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Contango Announces Second Quarter 2017 Financial Results and Provides Operational Update

HOUSTON, Aug. 02, 2017 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE MKT:MCF) (“Contango” or the “Company”) announced today its financial results for the three and six months ended June 30, 2017 and provided an operational update. 

Second Quarter Highlights

  • Production of 5.3 Bcfe for the quarter, or 58.0 Mmcfed, within guidance
  • Revenues of $20.3 million for the quarter, up from $19.4 million for the prior year quarter
  • Adjusted EBITDAX of $10.2 million for the quarter and net loss of $6.0 million
  • Brought two additional Southern Delaware Basin wells on production, and are in various stages of drilling/completion on three more

Summary Second Quarter Financial Results

Net loss for the three months ended June 30, 2017 was $6.0 million, or $0.24 per basic and diluted share, compared to a net loss of $17.3 million, or $0.90 per basic and diluted share, for the same period last year. This improvement was attributable primarily to higher revenues from higher commodity prices, lower operating expenses due to cost reduction efforts, lower depreciation, depletion, and amortization (“DD&A”) expense and an improvement in the mark to market valuation of our commodity price hedges. Average weighted shares outstanding were approximately 24.7 million and 19.1 million for the current and prior year quarters, respectively. 

Revenues for the current quarter were approximately $20.3 million compared to $19.4 million for the 2016 quarter, despite lower production during the current quarter. The increase in commodity prices was more than sufficient to offset the decline in production resulting from a very limited 2016 drilling program.  

The Company reported Adjusted EBITDAX, as defined below, of approximately $10.2 million for the three months ended June 30, 2017, compared to $10.1 million for the same period last year, a slight increase attributable to the increase in revenues and decrease in operating expenses, substantially offset by the decrease in the realized gain on our commodity price hedges.   

Production for the second quarter of 2017 was approximately 5.3 Bcfe, or 58.0 Mmcfe per day, within our previously provided guidance, compared to 74.6 Mmcfe per day for the second quarter of 2016.  This expected decline in production can be attributed to normal field decline, non-core property sales and 61 days of decreased production rates at Vermilion 170 due to temporary pipeline limitations. The field decline was expected due to minimal new production added from a reduced drilling program during the first half of 2016 in response to the low commodity price environment.  Crude oil and natural gas liquids production during the second quarter of 2017 was approximately 3,100 barrels per day, or 32% of total production, compared to approximately 3,800 barrels per day, or 31% of total production, in the second quarter of 2016. Natural gas production during the current quarter was approximately 39.6 Mmcf per day, or 68% of total production, compared to approximately 51.4 Mmcf per day, or 69% of total production, in the previous quarter, a decline also related to the lower onshore capital expenditures in 2016.  Our production guidance for the third quarter of 2017 is 56 – 61 Mmcfed, with the mid-point relatively flat with the first and second quarter of 2017 as production from new drilling begins to offset normal field decline. Because new production is primarily liquids, we expect crude oil and natural gas liquids to increase and represent approximately 33% of total production for the third quarter.       

The weighted average equivalent sales price during the three months ended June 30, 2017 was $3.84 per Mcfe, compared to $2.85 per Mcfe for the same period last year, as we experienced increases of 9%, 55% and 19% in crude oil, natural gas and natural gas liquids prices, respectively compared to the prior year quarter. 

Operating expenses for the three months ended June 30, 2017 were approximately $6.3 million, or $1.20 per Mcfe, compared to $7.0 million, or $1.03 per Mcfe, for the same period last year. Included in operating expenses are direct lease operating expenses, transportation and processing costs, workover expenses and production and ad valorem taxes. Operating expenses for the current quarter, exclusive of production and ad valorem taxes were approximately $5.6 million, or $1.07 per Mcfe, compared to approximately $5.9 million, or $0.86 per Mcfe, for the prior year quarter. Our guidance for operating expenses for the third quarter of 2017, exclusive of production and ad valorem taxes, is between $6.8 to $7.3 million, higher than the recent quarter due to additional workovers scheduled for the upcoming quarter.        

DD&A expense for the three months ended June 30, 2017 was $12.7 million, or $2.41 per Mcfe, compared to $17.9 million, or $2.63 per Mcfe, for the prior year quarter, a decrease primarily attributable to lower production during the quarter and the slight improvement in rate. 

Impairment and abandonment expense of oil and gas properties was $1.4 million for the current quarter, which related to the partial impairment of two unused offshore platforms.  Impairment and abandonment expense of oil and gas properties for the prior year quarter was $1.3 million, with substantially all of that related to non-core, unproved properties and prospects in Fayette and Gonzales counties, Texas.     

