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Contango Announces Fourth Quarter and Full Year 2018 Financial Results

HOUSTON, March 21, 2019 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE American: MCF) (“Contango” or the “Company”) announced today  that it is re-issuing its previous release that was made on March 18, 2019 to include certain disclosures that are required under the NYSE American Company Guide. Other than this additional disclosure,  the content of this release is the same as the content of the release issued on March 18, 2019.

Fourth Quarter 2018 Highlights

  • Production of 3.7 Bcfe for the quarter (39.8 Mmcfed, 42% liquids); within previously provided guidance, despite late December weather related shut-ins
     
  • Net loss of $33.8 million and Adjusted EBITDAX of $7.5 million for the quarter
     
  • Debt of $60 million at December 31, 2018, compared to $85.4 million at December 31, 2017
     
  • $33.0 million in proceeds from successful equity offering in November
     
  • Acquisition of an additional 4,200 gross operated acres (1,700 net) and 4,000 gross non-operated acres (200 net) in Pecos County, Texas adjacent to our current Southern Delaware Basin position
     
  • Over $6 million in cash proceeds from non-core asset sales

Management Commentary

Wilkie S. Colyer, the Company’s President and Chief Executive Officer, said, “We’ve been busy this quarter executing on several strategic initiatives that we believe will position the Company to deliver long term shareholder value, beginning with the non-core asset sales and equity offering which allowed us to be opportunistic in our purchase of high-quality, bolt-on acreage in the Southern Delaware Basin that we call NE Bullseye.  We will be prudent in the use of our capital in 2019, spending only what we need to spend to preserve our asset portfolio, which will largely be focused in NE Bullseye. With the help of our financial advisors, we continue to evaluate strategic alternatives available to the Company with the singular focus of maximizing value for shareholders. In addition, we’ve continued to focus on cost reduction by streamlining our organization and reducing related administrative costs, resulting in a projected $7.2 million, or 37%, decrease in cash G&A in 2019, increasing well north of 40% on a run rate basis starting in Q2.”

Summary Fourth Quarter Financial Results

Net loss for the three months ended December 31, 2018 was $33.8 million, or $(1.16) per basic and diluted share, compared to a net loss of $5.6 million, or $(0.23) per basic and diluted share, for the same period last year. This year’s quarter was negatively impacted by impairment charges of $27.0 million related to non-core asset sales and to price related reserve revisions.  Impairment charges for the same period last year were $0.4 million. Average weighted shares outstanding were approximately 29.0 million and 24.8 million for the current and prior year quarters, respectively.

The Company reported Adjusted EBITDAX, as defined below, of approximately $7.5 million for the three months ended December 31, 2018, compared to $10.2 million for the same period last year, a decrease attributable to a $1.3 million decrease in revenues from lower production and a $1.1 million realized loss from derivatives, compared to a $0.3 million gain for the same period last year. 

Revenues for the three months ended December 31, 2018 were approximately $18.7 million compared to $20.0 million for the same period last year, a decrease attributable to lower production during the current quarter and a 4% and 10% decrease in crude oil and natural gas liquids prices, respectively, partially offset by a 35% increase in natural gas prices. 

Production for the fourth quarter of 2018 was approximately 3.7 Bcfe, or 39.8 Mmcfe per day, compared to 51.8 Mmcfe per day for the fourth quarter of 2017, but within our previously provided guidance. This decrease in production can be attributed to our Vermilion 170 well ceasing production for the entire month of November because of third-party pipeline issues, cold weather shut-ins in some of our West Texas properties during the month of December, a reduction in our drilling program in the Southern Delaware Basin beginning in late 2018 in response to declining oil prices and high Mid-Cushing oil differentials in West Texas, and the divestiture of some non-core conventional properties.  Crude oil and natural gas liquids production during the fourth quarter of 2018 was approximately 2,800 barrels per day, or 42% of total production, compared to approximately 2,700 barrels per day, or 32% of total production, in the fourth quarter of 2017, an increase attributable to bringing on new production from our oil-based Southern Delaware Basin program and normal decline in our natural gas-based offshore Gulf of Mexico assets.  Our first quarter 2019 production guidance is 34 – 39 Mmcfed.

The weighted average equivalent sales price during the three months ended December 31, 2018 was $5.10 per Mcfe, compared to $4.20 per Mcfe for the same period last year.  As previously noted, stronger natural gas prices were responsible for the increase in the weighted average equivalent price.

