Contango Announces First Quarter 2015 Financial Results and Provides Operations Update

HOUSTON--()--Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango”) announced today its financial results for the three months ended March 31, 2015 and provided an operational update.

First Quarter 2015 Highlights

  • Production of 8.7 Bcfe for the quarter
  • Net loss of $18.6 million and Adjusted EBITDAX of $14.0 million for the quarter
  • Commenced production from initial multi-well pad drilled on 500 foot spacing in our Chalktown area
  • Commenced production from third well in our Elm Hill Project, with two additional wells expected to begin production in the second quarter
  • Commenced initial flowback on first Mowry Shale test in Natrona County, Wyoming
  • Borrowing base redetermined at $225 million, through November 1, 2015

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said, “Despite a dramatically reduced 2015 capital program due to the recent precipitous decline in hydrocarbon prices, we continue to make progress on testing new strategies, formations and acreage on our onshore resource plays. Early results on our initial two three-well pads on 500 foot spacing at Chalktown have been encouraging. We continue to evaluate overall results on the first five wells drilled in various formations in our new Elm Hill Project in Fayette and Gonzales counties, Texas, and are working with our partner to develop a long-term strategy for the position. We have started flowback on our initial Mowry Shale test in our new FRAMS Project in Natrona County, Wyoming and are preparing to frac our initial well targeting the Muddy Sandstone formation in our North Cheyenne Project in Weston County, Wyoming. While our first quarter activity represents more than a majority of our 2015 capital budget, we will continue to evaluate the possibility of drilling other proof of concept wells during the remainder of the year, if deemed appropriate in this low commodity price environment.”

Summary Financial Results for the Quarter Ended March 31, 2015

Net loss for the three months ended March 31, 2015 was $18.6 million, or $0.98 per basic and diluted share, compared to a net loss of $10.2 million, or $0.53 per basic and diluted share, for the prior year quarter. Lower revenues resulting from the dramatic decline in commodity prices and lower production related to reduced drilling activity were offset, in part, by a decrease in exploration and impairment expenses compared with the 2014 first quarter. Included in the prior year figure was $26.7 million in pre-tax exploration expenses attributable to our unsuccessful Ship Shoal 255 exploratory well and $15.1 million of non-cash impairment expense related to unproved lease costs and production facilities associated with the Ship Shoal 255 prospect. 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 $14.0 million for the three months ended March 31, 2015, compared to $58.0 million for the same period last year, a decrease mainly attributable to the $49.6 million decrease in revenues associated with the commodity price declines and lower production.

Revenues for the three months ended March 31, 2015 were $30.6 million compared to $80.3 million for the same period last year, a decrease also attributable to lower production and lower commodity prices.

Production for the three months ended March 31, 2015 was approximately 8.7 Bcfe, or 96.3 Mmcfed, which was within our previously provided guidance, but down from 10.6 Bcfe, or 117.5 MMcfed for the same period last year. This decrease in production was due to minimal new production being added during the quarter as a result of the reduced capital expenditure program generally, and due to the shift to multi-well pad drilling for the majority of the wells we drilled in the fourth quarter of 2014 and the current quarter. Crude oil and natural gas liquids production during the current period was approximately 5,200 barrels per day, or 32% of total production, down from approximately 7,000 barrels per day, or 35% of total production for the same period last year, with both declines a function of the overall change in drilling activity. For the second quarter of 2015, we estimate our production will be 90 - 100 Mmcfed, with current production averaging approximately 102 Mmcfed.

The weighted average equivalent sales price during the three months ended March 31, 2015 was $3.54 per Mcfe, compared to $7.59 per Mcfe for the same period last year. The decrease in the weighted average equivalent prices quarter over quarter was attributable to the decline in total production represented by oil and natural gas liquids, a 55% decrease in average oil and condensate prices, a 43% decline in natural gas prices and a 64% decrease in natural gas liquids prices.

Operating expenses for the three months ended March 31, 2015 were approximately $9.9 million, or $1.14 per Mcfe, compared to $11.1 million, or $1.05 per Mcfe, for the same period last year. Included in operating expenses are lease operating expenses (“LOE”), transportation and processing costs, workover expenses and production and ad valorem taxes. The decline in operating expenses resulted primarily from a decrease in production and ad valorem taxes associated with lower revenue.

Lease operating expenses, transportation and processing costs and workover expenses for the three months ended March 31, 2015 were approximately $8.8 million, or $1.01 per Mcfe, which was within our previously provided guidance, compared to approximately $8.1 million, or $0.77 per Mcfe, for the same period last year. A large portion of monthly lease operating expenses are fixed costs; therefore, the increase in per unit cost can be attributed primarily to the lower production.

