RISK FACTORS RELATED TO AN INVESTMENT IN OUR COMMON STOCK
The price of our common stock may fluctuate significantly, and you could lose all or part of your investment.
Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could fluctuate significantly for various reasons, including:
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our operating and financial performance and prospects;
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our quarterly or annual earnings or those of other companies in our industry;
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conditions that impact demand for crude oil, natural gas and natural gas liquids, domestically and globally;
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future announcements concerning our business;
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changes in financial estimates and recommendations by securities analysts;
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actions of competitors;
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market and industry perception of our success, or lack thereof, in pursuing our growth strategy;
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strategic actions by us or our competitors, such as acquisitions or restructurings;
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changes in government and environmental regulation;
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general market, economic and political conditions, domestically and globally;
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changes in accounting standards, policies, guidance, interpretations or principles;
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sales of common stock by us, our significant stockholders or members of our management team; and
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natural disasters, terrorist attacks and acts of war.
			
		
			
		
Natural gas and crude oil prices declined severely during 2015 and have declined even further through 2016 to date. In addition, in recent years, the stock market has experienced significant price and volume fluctuations. This decline in commodity prices and stock market volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. The changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our common stock could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially reduce our share price.
We have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.
Our board of directors presently intends to retain all of our earnings for the expansion of our business; therefore, we have no plans to pay regular dividends on our common stock. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends, and other considerations that our board of directors deems relevant. Also, the provisions of our senior secured revolving credit agreement and second lien credit agreement restrict the payment of dividends. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.
Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.
Future sales or the availability for sale of substantial amounts of our common stock in the public market could adversely affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity securities.
We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.
As of December 31, 2015, we had 116,461 stock options outstanding to purchase shares of our common stock outstanding, all of which were fully vested.
We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares of our common stock issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.
Our organizational documents may impede or discourage a takeover, which could deprive our investors of the opportunity to receive a premium for their shares.
Provisions of our certificate of incorporation and bylaws may make it more difficult for, or prevent a third party from, acquiring control of us without the approval of our board of directors. These provisions:
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permit us to issue, without any further vote or action by the stockholders, shares of preferred stock in one or more series and, with respect to each such series, to fix the number of shares constituting the series and the designation of the series, the voting powers (if any) of the shares of the series, and the preferences and relative, participating, optional, and other special rights, if any, and any qualification, limitations or restrictions of the shares of such series;
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require special meetings of the stockholders to be called by the Chairman of the board of directors, the Chief Executive Officer, the President, or by resolution of a majority of the board of directors;
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require business at special meetings to be limited to the stated purpose or purposes of that meeting;
			
		
			
		
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require that stockholder action be taken at a meeting rather than by written consent, unless approved by our board of directors;
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require that stockholders follow certain procedures, including advance notice procedures, to bring certain matters before an annual meeting or to nominate a director for election; and
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permit directors to fill vacancies in our board of directors.
We are subject to the Delaware business combination law.
We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.
Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:
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our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status;
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upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or
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the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.
This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.
Item 1B.
Item 1B. Unresolved Staff Comments
None
			
		
			
		
Item 2.
Item 2. Properties
As of December 31, 2015, we operated all of our offshore wells, with an average working interest of 59%, and operated 60% of our onshore wells with an average working interest of 74%. As of December 31, 2015, our properties were located in the following regions: Offshore Gulf of Mexico, Southeast Texas, South Texas, and Other.
Development, Exploration and Acquisition Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties, exploration costs incurred in the search for new reserves from unproved properties, and costs incurred in the development of those properties for the periods indicated (in thousands):
Included in unproved property acquisition costs for the year ended December 31, 2015, is $5.0 million related to Natrona and Weston counties, Wyoming.
Included in unproved property acquisition costs for the year ended December 31, 2014, is $7.0 million related to the acquisition of the right to earn acreage in Natrona and Weston counties, Wyoming. Included in the exploration costs for the year ended December 31, 2014, is $28.0 million related to the drilling of our unsuccessful offshore Ship Shoal 255 prospect.
Included in proved property acquisition costs for the year ended December 31, 2013, is $413.9 million related to the acquisition of Crimson properties as a result of the Merger. Also included is $15 million related to exercising a preferential right and purchasing an additional 7.84% working interest and 6.53% net revenue interest in the five Company-operated Dutch wells in our Eugene Island 10 Field from an independent oil and gas company for $18.8 million, $14.7 million net of normal purchase price adjustments.
Included in the exploration costs for the year ended December 31, 2013, is $10.6 million related to the drilling of our successful offshore South Timbalier 17 well and the unsuccessful Ship Shoal 255 prospect.
The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated (in thousands):
			
		
			
		
Drilling Activity
The following tables show our exploratory and developmental drilling activity for the periods indicated. In the tables, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells. As of December 31, 2015, we had one well awaiting to be completed, whose result is not included below.
Included in productive (onshore) exploratory wells for the year ended December 31, 2015, are two wells drilled on our Weston County, Wyoming acreage and three wells drilled in Fayette and Gonzales counties, Texas. Included in non-productive (offshore) exploratory wells for the periods presented is our unsuccessful well at Ship Shoal 255.
Exploration and Development Acreage
Developed acreage is acreage spaced or assigned to productive wells. Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would form the basis to determine whether the property is capable of production of commercial quantities of crude oil, natural gas and natural gas liquids. Gross acres are the total acres in which we own a working interest. Net acres are the sum of the fractional working interests we own in gross acres. The following table shows the approximate developed and undeveloped acreage that we have an interest in, by region, at December 31, 2015.
(1)
Excludes any interest in acreage in which we have no working interest before payout or before initial production.
(2)
Developed acreage consists of acres spaced or assignable to productive wells.
(3)
Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
(4)
Gross acres refer to the number of acres in which we own a working interest.
(5)
Net acres represent the number of acres attributable to our proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).
(6)
Other includes acreage in Louisiana, Colorado, Mississippi, Wyoming, North Texas, and East Texas.
			
		
			
		
Some of our offshore and onshore leases will expire over the next three years as follows, unless we establish production or take action to extend the terms of these leases:
(1)
Relates primarily to our acreage position that was acquired in Louisiana and Mississippi as part of our Tuscaloosa Marine Shale play. It is not expected that those leases will be extended or renewed.
Production, Price and Cost History
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Productive Wells
Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally producing wells are not considered here as a “productive” well. The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of December 31, 2015:
(1)
A gross well is a well in which we own an interest.
(2)
The number of net wells is the sum of our fractional working interests owned in gross wells.
Natural Gas and Oil Reserves
Estimates of proved reserves and future net revenue as of December 31, 2015, 2014 and 2013 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) and William M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms in accordance with the definitions and regulations of the SEC. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (“SPE”). Approximately 61% and 39% of the proved reserves estimates shown herein at December 31, 2015 have been independently prepared by Cobb and NSAI, respectively. Cobb prepared the proved reserves estimates as of December 31, 2015, 2014 and 2013 for all of our offshore properties and NSAI prepared the proved reserves estimates as of December 31, 2015, 2014 and 2013 for our onshore properties.
The technical individual at NSAI responsible for the preparation of our reserve estimates as of December 31, 2015, 2014, and 2013 has over 15 years of experience in the estimation and evaluation of reserves; is a licensed professional engineer in the state of Texas; and holds a Bachelor of Science Degree in Petroleum Engineering from the University of Tulsa. The technical individual at Cobb responsible for overseeing the preparation of our reserve estimates as of December 31, 2015, 2014, and 2013 has 40 years of experience in the estimation and evaluation of reserves; is a registered professional engineer in the state of Texas; holds a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University; is a member of the Society of Petroleum Engineers; and is a member of the Society of Petroleum Evaluation Engineers.
The estimates of proved reserves and future net revenue as of December 31, 2015, 2014 and 2013 were reviewed by our corporate reservoir engineering department that is independent of the operations department. The corporate reservoir engineering
			
		
			
		
department interacts with geoscience, operating, accounting, and marketing departments to review the integrity, accuracy and timeliness of the data, methods, and assumptions used in the preparation of the reserves estimates. All relevant data is compiled in a computer database application to which only authorized personnel are given access rights. Our Senior Vice President - Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for reviewing any reserves estimates prepared by an independent petroleum engineering firm. Our Senior Vice President - Engineering has a Bachelor of Science degree in Petroleum Engineering from the University of Texas and over 35 years of industry experience with positions of increasing responsibility. He reports directly to our President and Chief Executive Officer. Reserves are also reviewed internally with senior management and presented to our board of directors in summary form on a quarterly basis.
We maintain adequate and effective internal controls over the underlying data upon which reserves estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is communicated to our reservoir engineers quarterly, is confirmed when our third-party reservoir engineers hold technical meetings with geologists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Controls - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All data such as commodity prices, lease operating expenses, production taxes, field level commodity price differentials, ownership percentages, and well production data are updated in the reserve database by our third-party reservoir engineers and then analyzed by management to ensure that they have been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, our independent engineering firms prepare their independent reserve estimates and final report.
The following table reflects our estimated proved reserves as of the dates indicated:
(1)
Excludes reserves attributable to our 37% interest in Exaro.
(2)
During the year ended December 31, 2015, proved reserves decreased by approximately 88.0 Bcfe primarily due to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves, and in part to the impact of the significant reduction in our capital spending in response to the commodity price environment.
			
		
			
		
(3)
Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices were adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.
PV-10
PV-10 at year-end is a non-GAAP financial measure and represents the present value, discounted at 10% per year, of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure of Discounted Net Cash Flows represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.
The following table provides a reconciliation of our Standardized Measure to PV-10 (in thousands):
The following table reflects our estimated proved reserves by category as of December 31, 2015 (dollars in thousands):
Our estimated net proved reserves as of December 31, 2015 were approximately 15% crude oil and condensate, 68% natural gas and 17% natural gas liquids.
Proved Developed Reserves
Total proved developed reserves decreased from 208.7 Bcfe at December 31, 2014 to 157.2 Bcfe at December 31, 2015. This decline can be attributed to 34.0 Bcfe of production during the year, 15.6 Bcfe of negative revisions related to the reduction in the economic life of certain properties due to the decrease in commodity prices, and 6.9 Bcfe of negative revisions related to performance, partially offset by 5.0 Bcfe in extensions and new discoveries, and conversions from proved undeveloped reserves, from our reduced 2015 drilling program.
Proved Undeveloped Reserves
Total proved undeveloped reserves (“PUDs”) decreased from 66.5 Bcfe at December 31, 2014 to 30.0 Bcfe at December 31, 2015. As noted in the table below, this decrease was primarily attributable to negative revisions on certain 2014 PUDs that are no longer economical to develop under current commodity pricing.
Future drilling plans and timelines are re-evaluated at the end of each calendar year based on updated reserve reports, current drilling cost estimates and product price forecast. Our development plan prioritizes reserves based on the capital requirements and net present value of potential wells. Generally, the plan is to convert PUDs to developed reserves in an order that is based on their economic importance and impact on production and cash flow, but other factors may be considered such as technical merit, product
			
		
			
		
type, location, and available working interest partners. The PUD conversion rate in 2015 and 2014 was 26% and 29%, respectively, of the total net present value of the Company’s total PUDs at the beginning of the applicable year.
The Company annually reviews any PUDs to ensure their development within five years from the date of originally adding the reserves. Although the Company’s drilling and completion budget for 2016 has been reduced due to the continued drop in oil and gas prices, the Company’s financial resources are expected to be sufficient and within budget to drill all of the remaining 30.0 Bcfe of proved undeveloped reserves within the five year period. Development costs relating to the 30.0 Bcfe at December 31, 2015 are projected to be approximately $50 million over the next five years.
The following table presents the changes in our total proved undeveloped reserves for the year ended December 31, 2015:
(1)
Substantially all of the negative revisions related to reduction in economic life of certain reserves due to lower commodity prices.
(2)
Attributable to our limited onshore drilling program during the year ended December 31, 2015.
Significant Properties
Summary proved reserve information for our properties as of December 31, 2015, by region, is provided below (excluding reserves attributable to our investment in Exaro) (dollars in thousands):
(1)
Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices, using SEC rules, are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.
While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all of this data may vary. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
			
		
			
		
Reserves Attributable to our Investment in Exaro
Estimates of proved reserves and future net revenue as of December 31, 2015 and 2014 associated with our investment in Exaro, which we account for using the equity method, were prepared by W.D. Von Gonten and Associates (“Von Gonten”) in accordance with the definitions and regulations of the SEC. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Reserves as of December 31, 2015 and 2014 were reviewed by our corporate reservoir engineering department as described above. The technical individual at Von Gonten responsible for overseeing the preparation of our reserve estimates as of December 31, 2015 and December 31, 2014 has over 16 years of practical experience in the estimation and evaluation of reserves; is a registered professional engineer in the state of Texas; holds a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University; and is a member in good standing of the Society of Petroleum Engineers.
The following table reflects the estimated proved reserves attributable to our Investment in Exaro:
(1)
The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro does not include the effect of income taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or expense for tax purposes to its partners.
(2)
Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.
(3)
During the year ended December 31, 2015, Exaro’s proved reserves decreased by approximately 31.4 Bcfe attributable to the impact of the dramatic decline in commodity prices on the value and volume of proved reserves, and the impact of the significant reduction in capital spending in response to the low and uncertain commodity price environment.
Prior Year Reserves
Our estimated net proved natural gas, oil and natural gas liquids reserves as of December 31, 2014, 2013 and 2012 are disclosed in “Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Disclosures (Unaudited)”. Reserves as of December 31, 2014 and 2013 were based on reserve reports generated by NSAI and Cobb. Reserves as of December 31, 2012 are based on reserve reports generated by Cobb, while the reserves associated with our 37% investment in Exaro were prepared by Von Gonten.
			
