Aug 6, 2015

Contango Announces Second Quarter 2015 Financial Results and Provides Operations Update

HOUSTON--(BUSINESS WIRE)-- Contango Oil & Gas Company (NYSE MKT: MCF) ("Contango") announced today its financial results for the three months ended June 30, 2015 and provided an operational update.

Second Quarter 2015 Summary

  • Production of 9.0 Bcfe for the quarter (98.4 Mmcfed; 36% liquids), above the mid-point of guidance
  • Net loss of $19.5 million and Adjusted EBITDAX of $19.9 million for the quarter
  • Discovery and successful completion of our first well in the Muddy Sandstone formation in Weston County, Wyoming
  • Commenced production from four wells drilled from our second multi-well pad using 500 foot spacing in our Chalktown area
  • Lawsuit related to 2010 pipeline damage resolved in July 2015 with proceeds of approximately $4.8 million, net to Contango, received

Management Commentary

Allan D. Keel, the Company's President and Chief Executive Officer, said, "Though we continue to face a challenging and uncertain commodity price environment, we made significant progress during the quarter at accomplishing a number of strategic objectives we set for ourselves at the beginning of the year. We drilled our first test of the Muddy formation in Weston County, Wyoming and announced a very nice discovery on our 35,000 net acre prospect; we finished the completion of our two multi-well pads, and facilities, and brought production up to the optimum level on the seven wells drilled on 500 foot spacing in our Chalktown area; and we drilled a vertical pilot well and recovered 250 feet of whole core to analyze the potential of a number of zones, including the Eagle Ford and Lower Lewisville, in our Madison County acreage. We are also close to the completion of the initial testing of various formations in our Elm Hill Project in Fayette/Gonzales counties, Texas, with encouraging results seen during current completion operations on our two most recent wells. Though it appears oil prices will remain low for the remainder of this year, the results we have seen in these wells, declining service costs and the benefit to be derived from further delineation, are encouraging enough for us to increase our planned activity for the rest of the year in at least one or two of these areas."

Summary Financial Results for the Quarter Ended June 30, 2015

Net loss for the three months ended June 30, 2015 was $19.5 million, or $1.03 per basic and diluted share, compared to net income of $4.6 million, or $0.24 per basic and diluted share, for the prior year quarter. Revenues were lower because of the dramatic decline in commodity prices and lower production related to our reduced capital drilling program. Offsetting the impact of the revenue decline, in part, were decreases in exploration expense, operating expenses and G&A compared with the 2014 second quarter. Included in the prior year results was $10.1 million in pre-tax exploration expenses and $0.5 million of leasehold impairment attributable to our unsuccessful Ship Shoal 255 exploratory well. The current quarter includes $6.5 million related to our unsuccessful State #1H well in Natrona County, Wyoming targeting the Mowry Shale formation. Average weighted shares outstanding were approximately 18.9 million for the current quarter and 19.1 million for the prior year quarter.

The Company reported Adjusted EBITDAX, as defined below, of approximately $19.9 million for the three months ended June 30, 2015, compared to $56.7 million for the same period last year, a decrease mainly attributable to the decrease in revenues, partially offset by a decrease in lease operating costs and G&A expenses.

Revenues for the three months ended June 30, 2015 were $35.3 million compared to $78.4 million for the same period last year, a decrease attributable to lower commodity prices and lower production related to our reduced capital drilling program in the latter half of 2014 and in 2015.

Production for the three months ended June 30, 2015 was approximately 9.0 Bcfe, or 98.4 Mmcfed, which was toward the higher end of our previously provided guidance, but less than the 10.6 Bcfe, or 116.0 Mmcfed, for the same period last year. As previously discussed, due to the low and uncertain commodity price environment, we reduced our capital activity level dramatically beginning in the third quarter of 2014 and focused on projects for which the commencement of full production was deferred until the first half of 2015. In 2015, we have focused on confirmation of our exploratory prospects with emphasis more on maximizing success and ultimate recovery than on immediate production. Crude oil and natural gas liquids production during the current period was approximately 5,900 barrels per day, or 36% of total production, compared to approximately 7,000 barrels per day, or 36% of total production for the same period last year. For the third quarter of 2015, we estimate our production will be between 90 - 95 Mmcfed, with July 2015 production averaging approximately 97.5 Mmcfed.