Exploration costs for the three months ended March 31, 2015 were $4.5 million, compared to $26.9 million for the same period last year, as the prior year figure includes drilling costs for our unsuccessful Ship Shoal 255 exploratory well finalized in May 2014. Included in charges for the current year quarter was a $3.2 million early termination fee on a drilling rig contract.

DD&A expenses for the three months ended March 31, 2015 were $35.1 million, or $4.05 per Mcfe, compared to $34.4 million, or $3.25 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 March 31, 2015 included an impairment of $2.0 million for small marginal gas properties as a result of commodity price declines and $0.2 million for certain unproved prospects due to expiring leases.

G&A expenses for the three months ended March 31, 2015 were $7.8 million, or $0.90 per Mcfe, compared to $10.5 million, or $0.99 per Mcfe, for the prior year quarter. G&A expenses for the current and prior year quarter, exclusive of $1.1 million and $1.1 million, respectively, in non-cash stock compensation expense, were $6.7 million and $9.4 million, respectively, as the prior year quarter included $2.2 million of merger-related costs. For the second quarter of 2015, we have provided guidance of $6.7 million to $7.2 million for general and administrative expenses, exclusive of non-cash stock compensation (“Cash G&A”).

Derivative Instruments

In April 2015 we entered into the following derivative contracts with a member of our bank group:

                 
Commodity Period Derivative

Volume / Month

Price / Unit (1)
Crude Oil May 2015 - Dec 2015 Collar 35,000 Bbls $55.00 - $65.15
Crude Oil May 2015 - Jul 2015 Collar 25,000 Bbls $55.00 - $65.05

 

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

 

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 in late-2014, a strategy where three wells are drilled in succession, completed in succession, and subsequently put on production. While it will take several months of production to determine the true effectiveness of the down-spacing strategy on ultimate recovery and return on investment, i.e. compared with fewer wells on 1,000 foot spacing, early results are as follows:

                     

Total Measured

PAD 1

WI%

Depth (ft.)

Lateral (ft.)

Frac Stages

First Production

Vick Trust B 2H 69% 16,163 7,260 30 January 2015
Vick Trust B 3H 68% 15,818 6,542 29 January 2015
Vick Trust B 5H 69% 16,235 7,360 28 January 2015
 

The Vick Trust B three-well pad averaged 2,400 Boed for the initial 30 days and is still producing approximately 1,850 Boed after 100 days of production. Optimization is still ongoing.

                     

Total Measured

PAD 2

WI%

Depth (ft.)

Lateral (ft.)

Frac Stages

Status

Barr Unit A 2H 51% 15,570 6,554 25 Flowing Back
Barr Unit B 3H 67% 15,250 5,583 22 Flowing Back
Barr Unit B 4H 67% 14,943 5,350 21 Flowing Back
Barr Unit A 2H 56% 15,065 5,728 22 Flowing Back
 

The Barr Unit four-well pad has been online for less than 30 days; however, early flowback from the pad is showing good results with approximately 2,000 Boed. Optimization is still ongoing. Additionally, we have the following two wells in progress:

                             

Total Measured

30 Day Avg IP

WI%

Depth (ft.)

Lateral (ft.)

Frac Stages

Status

(boed)

% Oil

Viniarski A 1H 68% 16,773 7,656 30 Flowing Back TBD TBD
Hoke 1H (pilot) 70% 10,700 n/a n/a Evaluating TBD TBD
 

The Viniarski A 1H is currently flowing back 800 Boed and is just shy of 30 days of production.

In keeping with our previously stated objective of identifying and evaluating new resource play potential, the Hoke 1H well was drilled 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 has not been completed in any vertical or horizontal wells at this time. The section underlies the Upper Lewisville which has been the target in the 12 horizontal wells drilled to date in Chalktown. This Lower Lewisville is approximately 130’ thick as compared to the Upper Lewisville thickness of 50’. Early log indications are encouraging and we are currently awaiting the final core analysis of this zone prior to commencing any drilling for this potentially significant objective. Additional prospective zones were encountered in the wellbore and those will be fully evaluated also.

Iola/Grimes Area, Grimes County, Texas

We finalized, during the quarter, a Lewisville test in Grimes County testing the concept of longer laterals, more fracs and more proppant. We are still evaluating the Norwood well, and will for several months, before we can determine the effectiveness of that strategy. Specifics on that well are as follows:

                             

Total Measured

Status / First

30 Day Avg IP

Well

WI%

Depth (ft.)

Lateral (ft.)

Frac Stages

Production

(boed)

% Oil

Norwood 2H 90% 17,699 7,744 30 Evaluating TBD TBD
 

In addition, we drilled the Stokes #1H well in the same area to a depth of 10,300 feet in early 2014. This was a vertical pilot well for which a whole core was recovered in the Eagle Ford and other formations. We are encouraged by the core data from the Eagle Ford formation as to its comparisons to petrophysical and geologic properties that are seen in the productive areas of the East Texas Eagle Ford seen to the west in Brazos County. We are continuing to evaluate all the data to determine the viability of future drilling in those zones in the Madison and Grimes areas.