Total G&A expenses, i.e. inclusive of stock expense, for the three months ended June 30, 2017 were $5.8 million, or $1.11 per Mcfe, compared to $5.4 million, or $0.79 per Mcfe, for the prior year quarter.  G&A expenses for the current and prior year quarters, exclusive of $1.6 million and $1.3 million, respectively, in non-cash stock compensation expense, were comparable for both periods. For the third quarter of 2017, we have provided guidance of $4.5 million to $5.1 million for general and administrative expenses, exclusive of non-cash stock compensation (“Cash G&A”). 

Gain from affiliates (Exaro Energy III, LLC) for the three months ended June 30, 2017 was approximately $0.2 million, compared to $1.3 million for the same period last year.  

2017 Capital Program

Capital costs incurred for the three months ended June 30, 2017 were approximately $13.9 million, including $0.8 million in paid and accrued leasehold acquisition costs and $13.1 million for the drilling and completion of wells in the Southern Delaware Basin in Pecos County, Texas.  Our capital expenditure budget for 2017 was originally forecasted to be $46.3 million, including $36.6 million to drill and/or complete nine gross wells (4.0 net) on our Southern Delaware Basin acreage. We have revised our 2017 budget to approximately $55 million, to include an additional $9.0 million in drilling and completion costs for one additional gross well (0.5 net), a saltwater disposal well, and anticipated increases in the cost of vendor goods and services.

As of June 30, 2017, we had approximately $71.3 million of debt outstanding under our credit facility.  Effective May, 4, 2017, the borrowing base under our facility was redetermined at $125 million, which reflects the impact of lower commodity prices, our limited drilling program in 2016 as well as no current benefit from our 2017 drilling program as the borrowing base was redetermined based on the 2016 year-end reserves. 

Derivative Instruments

We have the following financial derivative contracts in place for the remainder of the year:

                   
Commodity   Period   Derivative   Volume/Month   Price/Unit (1)
Natural Gas   July 2017   Collar   400,000 MMBtus   $ 2.65 - 3.00
Natural Gas   Aug - Oct 2017   Collar   200,000 MMBtus   $ 2.65 - 3.00
Natural Gas   Nov - Dec 2017   Collar   400,000 MMBtus   $ 2.65 - 3.00
                   
Natural Gas   July 2017   Swap   300,000 MMBtus   $  3.51
Natural Gas   Aug - Oct 2017   Swap   70,000 MMBtus   $  3.51
Natural Gas   Nov - Dec 2017   Swap   300,000 MMBtus   $  3.51
                   
Oil   July 2017   Swap   9,000 Bbls   $  53.95
Oil   Aug - Oct 2017   Swap   6,000 Bbls   $  53.95
Oil   Nov - Dec 2017   Swap   8,000 Bbls   $  53.95
                   
Oil   Jul - Dec 2017   Swap   9,000 Bbls   $  56.20

/EIN News/ -- (1) Commodity price derivatives based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable.

Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three and six months ended June 30, 2017 and 2016: 

                                 
    Three Months Ended   Six months ended
    June 30,    June 30, 
    2017   2016   %   2017   2016   %
Offshore Volumes Sold:                                
Oil and condensate (Mbbls)      33      36   -8 %      55      87   -37 %
Natural gas (Mmcf)      2,908      3,676   -21 %      5,916      7,515   -21 %
Natural gas liquids (Mbbls)      83      111   -25 %      167      223   -25 %
Natural gas equivalents (Mmcfe)      3,602      4,559   -21 %      7,248      9,379   -23 %
                                 
Onshore Volumes Sold:                                
Oil and condensate (Mbbls)      109      131   -17 %      201      265   -24 %
Natural gas (Mmcf)      699      997   -30 %      1,419      2,079   -32 %
Natural gas liquids (Mbbls)      53      75   -29 %      97      163   -40 %
Natural gas equivalents (Mmcfe)      1,675      2,234   -25 %      3,209      4,640   -31 %
                                 
Total Volumes Sold:                                
Oil and condensate (Mbbls)      142      167   -15 %      256      352   -27 %
Natural gas (Mmcf)      3,607      4,673   -23 %      7,335      9,594   -24 %
Natural gas liquids (Mbbls)      136      186   -27 %      264      386   -32 %
Natural gas equivalents (Mmcfe)      5,277      6,793   -22 %      10,457      14,019   -25 %
                                 
