Nov 10, 2014

Contango Announces Third Quarter 2014 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 September 30, 2014 and provided an operational update.

Third Quarter 2014 Highlights

  • Production of 9.4 Bcfe for the quarter
  • Net income of $3.7 million and Adjusted EBITDAX of $47.7 million for the quarter
  • Commenced initial production at South Timbalier 17, our 2013 offshore discovery
  • Installed compression at Eugene Island Block 11 for our Dutch and Mary Rose wells
  • Spud initial horizontal well in newly acquired 53,200 gross (23,700 net) acre position in our Elm Hill project in Fayette County, Texas
  • Acquisition of the right to earn approximately 49,000 gross (44,000 net) acres in our North Cheyenne project in Weston County, Wyoming, targeting multiple formations, including the Muddy Sandstone formation
  • Reaffirmed our borrowing base of $275 million, through May 1, 2015

Management Commentary

Allan D. Keel, the Company's President and Chief Executive Officer, said "We are excited to begin drilling in our new prospective resource plays. To date we have spud two wells in our new Elm Hill project in Fayette County, Texas and have just spud our initial well in our new FRAMS project in Natrona County, Wyoming targeting the Mowry Shale. We expect to spud our initial well targeting the Muddy Sandstone formation in our North Cheyenne project in Weston County, Wyoming in late December or early January 2015. We are excited about the potential from these plays as a complement to our liquids-focused resource strategy currently focused on the Woodbine and Buda in Madison and Dimmit Counties, Texas, respectively. Since the beginning of the quarter we have brought two wells on-line in the Woodbine and have initiated a downspaced pad concept at Chalktown, where an additional four wells are in various stages of drilling or completion. In the Buda, we have brought five wells on-line since the beginning of the quarter, while an additional two are in various stages of drilling or completion."

Summary Financial Results for the Quarter Ended September 30, 2014

The results for the three months ended September 30, 2014 include the effect of the Company's October 1, 2013 merger with Crimson Exploration Inc. ("Crimson"), while the results for the three months ended September 30, 2013 include only the results of Contango.

Net income for the three months ended September 30, 2014 was $3.7 million, or $0.19 per basic and diluted share, compared to net income of $19.7 million, or $1.30 per basic and diluted share, for the same period last year. Included in the prior year figure is a $15.6 million pre-tax gain from our investment in Alta Resources. The remaining decrease in net income was primarily attributable to a $29.0 million pre-tax increase in depreciation, depletion and amortization ("DD&A"), an $8.2 million increase in operating expenses and a $4.2 million increase in general and administrative ("G&A") costs associated with our expanded asset base and organization subsequent to our merger with Crimson, partially offset by a $32.8 million increase in revenues. Revenues for the current year quarter were negatively impacted by an estimated $12.1 million related to the shut-in of our Eugene Island 11 platform for compressor installation. Average weighted shares outstanding were approximately 19.1 million and 15.2 million for the current and prior year quarters, respectively.

The Company reported Adjusted EBITDAX, as defined below, of approximately $47.7 million for the three months ended September 30, 2014, compared to $26.6 million for the same period last year. Crimson's field operations contributed $33.8 million to the current quarter, offset in part by the above mentioned impact of the shut-in at Eugene Island 11 and higher post-merger G&A costs.

Revenues for the three months ended September 30, 2014 were approximately $67.6 million compared to $34.7 million for the same period last year. This increase was primarily due to the addition of Crimson's operations which contributed $41.9 million in additional revenues, partially offset by the estimated $12.1 million decrease in Contango's revenues due to the shut-in at Eugene Island 11.