		
			
		
Item 3.
Item 3. Legal Proceedings
From time to time, we are involved in legal proceedings relating to claims associated with our properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
In July 2010, several parties associated with a limited partnership formed to invest in oil and gas properties that was dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in the district court for Madison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The plaintiffs’ expert has recently provided a range of estimated monetary damages of up to approximately $9.4 million as to our subsidiary. We are vigorously defending this lawsuit and believe we have meritorious defenses.
In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by us or by predecessor operators to which we had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on summary judgment, in late 2014 the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. We are vigorously defending this lawsuit, believe we have meritorious defenses and are appealing the trial court’s decision to the applicable state Court of Appeals.
In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by us in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). We have made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds and the plaintiff has appealed the trial court’s decision to the applicable state Court of Appeals. We are vigorously defending this lawsuit and believe we have meritorious defenses. We believe if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights we may have against other working interest and/or royalty interest owners in the unit.
Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in April 2013 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the alleged improprieties occurred prior to the Company’s ownership of an interest in the wells at issue, although we may have assumed liability otherwise attributable to its predecessors-in-interest through the acquisition documents relating to the acquisition of the Company’s interest in these wells. This case is based on the same actions and allegations as a prior case in which the Company and its co-defendants prevailed. The plaintiffs claim damages of approximately $2.5 million against a subsidiary of the Company and its co-defendants. The Company and its co-defendants are vigorously defending this lawsuit and believe that they have a meritorious position.
While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial
			
		
			
		
position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock was listed on the NYSE MKT (previously the American Stock Exchange) in January 2001 under the symbol “MCF”. The table below shows the high and low sales prices per share of our common stock for the periods indicated.
From the period from January 1, 2016 to March 9, 2016, our common stock traded at prices between $3.68 and $8.39 per share.
General
The following descriptions are summaries of material terms of our common stock, preferred stock, certificate of incorporation and bylaws. This summary is qualified by reference to our certificate of incorporation, bylaws and the designations of our preferred stock, which are filed as exhibits to this report on Form 10-K, and by the provisions of applicable law.
Common Stock
We are authorized to issue up to 50 million shares of common stock. As of March 9, 2016, there were approximately 24.7 million shares of common stock issued and 19.4 million shares of common stock outstanding held by approximately 120 registered shareholders. Approximately 0.1 million shares are in reserve for outstanding stock options under our 2005 Stock Incentive Plan, which we adopted from Crimson in connection with the Merger.
Holders of common stock are entitled to one vote for each share held of record on each matter submitted to a vote of stockholders and, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities (including preferential distribution and dividend rights of holders of preferred stock). Holders of common stock have no cumulative rights. The holders of a plurality of the outstanding shares of the common stock have the ability to elect all of the directors.
Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to such dividends as may be declared by the board of directors out of funds legally available therefor. The Company paid a special one-time dividend of $30.5 million, or $2 per share during the year ended December 31, 2012. Any decision to pay future dividends on our common stock will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, capital requirements, and other factors our board of directors may deem relevant. We do not anticipate paying any cash dividends on our common stock in the foreseeable future, as we currently intend to retain all future earnings to fund the development and growth of
			
		
			
		
our business. Our credit facility with Royal Bank of Canada and other lenders currently restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on our common stock.
Preferred Stock
Our board of directors is authorized, without further stockholder action, to issue preferred stock in one or more series and to designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series. We are authorized to issue up to five million shares of preferred stock. No preferred stock was outstanding at December 31, 2015.
Share-Based Compensation
The following table sets forth information about our equity compensation plans at December 31, 2015:
Amended and Restated 2009 Incentive Compensation Plan
On September 15, 2009, the Company’s board of directors (the “Board”) adopted the Contango Oil & Gas Company Equity Compensation Plan (the “Original 2009 Plan”), which was approved by shareholders on November 19, 2009. On April 10, 2014, the Board amended and restated the Original 2009 Plan through the adoption of the Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan (the “2009 Plan”), which was approved by shareholders on May 20, 2014. The 2009 Plan provides for both cash awards and equity awards (such as restricted stock and options) to officers, directors, employees and consultants of the Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.
Under the terms of the 2009 Plan, up to 1,500,000 shares of the Company’s common stock may be issued for plan awards. Stock options issued under the 2009 Plan must have an exercise price equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a four-year period.
Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific targeted performance measures under theses sub-plans are approved by the Compensation Committee and/or the Board. Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.
The CIBP awards will be paid in cash while the LTIP awards will consist of restricted common stock and/or stock options. The stock and/or option awards are expected to vest 25% per year, over the first through fourth anniversaries from the date of grant. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant.
During the year ended December 31, 2015, the Company granted 270,091 restricted stock awards under the 2009 Plan to officers, employees and directors of the Company pursuant to the LTIP, while 12,534 restricted shares were forfeited by former employees and are available to be reissued. During the year ended December 31, 2014, 26,386 restricted stock awards were granted
			
		
			
		
under the 2009 Plan to officers, employees and directors of the Company pursuant to the LTIP, while 7,230 restricted shares were forfeited by former employees and are available to be reissued. During the year ended December 31, 2013, 312,838 restricted stock awards were granted under the 2009 Plan to officers, employees and directors of the Company.
2005 Stock Incentive Plan
The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. Under the 2005 Plan, the Board may grant incentive stock options, nonstatutory stock options, restricted awards, unrestricted awards, performance awards, stock appreciation rights and dividend equivalent rights to officers, directors, employees or consultants of the Company and its affiliates. Awards made under the 2005 Plan are subject to such terms and conditions, without limitation, as may be determined by the Board. Options granted generally expire after ten years. The vesting schedule for all equity awards varies from immediately to over a four-year period. Upon adoption of the 2005 Plan at the Merger closing date, a total of 135,898 stock option awards and 136,428 shares of restricted stock (as converted, which all fully vested upon the Merger) were already issued and outstanding, leaving a balance of 43,472 shares of common stock or stock options available to be granted to Company employees and directors.
During the year ended December 31, 2015, the Company granted 7,030 restricted stock awards under the 2005 Plan to a new employee pursuant to the LTIP, while 189 restricted stock awards were forfeited by former employees. Additionally, during the year ended December 31, 2015, 13,473 stock options previously issued under the 2005 Plan were forfeited, leaving 116,461 stock options vested and exercisable at December 31, 2015. The exercise price for such options range from $28.96 to $60.33 per share, with an average remaining contractual life of five years. The 2005 Plan expired on February 25, 2015 and therefore no additional shares are available for grant.
During the year ended December 31, 2014, the Company did not issue any shares of restricted common stock under the 2005 Plan, but 4,165 stock options previously issued under the 2005 Plan were exercised. During the year ended December 31, 2013, the Company issued 43,461 shares of restricted common stock to Company employees under the 2005 Plan pursuant to the LTIP. Additionally, 791 stock options were exercised.
Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among other things, allow for share repurchases under certain circumstances. No shares were purchased for the years ended December 31, 2015 and 2013. For the year ended December 31, 2014, we purchased the following shares under the $50 million share repurchase program:
			
		
			
		
In addition, the Company repurchased the following shares from employees for the payment of withholding taxes due on shares of restricted stock issued under our stock-based compensation plans:
			
		
			
		
Stock Performance Graph
The following graph compares the yearly percentage change from June 30, 2010 until December 31, 2015 in the cumulative total stockholder return on our common stock to the cumulative total return on the S&P Smallcap 600 Index and a peer group of independent oil & gas exploration companies selected by us.
For the year ended December 31, 2014, the companies in our selected peer group included Petroquest Energy, Inc., Swift Energy Company, Callon Petroleum, Energy XXI (Bermuda) Limited and W&T Offshore, Inc. (“Old Peer Group”). Due to our focus on onshore resource plays, the reorganization of Swift Energy Company under Chapter 11 of the Bankruptcy Code and the financial uncertainty of other companies in our Old Peer Group, we have selected a new peer group of companies. As of December 31, 2015, the companies in our selected peer group included Resolute Energy, EXCO Resources, Comstock Resources, Sanchez Energy, Abraxas Petroleum and Gastar Exploration (“New Peer Group”).
Our common stock began trading on the NYSE MKT (previously American Stock Exchange) on January 19, 2001 and before that had traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in our common stock and each index on June 30, 2010, adjusted for stock splits and dividends. The stock performance for our common stock is not necessarily indicative of future performance.
			
		
			
		
Item 6.
Item 6. Selected Financial Data
On October 1, 2013, the Company's board of directors approved a change in fiscal year end from June 30 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 of each year. The following selected financial data for the years ended December 31, 2015 and 2014 have been derived from the audited consolidated financial statements of Contango contained in this Form 10-K. The following selected financial data for the years ended December 31, 2013, 2012 and 2011 have been derived from the audited consolidated financial statements of Contango contained in our Form 10-K/A for the applicable fiscal year. The selected consolidated financial data (not including proved reserve information) set forth below is for continuing operations and should be read in conjunction with Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report. On October 1, 2013 the Company's board of directors approved a change in fiscal year end from June 30 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 of each year. This Form 10-K covers the three year period ended December 31, 2015.
Overview
We are a Houston, Texas based independent oil and natural gas company. Our business is to maximize production and cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in various plays, and use that cash flow to explore, develop, exploit and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast 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 pursuant to which Crimson became a wholly-owned subsidiary of Contango (the “Merger”). The Merger gave us access to high rate of return onshore prospects in known, prolific producing areas as well as long-life resource plays. In 2015, our drilling activity focused primarily on the Woodbine oil and liquids-rich play in Madison and Grimes counties, Texas (our Southeast Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties, Texas (in our South Texas Region) and the late 2014/early 2015 commencement of drilling on our new acreage position in Wyoming where we are targeting the Mowry Shale and the Muddy Sandstone formations. We believe these areas could provide long-term growth potential from multiple formations that we believe to be productive for oil and natural gas.
Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”), which is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; (iii) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may also be prospective in the Niobrara Shale oil play; and (iv) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas.
Natural gas and crude oil prices declined severely during 2015 and have declined even further through 2016 to date. Due to the current challenging commodity price environment, we focused our 2015 capital program on: (i) the preservation of our strong and flexible financial position, including limiting our overall capital expenditure budget; (ii) dedicating capital primarily to de-risking and/or delineating strategic projects (i.e. versus field development); (iii) the identification of opportunities for cost and production efficiencies in all areas of our operations; and (iv) continuing to identify and, when appropriate, pursue the expansion of our resource potential through opportunistic acquisitions.
Our production for the year ended December 31, 2015 was approximately 34.0 Bcfe (or 93.0 Mmcfe/d) and was 63% offshore and 37% onshore. Our production for the three months ended December 31, 2015 was approximately 8.0 Bcfe (or 86.7 Mmcfe/d) and was 65% offshore and 35% onshore. As of December 31, 2015, our proved reserves were approximately 61% offshore and 39% onshore and were 84% proved developed, which were approximately 72% offshore and 28% onshore.
Revenues and Profitability
Our revenues, profitability and future growth depend substantially on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable, as well as prevailing prices for natural gas and oil.
Reserve Replacement
Generally, producing properties offshore in the Gulf of Mexico have high initial production rates, followed by steep declines. Likewise, initial production rates on new wells in the onshore resource plays start out at a relatively high rate with a decline curve which results in 60% to 70% of the ultimate recovery of present value occurring in the first eighteen months of the well’s life. We
			
		
			
		
must locate and develop, or acquire, new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and/or acquire natural gas and oil reserves. A prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes in our development plans. The Merger with Crimson allowed the Company to add significant proved developed and undeveloped reserves (see “Item 2. Properties”, for details of reserves acquired) and provided the Company with access to several onshore resource plays which have substantial reserve growth potential, including in oil and liquids rich plays that position us to move to a more balanced oil/gas profile.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oil reserves, the timing and costs of our future drilling, development and abandonment activities, and income taxes.
Related Party Transactions
Effective as of the close of business on December 31, 2015, the Company and the other members of Republic Exploration LLC (“REX”) agreed to dissolve and liquidate REX. REX’s assets are being distributed proportionately to its members. See Note 17 to our Financial Statements - "Related Party Transactions" for a detailed description of our transactions with REX.
See “Item 1A. Risk Factors” for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.
Results of Operations
The table below sets forth our average net daily production data in Mmcfe/d from our fields for each of the periods indicated:
(1)
Includes Ship Shoal 263 and South Timbalier 17.
(2)
Includes Madison and Grimes counties, among others.
(3)
Includes Zavala and Dimmit counties, among others.
(4)
Includes onshore wells in East Texas, Colorado, Wyoming and Tuscaloosa Marine Shale regions, among others.
(5)
Lower mainly due to shut-in for approximately three weeks to install compression.
Vermilion 170 Well
During December 2014, our Vermilion 170 well production was shut-in for fourteen days due to issues with the Sea Robin Pipeline, our third-party transporter.
			