The weighted average equivalent sales price during the three months ended June 30, 2015 was $3.94 per Mcfe, compared to $7.43 per Mcfe for the same period last year. The decrease in the weighted average equivalent prices quarter over quarter was attributable to a 43% decrease in average oil and condensate prices, a 42% decline in natural gas prices and a 53% decrease in natural gas liquids prices.

Total operating expenses for the three months ended June 30, 2015 were approximately $11.0 million, or $1.22 per Mcfe, compared to $11.6 million, or $1.10 per Mcfe, for the same period last year. Included in total operating expenses are direct lease operating expenses ("LOE"), transportation and processing costs, workover expenses and production and ad valorem taxes.

Direct operating expenses (i.e. total operating expenses, excluding production and ad valorem taxes) for the three months ended June 30, 2015 were approximately $9.2 million, or $1.02 per Mcfe, which was outside our previously provided guidance, compared to approximately $8.5 million, or $0.80 per Mcfe, for the same period last year. Approximately $1.1 million of workover costs were incurred during the current year quarter, as we accelerated the timing of future planned workovers, compared to $0.4 million in 2014. Exclusive of workover costs, direct operating costs were relatively flat compared to 2014 despite increased costs from new fields and wells (onshore and South Timbalier 17) and increased operating costs associated with the compression facilities added at Eugene Island during the third quarter of 2014. A large portion of monthly lease operating expenses are fixed costs; therefore, the increase in per unit cost can be attributed primarily to the higher workover expenses and the lower production.

Production and ad valorem tax expense for the three months ended June 30, 2015 was $1.8 million, or $0.20 per Mcfe, compared to $3.1 million, or $0.30 per Mcfe, for the same period last year, a decrease associated with lower revenues.

Exploration expense for the three months ended June 30, 2015 were $6.9 million, compared to $10.9 million for the same period last year, as the current quarter includes $6.5 million related to our unsuccessful State #1H well in Natrona County, Wyoming targeting the Mowry Shale formation, and the prior year included $10.1 million in drilling costs on our unsuccessful Ship Shoal 255 exploratory well finalized in May 2014.

DD&A expenses for the three months ended June 30, 2015 were $38.8 million, or $4.33 per Mcfe, compared to $39.9 million, or $3.78 per Mcfe, for the same period last year. The higher overall per unit charge in 2015 is primarily a result of specific field rate increases associated with price-related year-end 2014 reserve revisions.

Impairment and abandonment expense from oil and gas properties for the quarter ended June 30, 2015 included an impairment charge of $0.3 million for certain unproved prospects due to expiring leases.

G&A expenses for the three months ended June 30, 2015 were $7.4 million, or $0.82 per Mcfe, compared to $9.2 million, or $0.87 per Mcfe, for the prior year quarter. G&A expenses for the current and prior year quarter, exclusive of $1.4 million and $1.0 million, respectively, in non-cash stock compensation expense, were $6.0 million and $8.2 million, respectively. The prior year quarter included $1.3 million of merger-related costs, with the remainder of the improvement a reflection of the Company's focus on reducing costs in all areas of operation. For the third quarter of 2015, we have provided guidance of $5.2 million to $5.7 million for general and administrative expenses, exclusive of non-cash stock compensation ("Cash G&A").

