May 4, 2018

Contango Announces First Quarter 2018 Financial Results and Provides Operational Update

HOUSTON, May 04, 2018 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE American:MCF) (“Contango” or the “Company”) announced today its financial results for the first quarter ended March 31, 2018 and provided an operational update. 

First Quarter Highlights

  • Sale of non-core Eagle Ford Shale assets for $21 million
  • Production of 4.5 Bcfe for the quarter, or 50.0 Mmcfed
  • Net income of $0.9 million for the quarter
  • Adjusted EBITDAX, on a recurring basis, of $8.3 million for the quarter
  • Commenced production from two more Pecos County wells in the Southern Delaware Basin, and a third well in April  

Summary First Quarter Financial Results

Net income for the three months ended March 31, 2018 was $0.9 million, or $0.04 per basic and diluted share, consistent with last year’s net income of $0.9 million, or $0.04 per basic and diluted share. Current year net income was positively impacted by a gain from the sale of our Eagle Ford Shale assets in Karnes County, Texas.  Other positive items contributing to current year net income include higher revenues from higher oil and liquids prices, a higher percentage of production from oil and liquids, and lower depreciation, depletion, and amortization (“DD&A”) expense, partially offset by higher impairment expenses, a lower gain attributable to our investment in Exaro Energy III LLC (“Exaro”), and a loss on the mark-to-market value of our outstanding derivatives. Average weighted shares outstanding were approximately 24.8 million and 24.6 million for the current and prior year quarters, respectively. 

The Company reported Adjusted EBITDAX, as defined below and on a recurring basis, of approximately $8.3 million for the three months ended March 31, 2018, compared to $7.2 million for the same period last year, an increase attributable to higher revenues.  Cash flow for the current quarter was $6.9 million, or $0.28 per share, compared to $6.4 million, or $0.26 per share for the prior year quarter. 

Revenues for the current quarter were approximately $20.4 million compared to $19.4 million for the 2017 quarter. Despite lower production during the current quarter, the increase in crude oil and natural gas liquids prices was responsible for the increase in revenues. Revenues from the sale of crude oil and natural gas liquids increased to $11.8 million for the current quarter, compared to $8.3 million for the prior year quarter due to the increase in that production resulting from our Southern Delaware drilling program.

Production for the first quarter of 2018 was approximately 4.5 Bcfe, or 50.0 Mmcfe per day, within our previously provided guidance, compared to 57.6 Mmcfe per day for the first quarter of 2017.  This expected year over year decline in equivalent production volumes is mitigated in part by the fact that the percentage of production from higher-value oil and natural gas liquids increased from 28% to 35%.  As the year progresses, that percentage should continue to increase due to our oil-weighted drilling program.  Crude oil and natural gas liquids production during the first quarter of 2018 was approximately 3,000 barrels per day, compared to approximately 2,700 barrels per day in the first quarter of 2017.  Our production guidance for the second quarter of 2018 is expected to be between 41–46 Mmcfed, due to shutting in our offshore production for approximately two weeks for scheduled maintenance to install compression, normal production declines and the sale of our Eagle Ford Shale producing properties in Karnes County, Texas, partially offset by added production from our Southern Delaware Basin drilling activity, as we strive to continue to increase the percentage of production attributable to higher-value oil and natural gas liquids. 

The weighted average equivalent sales price during the three months ended March 31, 2018 was $4.53 per Mcfe, compared to $3.75 per Mcfe for the same period last year, as we experienced increases of 29% and 12% in crude oil and natural gas liquids prices, respectively, compared to the prior year quarter, and due to the increase in the higher percentage of oil and liquids in the production mix. 

Operating expenses for the three months ended March 31, 2018 were approximately $6.9 million, or $1.54 per Mcfe and within our previously provided guidance, compared to $6.8 million, or $1.32 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 exclusive of production and ad valorem taxes were approximately $6.1 million, or $1.37 per Mcfe, for the current quarter compared to approximately $6.2 million, or $1.19 per Mcfe, for the prior year quarter. Our guidance for operating expenses for the second quarter of 2018, exclusive of production and ad valorem taxes, is between $5.9 to $6.4 million, which is consistent with the current quarter.        

DD&A expense for the three months ended March 31, 2018 was $10.5 million, or $2.33 per Mcfe, compared to $11.8 million, or $2.27 per Mcfe, for the prior year quarter, a decrease primarily attributable to lower production during the quarter. 

Impairment and abandonment expense of oil and gas properties was $3.3 million for the current quarter. Included in this amount is $2.3 million related to the impairment of our Vermilion 170 offshore asset and $0.8 million related to expiring leases of unproved properties.