South Texas

Fayette and Gonzales County, Texas (Elm Hill Project)

We have commenced production from three wells in our Elm Hill Project, where we have a 50% working interest, and have presented limited information on results as we continue to lease in the area. We have drilled two additional wells in this area as reflected below:

             

Total Measured

Well

WI%

Depth (ft.)

Status

Henderson 1H 50% 15,513 Completing
Jennifer 1H 50% 13,722 Completing
 

To date, we and our partner have successfully drilled five vertical pilot holes (where four whole cores were recovered) to evaluate six hydrocarbon bearing formations that have potential for development. The five horizontal wells that we have drilled are testing for three of the six formations. Once we evaluate the results from each formation and area, we will develop a comprehensive program for further development of our approximate 55,000 gross acre position. At that point, we will be prepared to release what the composite results are and how they were evaluated in developing our strategy.

Zavala and Dimmit County, Texas (Eagle Ford)

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. It is possible that we will drill an Eagle Ford well in this area later this year.

Wyoming

Natrona County (FRAMS Project) and Weston County (N. Cheyenne Project)

We have two wells in Wyoming currently undergoing completion operations. We successfully drilled a pilot hole in each area and recovered a whole core in each to evaluate a total of six hydrocarbon bearing formations. The current status of the State 35-79-16 1H well in Natrona County, targeting the Mowry Shale, and the Elliot 13-44-66 1H well in Weston County, targeting the Muddy Sandstone formation, are as follows:

                             

Total Measured

30 Day Avg IP

WI%

Depth (ft.)

Lateral (ft.)

Frac Stages

Status

(boed)

% Oil

State 35-79-16 1H 60% 12,944 5,911 25 Flowing back TBD TBD
Elliot 13-44-66 1H 80% 13,116 6,601 30 Completing TBD TBD
 

We will evaluate the results from these two wells for a number of months before determining future drilling plans for these areas.

Continued R&D Efforts

Of the ten pilot holes discussed above, nine whole cores averaging 200’ in length were recovered. Enhanced formation evaluation tools were employed on all of the pilot holes. We have also joined industry consortiums, where possible, to leverage the collected data on our wells to their maximum value relative to play concepts for the future. With the ongoing R&D efforts across our major activity areas, we are positioning ourselves for a focused, meaningful drilling program in a more robust commodity market in the future.

2015 Capital Program & Liquidity

Capital expenditures incurred for the three months ended March 31, 2015 were $31.7 million, including $14.1 million on the Woodbine formation in Madison and Grimes Counties, Texas; $9.7 million on our Elm Hill Project in South Texas; $4.9 million on our FRAMS and North Cheyenne Projects in Wyoming; and $2.7 million for the acquisition of leases and other rights in new areas.

We currently anticipate that our total capital expenditure program for 2015 will be $50.6 million, including the amounts spent during the current quarter, and which will be funded primarily from internally generated cash flow.

As of March 31, 2015, we had approximately $104.5 million of debt outstanding under our credit facility compared to approximately $63.4 million at the end of 2014, an increase due to incurring the majority of our 2015 capital expenditure budget during the first quarter, as planned, coupled with lower revenues and production. As a result of the reduced capital program planned for the remainder of the year, we expect that our debt level at year-end 2015 will be similar to our current balance.

The credit facility has a borrowing base of $225 million, which was redetermined from $275 million by our bank group effective May 7, 2015 due to the lower commodity price environment, with our next regularly scheduled redetermination on November 1, 2015.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three month periods ended March 31, 2015 and 2014:

             
Three Months Ended
March 31,
2015 2014 %
Offshore Volumes Sold:
Oil and condensate (Mbbls) 54 80 -33%
Natural gas (Mmcf) 4,659 5,370 -13%
Natural gas liquids (Mbbls)   132   166 -20%
Natural gas equivalents (Mmcfe) 5,781 6,848 -16%
 
Onshore Volumes Sold:
Oil and condensate (Mbbls) 188 277 -32%
Natural gas (Mmcf) 1,211 1,460 -17%
Natural gas liquids (Mbbls)   91   102 -11%
Natural gas equivalents (Mmcfe) 2,883 3,729 -23%
 
Total Volumes Sold:
Oil and condensate (Mbbls) 242 357 -32%
Natural gas (Mmcf) 5,870 6,830 -14%
Natural gas liquids (Mbbls)   223   268 -17%
Natural gas equivalents (Mmcfe) 8,664 10,577 -18%
 