Derivative Instruments

We have the following derivative contracts in place for the remainder of the year with a member of our bank group:

Commodity Period Derivative Volume/Month Price/Unit (1)
Crude Oil July 2015 - Dec 2015 Collar 35,000 Bbls $55.00 - $65.15
Crude Oil July 2015 Collar 25,000 Bbls $55.00 - $65.05

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


Drilling Activity Update

Woodbine - Madison County, Texas

The initial three wells completed on 500 foot spacing in the Woodbine formation commenced production in January 2015 and averaged a combined restricted rate of 2,400 Boepd for the initial 30 days, and a combined unrestricted rate of approximately 1,300 Boepd (700 Boepd net to Contango) during July 2015. The remaining four wells were brought online during the current quarter and averaged a combined 2,017 Boepd for the initial 30 days, and approximately 1,200 Boepd (550 Boepd net to Contango) during July 2015. We are pleased with the production from the individual well results drilled on 500 foot spacing; however, in this commodity price environment, we do not believe that the 500 foot spacing strategy provides the optimum return on invested capital. Future drilling in this area will likely be planned on at least 1,000 foot spacing. Due to our strategy of limiting our capital program to internally generated cash flow, and the fact that this area is primarily acreage held by production, we will likely defer any additional drilling in this area until 2016 in order to further delineate our Wyoming and Fayette County plays.

We also recently drilled the following well in our Chalktown area:


Total Measured

30 Day Avg IP

WI %

Depth (ft.)

Lateral (ft.)

Frac Stages

First Production


% Oil

Viniarski A 1H 65% 16,773 7,656 30 April 2015 797 37%

In addition, we recently drilled the Hoke #1 well as a vertical pilot well in the Chalktown Area with 250' of whole core recovered for enhanced reservoir analysis. The primary zone of interest is the Lower Lewisville sand which is approximately 130' thick and in which no vertical or horizontal wells have been completed at this time. Early log indications were encouraging, and we are currently awaiting the final core analysis prior to drilling a horizontal test well or sidetracking the Hoke #1, likely in early 2016.

Woodbine (Lewisville) and Eagle Ford - Grimes County, Texas

We recently finalized an Upper Lewisville test well in Grimes County to test the concept of longer laterals, more frac stages and more proppant. The well began producing in March 2015, and initial results from this well have been disappointing. This is our third test of the Upper Lewisville formation in Grimes County, with the combined results, on average, failing to provide economics sufficient enough to continue to pursue the Upper Lewisville in this area.

We drilled the Stokes #1 vertical pilot well in Grimes County in March 2014 primarily to core the Eagle Ford. Preliminary core analysis indicates rock properties similar to our East Texas Eagle Ford play currently being developed in Brazos and Burleson counties, Texas, which, combined with recent off-set operator success in Burleson County adjacent to the west, provides optimism about the viability of the Eagle Ford in the Grimes County area.

Eagle Ford - Zavala and Dimmit Counties, Texas

In late 2014, we drilled a vertical pilot well to evaluate the Eagle Ford in Zavala and Dimmit Counties. We have been encouraged by the preliminary core analysis and will likely plan a test well targeting the Eagle Ford for 2016 on our KM Ranch acreage in Zavala County utilizing longer laterals, more frac stages and more proppant than used in our previous two Eagle Ford wells in this area; however, due to the likely dedication of additional capital to our Wyoming project this year, this Eagle Ford test is expected to be deferred until 2016. Operators continue to drill wells with excellent productivity in the immediate area of our leasehold.

Muddy Sandstone - Weston County, Wyoming

In June 2015, we announced the discovery and successful completion of the Elliott #1H well (80% WI) in the Muddy Sandstone formation in Weston County, Wyoming (North Cheyenne Project). While the well initially tested at 907 Boepd (98% oil) in May 2015, average production fell to 366 Boepd (100% oil) during June 2015. Due to low and inconsistent reservoir energy, we are currently installing a rod pump to provide a more effective and consistent lift mechanism. Due to the encouraging results from this well, we anticipate spudding one to two additional wells beginning in late summer 2015 to further delineate this discovery with full scale development expected to begin in early 2016 utilizing one to two rigs. Approximately 200 to 300 Muddy horizontal well locations are prospective on our acreage, based on a drilling density of three to four wells per 640 acres.