Daily Sales Volumes:                                
Oil and condensate (Mbbls)     1.6     1.8   -15 %     1.4     1.9   -27 %
Natural gas (Mmcf)     39.6     51.4   -23 %     40.5     52.7   -24 %
Natural gas liquids (Mbbls)     1.5     2.0   -27 %     1.5     2.1   -32 %
Natural gas equivalents (Mmcfe)      58.0      74.6   -22 %      57.8      77.0   -25 %
                                 
Average sales prices:                                
Oil and condensate (per Bbl)   $  45.61   $  41.80   9 %   $  46.99   $  34.75   35 %
Natural gas (per Mcf)   $  3.09   $  2.00   55 %   $  3.04   $  2.01   51 %
Natural gas liquids (per Bbl)   $  19.50   $  16.33   19 %   $  20.40   $  14.09   45 %
Total (per Mcfe)   $  3.84   $  2.85   35 %   $  3.80   $  2.63   44 %

  

                                 
    Three Months Ended   Six Months Ended
    June 30,    June 30, 
    2017   2016   %   2017   2016   %
Offshore Selected Costs ($ per Mcfe)                                
Lease operating expenses (1)   $  0.66   $  0.52   27 %   $  0.71   $  0.51   39 %
Production and ad valorem taxes   $  0.06   $  0.08   -25 %   $  0.06   $  0.07   -14 %
                                 
Onshore Selected Costs ($ per Mcfe)                                
Lease operating expenses (1)   $  1.94   $  1.56   24 %   $  2.07   $  1.67   24 %
Production and ad valorem taxes   $  0.29   $  0.36   -19 %   $  0.29   $  0.29   0 %
                                 
Average Selected Costs ($ per Mcfe)                                
Lease operating expenses (1)   $  1.07   $  0.86   24 %   $  1.13   $  0.89   27 %
Production and ad valorem taxes   $  0.13   $  0.17   -24 %   $  0.13   $  0.15   -13 %
General and administrative expense (cash)   $  0.80   $  0.60   33 %   $  0.89   $  0.59   51 %
Interest expense   $  0.18   $  0.17   6 %   $  0.16   $  0.15   7 %
                                 
Adjusted EBITDAX (2) (thousands)   $  10,231   $  10,103       $  17,385   $  17,366    
                                 
Weighted Average Shares Outstanding (thousands)                                
Basic      24,671      19,121          24,639      19,100    
Diluted      24,671      19,121          24,639      19,100    

(1) LOE includes transportation and workover expenses.
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income (loss).


CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
             
    June 30,    December 31, 
    2017   2016
             
ASSETS   (unaudited)
Cash and cash equivalents   $  —   $  —
Accounts receivable, net      11,621      16,727
Other current assets      3,422      2,327
Net property and equipment      342,335      340,382
Investment in affiliates and other non-current assets      18,790      17,078
             
TOTAL ASSETS   $  376,168   $  376,514
             
LIABILITIES AND SHAREHOLDERS' EQUITY            
Accounts payable and accrued liabilities      45,699      55,135
Other current liabilities      6,140      7,754
Long-term debt      71,316      54,354
Asset retirement obligations      18,592      22,618
Other non-current liabilities      248      248
Total shareholders’ equity      234,173      236,405
             
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY   $  376,168   $  376,514


CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
                         
    Three Months Ended   Six Months Ended
    June 30,    June 30, 
    2017     2016     2017     2016  
                                 
    (unaudited)
REVENUES                        
Oil and condensate sales   $  6,483     $  6,971     $  12,025     $  12,218  
Natural gas sales      11,135        9,337        22,275        19,272  
Natural gas liquids sales      2,658        3,054        5,400        5,454  
Total revenues      20,276        19,362        39,700        36,944  
                         
EXPENSES                        
Operating expenses      6,329        7,020        13,162        14,624  
Exploration expenses      284        324        375        644  
Depreciation, depletion and amortization      12,714        17,875        24,485        34,420  
Impairment and abandonment of oil and gas properties      1,401        1,252        1,431        3,103  
General and administrative expenses      5,833        5,384        12,429        11,286  
Total expenses      26,561        31,855        51,882        64,077  
                         
OTHER INCOME (EXPENSE)                        
Gain from investment in affiliates, net of income taxes      166        1,295        1,950        1,335  
Gain (loss) from sale of assets      (420 )      —        2,520        —  
Interest expense      (925 )      (1,178 )      (1,684 )      (2,056 )
Gain (loss) on derivatives, net      1,487        (4,381 )      4,583        (177 )
Other income (expense)      61        (270 )      (27 )      (310 )
Total other income (expense)      369        (4,534 )      7,342        (1,208 )
                         