Daily Sales Volumes:
Oil and condensate (Mbbls) 2.7 4.0 -32%
Natural gas (Mmcf) 65.2 75.9 -14%
Natural gas liquids (Mbbls)   2.5   3.0 -17%
Natural gas equivalents (Mmcfe) 96.3 117.5 -18%
 
Average sales prices:
Oil and condensate (per Bbl) $ 44.10 $ 98.43 -55%
Natural gas (per Mcf) $ 2.87 $ 5.07 -43%
Natural gas liquids (per Bbl) $ 14.01 $ 39.31 -64%
Total (per Mcfe) $ 3.54 $ 7.59 -53%
 
 
      Three Months Ended
March 31,
2015     2014     %
Offshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.64 $ 0.52 23%
Production and ad valorem taxes $ 0.08 $ 0.09 -11%
Depreciation and depletion expense $ 1.95 $ 1.66 17%
 
Onshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.76 $ 1.23 43%
Production and ad valorem taxes $ 0.23 $ 0.62 -63%
Depreciation and depletion expense $ 8.27 $ 6.17 34%
 
Average Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.01 $ 0.77 31%
Production and ad valorem taxes $ 0.13 $ 0.28 -54%
Depreciation and depletion expense $ 4.05 $ 3.25 25%
General and administrative expense (cash) $ 0.77 $ 0.76 1%
Interest expense $ 0.08 $ 0.06 33%
 
Adjusted EBITDAX (2) (thousands) $ 14,040 $ 58,029
 
Weighted Average Shares Outstanding (thousands)
Basic 18,939 19,071
Diluted 18,939 19,071
 

(1) LOE includes transportation and workover expenses.

(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net loss.
 
         
March 31, December 31,
2015 2014

ASSETS

Cash and cash equivalents $ $
Accounts receivable, net 21,767 25,309
Other current assets 8,100 5,731
Net property and equipment 743,381 748,623
Investments in affiliates and other non-current assets   64,517   63,752
TOTAL ASSETS $ 837,765 $ 843,415
 

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts payable and accrued liabilities 73,802 92,892
Other current liabilities 4,127 4,123
Long-term debt 104,463 63,359
Deferred tax liability 83,309 93,952
Asset retirement obligations 22,028 21,623
Total shareholders’ equity   550,036   567,466
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY $ 837,765 $ 843,415
 
         
Three Months Ended
March 31,
2015 2014
 
REVENUES
Oil and condensate sales $ 10,694 $ 35,100
Natural gas sales 16,823 34,627
Natural gas liquids sales   3,130     10,530  
Total revenues   30,647     80,257  
 
EXPENSES
Operating expenses 9,911 11,053
Exploration expenses 4,483 26,931
Depreciation, depletion and amortization 35,115 34,402
Impairment and abandonment of oil and gas properties 2,281 15,195
General and administrative expenses   7,828     10,457  
Total expenses   59,618     98,038  
 
OTHER INCOME (EXPENSE)
Gain from investment in affiliates (net of income taxes) 558 1,622
Interest expense (695 ) (668 )
Loss on derivatives, net (1,959 )
Other expense   (5 )    

Total other income (expense)

  (142 )   (1,005 )
 
NET LOSS BEFORE INCOME TAXES   (29,113 )   (18,786 )
 
Income tax benefit   10,549     8,593  
 
NET LOSS $ (18,564 ) $ (10,193 )
 

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
March 31,
2015 2014
 
Net loss $ (18,564 ) $ (10,193 )
Interest expense 695 668
Income tax provision (benefit) (10,549 ) (8,593 )
Depreciation, depletion and amortization 35,115 34,402
Exploration expenses   4,483     26,931  
EBITDAX $ 11,180   $ 43,215  
 
Unrealized loss on derivative instruments $ $ 257
Non-cash stock-based compensation charges 1,140 1,086
Impairment of oil and gas properties 2,270 15,093
Gain on sale of assets and investment in affiliates   (550 )   (1,622 )
Adjusted EBITDAX $ 14,040   $ 58,029  
 

Guidance for Second Quarter 2015

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

         
Second quarter 2015 production 90,000 – 100,000 Mcfe per day
 
LOE (including transportation and workovers) $8.5 million - $9.0 million
 
Production and ad valorem taxes 3.7%
(% of Revenue)
 
Cash G&A $6.7 million - $7.2 million
 
DD&A rate $4.00 - $4.25
 

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Monday, May 11, 2015 at 9:30am CDT. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-801-6499 (International 1-913-312-0382) and entering the following participation code: 8756321. A replay of the call will be available from Monday, May 11, 2015 at 12:30pm CDT through Monday, May 18, 2015 at 12:30pm CDT by dialing toll free 1-888-203-1112 (International 1-719-457-0820) and asking for replay ID code 8756321.

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 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.

Contacts

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