		
			
		
Other Offshore
Other offshore includes our Ship Shoal 263 well for all periods presented, except for periods after it was shut-in in September 2015 and for South Timbalier 17 for all quarters ended after June 30, 2014, as it commenced production in July 2014.
Southeast Texas
During 2014, Contango drilled 18 gross (11.6 net) wells on acreage targeting the Woodbine formation. During 2015, we brought seven gross wells (3.9 net) on production which we initiated in late 2014 utilizing a pad drilling strategy on 500 foot spacing, plus an additional one gross well (0.9 net) in our Iola/Grimes area. We also drilled one gross (0.7 net) well in our Chalktown area to satisfy a farm-in commitment and one gross (0.7 net) horizontal well testing a more aggressive completion design in the Lower Lewisville formation in our Grimes County area, as we limited our 2015 capital expenditures to strategic projects and to stay within internally generated cash flows.
South Texas
During 2014, Contango drilled 14 gross operated wells (6.8 net) in the Buda formation, which are all on production. We drilled one additional well during the fourth quarter of 2014 as a vertical pilot well to test the viability of the Eagle Ford and other formations in Zavala and Dimmit counties. Though core analysis indicates the viability of the Eagle Ford formation in the area, no drilling activity was conducted in this area in 2015, or is planned for 2016, because of the low commodity price environment.
			
		
			
		
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014; and Year Ended December 31, 2014 Compared to Year Ended December 31, 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 years ended December 31, 2015, 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 Mcf of natural gas. Reported lease operating expenses include production taxes, such as ad valorem and severance. Information for the year ended December 31, 2013 includes twelve months of Contango activity (January - December) and three months of post-merger Crimson activity (October - December).
			
		
			
		
			
		
			
		
** Greater than 1,000%
Natural Gas, Oil and NGL Sales and Production
All of our revenues are from the sale of our natural gas, crude 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 and mechanical related problems. In addition, the production rate associated with our oil and gas properties declines over time as we produce our reserves.
We reported revenues of approximately $116.5 million for the year ended December 31, 2015, compared to revenues of approximately $276.5 million for the year ended December 31, 2014. This decrease in revenues was primarily attributable to lower oil and natural gas prices in 2015 and lower production resulting from the significant reduction in our capital program because of the dramatic decline in, and uncertain outlook for, commodity prices.
Total production for the year ended December 31, 2015 was approximately 34.0 Bcfe, or 93.0 Mmcfe/d, compared to approximately 40.3 Bcfe, or 110.5 Mmcfe/d, in the prior year, a decline attributable in large part to our limited drilling activity in 2015 due to the low commodity price environment. Net natural gas production for the year ended December 31, 2015 was approximately 61.9 Mmcf/d, compared with approximately 70.9 Mmcf/d for the year ended December 31, 2014, due to normal decline in production from our offshore properties. Net oil production declined from 3,800 barrels per day to 2,500 barrels per day, while NGL production decreased from approximately 2,800 barrels per day to 2,600 barrels per day, both decreases as a result of normal decline that was not offset by new production from a limited 2015 capital program.
We reported revenues of approximately $276.5 million for the year ended December 31, 2014, compared to revenues of approximately $164.1 million for the year ended December 31, 2013. This increase in revenues was primarily attributable to our merger with Crimson, to additional interests purchased in our Dutch wells in December 2013, to production from our South Timbalier 17 discovery which began producing in July 2014, and to new natural gas, oil, condensate and NGL production from our 2014 drilling program, partially offset by lower oil, condensate and NGL prices. Revenue for 2013 was also negatively impacted by our Vermilion 170 well shut-in for the first half of 2013 for workover.
Total production for the year ended December 31, 2014 was approximately 40.3 Bcfe, or 110.5 Mmcfe/d, compared to approximately 28.2 Bcfe, or 107.8 Mmcfe/d, for the year ended December 31, 2013, an increase primarily attributable to our merger with Crimson, new production from our 2014 drilling program, the resumption of production at Vermilion 170 and the additional interests purchased in our Dutch wells discussed above. This increase was partially offset by the shut-in for approximately three weeks, and subsequent ramp up during the third quarter 2014, to install compression for the Dutch and Mary Rose wells. Our net natural gas production for the year ended December 31, 2014 was 70.9 Mmcf/d, up from approximately 69.7 Mmcf/d for the year ended December 31, 2013. Additionally, net oil production increased from 3,600 barrels per day to 3,800 barrels per day, while NGL production increased from approximately 2,600 barrels per day to 2,800 barrels per day.
Average Sales Prices
The average equivalent sales price realized for the years ended December 31, 2015, 2014 and 2013 were $3.43 per Mcfe, $6.86 per Mcfe and $5.82 per Mcfe, respectively. For the year ended December 31, 2015, the price of natural gas was $2.61 per Mcf while the price for oil and NGLs was $46.80 per barrel and $14.68 per barrel, respectively. For the year ended December 31, 2014, the price of natural gas was $4.36 per Mcf while the prices for oil and NGLs were $92.98 per barrel and $33.27 per barrel, respectively.
			
		
			
		
For the year ended December 31, 2013, the price of natural gas was $3.84 per Mcf while the prices for oil and NGLs were $101.21 per barrel and $37.26 per barrel, respectively.
Operating Expenses (including production taxes)
Operating expenses for the year ended December 31, 2015 were approximately $37.8 million, or $1.11 per Mcfe, compared to approximately $47.2 million, or $1.17 per Mcfe, for the year ended December 31, 2014. Operating expenses for the year ended December 31, 2013 were approximately $36.8 million, or $1.30 per Mcfe. The table below provides additional detail of operating expenses for the years ended December 31, 2015, 2014 and 2013.
Lease operating expenses decreased by 8% for the year ended December 31, 2015, compared to the year ended December 31, 2014, as a direct result of our efforts to reduce costs during the second half of 2015 during this challenging commodity price environment. Production and ad valorem taxes decreased by 59% for the year ended December 31, 2015, compared to the prior year, primarily due to the decrease in revenues for the same period.
Lease operating expenses increased for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to the incremental operational activity associated with the expanded asset base as a result of our merger with Crimson. Production and ad valorem taxes increased for the year ended December 31, 2014, compared to the prior year, primarily due to the increase in revenues related to the Merger. The $12.0 million in workover costs for the year ended December 31, 2013, was associated with the tubing and casing replacement at Vermilion 170.
Exploration Expenses
We reported approximately $12.0 million of exploration expenses for the year ended December 31, 2015, which included $6.7 million in dry-hole costs related to our State #1H well in Natrona County, Wyoming, and $2.8 million related to the early termination of a drilling rig contract, compared to $33.4 million for the year ended December 31, 2014. The 2014 costs include $31.5 million related to our exploratory dry hole at Ship Shoal 255 and $1.9 million for geological and geophysical activities, seismic data and delay rentals. We reported approximately $1.8 million of exploration expenses for the year ended December 31, 2013.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the year ended December 31, 2015 was approximately $133.4 million, or $3.93 per Mcfe, compared with approximately $156.1 million, or $3.87 per Mcfe, for the year ended December 31, 2014, a decrease primarily attributable to lower production during 2015. The rate was reduced substantially for the fourth quarter 2015 as a result of the impairment recorded in the quarter ended September 30, 2015, as discussed below.
Depreciation, depletion and amortization for the year ended December 31, 2014 was approximately $156.1 million, or $3.87 per Mcfe, compared to approximately $65.5 million, or $2.32 per Mcfe, for the year ended December 31, 2013, an increase primarily attributable to the expanded asset base and production levels subsequent to our merger with Crimson.
Impairment and Abandonment of Oil and Gas Properties
Impairment and abandonment expenses for the year ended December 31, 2015 included producing property impairment of $269.6 million related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Approximately $235.8 million of the total producing property impairment for the year ended December 31, 2015 is
			
		
			
		
attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties, our highest valued properties stemming from the Merger with Crimson. Impairment expenses for the year ended December 31, 2015 included a $16.3 million impairment of certain unproved properties and onshore prospects due primarily to the sustained low commodity price environment and expiring leases. Approximately $9.3 million of the total for the year ended December 31, 2015 is related to unproved lease cost amortization of the Elm Hill project in Fayette and Gonzales counties, Texas.
Impairment and abandonment expenses for the year ended December 31, 2014 included producing property impairments of $7.7 million for South Timbalier 17 and $3.7 million for the Tuscaloosa Marine Shale (“TMS”) proved properties due to performance and commodity price declines in 2014, $3.5 million impairment of unproved leasehold cost related to the dry hole on our Ship Shoal 255 block and $12.1 million for impairment of an existing platform which was expected to be used by the Ship Shoal 255 well if it had been successful. Impairment expenses for the year ended December 31, 2014 also included a $20.1 million impairment charge for certain unproved prospects due to expiring leases and leases not likely to be drilled, primarily related to GOM leases and unproved TMS leases.
For the year ended December 31, 2013, the Company recorded impairment expense of approximately $0.8 million, related to expiring leasehold costs in our Ship Shoal 83 and Brazos 543 prospects.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2015 were approximately $26.4 million, compared to $34.0 million for the year ended December 31, 2014. Included in our current year expense was approximately $0.6 million in cash severance costs resulting from an August 2015 reduction in force and $6.5 million in non-cash stock based compensation. Included in the prior year expense was approximately $4.5 million in non-cash stock based compensation and $2.6 million in merger-related costs. Exclusive of the stock compensation and severance related costs, cash general and administrative expenses for the current year were $19.3 million, compared to cash expenses of $29.5 million for the prior year. The 2015 reduction in force was a major step in our ongoing cost cutting efforts necessitated by the current challenging commodity price environment.
General and administrative expenses for the year ended December 31, 2014 were approximately $34.0 million, compared to $26.5 million for the year ended December 31, 2013. General and administrative expenses for the year ended December 31, 2014 included approximately $4.5 million in non-cash stock based compensation and $2.6 million in merger-related costs. General and administrative expenses for the year ended December 31, 2013 included approximately $3.2 million in non-cash stock based compensation and $3.9 million attributable to the merger with Crimson.
Gain (loss) from Affiliates
For the year ended December 31, 2015, the Company recorded a loss from affiliates of approximately $30.6 million, net of tax benefit of $16.5 million, related to our equity investment in Exaro, compared with a gain from affiliates of approximately $6.9 million, net of taxes of $3.8 million, for the year ended December 31, 2014. The decline in 2015 was related primarily to an impairment of Exaro’s oil and gas properties as a result of the recent dramatic decline in commodity prices.
For the year ended December 31, 2013, the Company recorded a gain from affiliates of approximately $2.3 million, net of taxes of $1.2 million, related to our investment in Exaro.
Other Income (Expense)
Other expense for the year ended December 31, 2015 was approximately $0.7 million, which is primarily related to $5.6 million of costs incurred in pursuit of an unsuccessful acquisition in the fourth quarter and interest expense of $3.2 million, partially offset by $6.1 million in proceeds related to favorable outcomes in two lawsuits and realized gains on derivatives of $2.3 million.
Other expense for the year ended December 31, 2014 was approximately $2.7 million, which is primarily related to interest expense.
Other income for the year ended December 31, 2013 was approximately $29.5 million, which included a $15.3 million gain on the sale of assets related to our equity investment in Alta Resources, Inc., a $6.6 million gain related to the disposition of a minority working interest in all developed and undeveloped properties in Madison and Grimes counties, and the proceeds from a $10 million
			
		
			
		
key-man life insurance policy on the Company's former Chairman, President and Chief Executive Officer, Mr. Kenneth Peak, who passed away on April 19, 2013.
Capital Resources and Liquidity
Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our credit facility.
The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from internal and external sources, for the periods indicated, in thousands.
Cash flow from operating activities, including changes in working capital, provided approximately $25.0 million in cash for the year ended December 31, 2015 compared to $210.0 million for the year ended December 31, 2014. The deficit in working capital was reduced by approximately $27.2 million during 2015, compared to an increase in 2014 of approximately $16.7 million. Cash flow from operating activities, excluding changes in working capital, provided approximately $52.2 million in cash for the year ended December 31, 2015 compared to $193.3 million for the year ended December 31, 2014. This decrease in cash provided by operating activities was primarily attributable to lower oil and natural gas prices for 2015, as well as a decline attributable to our reduced drilling activity in 2015 due to the low commodity price environment.
Cash flow from operating activities provided approximately $210.0 million in cash for the year ended December 31, 2014 compared to $105.0 million for the year ended December 31, 2013. This increase in cash provided by operating activities was primarily attributable to our merger with Crimson.
Cash used in investing activities was approximately $76.8 million for the year ended December 31, 2015, which included approximately $77.8 million for capital expenditures, partially offset by approximately $1.0 million in distributions from REX as a result the dissolution of that entity.
Cash used in investing activities was approximately $175.1 million for the year ended December 31, 2014, which included approximately $180.4 million for capital expenditures, partially offset by approximately $5.4 million related to the sale of assets and distributions from affiliates.
Cash used in investing activities was approximately $34.8 million for the year ended December 31, 2013, which included approximately $62.6 million for capital expenditures and approximately $15.4 million for investments in affiliates, partially offset by approximately $43.2 million related to the sale of assets and distributions from affiliates.
Cash provided by financing activities was approximately $51.9 million for the year ended December 31, 2015 compared to $34.9 million used in financing activities in 2014. The cash provided by financing activities in 2015 was primarily attributable to net borrowings under our RBC Credit Facility (defined below) used to reduce the working capital deficit at December 31, 2014, while the cash used in financing activities in 2014 reflected the net repayment of borrowings under the RBC Credit Facility that existed at the beginning of that year.
Cash used in financing activities was approximately $34.9 million for the year ended December 31, 2014 compared to $149.7 million used in financing activities in 2013, a change primarily attributable to the retirement of a portion of Crimson's debt assumed upon closing of the Merger, partially offset by post-merger borrowings under our RBC Credit Facility.
			