Production for the three months ended September 30, 2014 was approximately 9.4 Bcfe, or 102.3 Mmcfed, which was within our previously provided guidance. This 42% increase over production for the same period last year, despite the shut in at Eugene Island 11 (estimated 17.9 Mmcfed impact for the quarter), was attributable primarily to the addition of Crimson's operations, new production from our 2014 drilling program, additional interests in our Dutch wells acquired in December 2013 and new production from our 2013 discovery at South Timbalier 17 that began producing in the current year quarter. Our Dutch and Mary Rose wells at Eugene Island were shut in completely for approximately three weeks during the current quarter to install compression, with reduced production rates over several days as the area was restored to full production at 99% of pre-shut in rates. Crude oil and natural gas liquids production during the third quarter was approximately 6,900 barrels per day, or 40% of total production, up from approximately 2,600 barrels per day, or 22% of total production for the same period last year, an increase attributable to the addition of the Crimson properties and the subsequent focus on the development of our oil and liquids-rich onshore resource plays. For the fourth quarter of 2014, we estimate our production will be 105 - 115 Mmcfed. Guidance for the fourth quarter is less than the shut-in adjusted actual production for the third quarter due to drilling-related interference in three wells in our Buda play and due to the Company initiating a pad drilling strategy in the fourth quarter in our Chalktown area, thereby resulting in no new production during the quarter from that drilling. When drilling from pads, three wells are drilled in succession, those wells are then completed in succession, and then all three are put on production simultaneously to maximize recovery. It is anticipated that initial production will occur in January 2015.

The weighted average equivalent sales price during the three months ended September 30, 2014 was $7.17 per Mcfe, compared to $5.24 per Mcfe for the same period last year. The increase in the weighted average equivalent prices resulted from a higher percentage mix of crude and liquids production to total production, as well as from an increase in natural gas prices, which accounted for 60% of our volumes. The impact from the increase in liquids mix and higher gas prices was partially offset by lower oil and condensate prices during the current quarter.

Operating expenses for the three months ended September 30, 2014 were approximately $13.8 million, or $1.47 per Mcfe, compared to $5.6 million, or $0.84 per Mcfe, for the same period last year. Included in operating expenses are lease operating expenses, transportation and processing costs, workover expenses and production and ad valorem taxes, all of which increased as a result of our expanded operations and increased production subsequent to our merger with Crimson.

Lease operating expenses ("LOE"), transportation and processing costs and workover expenses for the three months ended September 30, 2014 were approximately $10.6 million, or $1.13 per Mcfe, compared to approximately $4.8 million, or $0.72 per Mcfe, for the same period last year. Current quarter expense was slightly outside of our previously provided guidance due to higher than expected offshore transportation costs.

Exploration costs for the three months ended September 30, 2014 included a $5.2 million credit related to the adjustment of estimated costs accrued in the previous quarter for our unsuccessful Ship Shoal 255 well, including credits negotiated with certain service providers.

DD&A expenses for the three months ended September 30, 2014 were $40.6 million, or $4.31 per Mcfe, compared to $11.5 million, or $1.71 per Mcfe, for the same period last year. This increase is primarily attributable to the incremental production from Crimson's properties, and an increase in the DD&A rate resulting from higher costs associated with onshore oil plays and the impact of purchase price accounting related to the merger.

Impairment and abandonment expense from oil and gas properties was $6.7 million for the three months ended September 30, 2014 due to the impairment of certain unproved properties due to the estimated decline in the value of leases expiring in the near term and/or not likely to be drilled prior to expiration. The impairment relates primarily to certain portions of our Tuscaloosa Marine Shale acreage position and to our Gulf of Mexico exploratory prospects.

G&A expenses for the three months ended September 30, 2014 were $6.8 million, or $0.72 per Mcfe, compared to $2.7 million, or $0.40 per Mcfe, for the prior year quarter. G&A expenses for the quarter, exclusive of $1.2 million in non-cash stock compensation expense were $5.6 million, compared to $2.7 million for the same period last year, an increase due to the post-merger combination of the staffs and facilities of both companies. This was below our previously provided guidance due to lower than projected legal and compensation costs. For the fourth quarter of 2014, we have provided guidance of $6.5 million to $7.5 million for general and administrative expenses, exclusive of non-cash stock compensation ("Cash G&A").

Drilling Activity Update

Onshore Activity

Southeast Texas (Woodbine)

Chalktown Area, Madison County, Texas

Our drilling efforts in Madison and Grimes counties this quarter were concentrated in the Chalktown Area and focused on the Woodbine/Lewisville. Our quarterly results and current activity in the Chalktown Area consist of the following. We anticipate keeping two rigs in this area for the remainder of the year, and have commenced a pad drilling strategy on 500 foot spacing:

Well

 

WI%

 

Total Measured
Depth (ft.)

 

Lateral (ft.)