Mowry Shale - Natrona County, Wyoming

During the fourth quarter of 2014, we drilled the State #1H well in the Mowry Shale formation in Natrona County, Wyoming (referred to as our FRAMS Project). In April 2015, initial flowback began and no hydrocarbons were produced during the testing period. As a result, for the three months ended June 30, 2015, we recognized $6.5 million in exploration expense for the cost of drilling the well. Though this well was disappointing, we did earn approximately 23,000 net acres in the prospect area under this drill-to-earn arrangement, and will continue to evaluate the possibility of testing other formations on the acreage earned.

Elm Hill Project - Fayette and Gonzales Counties, Texas

As of June 30, 2015, we had drilled a total of five wells in Fayette and Gonzales counties, Texas, targeting multiple formations. The first well, the Janecka 1H, targeted the Navarro formation and began production in November 2014. This well averaged 381 Boepd (87% oil) for the initial 30 days and averaged 130 Boepd (73% oil) during July 2015. The next two wells fell short of expectations. The fourth well (targeting the Buda formation) and fifth well (targeting the Austin Chalk formation) are in the completions stages, but had encouraging indications during the initial stages. Subsequent to the completion and testing of these two wells, we and our partner will analyze all results to determine what further delineation efforts and long-term development plan will be pursued in the second half of the year and beyond.

2015 Capital Program & Liquidity

Capital expenditures incurred for the three months ended June 30, 2015 were $11.9 million, including $1.1 million on the Woodbine formation in Madison and Grimes counties, Texas; $1.4 million on our Elm Hill Project in Fayette and Gonzales counties; $4.2 million in Wyoming; and $4.5 million for the acquisition of leases and other rights in areas.

We currently anticipate that our total capital expenditure program for 2015 will be between $50 and $60 million (including amounts spent during the first six months of the year), depending on how many incremental wells we ultimately drill - which will be funded primarily from internally generated cash flow.

As of June 30, 2015, we had approximately $111.4 million of debt outstanding under our credit facility compared to approximately $63.4 million at the end of 2014, an increase due to having incurred the vast majority of our 2015 capital expenditure budget during the first two quarters, as planned, and lower revenues. We currently project that our debt level at year-end 2015 will be similar to our current level with a simultaneous decrease in overall current trade payables and accruals.

Our revolving credit facility has a borrowing base of $225 million, with our next regularly scheduled redetermination on November 1, 2015.

Legal Proceedings

In May 2015, a subsidiary of the Company and several working interest partners successfully settled a lawsuit with a mineral interest owner and a third-party operator in Dimmit County, Texas, resulting in the Company and its working interest partners receiving $5.0 million ($2.5 million net to Contango). The suit involved a challenge from the mineral interest owner to the validity of an oil and gas lease and various other claims relating to the property subject to the lease.

In February 2011, a subsidiary of the Company, certain working interest partners and its insurance carriers brought suit against a marine construction, dredging and tunneling company and an instrumentality of the United States of America seeking monetary damages for damage to one of our offshore pipelines which was struck by a dredge in 2010. Following a bench trial in December 2013, the Company and its co-defendants obtained a favorable judgment from the trial court. The U.S. Court of Appeals for the 5th Circuit affirmed the trial court's ruling in late May 2015 and one of the co-defendants recently paid the full judgment amount of $13.9 million ($4.8 million net to the Company).