Total G&A expenses, inclusive of stock compensation expense, for the three months ended March 31, 2018 were $6.7 million, compared to $6.6 million, for the prior year quarter.  Cash G&A expenses, i.e. G&A exclusive of stock compensation expense, were $5.3 million, or $1.18 per Mcfe, and $5.1 million, or $0.99 per Mcfe, respectively, for the two quarterly periods.  For the second quarter of 2018, we have provided guidance of $4.9 million to $5.4 million for cash general and administrative expenses. 

Gain from affiliates (i.e. Exaro Energy III) for the three months ended March 31, 2018 was approximately $0.7 million, compared to a gain of $1.8 million for the same period last year.  

Gain from sale of assets for the three months ended March 31, 2018 was approximately $9.4 million, which related to the sale of our operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21 million.  

2018 Capital Program

Capital costs incurred for the three months ended March 31, 2018 were approximately $19.5 million, including $17.4 million for the drilling and completion of wells in the Southern Delaware Basin in Pecos County, Texas and $1.7 million in leasehold acquisition and other costs.  Our capital expenditure budget for 2018 was originally forecasted to be approximately $54 million, including $52 million in the Southern Delaware Basin. As of March 31, 2018, our capital expenditure forecast for 2018 was approximately $57 million, including $52 million to drill and/or complete eight to nine wells, in our Southern Delaware Basin position.

As of March 31, 2018, we had approximately $78.7 million of debt outstanding under our credit facility. 

Drilling Activity Update

Our recent Southern Delaware Basin activity consists of the following:

River Rattler #1H

As previously reported, the River Rattler #1H (44% WI, 33% NRI), our first Wolfcamp B test, was spud in December 2017. Production began in March 2018 at an initial 24-hour max IP rate of 1,416 Boed (74% oil) and an initial 30-day rate of 1,225 Boed (74% oil), making it our best well to date from an IP perspective. We continue to identify cost efficiencies in our drilling efforts, as evidenced by the fact that the Ragin Bull #3H, which immediately preceded this well, and River Rattler #1H have taken only 27 days from spud to TMD.

Ragin Bull #2H

The Ragin Bull #2H (49% WI, 37% NRI), our second Wolfcamp B test, was spud in January 2018. Production began in April 2018 at an initial 24-hour max IP rate of 805 Boed (68% oil). This well represents our fastest spud to total depth so far at 26.5 days. 

Sidewinder #1H / Gunner #3H

The Sidewinder #1H (49% WI, 37% NRI), the first of two wells to be drilled from a common pad, was spud in March 2018. The Sidewinder was drilled into the Wolfcamp A horizon just south of the Rude Ram #1H Wolfcamp A completion, which has produced 155 MBoe in nine months. The Gunner #3H well (47% WI, 35% NRI) was spud in April 2018 and was drilled to a total measured depth of 20,167 feet, including a 10,067 foot lateral.  This well will be a Wolfcamp B test in the same unit as the Gunner #2H Wolfcamp A completion, which so far is our best producing well to date having produced approximately 130 MBoe in six months.  Both wells from this pad are expected to begin completion operations via a zipper frac strategy in June 2018.

For the remainder of the year, our capital expenditure budget calls for us to drill five to six more wells, with the next one being the Fighting Ace #2H.  This well will target the Wolfcamp B formation and is expected to be spud in May 2018. 

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said, “We are excited about the recent results from our Southern Delaware Basin program, including the performance from our first two Wolfcamp B wells.  We now have eight wells on production, with two more to come on in early July from the Sidewinder/Gunner pad we are currently drilling, one well in the Wolfcamp A and one in the Wolfcamp B.  We were also pleased to be able to monetize our Karnes County position during the quarter for a value reflective of the downspacing potential in that position."

Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three months ended March 31, 2018 and 2017: 

                 
    Three Months Ended
    March 31, 
    2018   2017   %
Offshore Volumes Sold:                
Oil and condensate (Mbbls)      19      22   -14%
Natural gas (Mmcf)      2,296      3,008   -24%
Natural gas liquids (Mbbls)      78      84   -7%
Natural gas equivalents (Mmcfe)      2,877      3,646   -21%
                 
Onshore Volumes Sold:                
Oil and condensate (Mbbls)      121      92   32%
Natural gas (Mmcf)      617      720   -14%
Natural gas liquids (Mbbls)      47      44   7%
Natural gas equivalents (Mmcfe)      1,627      1,534   6%
                 
Total Volumes Sold:                
Oil and condensate (Mbbls)      140      114   23%
Natural gas (Mmcf)      2,913      3,728   -22%
Natural gas liquids (Mbbls)      125      128   -2%
Natural gas equivalents (Mmcfe)      4,504      5,180   -13%
                 
Daily Sales Volumes:                
Oil and condensate (Mbbls)     1.6     1.3   23%
Natural gas (Mmcf)     32.4     41.4   -22%
Natural gas liquids (Mbbls)     1.4     1.4   -2%
Natural gas equivalents (Mmcfe)      50.0      57.6   -13%
                 