NET LOSS BEFORE INCOME TAXES      (5,916 )      (17,027 )      (4,840 )      (28,341 )
                         
Income tax provision      (118 )      (269 )      (309 )      (359 )
                         
NET LOSS   $  (6,034 )   $  (17,296 )   $  (5,149 )   $  (28,700 )


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 our 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 agreement.  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 agreement.  We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX.  Non-compliance with the financial covenants contained in our credit agreement 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   Six Months Ended
    June 30,    June 30, 
    2017     2016     2017     2016  
                                 
    (in thousands)
Net loss   $  (6,034 )   $  (17,296 )   $  (5,149 )   $  (28,700 )
Interest expense      925        1,178        1,684        2,056  
Income tax provision (benefit)      118        269        309        359  
Depreciation, depletion and amortization      12,714        17,875        24,485        34,420  
Exploration expense      284        324        375        644  
EBITDAX   $  8,007     $  2,350     $  21,704     $  8,779  
                         
Unrealized loss (gain) on derivative instruments   $  (1,052 )   $  6,629     $  (4,327 )   $  3,932  
Non-cash stock-based compensation charges      1,622        1,279        3,078        2,978  
Impairment of oil and gas properties      1,400        1,140        1,400        3,012  
Loss (gain) on sale of assets and investment in affiliates      254        (1,295 )      (4,470 )      (1,335 )
Adjusted EBITDAX   $  10,231     $  10,103     $  17,385     $  17,366  

Drilling Activity Update

The derisking and development of our Southern Delaware Basin acreage in Pecos County, Texas continued through the second quarter.  Specific highlights, through the date of this release, were as follows:

Rude Ram

As previously disclosed, the Rude Ram #1H, our second well in the Southern Delaware Basin, was drilled from a common surface location with the Ripper State #1H targeting the Upper Wolfcamp A. The well was completed in April 2017, and after 30 days of flowback, reached a maximum 24-hour IP rate of 1,304 Boed (69% oil) with a 30 day average rate of 1,065 Boed (68% oil). 

Ripper State

As previously disclosed, the Ripper State #1H was drilled from a common surface location with the Rude Ram #1H, targeting the Middle Wolfcamp A. The well was completed in April 2017, and after 30 days of flowback, reached a maximum 24-hour IP rate of 1,131 Boed (73% oil) with a 30 day average rate of 806 Boed (73% oil).    

Gunner

The Gunner #2H was drilled to a TMD of 20,430 feet, including a 10,600 foot lateral, targeting the Lower Wolfcamp A.  The well has been completed with 50 stages of fracture stimulation and we are currently drilling out the frac plugs to initiate flowback, which is expected to begin in early August.  

Crusader and Fighting Ace

Both the Crusader #1H and Fighting Ace #1H were spud in June 2017 from the same pad, allowing us to easily skid the rig from one well to the other.  The Crusader is currently drilling at a measured depth of 11,139 feet.  Once this well is finished, we will skid back to the Fighting Ace and finish the lateral section. Both wells will be drilled to a total measured depth of approximately 20,000 feet, including a 10,000 foot lateral with 50 stages of frac.  Completion operations on both wells are expected to commence in late September, with initial production expected in the fourth quarter. 

Upon completion of these two wells, we expect to move the rig to our seventh horizontal well, the Ragin Bull #1H, which will be on the same pad as the Lonestar Gunfighter well. 

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said “With three wells producing and three more wells scheduled to come on-line soon, we continue to be encouraged by the development of our Southern Delaware Basin acreage. With the Gunner #2H well expected to commence production in early August, our Fighting Ace #1H and Crusader #1H wells expected to commence completion operations later this quarter, and our upcoming drilling schedule, we have budgeted to have eight Southern Delaware Basin wells on production by the end of the year.”

Guidance for Third Quarter 2017

The Company is providing the following guidance for the third calendar quarter of 2017.

     
Production   56,000 - 61,000 Mcfe per day
     
LOE (including transportation and workovers)   $6.8 million - $7.3 million
     
Production and ad valorem taxes (% of Revenue)   4.00%  
     
Cash G&A   $4.5 million - $5.1 million
     
DD&A Rate   $2.30 - $2.55

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Thursday, August 3, 2017 at 9:30am Central Standard Time.  Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-737-3705, (International 1-719-325-2170) and entering the following participation code: 8587146.  A replay of the call will be available from Thursday, August 3, 2017 at 12:30pm CST through Thursday, August 10, 2017 at 12:30pm CST by clicking on the audio replay link here, and entering participation code 8587146.

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 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.

Contact:
                    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
                    

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