HOUSTON--(BUSINESS WIRE)-- Contango Oil & Gas Company (NYSE MKT: MCF) ("Contango") announced today its fourth quarter production results, year-end reserves, preliminary 2015 capital program and provided an operational update on recent drilling activity.

Allan Keel, President and CEO of Contango, commented: "We believe that the appropriate strategy for creating shareholder value in this low commodity price, high cost environment is to reduce drilling activity, utilize excess cash flow to improve our already strong financial profile, and stay positioned to potentially take advantage of growth opportunities that might surface in the near future as capital-stressed companies shed assets, search for JV partners or pursue long term strategic alternatives. Our financial flexibility, and inventory of drilling locations, also position us to expand our 2015 capex program if commodity prices improve, service costs decline, or both." But more importantly, drilling development wells and selling our product into this environment, we believe is counter-productive to enhancing shareholder value. Since a substantial portion of the present value of production from new wells is realized within the first 18 months of a well's life, i.e. during this low price environment, and because the cost of drilling those wells is expected to decline as the service sector cost structure aligns with the commodity price environment, we believe that drilling activity should be limited to only that which is necessary to meet short-term lease expirations, and in some cases, strategic exploratory test wells that potentially expose us to multiple long-term growth opportunities if successful.

Fourth Quarter Production Results

Production for the fourth quarter of 2014 was approximately 9.8 Bcfe, or 106.2 Mmcfe per day. Production for the fourth quarter was approximately 3% less than production for the fourth quarter of 2013, due primarily to our transition to a multi-well pad drilling strategy in our Chalktown area late in the third quarter of 2014. The change to multi-well pad drilling provides drilling cost efficiencies and overall recovery enhancement; however, the related delay in initial production from the two new three-well pads drilled in September through December precluded us from increasing production compared to the prior year quarter. One multi-well pad began producing in mid-January at a restricted rate due to limited natural gas takeaway capacity, while the second multi-well pad is expected to begin production in late-March. Further impacting fourth quarter production, and expected production for 2015, was a reduction in drilling activity associated with the dramatic downturn in crude oil and natural gas prices during the fourth quarter. Partially offsetting this decrease in production was increased production from additional interests in our Dutch wells acquired in December 2013 and new production from our 2013 discovery at South Timbalier 17 which began producing in July 2014. Crude oil and natural gas liquids production during the fourth quarter of 2014 was approximately 5,600 barrels per day, or 32% of total production, compared to approximately 6,300 barrels per day, or 34% of total production, in the fourth quarter of 2013, a decline also associated with the lower capital expenditures in the fourth quarter and the change in drilling strategy in our Chalktown area. Our first quarter 2015 production guidance of 95-105 Mmcfed reflects the impact of the lower fourth quarter 2014 capital program, the expected delays in attaining full production rates from new multi-well pads drilled in our Chalktown area and our decision to reduce our planned 2015 capital program (as described herein) due to the low and uncertain commodity price environment.

Year-end 2014 Proved Reserves

As of December 31, 2014, our independent third-party engineering firms estimated our proved oil and natural gas reserves to be approximately 275.2 Bcfe, of which 65% was natural gas, 18% was oil and condensate, and 17% was natural gas liquids. This represents a 12% decrease compared to our proved reserves reported as of December 31, 2013. Exclusive of an approximate 22.4 Bcfe negative revision of proved developed producing reserves at our Eugene Island 11 field, reserves as of December 31, 2014 would have been approximately 5% lower than the prior year reserves, mainly attributable to the change in late 2014 drilling strategy and normal production decline. The negative revision at Eugene Island 11 resulted from a change in forecasted condensate yield and lower original gas in place, as determined by our third party engineers as a result of recent field performance and a pressure study done in conjunction with the recent shut-in for compression installation. As of December 31, 2013, our reported proved reserves were 66% natural gas, 19% oil and condensate, and 15% natural gas liquids. These estimates were prepared in accordance with reserve reporting guidelines mandated by the Securities and Exchange Commission. These estimates do not include net reserves of approximately 70.2 Bcfe attributable to our 37% equity ownership interest in Exaro Energy III LLC ("Exaro") as of December 31, 2014.