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and six month periods ended June 30, 2015 and 2014:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 % 2015 2014 %
Offshore Volumes Sold:
Oil and condensate (Mbbls) 53 74 -28 % 107 155 -31 %
Natural gas (Mmcf) 4,267 4,893 -13 % 8,927 10,263 -13 %
Natural gas liquids (Mbbls)   126   152 -17 %   259   318 -19 %
Natural gas equivalents (Mmcfe) 5,342 6,250 -15 % 11,123 13,098 -15 %
Onshore Volumes Sold:
Oil and condensate (Mbbls) 222 307 -28 % 410 583 -30 %
Natural gas (Mmcf) 1,444 1,837 -21 % 2,653 3,298 -20 %
Natural gas liquids (Mbbls)   141   105 34 %   231   207 12 %
Natural gas equivalents (Mmcfe) 3,616 4,310 -16 % 6,500 8,038 -19 %
Total Volumes Sold:
Oil and condensate (Mbbls) 275 381 -28 % 517 738 -30 %
Natural gas (Mmcf) 5,711 6,730 -15 % 11,580 13,561 -15 %
Natural gas liquids (Mbbls)   267   257 4 %   490   525 -7 %
Natural gas equivalents (Mmcfe) 8,958 10,560 -15 % 17,623 21,136 -17 %
Daily Sales Volumes:
Oil and condensate (Mbbls) 3.0 4.2 -28 % 2.9 4.1 -30 %
Natural gas (Mmcf) 62.8 74.0 -15 % 64.0 74.9 -15 %
Natural gas liquids (Mbbls)   2.9   2.8 4 %   2.7   2.9 -7 %
Natural gas equivalents (Mmcfe) 98.4 116.0 -15 % 97.4 116.8 -17 %
Average sales prices:
Oil and condensate (per Bbl) $ 57.14 $ 100.53 -43 % $ 51.03 $ 99.52 -49 %
Natural gas (per Mcf) $ 2.68 $ 4.64 -42 % $ 2.77 $ 4.86 -43 %
Natural gas liquids (per Bbl) $ 16.33 $ 34.40 -53 % $ 15.27 $ 36.91 -59 %
Total (per Mcfe) $ 3.94 $ 7.43 -47 % $ 3.74 $ 7.51 -50 %
    Three Months Ended       Six Months Ended
June 30, June 30,
2015     2014     % 2015     2014     %
Offshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.60 $ 0.41 46 % $ 0.62 $ 0.47 32 %
Production and ad valorem taxes $ 0.08 $ 0.10 -20 % $ 0.08 $ 0.10 -20 %
Onshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.65 $ 1.36 21 % $ 1.70 $ 1.30 31 %
Production and ad valorem taxes $ 0.37 $ 0.59 -37 % $ 0.31 $ 0.60 -48 %
Average Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.02 $ 0.80 28 % $ 1.01 $ 0.78 29 %
Production and ad valorem taxes $ 0.20 $ 0.30 -33 % $ 0.17 $ 0.29 -41 %
General and administrative expense (cash) $ 0.66 $ 0.77 -14 % $ 0.72 $ 0.83 -13 %
Interest expense $ 0.09 $ 0.07 29 % $ 0.09 $ 0.07 29 %
Adjusted EBITDAX (2) (thousands) $ 19,870 $ 56,742 $ 33,945 $ 114,771
Weighted Average Shares Outstanding (thousands)
Basic 18,939 19,074 18,939 19,073
Diluted 18,939 19,130 18,939 19,073
(1) LOE includes transportation and workover expenses
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net loss.
June 30, December 31,
2015 2014


Cash and cash equivalents $




Accounts receivable, net 23,171 25,309
Other current assets 5,441 5,731
Net property and equipment 710,486 748,623
Investments in affiliates and other non-current assets   63,283   63,752
TOTAL ASSETS $ 802,381 $ 843,415