 

Frac Stages

 

Status/First
Production

 

30 Day Avg IP
(boed)

 

% Oil

Dean 1H 70% 16,194 6,737 29 July 2014 927 79% *
Heath Unit A 1H 70% 16,358 7,050 30 Evaluating not yet available
Vick Trust B 2H 68% TBD TBD TBD Drilled TBD TBD
Barr Unit A 2H 50% TBD TBD TBD Drilling - 9,300' TBD TBD
Vick Trust B 5H 68% TBD TBD TBD Drilling - 9,200' TBD TBD

* Previously reported

Iola/Grimes Area, Grimes County, Texas

We brought one well online in Grimes County during the quarter that was spud during the second quarter. We currently expect the arrival of a third rig (in addition to the two rigs in Chalktown) late in the fourth quarter that will target an extended lateral in the Woodbine in Grimes County.

Well

 

WI%

 

Total Measured
Depth (ft.)

 

Lateral (ft.)

 

Frac Stages

 

Status/First
Production

 

30 Day Avg IP
(boed)

 

% Oil

Tommie Carroll 2H 46% 14,950 5,221 22 July 2014 648 81% *

* Previously reported

South Texas (Buda), Zavala and Dimmit Counties

Our recent and current activity in the Buda in South Texas consists of the following:

Well

 

WI%

 

Total Measured
Depth (ft.)

 

Lateral (ft.)

 

Frac Stages

 

Status/First
Production

 

30 Day Avg IP
(boed)

 

% Oil

Beeler 19H 50% 14,290 7,096 n/a July 2014 1,198 73% *
Beeler C 20H 50% 16,574 9,474 n/a July 2014 835 65% *
Bruce Weaver 2H 12.5% (Non-Op) 13,290 6,386 n/a July 2014 1,047 57% *
Dunlap 4H 100% 12,570 5,518 n/a August 2014 235 12%
Bruce Weaver 1H 12.5% (Non-Op) 10,530 3,918 n/a August 2014 684 80%
Beeler Unit 26H 50% TBD TBD TBD Completing TBD TBD
Beeler Unit J 24H 50% TBD TBD TBD Drilling TBD TBD

* Previously reported

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 into the Buda will be limited going forward as our attention will focus on the Eagle Ford's prospectivity over our 9,500 net acre position in Zavala and Dimmit Counties. We have drilled a pilot with whole core into the Eagle Ford and expect results in Q1 2015 from that analysis. Operators continue to drill wells with excellent productivity in the immediate area of our leasehold.

Fayette County, Texas (Elm Hill Project)

We commenced our drilling program in this area during the quarter, and our current activity in the Elm Hill project consists of the following:

Well

 

WI%

 

Total Measured
Depth (ft.)

 

Lateral (ft.)

 

Frac Stages

 

Status/First
Production

 

30 Day Avg IP
(boed)

 

% Oil

Janecka 1H 50% 11,758 6,000 25 Flowing back not yet available
Vinklarek 1H 50% TBD TBD TBD Drilling - 9,800' TBD TBD

We anticipate drilling a total of four wells in this area by the end of the year, will evaluate results at that time, and then decide on a rig and development strategy for 2015. We and our partner have approximately 53,200 gross acres (23,700, net to the Company) in the area on which we may pursue a number of formations horizontally.

Wyoming (FRAMS Project and N. Cheyenne Project)

Last week we spud our initial well targeting the Mowry Shale in Natrona County, Wyoming. We originally acquired in May 2014 the right to earn an 80% working interest in approximately 119,500 gross acres (93,000 net acres) in the area on which to pursue the Mowry and other potential formations. We expect to spud our initial well targeting the Muddy Sandstone formation in Weston County, Wyoming in late December or early January 2015. We originally acquired in September 2014 the right to earn a 100% working interest in approximately 49,000 gross acres (44,000 net acres), where the prospect generator retains an option to participate for a 10% working interest, in the area on which to pursue the Muddy Sandstone and other potential formations.

2014 Capital Program & Liquidity

Capital expenditures incurred for the three months ended September 30, 2014 were $25.8 million, of which $8.6 million was spent drilling in the Woodbine formation in Madison and Grimes Counties, Texas; $9.1 million was spent drilling the Buda formation in Dimmit County, Texas; and $7.3 million was invested in acreage positions primarily in new areas.

We currently anticipate that our total capital expenditure program for 2014 will be in the $215 - $225 million range, funded primarily from internally generated cash flow.