As of December 31, 2014, the PV-10 value of our proved reserves was approximately $797 million, compared to our PV-10 value of $987 million as of December 31, 2013. The decrease in PV-10 year over year can be attributed to 2014 production, the negative revision to our Eugene Island 11 reserves, the slowdown in drilling activity in the fourth quarter of 2014 and the decrease in crude oil and natural gas liquids prices. As of December 31, 2014, the average adjusted product prices over the remaining lives of the reserves used in determining our proved reserves and PV-10 value were $92.89/Bbl for oil and condensate, $4.38/Mmbtu for natural gas and $33.45/Bbl for natural gas liquids. As of December 31, 2013, the average adjusted product prices over the remaining lives of the reserves used in determining our proved reserves and PV-10 value were $106.80/Bbl for oil and condensate, $3.73/Mmbtu for natural gas and $35.92/Bbl for natural gas liquids.

Our proved developed reserves for the year ended December 31, 2014 decreased by 46.9 Bcfe. Of this amount, 40.4 Bcfe related to production during the year and 22.4 Bcfe related to the negative revision at Eugene Island 11 discussed above, partially offset by 9.4 Bcfe in positive onshore revisions and 6.5 Bcfe in extensions and discoveries from our 2014 drilling program.

Our proved undeveloped reserves for the year ended December 31, 2014 increased by 8.2 Bcfe, an increase attributable to our 2014 drilling program that added 27.0 Bcfe, partially offset by negative revisions of 17.2 Bcfe associated with a revised type curve for our Force area of our Madison/Grimes acreage.

2015 Capital Program

As a result of the dramatic downturn in crude oil, natural gas and natural gas liquids prices in late 2014 and 2015, the negative impact of those price declines on the economics of most domestic resource plays, and the continuing uncertainty as to when, or how much, the commodity price environment might improve, we believe that deferring further drilling in our current resource plays until prices improve is the most prudent strategy to pursue at this time. Since 60-70% of the PV-10 of a typical resource well's life (in our areas, and on a flat price basis) is produced within the first 18 months, we believe that the deferral of further drilling in our areas pending a better price environment is a better strategy for realizing value from our portfolio. Accordingly, our capital expenditure program for 2015 will be focused on: 1) the enhancement of our already strong and flexible financial position through limiting our capital expenditure budget to no more than internally generated cash flow; 2) focusing drilling expenditures on strategic projects; and 3) identifying and implementing opportunities for cost efficiencies and improvements in all areas of our operations. Though not formally incorporated in our 2015 budget, our strong financial liquidity position should allow us to be opportunistic and take advantage of new resource potential opportunities, organically or through acquisition, which we might identify in a continuing low commodity price environment. Our current capital budget of approximately $51 million for 2015 will allow us to meet our contractual requirements, remain in position to preserve our term acreage where appropriate and improve our financial profile by lowering overall Company liabilities. Our current 2015 capital budget represents a decrease of 73% compared to our total 2014 capital expenditures of $189 million, and a 68% decrease in onshore, drilling capital expenditures. We have the flexibility, liquidity, and inventory to significantly increase our level of spending should circumstances change over the course of the year. Our specific plans, by area, include:

We will continuously monitor commodity prices and the expected decline in service/supply costs during the year, and if deemed appropriate, we possess the financial flexibility to expand our drilling program for the remainder of the year.

Drilling Activity Update

Southeast Texas (Woodbine)

Chalktown Area, Madison County, Texas

We initiated a multi-well pad drilling strategy on 500 foot spacing in our Chalktown area late in the third quarter of 2014, a strategy where three wells are drilled in succession, completed in succession, and then put on production simultaneously to maximize recovery. Results of fourth quarter activity are as follows:

Iola/Grimes Area, Grimes County, Texas

We spud one well in Grimes County during the fourth quarter:

The Norwood well was designed as an extended lateral into the Upper Lewisville formation. The well will be completed using twice the number of frac stages, four times the amount of proppant, and fifty percent longer effective lateral lengths as our previous two attempts in the Iola Grimes area. We believe that this test could have significant impact on the southern portion of our leasehold.