		
			
		
Credit Facility
In connection with the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million second lien term loan with Barclays Bank PLC ("Barclays") and other lenders, and Crimson’s $58.6 million balance under its senior secured revolving credit facility with Wells Fargo and other lenders, and $1.8 million in accrued interest and prepayment premiums. In order to refinance the assumed debt, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”), which matures on October 1, 2017, with an initial hydrocarbon-supported borrowing base of $275 million. As part of the regular redetermination schedule, the borrowing base was redetermined at $225 million effective May 8, 2015, and $190 million effective November 13, 2015 due primarily to lower commodity prices and the impact of the significant reduction in the Company’s drilling program in 2015. The borrowing base under our RBC Credit Facility is redetermined each November 1 and May 1. Since the last regularly scheduled redetermination of our borrowing base, effective through May 1, 2016, commodity prices have continued to decline. The decline in prices will likely negatively impact the price decks utilized by banks in their calculation of the Company’s borrowing base at May 1, 2016. If our next borrowing base redetermination results in a lower borrowing base, we may be unable to obtain financing otherwise currently available under the RBC Credit Facility.
The Company incurred $2.2 million of arrangement and upfront fees in connection with the RBC Credit Facility. Proceeds of the RBC Credit Facility were, or may be used (i) to finance working capital and for general corporate purposes, (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 producing 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 0.50% to 2.50% margin dependent upon the amount of borrowings outstanding.
On October 28, 2014, the Company entered into a second amendment to the RBC Credit Facility, which reduced the effective interest rate on borrowings and provided for the repurchase by the Company of common shares under its 2011 Share Repurchase Plan, subject to certain limitations. As of December 31, 2015, we had $115.4 million outstanding under the RBC Credit Facility, compared with $63.4 million outstanding under the RBC Credit Facility at the end of 2014.
The RBC Credit Facility requires us to maintain a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. Our compliance with these covenants is tested each quarter. At December 31, 2015, we were in compliance with the covenants under the RBC Credit Facility, and at current commodity prices, we do not except any covenant compliance issues over the next twelve months. See Note 13 to our Financial Statements -“Long-Term Debt” for a more detailed description of terms and provisions of our credit agreement.
Future Capital Requirements
Our future crude oil, natural gas and natural gas liquids reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We intend to grow our reserves and production by further exploiting our existing property base through drilling opportunities in our resource plays and in our conventional onshore inventory in the Texas Gulf Coast, with activity in any particular area and period of time to be a function of market and field economics. We anticipate that acquisitions, including those of undeveloped leasehold interests, will continue to play a role in our business strategy as those opportunities arise from time to time; however, there can be no assurance that we will be successful in consummating any acquisitions, or that any such acquisition entered into will be successful. These potential acquisitions are not part of our current capital budget and would require additional capital. Natural gas and oil prices continue to be volatile and our financial resources may be insufficient to fund any of these opportunities. While there are currently no unannounced agreements for the acquisition of any material businesses or assets, such transactions can be effected quickly and could occur at any time.
We believe that our internally generated cash flow, combined with availability under our RBC Credit Facility will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve months. We currently plan to limit our 2016 capital expenditures to a level within our forecasted cash flow from operations for the year; however, we do possess the capacity, through forecasted excess cash flow and through our RBC Credit Facility, to increase and/or accelerate drilling on any particular area should we determine that market and project economics so warrant. Our ability to execute on our growth strategy will be determined, in large part, by our cash flow and the
			
		
			
		
availability of debt and equity capital at that time. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors.
Our 2016 capital budget is expected to be funded from internally generated cash flow, exclusive of acquisitions, if any, and due to the current commodity price environment will be focused primarily on: (i) the preservation of our strong and flexible financial position by limiting our overall capital expenditure budget to no more than internally generated cash flow; (ii) focusing expenditures on strategic projects only, and (iii) identification of opportunities for cost efficiencies in all areas of our operations. Our current capital budget for 2016 should allow us to meet our contractual requirements, remain in position to preserve our term acreage where appropriate and maintain our already healthy financial profile during this challenging period for our industry. We will continuously monitor the commodity price environment, and if warranted, make adjustments to our investment strategy as the year progresses.
Inflation and Changes in Prices
While the general level of inflation affects certain costs associated with the energy industry, factors unique to the industry result in independent price fluctuations. Such price changes have had, and will continue to have, a material effect on our operations; however, we cannot predict these fluctuations.
Income Taxes
During the year ended December 31, 2015, we received a refund of approximately $0.2 million in federal and state income taxes. During the years ended December 31, 2014 and 2013, we paid approximately $0.2 million and $0.3 million, respectively, in federal and state income taxes, net of cash refunds received.
Contractual Obligations
The following table summarizes our known contractual obligations as of December 31, 2015:
(1)
Estimated interest is based on the outstanding debt at December 31, 2015 using the interest rate in effect at that time.
(2)
Operating leases include contracts related to office space, compressors, vehicles, office equipment and other. Operating lease commitments from our previous office space are expected to be substantially recovered by the subleases that we have entered into for the remainder of our lease term.
(3)
We cannot predict at this time when, or if, this obligation may be required to be paid.
In addition to the above, we have also committed to invest up to an additional $20.6 million in Exaro.
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. 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 as part of this Form 10-K. 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.
Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at December 31, 2015 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $1.0 million, $2.2 million and $3.4 million, respectively.
Impairment of Natural Gas and Oil Properties
The Company reviews its proved natural gas and oil properties for impairment whenever events and circumstances, such as the current low commodity price environment, indicate a potential decline in the recoverability of their carrying value. An impairment loss associated with an asset group is the amount by which the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. An asset’s fair value is preferably indicated by a quoted market price in the asset’s principal market. Unlike many businesses where independent appraisals can be obtained for items such as equipment, oil and gas proved reserves are unique assets. Most oil and gas valuations are based on a combination of the income approach and market approach methodologies. We utilize the
			
		
			
		
income approach also known as the discounted cash flow (“DCF”) approach. Under the DCF method in determining fair value, there are specific guidelines and ranges within the evaluation that we can consider and estimate.
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 impair 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. Assuming strip pricing as of March 1, 2016 through 2020 and keeping pricing flat thereafter, instead of 2015 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserves would have been 185.4 Bcfe and the PV-10 value of proved reserves would have been $226.3 million.
Derivative Instruments
At the end of each reporting period we record on our balance sheet the mark-to-market valuation of our derivative instruments. The estimated change in fair value of the derivatives, along with the realized gain or loss for settled derivatives, is reported in Other Income (Expense) as Gain (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. As of December 31, 2015, we had federal net operating loss (“NOL”) carryforwards of $140.4 million which occurred due to the Merger, and subsequent taxable losses in 2014 and 2015 due to lower commodity prices and impairment of oil and gas property. Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382. Given the uncertainty of our ability to generate taxable income, a valuation allowance of $57.5 million has been recorded for the year ended December 31, 2015 against the deferred tax assets, reduced by the amount of the deferred tax liability.
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. See Note 16 - "Income Taxes” to our consolidated financial statements.
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. 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 Accounting Standards Codification (“ASC”) 805, Business Combinations.
Recent Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows.
In January 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2016-01: Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). The main objective of ASU 2016-01 is enhancing the reporting model for financial instruments to provide users of financial statements with more decision-useful information. The amendments in ASU 2016-01 make targeted improvements to GAAP by: (i) requiring equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income; (ii) simplifying the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; (iii) exempting all non-public business entities from disclosing fair value information for financial instruments measured at amortized cost; (iv) eliminating requirement for public business entities to disclose the methods and significant assumptions used to estimate the fair value for financial instruments measured at amortized cost on the balance sheet: (v) requiring public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; (vi) requiring separate presentation in other comprehensive income the portion of the total change in fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; (vii) requiring separate presentation of financial assets and financial liabilities by measurement category and form of financial asset; and (viii) clarifying that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. For public entities, ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.
In November 2015, the FASB issued Accounting Standards Update No. 2015-17: Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17). ASU 2015-17 is part of an initiative to reduce complexity in accounting standards. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. However, this classification does not generally align with the time period in which the
			
		
			
		
recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of the deferred income taxes, ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of an entity be offset and presented as a single amount is not affected by the amendments of ASU 2015-17. For public entities, ASU 2015-17 is effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years; early application is permitted. The Company has selected early application starting with the financial statements issued for the year ended December 31, 2015. The provisions of this accounting update do not have a material impact on the Company’s financial position or results of operations. Accordingly, the deferred tax liability and the valuation allowance are classified as non-current.
In September 2015, the FASB issued Accounting Standards Update No. 2015-16: Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 is part of an initiative to reduce complexity in accounting standards, and requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In addition, the amendments of this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the changes to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Furthermore, ASU 2015-16 requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustments to the provisional amounts had been recognized as of the acquisition date. For public entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15). ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is permitted. The provisions of this accounting update are not expected to have a material impact on our financial position or results of operations.
In May 2014, the FASB and the International Accounting Standards Board jointly issued new accounting guidance for recognition of revenue Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU 2014-09). This new guidance replaces virtually all existing US GAAP and International Financial Reporting Standards guidance on revenue recognition. ASU 2014-09 is effective for fiscal years beginning after December 15, 2017. This new guidance applies to all 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 does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented.
Off Balance Sheet Arrangements
We may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of December 31, 2015, 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 and drilling rig in the commitments and contingencies table, we have no other arrangements that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.
			
		
			
		
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Commodity Risk
We are exposed to various risks including energy commodity price risk for our oil, natural gas and natural gas liquids production. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. Our major commodity price risk exposure is to the prices received. Realized commodity prices received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices received for oil, natural gas and natural gas liquids are volatile and unpredictable. For the year ended December 31, 2015, a 10% fluctuation in the prices received for oil, natural gas and natural gas liquids production would have had an approximately $11.6 million impact on our revenues.
Derivative Instruments and Hedging Activity
We expect commodity prices to remain volatile and unpredictable, therefore we have designed a risk management strategy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include swaps and costless collars. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, since the Merger, our objective has generally been to potentially hedge approximately 40% to 50% of our current and anticipated production for the next 12 to 18 months, excluding offshore production during hurricane season. As of December 31, 2015, we did not have any commodity price hedges in place. In January 2016, we entered into financial derivative contracts with a member of our bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps. Our hedge strategy and objectives may change significantly as our operational profile changes and/or commodities prices change.
We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current and previous derivative contracts are large financial institutions and also lenders or affiliates of lenders in our RBC Credit Facility. We do not post collateral under any of these contracts as they are secured under our RBC Credit Facility. See Note 7 to our Financial Statements - "Derivative Instruments" for additional information.
We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. As of December 31, 2015, we have not entered into any derivative contracts to reduce the exposure to market rate fluctuations. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Note 7 to our Financial Statements - "Derivative Instruments" for more details.
Interest Rate Sensitivity
We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and the U.S. prime rate based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.
As of December 31, 2015, our total long-term debt was $115.4 million, which bears interest at a floating or market interest rate that is tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. During the year ended December 31, 2015 our effective rate fluctuated between 1.7 percent and 4.5 percent, depending on the term of
			
		
			
		
the specific debt drawdowns. At December 31, 2015, we did not have any outstanding interest rate swap agreements. As of December 31, 2015, the weighted average interest rate on our variable rate debt was 2.4% per year. Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our RBC Credit Facility would result in an increase of our interest expense by $1.2 million for a twelve month period.
Other Financial Instruments
As of December 31, 2015, we had no cash or cash equivalents. Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments to hedge any changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we may invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of December 31, 2015, an immediate 10% change in interest rates is not expected to have a material effect on our near-term financial condition or results of operations.
Item 8.
Item 8. Financial Statements and Supplementary Data
The financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented on pages through of this Form 10-K.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Company’s senior management of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of December 31, 2015, the end of the period covered by this report. Based on that evaluation, the Company’s management, including the President and Chief Executive Officer and the Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of such date to ensure that information required to be disclosed in the reports that the Company files under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to the Company’s management, including the President and Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
Changes in Internal Control Over Financial Reporting
There was no change in our internal controls over financial reporting during the fiscal quarter ended December 31, 2015 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company’s management, including the President and Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation under the framework in 2013 Internal Control-Integrated Framework, the Company’s management concluded that its internal control over financial reporting was effective as of December 31, 2015.
			
		
			
		
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Form 10-K, has audited the effectiveness of our internal control over financial reporting as of December 31, 2015, as stated in their report which is included herein.
			
		
			
		
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited the internal control over financial reporting of Contango Oil & Gas Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2015, and our report dated March 14, 2016 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2016
			
		
			
		
Item 9B.
Item 9B. Other Information
Amendment to Bylaws
On February 25, 2015, the board of directors of the Company adopted the Third Amended and Restated Bylaws (the “Bylaws”) of the Company. The amendment and restatement of the Bylaws was effective immediately and includes, among other things, the following changes:
·
Providing for additional disclosure requirements for notices of director nominations and stockholder proposals.
·
Modifying the time period during which notice of director nominations and stockholder proposals may be given.
·
Clarifying the procedures relating to the appointment of the chairman of a meeting of stockholders and the powers of the chairman of a meeting to conduct such a meeting.
·
Clarifying that the board of directors has the power to fix the record date, meeting date, time and place for each special meeting of stockholders.
·
Removing certain obsolete provisions arising from and relating to our merger with Crimson Exploration Inc.
·
Clarifying the requirements for removal of a director for cause by stockholders of the Company.
·
Designating the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain legal action, unless the Company consents in writing to the selection of an alternative forum.
The foregoing description of the Bylaws is not complete and is qualified in its entirety by reference to the complete text of the Bylaws, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated by reference herein.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be contained in our Definitive Proxy Statement for our 2016 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Proposal 1: Election of Directors”, “Executive Compensation”, “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance and our Board” and is incorporated herein by reference. The Proxy Statement will be filed with the SEC pursuant to Regulation 14A of the Exchange Act, not later than 120 days after December 31, 2015.
Item 11.
Item 11. Executive Compensation
The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the headings “Corporate Governance and our Board”, “Transactions with Related Persons” and “Executive Compensation” and is incorporated herein by reference.
			