Accounts payable and accrued liabilities 60,047 92,892
Other current liabilities 4,935 4,123
Long-term debt 111,402 63,359
Deferred tax liability 72,409 93,952
Asset retirement obligations 21,643 21,623
Total shareholders' equity   531,945   567,466
Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Oil and condensate sales $ 15,688 $ 38,340 $ 26,382 $ 73,440
Natural gas sales 15,287 31,244 32,110 65,871
Natural gas liquids sales   4,359     8,835     7,489     19,365  
Total revenues   35,334     78,419     65,981     158,676  
Operating expenses 10,972 11,576 20,883 22,629
Exploration expenses 6,924 10,853 11,407 37,784
Depreciation, depletion and amortization 38,770 39,901 73,885 74,303
Impairment and abandonment of oil and gas properties 236 1,371 2,517 16,566
General and administrative expenses   7,351     9,207     15,179     19,664  
Total expenses   64,253     72,908     123,871     170,946  
Gain (loss) from investment in affiliates (net of income taxes) (745 ) 1,478 (187 ) 3,100
Interest expense (835 ) (737 ) (1,530 ) (1,405 )
Loss on derivatives, net (10 ) (1,263 ) (10 ) (3,222 )
Other income (expense)   995     (196 )   990     (196 )
Total other income (expense)   (595 )   (718 )   (737 )   (1,723 )
NET INCOME (LOSS) BEFORE INCOME TAXES   (29,514 )   4,793     (58,627 )   (13,993 )
Income tax benefit (provision)   9,986     (212 )   20,535     8,381  
NET INCOME (LOSS) $ (19,528 ) $ 4,581   $ (38,092 ) $ (5,612 )

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, depletion and amortization, and oil & gas expenses. Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below, all of which will be required in determining our compliance with financial covenants under the RBC Credit Facility.

We have included EBITDAX and Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreements. We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results. Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreements. We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX. Non-compliance with the financial covenants contained in these credit agreements could result in a default, an acceleration in the repayment of amounts outstanding and a termination of lending commitments. Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:

  • the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
  • the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
  • our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
  • the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX and Adjusted EBITDAX are not presentations made in accordance with generally accepted accounting principles, or GAAP. As discussed above, we believe that the presentation of EBITDAX and Adjusted EBITDAX in this release is appropriate. However, when evaluating our results, you should not consider EBITDAX and Adjusted EBITDAX in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss). EBITDAX and Adjusted EBITDAX have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations. Because other companies may calculate EBITDAX and Adjusted EBITDAX differently than we do, EBITDAX may not be, and Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

The following table reconciles net loss to EBITDAX and Adjusted EBITDAX for the periods presented:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Net income (loss) $ (19,528 ) $ 4,581 $ (38,092 ) $ (5,612 )
Interest expense 835 737 1,530 1,405
Income tax provision (benefit) (9,986 ) 212 (20,535 ) (8,381 )
Depreciation, depletion and amortization 38,770 39,901 73,885 74,303
Exploration expenses   6,924     10,853     11,407     37,784  
EBITDAX $ 17,015   $ 56,284   $ 28,195   $ 99,499  
Unrealized loss on derivative instruments $ 10 $ 212 $ 10 $ 469
Non-cash stock-based compensation charges 1,438 1,028 2,578 2,115
Impairment of oil and gas properties 239 500 2,544 15,592
Loss (gain) on sale of assets and investment in affiliates   1,168     (1,282 )   618     (2,904 )
Adjusted EBITDAX $ 19,870   $ 56,742   $ 33,945   $ 114,771  

Guidance for Third Quarter 2015

The Company is providing the following guidance for the third calendar quarter of 2015.

Third quarter 2015 production 90,000 - 95,000 Mcfe per day
LOE (including transportation and workovers) $9.0 million - $9.5 million
Production and ad valorem taxes 5.5%
(% of Revenue)
Cash G&A $5.2 million - $5.7 million
DD&A rate $4.15 - $4.35

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Friday, August 7, 2015 at 10:30am CDT. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-637-7707, (International 1-913-312-0418) and entering the following participation code: 7102676. A replay of the call will be available from Friday, August 7, 2015 at 1:30pm CDT through Friday, August 14, 2015 at 1:30pm CDT by dialing toll free 1-888-203-1112, (International 1-719-457-0820) and asking for replay ID code 7102676.

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 properties 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

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
Sergio Castro, 713-236-7400
Vice President and Treasurer

Source: Contango Oil & Gas Company

News Provided by Acquire Media