As of September 30, 2014, we had approximately $54.4 million of debt outstanding under our credit facility with Royal Bank of Canada and other lenders. The credit facility has a borrowing base of $275 million, which was reaffirmed on October 28, 2014 and through May 1, 2015.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and nine month periods ended September 30, 2014 and 2013:

   
Three Months Ended Nine Months Ended
September 30, September 30,
2014  

2013(1)

   % 2014  

2013(1)

   %
Offshore Volumes Sold:
Oil and condensate (Mbbls) 57 91 -37 % 211 255 -17 %
Natural gas (Mmcf) 4,039 5,190 -22 % 14,302 13,985 2 %
Natural gas liquids (Mbbls)   121   148   -18 %   439   431   2 %
Natural gas equivalents (Mmcfe) 5,104 6,623 -23 % 18,201 18,100 1 %
 
Onshore Volumes Sold:
Oil and condensate (Mbbls) 335 - n/a 919 - n/a
Natural gas (Mmcf) 1,598 - n/a 4,896 - n/a
Natural gas liquids (Mbbls)   117   -   n/a   323   -   n/a
Natural gas equivalents (Mmcfe) 4,312 - n/a 12,352 - n/a
 
Total Volumes Sold:
Oil and condensate (Mbbls) 392 91 331 % 1,130 255 343 %
Natural gas (Mmcf) 5,637 5,190 9 % 19,198 13,985 37 %
Natural gas liquids (Mbbls)   238   148   61 %   762   431   77 %
Natural gas equivalents (Mmcfe) 9,416 6,623 42 % 30,553 18,100 69 %
 
Daily Sales Volumes:
Oil and condensate (Mbbls) 4.3 1.0 331 % 4.1 0.9 343 %
Natural gas (Mmcf) 61.3 56.4 9 % 70.3 51.2 37 %
Natural gas liquids (Mbbls)   2.6   1.6   61 %   2.8   1.6   77 %
Natural gas equivalents (Mmcfe) 102.3 72.0 42 % 111.9 66.3 69 %
 
Average sales prices:
Oil and condensate (per Bbl) $ 96.05

$

110.37

-13 % $ 98.32 $ 109.65 -10 %
Natural gas (per Mcf) $ 3.85 $ 3.64 6 % $ 4.56 $ 3.81 20 %
Natural gas liquids (per Bbl) $ 34.55 $ 39.01 -11 % $ 36.17 $ 37.02 -2 %
Total (per Mcfe) $ 7.17 $ 5.24 37 % $ 7.40 $ 5.37 38 %
 
(1) Results for the three and nine months ended September 30, 2013 include only the results of Contango, prior to the merger with Crimson.
 
  Three Months Ended   Nine Months Ended
September 30, September 30,
2014  

2013(1)

   % 2014  

2013(1)

   %
Offshore Selected Costs ($ per Mcfe):
LOE (including transportation and workovers) $ 0.83 $ 0.72 15 % $ 0.57 $ 1.31 -57 %
Production and ad valorem taxes $ 0.11 $ 0.12 -12 % $ 0.10 $ 0.13 -26 %
Depreciation and depletion expense $ 2.39 $ 1.71 40 % $ 1.88 $ 1.78 6 %
 
Onshore Selected Costs ($ per Mcfe):
LOE (including transportation and workovers) $ 1.48 $ - n/a $ 1.36 $ - n/a
Production and ad valorem taxes $ 0.62 $ - n/a $ 0.61 $ - n/a
Depreciation and depletion expense $ 6.58 $ - n/a $ 6.53 $ - n/a
 
Average Selected Costs ($ per Mcfe):
LOE (including transportation and workovers) $ 1.13 $ 0.72 57 % $ 0.89 $ 1.31 -32 %
Production and ad valorem taxes $ 0.34 $ 0.12 181 % $ 0.30 $ 0.13 129 %
Depreciation and depletion expense $ 4.31 $ 1.71 152 % $ 3.76 $ 1.78 110 %
General and administrative expense (cash) $ 0.60 $ 0.40 49 % $ 0.76 $ 0.64 18 %
Interest expense $ 0.07 $ - 100 % $ 0.07 $ - 100 %
 
Adjusted EBITDAX (2) (thousands) $ 47,694 $ 26,565 $ 162,467 $ 69,674
 
Weighted Average Shares Outstanding (thousands)
Basic 19,077 15,195 19,074 15,195
Diluted 19,122 15,195 19,074 15,195
 
(1) Results for the three and nine months ended September 30, 2013 include only the results of Contango, prior to the merger with Crimson.
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).
 
CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
 
  September 30,   December 31,
2014 2013

ASSETS

Cash and cash equivalents $ - $ -
Accounts receivable 35,990 60,613
Other current assets 7,940 5,504
Net property and equipment 767,637 791,023
Investments in affiliates and other non-current assets   59,885   53,164
 
TOTAL ASSETS $ 871,452 $ 910,304
 

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts payable and accrued liabilities 93,133 96,833
Other current liabilities 4,176 2,446
Long-term debt 54,415 90,000
Deferred tax liability 103,849 105,956
Asset retirement obligations 21,325 22,019
Total shareholders' equity   594,554   593,050
 
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 871,452 $ 910,304
 
CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
 
  Three Months Ended   Nine Months Ended
September 30, September 30,
  2014       2013     2014       2013  
 
REVENUES
Oil and condensate sales $ 37,662 $ 10,044 $ 111,102 $ 27,961
Natural gas sales 21,676 18,914 87,547 53,308
Natural gas liquids sales   8,214     5,764     27,579     15,948  
Total revenues   67,552     34,722     226,228     97,217  
 
EXPENSES
Operating expenses 13,797 5,553 36,426 26,025
Exploration expenses (4,713 ) 89 33,071 223
Depreciation, depletion and amortization 40,550 11,518 114,853 32,242
Impairment and abandonment of oil and gas properties 6,693 - 23,259 767
General and administrative expenses   6,821     2,657     26,485     11,622  
Total expenses   63,148     19,817     234,094     70,879  
 
OTHER INCOME (EXPENSE)
Gain from investment in affiliates (net of income taxes) 1,287 669 4,387 1,402
Interest expense (672 ) (13 ) (2,077 ) (38 )
Gain (loss) on derivatives, net 1,734 - (1,488 ) -
Other income (loss)   48     15,698     (148 )   25,573  

Total other income (expense)

  2,397     16,354     674     26,937  
 
NET INCOME (LOSS) BEFORE INCOME TAXES   6,801     31,259     (7,192 )   53,275  
 
Income tax benefit (provision)   (3,137 )   (11,519 )   5,244     (18,310 )
 
NET INCOME (LOSS) $ 3,664   $ 19,740   $ (1,948 ) $ 34,965  
 

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 income to EBITDAX and Adjusted EBITDAX for the periods presented:

   
Three Months Ended Nine Months Ended
September 30, September 30,
  2014       2013     2014       2013  
 
Net income (loss) $ 3,664 $ 19,740 $ (1,948 ) $ 34,965
Interest expense 672 13 2,077 38
Income tax provision (benefit) 3,137 11,519 (5,244 ) 18,310
Depreciation, depletion and amortization 40,550 11,518 114,853 32,242
Exploration expenses   (4,713 )   89     33,071     223  
EBITDAX $ 43,310   $ 42,879   $ 142,809   $ 85,778  
 
Unrealized gain on derivative instruments $ (1,963 ) $ - $ (1,494 ) $ -
Non-cash equity-based compensation charges 1,217 - 3,333 -
Impairment of oil and gas properties 6,417 - 22,010 767
Loss (gain) on sale of assets and investment in affiliates   (1,287 )   (16,314 )   (4,191 )   (16,871 )
Adjusted EBITDAX $ 47,694   $ 26,565   $ 162,467   $ 69,674  
 

Guidance for Fourth Quarter 2014

The Company is providing the following guidance for the fourth calendar quarter of 2014.

      Fourth quarter 2014 production     105,000 - 115,000 Mcfe per day
 
LOE (including transportation and workovers) $9.5 million - $10.0 million
 
Production and ad valorem taxes 4.7%
(% of Revenue)
 
Cash G&A $6.5 million - $7.5 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 Tuesday, November 11, 2014 at 8:00am CST. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-337-8192, (International 1-719-325-2332) and entering the following participation code: 6281005. A replay of the call will be available from Tuesday, November 11, 2014 at 11:00am CST through Tuesday, November 18, 2014 at 11:00am CST by dialing toll free 1-888-203-1112, (International 1-719-457-0820) and asking for replay ID code 6281005.

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

Source: Contango Oil & Gas Company

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