		
			
		
Item 14.
Item 14. Principal Accountant Fees and Services
The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the subheading “Principal Accountant Fees and Services” and is incorporated herein by reference.
			
		
			
		
GLOSSARY OF SELECTED TERMS
The following is a description of the meanings of some of the oil and gas industry terms used in this report.
2D seismic or 3D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions, respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Boe. Barrel of oil equivalent per day determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Boe/d. Boe per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or crude oil in another reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBbls. million barrels of crude oil or other liquid hydrocarbons.
MMBtu. million British Thermal Units. One MMBtu equates to one Mcf.
MMcf. million cubic feet of natural gas.
MMcfe. million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
			
		
			
		
MMcfe/d. Mmcfe per day.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed producing reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved developed reserves. Has the meaning given to such term in Rule 4-10(a)(6) of Regulation S-X, which defines proved developed reserves as reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines proved reserves as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
The area of a reservoir considered proved includes (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geological and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geological, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when successful testing by a pilot project, the operation of an installed program in the reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and the project has been approved for development by all necessary parties and entities, including governmental entities.
Proved undeveloped reserves. Has the meaning given to such term in Rule 4-10(a)(31) of Regulation S-X, which defines proved undeveloped reserves as reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir, or by other evidence using reliable technology establishing reasonable certainty.
			
		
			
		
PV-10. A non-GAAP financial measure that represents the present value, discounted at 10% per year, of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes or non-property related expenses such as general and administrative expenses and debt service or depreciation, depletion and amortization on future net revenues. Neither PV-10 nor Standardized Measure of Discounted Net Cash Flows represents an estimate of fair market value of natural gas and crude oil properties. PV-10 is used by the industry as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Trucking. The provision of trucks to move our drilling rigs from one well location to another and to deliver water and equipment to the field.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
			
		
			
		
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Financial Statements and Schedules:
The financial statements are set forth in pages to of this Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.
(b) Exhibits:
The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, which were previously filed, are incorporated herein by reference.
			
		
			
		
			
		
			
		
* Indicates a management contract or compensatory plan or arrangement.
† Filed herewith
			
		
			
		
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTANGO OIL & GAS COMPANY
By: /s/ ALLAN D. KEEL Date: March 14, 2016
Allan D. Keel
Chief Executive Officer
POWER OF ATTORNEY
Know all men by these presents, that the undersigned constitutes and appoints Allan D. Keel as his true and lawful attorneys-in-fact and agent, with full power of substitution for him and in his name, place and stead, in any and all capacities to sign any and all amendments or supplements to this Annual Report on Form 10-K, and to file the same, and with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
			 		
			
		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
			
		
			
		
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Contango Oil & Gas Company and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company adopted new accounting guidance in 2015, related to the presentation of deferred income taxes.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2016 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2016
			
		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except shares)
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(in thousands, expect share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
			 		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
			
		
			
		
1. Organization and Business
Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in various plays, and use that cash flow to explore, develop, exploit, produce and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States.
On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. ("Crimson"), in an all-stock transaction pursuant to which Crimson became a wholly-owned subsidiary of Contango (the "Merger"). As a result of the Merger, the Company issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding capital stock. See Note 4 - "Merger with Crimson Exploration Inc." for additional information.
The Company has historically focused operations in the GOM, but the Merger has given the Company access to lower risk, long life resource plays. In 2015, the Company’s drilling activity focused primarily on the Woodbine oil and liquids-rich play in Madison and Grimes counties, Texas (the Southeast Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties, Texas (the South Texas Region) and in Wyoming where the Company is initially targeting the Muddy Sandstone. The Company believes these plays could provide long-term growth potential from multiple formations that it believes to be productive for oil and natural gas.
Additionally, the Company has (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; (iii) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which the Company believes may also be prospective in the Niobrara Shale oil play; and (iv) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas.
Due to the current challenging commodity price environment, the Company focused its 2015 capital program on: (i) the preservation of its healthy financial position, including limiting its overall capital expenditure budget to internally generated cash flow; (ii) dedicating capital primarily to de-risking and/or delineating strategic projects (i.e. versus field development); (iii) the identification of opportunities for cost and production efficiencies in all areas of its operations; and (iv) continuing to identify and, when appropriate, pursue the expansion of its resource potential through opportunistic acquisitions.
2. Summary of Significant Accounting Policies
Basis of Presentation
The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. Oil and gas exploration and development affiliates which are not controlled by the Company, such as Republic Exploration LLC (“REX”), are proportionately consolidated. Financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015 contained herein, include consolidated results of operations of both Contango Oil & Gas Company and Crimson for the period from the closing date of the Merger to December 31, 2015 and only consolidated financial statements of Contango for all other the periods presented herein.
Change of Year-End
On October 1, 2013, the Company's board of directors approved a change in fiscal year end from June 30 to December 31, commencing with the twelve-month period beginning on January 1, 2014. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 of each year.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
Other Investments
The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net income or loss is reported as a single line-item in Gain (loss) from investment in affiliates (net of income taxes).
Contango’s 21.9% ownership of Moblize Inc. (“Moblize”) and 2.0% indirect ownership of Alta Energy Canada Partnership, LLC ("Alta") are accounted for using the cost method, as the Company does not exercise significant influence over either company. Under the cost method, Contango records an investment at cost, and recognizes dividends or distributions received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment. During the year ended December 31, 2013, the Company had a significant distribution from Alta in excess of its original investment. The gain in excess of the original investment is included in the Other income line item in the Company's statement of operations and in the investing cash flows in the Company's statement of cash flow for the year ended December 31, 2013.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates include oil and gas revenues, income taxes, stock-based compensation, reserve estimates, impairment of natural gas and oil properties, valuation of derivatives, and accrued liabilities. Actual results could differ from those estimates.
Revenue Recognition
Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. As of December 31, 2015, 2014 and 2013, the Company had no significant imbalances.
Cash Equivalents
Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2015, the Company had no cash and cash equivalents, as cash balances at the end of each day are transferred to reduce outstanding debt under our revolving credit facility to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2015, accounts payable included $6.8 million representing outstanding checks that had not been presented for payment net of cash balance in the bank as of December 31, 2015. At December 31, 2014, accounts payable included $12.1 million representing outstanding checks that had not been presented for payment net of cash balance in the bank as of December 31, 2014.
Accounts Receivable
The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Amounts deemed uncollectible are charged to the allowance.
Accounts receivable allowance for bad debt was $0.7 million and $0.6 million, as of December 31, 2015 and 2014, respectively. At December 31, 2015 and 2014, the carrying value of the Company’s accounts receivable approximated fair value.
Oil and Gas Properties - Successful Efforts
The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developed reserves.
Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producing natural gas and crude oil properties, including related support equipment and facilities net of salvage value, are computed using the unit-of-production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit-of-production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates.
Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 13 years.
Impairment of Oil and Gas Properties
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. For the year ended December 31, 2015, the Company recorded an impairment expense of approximately $269.6 million related to proved properties. Approximately $235.8 million of this amount is attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties. For the year ended December 31, 2014, the Company recorded an impairment expense of approximately $11.4 million related to proved properties. Of this amount, $7.7 million related to South Timbalier 17 and $3.7 million related to the Tuscaloosa Marine Shale (“TMS”), a shale play in central Louisiana and Mississippi. No impairment of proved properties was recognized during the year ended December 31, 2013.
Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such impairment is charged to expense in the period. During the year ended December 31, 2015, the Company recognized impairment expense of approximately $16.3 million related to impairment and partial impairment of certain unproved properties and onshore prospects due primarily to the sustained low commodity price environment and expiring leases. Approximately $9.3 million of this amount is related to unproved lease cost amortization of the Elm Hill project in Fayette and Gonzales counties, Texas.
On April 29, 2014, the Company reached total depth on its Ship Shoal 255 well, and no commercial hydrocarbons were found. As a result, for the year ended December 31, 2014, the Company recognized $31.5 million in exploration expense for the cost
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
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 Ship Shoal 263 block which was expected to be used by the Ship Shoal 255 well had it been successful.
During the year ended December 31, 2014, the Company also recognized impairment expense of approximately $20.1 million related to impairment and partial impairment of certain unproved properties due to expiring leases and leases not likely to be drilled. Of this amount, approximately $9.7 million relates to undrilled offshore leases and approximately $9.7 million relates to undeveloped TMS acreage.
For the year ended December 31, 2013, the Company recorded an impairment expense on unproved properties of $0.6 million related to leasehold costs on the Ship Shoal 83 prospect which it relinquished in August 2013, and $0.2 million related to leasehold costs on the Brazos Area 543 prospect.
Asset Retirement Obligations
ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company's legal obligations related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in depreciation, depletion and amortization expense.
The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate.
Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate or changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See Note 12 - "Asset Retirement Obligation" for additional information.
Income Taxes
The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2015. The amount of unrecognized tax benefits did not materially change from December 31, 2014. The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns for 1998 - 2014, and state tax returns for 2009 - 2014, remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.
Concentration of Credit Risk
Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 - "Concentration of Credit Risk" for additional information.
Debt Issuance Costs
Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. During the year ended December 31, 2013, the Company incurred $2.2 million of debt issuance costs relating to the new RBC credit facility entered into in conjunction with the Merger with Crimson. The debt issuance costs will be amortized over the original four year term of the credit line with amortization expense included in the Depreciation, Depletion and Amortization line item in the Company's income statement for the years ended December 31, 2015, 2014 and 2013.
Stock-Based Compensation
The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each award is estimated as of the date of grant using the Black-Scholes option-pricing model.
Inventory
Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method.
Derivative Instruments and Hedging Activities
The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. As of December 31, 2015, the Company had not entered into any derivative contracts to reduce exposure to interest rate risk. However, from time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transactions using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in "Gain (loss) on derivatives, net" on the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013. Derivative instruments with settlement date within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. As of December 31, 2015, there were no commodity hedges in place. In January 2016, the Company entered into financial derivative contracts with a member of its bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps. See Note 7 - "Derivative Instruments" for additional information.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
Reclassifications
Certain reclassifications have been made to the presentation of certain, income statement and cash flow items in the respective statements for the year ended December 31, 2013 in order to conform to the presentation for the year ended December 31, 2014. These reclassifications were not material.
Subsidiary Guarantees
Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Crimson Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one other wholly-owned subsidiary that is inactive. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.
Recent Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows.
In January 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2016-01: Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). The main objective of ASU 2016-01 is enhancing the reporting model for financial instruments to provide users of financial statements with more decision-useful information. The amendments in ASU 2016-01 make targeted improvements to GAAP by: (i) requiring equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income; (ii) simplifying the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; (iii) exempting all non-public business entities from disclosing fair value information for financial instruments measured at amortized cost; (iv) eliminating requirement for public business entities to disclose the methods and significant assumptions used to estimate the fair value for financial instruments measured at amortized cost on the balance sheet: (v) requiring public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; (vi) requiring separate presentation in other comprehensive income the portion of the total change in fair value of a liability resulting from a change in the instrument-
			
		
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specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; (vii) requiring separate presentation of financial assets and financial liabilities by measurement category and form of financial asset; and (viii) clarifying that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. For public entities, ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.
In November 2015, the FASB issued Accounting Standards Update No. 2015-17: Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17). ASU 2015-17 is part of an initiative to reduce complexity in accounting standards. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. However, this classification does not generally align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of the deferred income taxes, ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of an entity be offset and presented as a single amount is not affected by the amendments of ASU 2015-17. For public entities, ASU 2015-17 is effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years; early application is permitted. The Company has selected early application starting with the financial statements issued for the year ended December 31, 2015. The provisions of this accounting update do not have a material impact on the Company’s financial position or results of operations. Accordingly, the deferred tax liability and valuation allowance are classified as non-current.
In September 2015, the FASB issued Accounting Standards Update No. 2015-16: Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 is part of an initiative to reduce complexity in accounting standards, and requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In addition, the amendments of this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the changes to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Furthermore, ASU 2015-16 requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustments to the provisional amounts had been recognized as of the acquisition date. For public entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15). ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.
In May 2014, the FASB and the International Accounting Standards Board (“IASB”) jointly issued new accounting guidance for recognition of revenue Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU 2014-09). This new guidance replaces virtually all existing US GAAP and IFRS guidance on revenue recognition. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016. This new guidance applies to all 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 for the years ended December 31, 2015 and 2016, must be retrospectively presented in
			
		
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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 does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented.
Further, management is closely monitoring the joint standard-setting efforts of the FASB and the International Accounting Standards Board. There are a large number of pending accounting standards that are being targeted for completion in 2016 and beyond. Because these pending standards have not yet been finalized, management is not able to determine the potential future impact that these standards will have, if any, on the Company's financial position, results of operations, or cash flows.
3. Concentration of Credit Risk
The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers of the Company’s natural gas, oil and natural gas liquids for the year ended December 31, 2015 were ConocoPhillips Company (48.3%), Sunoco Inc. (22.8%), Energy Transfer Company (5.5%) Shell Trading US Company (5.2%) and ExxonMobil Oil Corp. (5.1%). The Company’s sales to these companies are not secured with letters of credit and in the event of non-payment, the Company could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position. There are numerous other potential purchasers of the Company’s production.
4. Merger with Crimson Exploration Inc.
On October 1, 2013, the Company completed the Merger with Crimson. The Merger was effected pursuant to an Agreement and Plan of Merger, dated as of April 29, 2013, by and among Contango, Crimson and certain subsidiaries (the “Merger Agreement”).
As a result of the Merger, each share of Crimson common stock was converted into 0.08288 shares of common stock of Contango, and the Company issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding capital stock, resulting in Crimson stockholders owning 20.3% of the post-merger Contango.
The Merger qualified as a tax-free reorganization for U.S. federal income tax purposes, so that none of the Company, Crimson, or any of its stockholders recognized any gain or loss in the Merger, except that Crimson's stockholders may have recognized gain or loss with respect to cash received in lieu of fractional shares of Company common stock.
The Merger was accounted for as a business combination in accordance with ASC 805 which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Crimson's results of operations are reflected in the Company's consolidated statement of operations, beginning October 1, 2013.
			