South Texas (Buda),Zavala and Dimmit Counties

Our recent activity in the Buda in South Texas consisted of the following:

Since May of 2013, we have drilled or participated in 19 wells within the Buda trend and believe that we have defined the optimum spacing and productive sweet spot. Additional drilling in the Buda will be limited going forward; instead we will drill an Eagle Ford Shale well on our KM Ranch acreage in Zavala County utilizing a longer lateral, more frac stage and more proppant strategy than we used in our two previous wells in this area.

Additionally, during the fourth quarter of 2014, we drilled the Beeler Unit 24H as a vertical pilot well to evaluate the Eagle Ford in Zavala and Dimmit Counties. We are evaluating the recovered core data prior to deciding on a new development strategy for the Eagle Ford in these areas.

Fayette & Gonzales County, Texas (Elm Hill Project)

We brought three wells on production on our Elm Hill project during the quarter, and spud two additional wells. We continue to lease in this area, so we have presented limited information on the results on our drilling activity due to competition in the area.

We expect to analyze and evaluate the combined results and then confer with our partner to determine a future strategy for our 56,000 gross acre position in the area.

Natrona County, Wyoming (FRAMS Project)

We drilled our first well in Natrona County during the fourth quarter, targeting the Mowry Shale:

The well was drilled to its intended total measured depth, with completion operations expected to commence in March or April. We will monitor results on this well for several months and determine future drilling plans for this approximate 120,000 gross acre position.

Weston County, Wyoming (N. Cheyenne Project)

Upon completion of drilling on the Natrona County well, we moved the rig to Weston County and spud our first well there in January 2015, targeting the Muddy Sandstone formation:

We are currently drilling the lateral section of this well and anticipate reaching total depth prior to completion operations commencing in Natrona County. Upon completion of the frac in Natrona County, the crew will be mobilized to Weston County to begin completion operations. We will also monitor results on this well for several months and determine next steps for this 49,000 gross acre position.

Borrowing Base Reaffirmation

During the fourth quarter of 2014, our bank group reaffirmed our $275 million borrowing base under our senior revolving credit facility. The borrowing base was reaffirmed through May 1, 2015, the next regularly scheduled borrowing base redetermination date. As of December 31, 2014, we had approximately $63.4 million outstanding under our credit facility.

Contango Oil & Gas Company is a Houston, Texas-based, independent energy company engaged in the acquisition, exploration, development, exploitation and production of crude oil and natural gas offshore in the shallow waters of the Gulf of Mexico and in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States. Additional information is available on the Company's website at http://contango.com.

This press release contains forward-looking statements regarding Contango that are intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995, based on Contango's current expectations and includes statements regarding acquisitions and divestitures, estimates of future production, future results of operations, quality and nature of the asset base, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance (often, but not always, using words such as "expects", "projects", "anticipates", "plans", "estimates", "potential", "possible", "probable", or "intends", or stating that certain actions, events or results "may", "will", "should", or "could" be taken, occur or be achieved). Statements concerning oil and gas reserves also may be deemed to be forward looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those, reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters); uncertainties as to the availability and cost of financing; fluctuations in oil and gas prices; risks associated with derivative positions; inability to realize expected value from acquisitions, inability of our management team to execute its plans to meet its goals, shortages of drilling equipment, oil field personnel and services, unavailability of gathering systems, pipelines and processing facilities and the possibility that government policies may change or governmental approvals may be delayed or withheld. Additional information on these and other factors which could affect Contango's operations or financial results are included in Contango's other reports on file with the Securities and Exchange Commission. Investors are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking statements. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Contango does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.

Contango Oil & Gas Company
E. Joseph Grady, 713-236-7400
Senior Vice President and Chief Financial Officer
or
Sergio Castro, 713-236-7400
Vice President and Treasurer

Source: Contango Oil & Gas Company

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