Average sales prices:                
Oil and condensate (per Bbl)   $  62.76   $  48.71   29%
Natural gas (per Mcf)   $  2.96   $  2.99   -1%
Natural gas liquids (per Bbl)   $  23.97   $  21.36   12%
Total (per Mcfe)   $  4.53   $  3.75   21%

  

                 
    Three Months Ended
    March 31, 
    2018   2017   %
Offshore Selected Costs ($ per Mcfe)                
Lease operating expenses (1)   $  0.82   $  0.93   -12%
Production and ad valorem taxes   $  0.07   $  0.13   -46%
                 
Onshore Selected Costs ($ per Mcfe)                
Lease operating expenses (1)   $  2.33   $  1.81   29%
Production and ad valorem taxes   $  0.36   $  0.13   177%
                 
Average Selected Costs ($ per Mcfe)                
Lease operating expenses (1)   $  1.37   $  1.19   15%
Production and ad valorem taxes   $  0.17   $  0.13   31%
General and administrative expense (cash)   $  1.18   $  0.99   19%
Interest expense   $  0.31   $  0.15   107%
                 
Adjusted EBITDAX (2) (thousands)   $  8,344   $  7,154    
                 
Weighted Average Shares Outstanding (thousands)                
Basic      24,793      24,607    
Diluted      24,841      24,641    

_______________________________

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


 
CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
 
    March 31,    December 31, 
    2018   2017
ASSETS   (unaudited)
Cash and cash equivalents   $  —   $  —
Accounts receivable, net      13,701      13,059
Other current assets      1,688      2,714
Net property and equipment      340,533      345,957
Investment in affiliates and other non-current assets      20,638      19,723
             
TOTAL ASSETS   $  376,560   $  381,453
             
LIABILITIES AND SHAREHOLDERS' EQUITY            
Accounts payable and accrued liabilities      42,610      46,755
Other current liabilities      3,639      3,782
Long-term debt      78,660      85,380
Asset retirement obligations      20,455      20,388
Other non-current liabilities      4,306      548
Total shareholders’ equity      226,890      224,600
             
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY   $  376,560   $  381,453


 
CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
 
    Three Months Ended
    March 31, 
    2018     2017  
    (unaudited)
REVENUES            
Oil and condensate sales   $  8,811     $  5,542  
Natural gas sales      8,609        11,140  
Natural gas liquids sales      3,017        2,742  
Total revenues      20,437        19,424  
             
EXPENSES            
Operating expenses      6,927        6,833  
Exploration expenses      469        91  
Depreciation, depletion and amortization      10,485        11,771  
Impairment and abandonment of oil and gas properties      3,327        30  
General and administrative expenses      6,726        6,596  
Total expenses      27,934        25,321  
             
OTHER INCOME (EXPENSE)            
Gain from investment in affiliates, net of income taxes      707        1,784  
Gain from sale of assets      9,447        2,940  
Interest expense      (1,409 )      (759 )
Gain (loss) on derivatives, net      (1,032 )      3,096  
Other income (expense)      879        (88 )
Total other income      8,592        6,973  
             
NET INCOME BEFORE INCOME TAXES      1,095        1,076  
             
Income tax provision      (158 )      (191 )
             
NET INCOME   $  937     $  885  


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
    March 31, 
    2018     2017  
    (in thousands)
Net income   $  937     $  885  
Interest expense      1,409        759  
Income tax provision      158        191  
Depreciation, depletion and amortization      10,485        11,771  
Exploration expense      469        91  
EBITDAX   $  13,458     $  13,697  
             
Unrealized loss (gain) on derivative instruments   $  519     $  (3,275 )
Non-cash stock-based compensation charges      1,424        1,456  
Impairment of oil and gas properties      3,097        —  
Gain on sale of assets and investment in affiliates      (10,154 )      (4,724 )
Adjusted EBITDAX   $  8,344     $  7,154  

Guidance for Second Quarter 2018

The Company is providing the following guidance for the second calendar quarter of 2018.

     
Production   41,000 - 46,000 Mcfe per day
     
LOE (including transportation and workovers)   $5.9 million - $6.4 million
     
Production and ad valorem taxes (% of Revenue)   3.5 - 4.0%
     
Cash G&A   $4.9 million - $5.4 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 Monday, May 7, 2018 at 9:30am Central Daylight Time.  Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-394-8218, (International 1-323-701-0225) and entering participation code 5790752.  A replay of the call will be available from Monday, May 7, 2018 at 12:30pm CDT through Monday, May 14, 2018 at 12:30pm CDT by clicking in the audio replay link here and entering participation code 5790752.

Contango Oil & Gas Company is a Houston, Texas based, independent oil and natural gas company whose business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in onshore West Texas, the Texas Gulf Coast and the 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 Sergio Castro – 713-236-7400
Senior Vice President and Chief Financial Officer Vice President and Treasurer

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Source: Contango Oil & Gas