		
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The following table summarizes the consideration transferred and the fair value of assets acquired, and liabilities assumed as of the date of the Merger (in thousands, except for number of shares and share price):
As of December 31, 2013, estimates of the fair value of assets acquired and liabilities assumed were preliminary and based on information available at that time. The fair value estimate of certain of Crimson's assets and liabilities, including asset retirement obligations and current and deferred tax balances, could not be finalized at December 31, 2013 due to information not being available to the Company. During the quarter ended June 30, 2014, the Company completed an analysis of Crimson’s asset retirement obligations as of the acquisition date. Based on this analysis, the Company recorded a measurement period adjustment of $2.5 million to increase the asset retirement obligations liability. As of September 30, 2014, the Company had finalized the purchase price allocation for the Merger.
Consideration paid by the Company consisted of approximately 3.9 million shares of Contango’s common stock issued in exchange for 46.6 million of Crimson’s shares outstanding as of September 30, 2013, including restricted stock vesting at the transaction date and approximately 136,000 of vested Contango stock options issued to Crimson’s employees in exchange for all Crimson stock options issued and outstanding as of September 30, 2013. The number of options granted and the strike price of the options was adjusted using the same conversion ratio as for the exchange of common stock. All of Crimson’s restricted shares and stock options vested immediately prior to the merger.
The purchase price was calculated assuming fair value of the Company’s stock of $37.75 per share based upon the closing price of the Company’s common stock as of October 1, 2013.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
Fair value of the Company’s options issued in exchange for Crimson’s stock options was calculated using the Black-Scholes Model by applying the following weighted-average assumptions: (a) risk-free interest rate of 0.62% to 1.35%; (b) expected life of 2.70 to 4.79 years; (c) expected volatility of 29.3% to 38.6%; and (d) expected dividend yield of 0%. The weighted average fair value per share for the options was estimated to be $5.14.
Immediately subsequent to the closing of the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million term loan with Barclays Bank PLC ("Barclays") and other lenders, its $58.6 million in loans outstanding under its senior revolving credit facility with Wells Fargo and other lenders, and $1.8 million in accrued interest and prepayment premiums.
In order to finance the assumed debt, 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. The RBC Credit Facility replaced the Company's $40 million revolving credit facility with Amegy Bank. The Company incurred $2.2 million of arrangement and upfront fees in connection with the RBC Credit Facility. 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 0.5% to 2.5% margin dependent upon the amount outstanding. On October 1, 2013, the $235.4 million of assumed debt, accrued interest, and prepayment premium and $2.2 million of arrangement and upfront fees under the RBC Credit Facility were paid with the Company's existing cash of $127.6 million and drawings under the Company’s RBC Credit Facility of $110.0 million.
Fair value of the deferred tax liabilities was calculated giving the tax effect of step-up adjustment for oil and gas properties. Contango received carryover tax basis in Crimson’s assets and liabilities because the merger is not a taxable transaction under the United States Internal Revenue Code. Based upon the purchase price allocation, a step-up in financial reporting carrying value related to the property to be acquired from Crimson resulted in an additional deferred tax liability of approximately $42.8 million assuming a 37% expected effective tax rate of the combined company.
Additionally, fair value of the deferred tax assets was increased by approximately $10.2 million due to elimination of a valuation allowance included in the historical financial statements of Crimson. This adjustment was based on the expectation that it is more likely than not that the majority of $110 million of Crimson’s accumulated Net Operating Losses ("NOLs") will be realized by the combined company in the foreseeable future. At December 31, 2015, the Company has recorded a valuation allowance due to losses incurred post-merger. The fair value of Crimson’s oil and gas properties acquired was determined by using commodity prices based on future expected prices for oil, natural gas and NGLs, after adjustment for transportation fees and regional price differentials.
There is no goodwill attributable to the Merger as the consideration transferred did not exceed the fair value of Crimson's net assets acquired on October 1, 2013.
5. Acquisitions, Dispositions and Gains from Affiliates
Acquisition of Additional Interest in Dutch Wells
In December 2013, the Company 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 $18.8 million, subject to a purchase price adjustment, based on production and operating expenses between the effective date of July 1, 2013 and the closing date of December 12, 2013. During 2014, a purchase price adjustment of approximately $4.1 million reduced the purchase price to a total of $14.7 million, net to the Company.
Southeast Texas Disposition
On December 31, 2013, the Company sold to an independent oil and gas company approximately 7.1% of its interest in all developed and undeveloped properties in Madison and Grimes Counties for $20 million, subject to a purchase price adjustment, based on production and operating expenses between the effective date of July 1, 2013 and the closing date of December 31, 2013. A preliminary estimated adjustment to the sales price of approximately $0.4 million to increase the purchase price was recorded in 2013, and an adjustment of approximately $0.1 million to reduce the purchase price was recorded in 2014 resulting in final proceeds of
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
$20.3 million. A loss of approximately $0.2 million and a gain of approximately $6.6 million related to this sale were recognized in the years ended December 31, 2014 and 2013, respectively.
Proceeds from Alta
In August 2013, Alta sold its interest in the liquids-rich Kaybob Duvernay, which closed in October 2013 for approximately $30.5 million, net to Contango. Contango has a 2% interest in Alta and a 5% interest in the Kaybob Duvernay project. The total distribution received from Alta during the year ended December 31, 2013 was approximately $23.1 million. An additional $5.4 million was received during 2014. The Company expects to receive the remaining $2.0 million once approved by Canadian regulatory officials. The total distributions from Alta are expected to exceed the Company’s original investment by $15.3 million.
6. Fair Value Measurements
Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.
The Company had outstanding commodity price contracts during the years ended December 31, 2015 and 2014, which were settled prior to each year end. Thus, the Company did not have any outstanding commodity price contracts as of December 31, 2015 and 2014. In January 2016, the Company entered into financial derivative contracts with a member of its bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps.
Derivatives above are swaps that are carried at fair value for the appropriate period. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 7 - "Derivative Instruments" for additional discussion of derivatives.
During the year ended December 31, 2015, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which were believed to have a minimal credit risk. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not anticipate any nonperformance. The counterparties to the Company's current and previous derivative contracts are lenders in the Company's RBC Credit Facility. The Company did not post collateral under any of these contracts as they were secured under the RBC Credit Facility.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's RBC Credit Facility approximates carrying value because the interest rate approximates current market rates and are re-set at least every three months. See Note 13 - "Long-Term Debt" for further information.
Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis include oil and gas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair value measurements based on these inputs are classified as Level 3.
Impairments
Contango tests proved oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.
Asset Retirement Obligations
The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves.
7. Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company believes that derivative arrangements, although not free of risk, allowed us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, the Company’s derivative arrangements applied only to a portion of its production and provided only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions, and commodity price forecasts.
The Company had outstanding commodity price contracts during the year ended December 31, 2015, which were settled prior to year end. Thus, the Company did not have any outstanding derivative positions as of December 31, 2015. In January 2016, the Company entered into financial derivative contracts with a member of its bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. A sold put option limits the exposure of the counterparty's risk should the price fall
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold.
It is the Company's practice to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current and previous derivative contracts are lenders or affiliates of lenders in the RBC Credit Facility. The Company does not post collateral under any of these contracts as they are secured under the RBC Credit Facility.
The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain (loss) on derivatives, net" on the consolidated statements of operations. See Note 6 - “Fair Value Measurements” for additional information.
There were no derivative contracts in place as of December 31, 2015 and 2014.
The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013 (in thousands):
In January 2016, the Company entered into the following financial derivative contracts with a member of its bank group:
(1)
Commodity price derivatives based on Henry Hub NYMEX natural gas prices.
8. Stock Based Compensation
As of December 31, 2015, the Company had in place a share-based compensation program which allows for stock options and/or restricted stock to be awarded to officers, directors and employees as a performance-based award. This program includes (i) the Company's Amended and Restated 2009 Incentive Compensation Plan (the “2009 Plan”); and (ii) the Crimson 2005 Stock Incentive Plan (the “2005 Plan” or "Crimson Plan") adopted in conjunction with the Merger.
Amended and Restated 2009 Incentive Compensation Plan
On September 15, 2009, the Company’s board of directors (the “Board”) adopted the Contango Oil & Gas Company Equity Compensation Plan (the “Original 2009 Plan”). On April 10, 2014, the Board amended and restated the Original 2009 Plan through the adoption of the Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan. The 2009 Plan provides for both cash awards and equity awards (such as restricted stock and options) to officers, directors, employees or consultants of the
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.
Under the terms of the 2009 Plan, up to 1,500,000 shares of the Company’s common stock may be issued for plan awards. Stock options under the 2009 Plan must have an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a four-year period.
As of December 31, 2015, the Company had approximately 0.9 million shares of common stock and stock options available for future grant under the 2009 Plan. In January 2016, the Company granted 38,943 stock awards to employees and 1,745 stock awards to its board of directors under the 2009 Plan as a result of the Salary Replacement Program. See Note 14 - “Commitments and Contingencies” for a description of the Salary Replacement Program.
Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Board. Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.
The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock and/or stock options. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant.
2005 Stock Incentive Plan
The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. Under the 2005 Plan, the Board may grant incentive stock options, nonstatutory stock options, restricted awards, unrestricted awards, performance awards, stock appreciation rights and dividend equivalent rights to eligible officers, directors, employees or consultants of the Company and its affiliates. Awards made under the 2005 Plan are subject to such terms and conditions, without limitation, as may be determined by the Board. Options granted generally expire after ten years. The vesting schedule for all equity awards varies from immediately to over a four-year period. Upon adoption of the 2005 Plan at the Merger closing date, a total of 135,898 stock option awards and 136,428 shares of restricted stock (as converted, which all fully vested upon the Merger) were already issued and outstanding, leaving a balance of 43,472 shares of common stock or stock options available to be granted to Company employees and directors.
On February 24, 2015, the Company granted 7,030 restricted stock awards under the 2005 Plan to a new employee pursuant to the LTIP. This plan expired on February 25, 2015 and therefore no additional shares are available for grant.
Stock Options
During the years ended December 31, 2015 and 2014, the Company did not issue any stock options. However, 13,473 stock options that were previously issued were forfeited, leaving 116,461 stock options vested and exercisable at December 31, 2015, with exercise prices ranging from $28.96 to $60.33 per share, with an average remaining contractual life of five years.
During the year ended December 31, 2014, employees exercised 4,165 stock options to purchase shares of the Company’s common stock that were sold in the open market.
During the year ended December 31, 2013, employees exercised 791 stock options to purchase shares of the Company’s common stock that were sold in the open market.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
A summary of the stock options granted under the 2009 Plan and 2005 Plan as of and for the years ended December 31, 2015, 2014, and 2013 is presented in the table below (dollars in thousands, except per share data):
Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the year ended December 31, 2015, there was no excess tax benefit recognized. For the year ended December 31, 2014, there was an insignificant excess tax benefit recognized. For the year ended December 31, 2013, there was no excess tax benefit recognized. See Note 2 - "Summary of Significant Accounting Policies".
Compensation expense related to employee stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model.
During the years ended December 31, 2015, 2014 and 2013, the Company did not recognize any stock option expense. The aggregate intrinsic value of stock options exercised/forfeited during the years ended December 31, 2015, 2014 and 2013 was approximately zero, $59,009 and $7,721, respectively.
Restricted Stock
During the year ended December 31, 2015, the Company issued 249,917 restricted stock awards to new and existing employees, which vest over four years, plus an additional 27,204 restricted stock awards to the members of the board of directors which vest on the one-year anniversary of the date of grant. The weighted average fair value of the restricted shares granted during the year was $22.02, with a total grant date fair value of approximately $6.1 million after adjustment for estimated weighted average forfeiture rate of 4.9%.
During the year ended December 31, 2014, the Company issued 10,714 restricted stock awards to new and existing employees pursuant to the LTIP, which vest over four years, plus an additional 15,672 restricted stock awards to the board of directors which vest on the one-year anniversary of the date of grant. The weighted average fair value of the restricted shares granted during the year was $40.83, with a total grant date fair value of approximately $1.1 million after adjustment for estimated weighted average forfeiture rate of 2.2%.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
In November 2013, the Company issued 254,677 shares of restricted common stock to senior officers and certain other vice presidents pursuant to the LTIP, of which 25 percent vested immediately and the remaining balance vests over a three-year period. Also in November 2013, the Company issued 1,802 shares of restricted common stock to newly hired employees pursuant to the LTIP, which vest over a four-year period. In December 2013, the Company also issued 88,466 shares of restricted common stock to Company employees pursuant to the LTIP, which vest over a four-year period, plus an additional 11,354 shares of restricted common stock to the board of directors as compensation pursuant to the Company’s new director compensation plan which vest on the one-year anniversary of the date of grant. The weighted average fair value of the restricted shares granted during the fourth quarter of 2013 was $44.10, with a total grant date fair value of approximately $8.1 million after adjustment for estimated weighted average forfeiture rate of 5.7%.
Restricted stock activity as of December 31, 2015, 2014 and 2013 and for the years then ended is presented in the table below (dollars in thousands, except per share data):
The Company recognized approximately $6.5 million, $4.5 million and $3.2 million in stock compensation expense during the years ended December 31, 2015, 2014 and 2013, respectively, for restricted shares granted to its officers, employees and directors. An additional $7.2 million of compensation expense will be recognized over the remaining vesting period.
9. Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company believes its stock price to be undervalued. Repurchased shares of common stock became authorized but unissued shares, and may be issued in the future for general corporate and other purposes. During the year ended December 31, 2014, the Company purchased 205,457 shares at an average price of $35.89 per share, for a total of approximately $7.4 million. No shares were purchased during the years ended December 31, 2015 and 2013. As of December 31, 2015, the Company had $31.8 million available under the share repurchase program for future purchases.
In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among other things, allow for share repurchases subject to certain conditions. The Company is currently in compliance with these conditions.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
10. Other Financial Information
The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):
Included in the table below is supplemental information about non-cash transactions during the years ended December 31, 2015, 2014 and 2013, in thousands:
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
11. Investment in Exaro Energy III LLC
In April 2012, the Company entered into a Limited Liability Company Agreement (the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC Agreement, as amended, the Company has committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately $183 million. The Company did not make any contributions during the year ended December 31, 2015. As of December 31, 2015, the Company had invested approximately $46.9 million.
The following table presents condensed balance sheet data for Exaro as of December 31, 2015 and December 31, 2014. The balance sheet data was derived from the Exaro balance sheet as of December 31, 2015 and December 31, 2014 and was not adjusted to represent Contango’s percentage of ownership interest in Exaro. Contango’s share in the equity of Exaro at December 31, 2015 was approximately $14.1 million.
(1)
Approximately $14.4 million of current assets as of December 31, 2015, is cash.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
The following table presents the condensed results of operations for Exaro for the years ended December 31, 2015, 2014 and 2013. The results of operations for the years ended December 31, 2015, 2014 and 2013 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent Contango’s ownership interest but rather reflects the results of Exaro as a Company. The Company's share in Exaro's results of operations recognized for the years ended December 31, 2015, 2014 and 2013 was a loss of $30.6 million, net of tax benefit of $16.5 million; a gain of $6.9 million, net of tax expense of $3.8 million; and a gain of $2.3 million, net of tax expense of $1.2 million, respectively.
Included in Other gain (loss) are realized and unrealized losses attributable to derivatives, whose value is likely to change based on future oil and gas prices. Exaro's results of operations do not include income taxes, because Exaro is treated as a partnership for tax purposes.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
12. Asset Retirement Obligation
The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Company’s ARO during the year ended December 31, 2015 and 2014 were as follows (in thousands):
All of the total liabilities incurred during the year ended December 31, 2015 were related to new wells drilled during the period. All of the total liabilities settled during the year ended December 31, 2015, related to wells plugged and abandoned during the period.
Of the total liabilities incurred during the year ended December 31, 2014, $2.5 million was due to a purchase price adjustment for the merger with Crimson and $0.6 million related to new wells drilled during the period. All of the total liabilities settled during the year ended December 31, 2014 related to wells plugged and abandoned during the period.
13. Long-Term Debt
RBC Credit Facility
In connection with the Merger during 2013, the Company assumed and immediately repaid $235.4 million of Crimson debt, including Crimson’s $175.0 million second lien term loan with Barclays and other lenders, Crimson’s $58.6 million balance under its senior secured revolving credit facility with Wells Fargo Bank and other lenders, and a $1.8 million prepayment premium for the second lien term loan and accrued interest. Of the amount repaid, $127.6 million was made from existing cash with the remainder financed through new borrowing arrangements.
In order to finance the retirement of the assumed debt, the Company entered into a $500 million four-year secured revolving credit facility with Royal Bank of Canada and other lenders on October 1, 2013, with an initial hydrocarbon-supported borrowing base of $275 million. As part of the regular redetermination schedule, the Company’s bank group redetermined the Company’s borrowing base at $225 million effective May 8, 2015, and $190 million effective November 13, 2015, primarily to reflect lower commodity prices and the impact of the significant reduction in the Company’s drilling program in 2015 because of the low price environment. The borrowing base under the facility is redetermined each November 1 and May 1. Since the last regularly scheduled redetermination of our borrowing base, effective through May 1, 2016, commodity prices have continued to decline. The decline in prices will likely negatively impact the price decks utilized by banks in their calculation of the Company’s borrowing base at May 1, 2016. If our next borrowing base redetermination results in a lower borrowing base, we may be unable to obtain financing otherwise currently available under the RBC Credit Facility. The Company incurred $2.2 million of arrangement and upfront fees in connection with the facility which will be amortized over the original four-year term of the facility. Proceeds of the RBC Credit Facility were, or may be used (i)
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
to finance working capital and for general corporate purposes, (ii) for permitted acquisitions, and (iii) to finance transaction expenses in connection with the facility and the Merger.
As of December 31, 2015, the Company had $115.4 million outstanding under the RBC Credit Facility, which matures on October 1, 2017, and $1.9 million in outstanding letters of credit. As of December 31, 2014, the Company had $63.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2015, borrowing availability under the RBC Credit Facility was $72.7 million.
The RBC Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties.
Borrowings under the RBC Credit Facility bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 0.5% to 2.5% margin, dependent upon the amount outstanding. Additionally, the Company must pay a commitment fee on the amount of the facility that remains unused, which varies from .375% to .5%, depending on the amount of the credit facility that is unused. Total interest expense under the RBC Credit Facility, including commitment fees, for the years ended December 31, 2015, 2014 and 2013 was approximately $3.2 million, $2.7 million and $1.2 million, respectively.
The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. As of December 31, 2015, the Company was in compliance with all covenants under the RBC Credit Facility, and at current commodity prices, we do not expect any covenant compliance issues over the next twelve months. The RBC Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events.
Amegy Bank Credit Facility
The RBC Credit Facility replaced the Company's $40 million credit facility with Amegy Bank. On October 22, 2010, the Company completed the arrangement of a secured revolving credit agreement with Amegy Bank (the “Amegy Credit Agreement”). Upon termination of the Amegy Credit Agreement, the Company was in compliance with all covenants and had no amounts outstanding. No early termination penalty was incurred as a result of the termination of the Amegy Credit Agreement. Interest expense under the Amegy Credit Agreement for the year ended December 31, 2013 was approximately $37,000.
14. Commitments and Contingencies
Contango pays delay rentals on its offshore leases and leases its office space and certain other equipment. Effective October 1, 2013, the Company moved its corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease that expires March 31, 2019. The Company remains responsible for the rent at its previous corporate office at 3700 Buffalo Speedway in Houston, Texas, through February 29, 2016; however, effective January 1, 2014, it subleased the previous corporate offices through February 29, 2016 and expects to recover the substantial majority of the rent it pays at that location.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
As of December 31, 2015, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years are as follows (in thousands):
The amounts incurred under operating leases and delay rentals during the years ended December 31, 2015, 2014, and 2013 were approximately $6.3 million, $6.0 million and $1.0 million, respectively. As of December 31, 2015, the Company’s commitment for potential future equity contributions with Exaro Energy III, LLC to develop onshore natural gas assets, was $20.6 million.
Legal Proceedings
From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
In July 2010, several parties associated with a limited partnership formed to invest in oil and gas properties that was dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in district court for Madison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The plaintiffs’ expert has recently provided a range of estimated monetary damages of up to approximately $9.4 million as to our Subsidiary. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses.
In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by us or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on summary judgment, in late 2014 the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing the trial court’s decision to the applicable state Court of Appeals.
In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by us in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds and the plaintiff has appealed the trial court’s decision to the
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
applicable state Court of Appeals. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit.
Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in April 2013 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the alleged improprieties occurred prior to the Company’s ownership of an interest in the wells at issue, although the Company may have assumed liability otherwise attributable to its predecessors-in-interest through the acquisition documents relating to the acquisition of the Company’s interest in these wells. This case is based on the same actions and allegations as a prior case in which the Company and its co-defendants prevailed. The plaintiffs claim damages of approximately $2.5 million against a subsidiary of the Company and its co-defendants. The Company and its co-defendants are vigorously defending this lawsuit and believe that they have a meritorious position.
While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.
Employment Agreements
As a result of successfully completing the Merger, Mr. Joseph J. Romano, the Company's Chairman and former Chief Executive Officer received a $4.0 million bonus payment in July 2014.
Also in connection with the Merger, Contango entered into employment agreements with each of Allan D. Keel, E. Joseph Grady, A. Carl Isaac, Jay S. Mengle and Thomas H. Atkins, all of which became effective on October 1, 2013. The employment agreements provide for an initial term of three years with automatic two-year extensions of the initial term, unless Contango or the executive provides prior notice of intention not to extend the agreement.
Under the employment agreements, Mr. Keel is entitled to a base salary of $600,000, Mr. Grady is entitled to a base salary of $400,000, Mr. Isaac is entitled to a base salary of $320,000, Mr. Mengle is entitled to a base salary of $300,000 and Mr. Atkins is entitled to a base salary of $310,000. The aforementioned executives entered into a Limited Waiver on or about September 1, 2015 to participate in a salary replacement program (the “Salary Replacement Program”) effective September 1, 2015 and expected to continue through December 31, 2016. The Salary Replacement Program reduces all office employees’ base salary by 10% and all board of director retainer and committee chairman fees by 10% and replaces annually the portion of the salary/fees being reduced with common stock in a number of shares commensurate with the salary/fees reduction amount. While the executives are participating in the Salary Replacement Program, Mr. Keel is entitled to a cash base salary of $540,000, Mr. Grady is entitled to a cash base salary of $360,000, Mr. Isaac is entitled to a cash base salary of $288,000, Mr. Mengle is entitled to a cash base salary of $270,000 and Mr. Atkins is entitled to a cash base salary of $279,000.
Per the employee agreements, each executive shall participate in the CIBP and the LTIP. With respect to the CIBP, these employee agreements provide that the executives are eligible to receive a cash bonus based upon minimum, target and maximum award levels of 50%, 100% and 150% for Mr. Keel; 50%, 90% and 130% for Mr. Grady; and 50%, 80% and 120% for Messrs. Isaac, Mengle and Atkins, respectively, of such executive’s base salary effective prior to the executive’s participation in the Salary Replacement Program. With respect to the LTIP, these employee agreements provide that the executives are eligible to receive stock option awards, restricted stock awards or a combination of both based upon minimum, target and maximum award levels of 75%, 350% and 450% for Mr. Keel; 75%, 250% and 450% for Mr. Grady; and 75%, 250% and 350% for Messrs. Isaac, Mengle and Atkins, respectively, of such executive’s base salary effective prior to the executive’s participation in the Salary Replacement Program. Actual awards for executives under the CIBP and the LTIP are subject to attainment of pre-determined corporate and personal goals for minimum, target or maximum levels of performance as determined by the board of directors for the performance period. Performance
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
levels below the minimum threshold in any performance metric result in forfeiture of that portion of the CIBP and/or LTIP award, unless otherwise determined by the board of directors.
15. Net Income (Loss) Per Common Share
A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2015, 2014 and 2013 is presented below (in thousands):
The numerator for basic earnings per share is net income (loss) attributable to common stockholders. The numerator for diluted earnings per share is net income unless there is a loss and then is (loss) available to common stockholders, due to antidilution.
Potential dilutive securities (stock options, stock warrants and convertible preferred stock) have not been considered when their effect would be antidilutive. The potentially dilutive shares, including both stock options and restricted shares, would have been 453,626 shares for the year ended December 31, 2015. The potentially dilutive shares, including both stock options and restricted shares, would have been 339,896 shares for the year ended December 31, 2014. The potentially dilutive shares, including both stock options and restricted stock, would have been 187,302 shares for the year ended December 31, 2013.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
16. Income Taxes
Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows (dollars in thousands):
The effective tax rate for December 31, 2015 varies from the statutory rate primarily as a result of recording a valuation allowance. The effective tax rate for December 31, 2014 varies from the statutory rate primarily due to the effect of state income tax expenses.
The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands):
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
The net deferred tax liability is comprised of the following (in thousands):
In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is less-than-more-likely-than-not that it will realize the benefits of these deductible differences and has recorded a valuation allowance of $57.5 million.
As of December 31, 2015, the Company had federal net operating loss (“NOL”) carryforwards of approximately $140.4 million and state NOLs of $12.0 million. The federal NOL carryforwards reported as of December 31, 2014 were acquired in the 2013 merger with Crimson. A valuation allowance was recorded at the time of the Merger to reflect the impact of Internal Revenue Code Section 382 limitations on the use of the federal NOLs acquired. The federal NOL carryforwards expire at various dates beginning in 2018 and ending in 2035.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
ASC 740, Income Taxes ("ASC 740") 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. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands):
The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in the Company’s Consolidated Statements of Operations. The Company had no interest or penalties related to unrecognized tax benefits for the year ended December 31, 2015 or any prior years. The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero.
The Company's tax returns are subject to periodic audits by the various jurisdictions in which the Company operates. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2015.
Generally, the Company's income tax years of 1998 through the current year remain open and subject to examination by Federal tax authorities, and the tax years of 2009 through current remain open and subject to examination by the tax authorities in Texas and Louisiana which are the jurisdictions where the Company carries its principal operations.
17. Related Party Transactions
Juneau Exploration L.P.
In April 2012, the Company announced that Mr. Brad Juneau, the sole manager of the general partner of Juneau Exploration L.P. (“JEX”), had joined the Company’s board of directors. In January 2013, Contaro Company, a wholly-owned subsidiary of the Company, entered into an advisory agreement with JEX (the "Contaro Advisory Agreement"). Under the Contaro Advisory Agreement, JEX provided advisory services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau served on the Board of Managers of Exaro and performed such duties as described in the limited liability company operating agreement of Exaro. Pursuant to the Contaro Advisory Agreement, JEX was paid a monthly fee of $10,000 and was entitled to receive a one percent (1%) fee of the cash profit earned by Contaro.
On March 19, 2014, Mr. Juneau resigned from the Company’s board of directors and no longer provides services under the Contaro Advisory Agreement. As a result, the Contaro Advisory Agreement was terminated effective as of March 19, 2014.
Olympic Energy Partners
Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company in December 2012, and named Chairman of the Company in April 2013. Upon the Merger with Crimson on October 1, 2013, Mr. Romano resigned as President and Chief Executive Officer, but continued as Chairman. Mr. Romano is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic").
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
JEX, affiliates of JEX, and Olympic have 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 ("WI"), net revenue interest ("NRI"), 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, excluding Mr. Juneau, except where otherwise noted. Olympic last participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to its Dutch and Mary Rose wells.
Republic Exploration LLC
In his capacity as sole manager of the general partner of JEX, Mr. Juneau also controlled the activities of Republic Exploration LLC ("REX"), an entity owned 34.4% by JEX, 32.3% by Contango, and 33.3% by a third party which contributed other assets to REX. REX generated and evaluated offshore exploration prospects and 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 of up to 3.33% to benefit the employees of JEX. The Company proportionately consolidates the results of REX in its consolidated financial statements.
Effective as of the close of business on December 31, 2015, the Company, and the other members of REX agreed to dissolve and liquidate REX. REX’s assets are being distributed proportionately to its members.
As of December 31, 2015, Contango, Olympic, JEX, REX and JEX employees owned the following interests in the Company's offshore wells.
Prior to December 2013, Contango, Olympic, and JEX had the following lower WI and NRI in Dutch #1-#5, as a result of exercising a preferential right in December 2013:
During the year ended December 31, 2015, Mr. Romano earned $79 thousand for his service as a director of the Company. During the year ended December 31, 2014, Mr. Romano earned $105 thousand for his service as a director of the Company. In April 2014, the board of directors accelerated the vesting of Mr. Juneau’s 1,622 shares which would have otherwise been forfeited upon his resignation in March 2014. The Company recognized compensation expense of approximately $71 thousand related to the shares granted to Mr. Juneau for the three months ended March 31, 2014. Additionally, during the years ended December 31, 2015 and 2014, Mr. Romano received 4,534 and 2,612 shares of restricted stock, respectively, which both vest 100% on the one-year anniversary of the date of grant, as part of his board of director compensation. The Company recognized compensation expense of $99 thousand and $124 thousand related to shares granted to Mr. Romano during the years ended December 31, 2015 and 2014, respectively. Below is a summary of transactions between the Company, Olympic, JEX, and REX during the years ended December 31, 2015, 2014 and 2013.
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
·
In June 2012, the Company purchased five federal lease blocks that were generated by REX. In connection with the dissolution and liquidation of REX, all participation agreements for these blocks that discussed carried interest arrangements, prospect fee payments, etc. are being terminated effective as of the date of the dissolution.
·
In June 2012, the Company purchased one federal lease block that was generated by REX. The Company paid JEX a prospect fee of $250,000 in December 2013 upon spudding this unsuccessful prospect.
·
In March 2013, the Company purchased three federal lease blocks that were generated by REX. In connection with the dissolution and liquidation of REX, all participation agreements for these blocks that discussed carried interest arrangements, prospect fee payments, etc. are being terminated effective as of the date of the dissolution. The Company paid JEX two prospect fees of $250,000 each in 2013, for evaluating these two prospects located on three leases.
·
In June 2013, the Company purchased South Timbalier 17 from an independent oil and gas company. Under the terms of the applicable participation agreement, the Company has a 75% working interest in this well, with several other owners owning the remainder. The Company paid JEX a prospect fee of $250,000 for evaluating this prospect.
·
In the Tuscaloosa Marine Shale the Company has a 100% working interest through first production. JEX will receive a carried working interest of 10% in certain of the Company’s TMS wells, and JEX employees will receive an ORRI of 2%, of which Mr. Juneau receives 0.75%, to reimburse Mr. Juneau for out-of-pocket costs incurred in order for Contango to participate in the prospect. An additional 2% ORRI was granted to the geologist who generated the TMS prospect for us. The geologist has subsequently been employed by Contango.
·
Effective January 1, 2014, the Company subleased to JEX a portion of its previous office space at 3700 Buffalo Speedway, Houston, Texas for approximately $0.1 million per year, which approximates its rental liability for that space. The sublease expires in February 2016.
Below is a summary of payments the Company received from (paid to) Olympic, JEX, and REX in the ordinary course of business in its capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types of payments with other well owners (in thousands):
Below is a summary of payments the Company received from (paid to) Olympic, JEX and REX as a result of specific transactions between the Company, Olympic, JEX and REX. While these payments are in the ordinary course of business, the Company did not have similar transactions with other well owners (in thousands):
			
		
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
			
		
As of December 31, 2015 and 2014, the Company's consolidated balance sheets reflected the following balances (in thousands):
Oaktree Capital Management L.P.
Oaktree Capital Management L.P. ("Oaktree"), through various funds, owns approximately 6.6% of the Company's stock. On October 1, 2013 following the closing of the Merger, Mr. James Ford, a Managing Director and Portfolio Manager within Oaktree at the time, was elected to the Company's board of directors. Mr. Ford was previously a member of Crimson's board of directors from February 2005 until the closing of the Merger.
As part of Mr. Ford's director compensation, all cash and equity awards payable to Mr. Ford, have been instead granted to an affiliate of Oaktree. During the year ended December 31, 2015, an affiliate of Oaktree earned $61 thousand in cash and 4,534 shares of restricted common stock as a result of Mr. Ford's board participation. During the year ended December 31, 2014, an affiliate of Oaktree earned $64 thousand in cash and 2,612 shares of restricted common stock as a result of Mr. Ford’s board participation. These shares vest one year from the date of grant. During the years ended December 31, 2015 and 2014, the Company recognized compensation expense of approximately $99 thousand and $124 thousand, respectively, related to the shares of restricted stock previously granted to an affiliate of Oaktree under the Director Compensation Plan
Prior to the Merger, Crimson maintained a second lien credit agreement with Barclays Bank Plc, as agent, and other parties, including an affiliate of Oaktree, which was Crimson's largest stockholder at the time (the “Second Lien Credit Agreement”). The Second Lien Credit Agreement provided for a term loan, made to Crimson in a single draw, in an aggregate principal amount of $175.0 million. In connection with the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million loan under the Second Lien Credit Agreement, plus $1.8 million in interest and prepayment premiums.
18. Subsequent Events
The Company has evaluated subsequent events through the date the financial statements were available to be issued. Nothing that would require recognition or disclosure in the financial statements was identified in addition to the items disclosed in the financial statements.
			 		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
			
		
In accordance with U.S. GAAP for disclosures regarding oil and gas producing activities, and SEC rules for oil and gas reporting disclosures, we are making the following disclosures regarding our natural gas and oil reserves and exploration and production activities.
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents information regarding our net capitalized costs related to oil and gas producing activities as of the date indicated (in thousands):
Costs Incurred
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated (in thousands):
The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated (in thousands):
Natural Gas and Oil Reserves
Proved reserves are the estimated quantities of natural gas, oil and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and current regulatory practices. Proved developed reserves are proved reserves which are expected to be produced from existing completion intervals with existing equipment and operating methods.
Proved natural gas and oil reserve quantities at December 31, 2012, and the related discounted future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc. Proved natural gas and oil reserve quantities at
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
			
		
December 31, 2015, 2014 and 2013, and the related discounted future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc. and Netherland, Sewell & Associates, Inc. All estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.
The below table summarizes the Company’s net ownership interests in estimated quantities of proved natural gas, oil and natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2015, 2014, 2013 and 2012, all of which are located in the continental United States.
During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe attributable primarily to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves, and in part to the impact of the significant reduction in our capital spending in response to the low and uncertain commodity price environment.
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe. This decrease is primarily attributable to 40.3 Bcfe of production and a 22.4 Bcfe negative revision of proved developed producing reserves at our
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
			
		
Eugene Island 11 field due to a change in forecasted condensate yield and ultimate field abandonment pressure; these decreases were partially offset by 36.1 Bcfe for extensions and discoveries.
During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe. This increase is primarily attributable to our Merger with Crimson, offset by normal production of 28.2 Bcfe during the year, a 19.2 Bcfe decrease in our Dutch and Mary Rose reserve estimates based upon additional pressure data, and a 2.5 Bcfe decrease in our Vermilion 170 reserve estimates, as determined by our reservoir engineer.
The below table summarizes the Company’s net ownership interests in estimated quantities of proved natural gas, oil and natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2015, 2014, 2013and 2012, attributable to its Investment in Exaro.
During the year ended December 31, 2015, Exaro’s proved reserves decreased by approximately 31.4 Bcfe attributable to the impact of the dramatic decline in commodity prices on the value and volume of proved reserves, and the impact of the significant reduction in capital spending in response to the low and uncertain commodity price environment.
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
			
		
The increase in Exaro’s extensions and discoveries in 2014 is due to the increase in the number of wells drilled in conjunction with higher development costs spent in 2013 and 2014. Exaro began operations in 2012.
Standardized Measure
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved natural gas and oil reserves as of December 31, 2015, 2014 and 2013 are shown below (in thousands):
Future cash inflows represent expected revenues from production and are computed by applying certain prices of natural gas and oil to estimated quantities of proved natural gas and oil reserves. Prices are based on the first-day-of-the-month prices for the previous 12 months. As of December 31, 2015, future cash inflows were based on unadjusted prices of $2.59 per MMbtu of natural gas, $47.36 per barrel of oil, and $14.41 per barrel of NGLs. As of December 31, 2014, future cash inflows were based on unadjusted prices of $4.32 per MMbtu of natural gas, $93.32 per barrel of oil, and $33.45 per barrel of NGLs. As of December 31, 2013, future cash inflows were based on unadjusted prices of $3.66 per MMbtu of natural gas, $97.33 per barrel of oil, and $37.39 per barrel of NGLs.
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved natural gas and oil reserves as of December 31, 2015, 2014 and 2013 attributable to its Investment in Exaro are shown below (in thousands):
Realized Prices
The average realized prices for the year ended December 31, 2015 production were $2.61 per MCF of gas, $46.80 per barrel of oil, and $14.68 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging gains of $2.3 million for the year ended December 31, 2015.
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
			
		
The average realized prices for the year ended December 31, 2014 production were $4.36 per MCF of gas, $92.98 per barrel of oil, and $33.27 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging gains of $1.3 million for the year ended December 31, 2014.
Future production and development costs are estimated expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves based on historical costs and assuming continuation of existing economic conditions. Future development costs relate to compression charges at our platforms, abandonment costs, recompletion costs, and additional development costs for new facilities.
Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.
The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro does not include the effect of income taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or expense for tax purposes to its partners.
Change in Standardized Measure
Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized below (in thousands):
During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe and our standardized measure decreased by approximately $398.6 million. This decrease is attributable primarily to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves, and in part to the impact of the significant reduction in our capital spending in response to the low and uncertain commodity price environment.
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe and our standardized measure decreased by approximately $123.4 million. This decrease is primarily attributable to 40.3 Bcfe of production and a 22.4 Bcfe
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
			
		
negative revision of proved developed producing reserves at our Eugene Island 11 field due to a change in forecasted condensate yield and ultimate field abandonment pressure; these decreases were partially offset by 36.1 Bcfe for extensions and discoveries.
During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe and our standardized measure increased by approximately $383.4 million. This increase is primarily attributable to our Merger with Crimson as well as the acquisition of additional interests in our operated Dutch offshore reserves, offset by normal production of 28.2 Bcfe during the year, a 19.2 Bcfe decrease in our Dutch and Mary Rose reserve estimates based upon additional pressure data, and a 2.5 Bcfe decrease in our Vermilion 170 reserve estimates, as determined by our reservoir engineer. The "Sale of reserves" line includes the sale of a partial interest in the Company's properties located in Madison and Grimes Counties.
Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves attributable to the Company’s investment in Exaro are summarized below (in thousands):
			 		
			
		
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
QUARTERLY RESULTS OF OPERATIONS (Unaudited)
			
		
Quarterly Results of Operations
The following table sets forth the results of operations by quarter for the fiscal years ended December 31, 2015 and 2014, (in thousands, except per share amounts):
(1)
Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of natural gas and oil properties, general and administrative expense, and other income and expense before income taxes.
(2)
The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income for that quarter and the weighted average number of common shares outstanding during that quarter.