Operating expenses for the three months ended December 31, 2018 were approximately $5.8 million, or $1.57 per Mcfe, compared to $7.0 million, or $1.47 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. Operating expenses exclusive of production and ad valorem taxes for the three months ended December 31, 2018 were approximately $5.1 million, or $1.39 per Mcfe, compared to approximately $6.4 million, or $1.34 per Mcfe, for the same period last year, and below our previously provided guidance for the quarter. This decrease is attributable to routing substantially all of our offshore gas production through a lower cost pipeline and the routing of substantially all of our offshore condensate through a new pipeline we constructed in early 2018.      

DD&A expense for the three months ended December 31, 2018 was $8.8 million, or $2.41 per Mcfe, compared to $11.5 million, or $2.42 per Mcfe, for the same period last year, a decrease primarily attributable to lower production during the quarter. 

Impairment and abandonment expense from oil and gas properties was $27.1 million for the three months ended December 31, 2018.  Of this amount, $12.1 million related to the impairment of certain non-core conventional properties in South Texas that were reduced to their fair value as a result of planned sales during the current quarter, and $14.9 million was attributable to price related reserve revisions primarily on our Wyoming and certain South Texas assets.  For the same period last year, impairment and abandonment expense from oil and gas properties was $0.9 million.

General and administrative (“G&A”) expenses for the three months ended December 31, 2018 were $5.4 million, or $1.46 per Mcfe, compared to $5.5 million, or $1.16 per Mcfe, for the prior year quarter.  G&A expenses for the current quarter includes $1.0 million in non-cash stock compensation expense and $0.2 million in non-cash bad-debt expense, while the prior year quarter includes $1.5 million in non-cash stock compensation expense.  For the first quarter of 2019, we have provided guidance of $4.0 million to $4.5 million for general and administrative expenses, exclusive of non-cash stock compensation (“Cash G&A”). 

Loss from affiliates for the three months ended December 31, 2018 was approximately $12.7 million which was primarily related to impairment expenses, compared to a gain from affiliates of $0.2 million for the same period last year, both associated with our 37% equity interest in Exaro Energy III.  

2019 Capital Program

Capital costs incurred for the three months ended December 31, 2018 were approximately $8.9 million, which was primarily related to the acquisition our new NE Bullseye acreage in the Southern Delaware Basin in Pecos County, Texas. 

We currently forecast to spend approximately $30.3 million on our 2019 capital expenditure program.  Of this amount, approximately $28.4 million has been allocated to the Southern Delaware Basin. Our current plans call for us to drill four gross wells and complete five in this area at a net cost to us of $21.6 million. We have contracted a rig and plan to spud our first well in NE Bullseye in late March 2019 and follow with two additional NE Bullseye wells and our 14th well in Bullseye. All wells are expected to be approximately 10,000’ laterals in the Wolfcamp section. The fifth completion in 2019 is the Ripper State 2H, a Wolfcamp B well drilled in late 2018 with completion deferred until it could be done in sequence with the 2019 wells. All completions are expected to be designed similar to our previous completions and other completions by operators in the area. In addition, we have forecasted to spend $1.3 million in additional lease hold costs and extensions on this acreage and $5.5 million in infrastructure costs, primarily gathering facilities in NE Bullseye.

In addition to our Southern Delaware Basin activity in 2019, we have allocated an additional $1.9 million of our 2019 capital budget to participate in two non-operated wells targeting the Georgetown formation in our Booth-Tortuga area in Zavala and Dimmit Counties of south Texas.  We participated for an approximate 20% working interest in two very successful Georgetown horizontal wells in this area in 2017 and 2018. We expect our 2019 capital expenditure program to be funded by internally generated cash flow and temporary borrowings under our revolving credit facility. We will continue to monitor commodity prices, drilling results and service/supply costs during the year, and if deemed appropriate, may make adjustments to our drilling strategy as the year progresses.

Liquidity

Our debt at December 31, 2018 was approximately $60.0 million, all of which is currently reflected as short-term due to the fact that it matures in less than twelve months from the December 31 balance sheet date.  We are currently working towards extending or replacing our revolving credit facility and anticipate having that done prior to the October 1, 2019 facility maturity date. Our credit facility currently provides for a borrowing base of $90 million through May 1, 2019, and we are in compliance with our bank facility covenants as of December 31, 2018.  We will continue to investigate ways of prudently increasing the availability of drilling capital during 2019.  

2018 Year End Reserves

As of December 31, 2018, the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) value of our proved reserves was approximately $218.9 million and the SEC PV-10 value of our proved reserves was approximately $220.5 million, compared to the Standardized Measure value of $255.9 million and SEC PV-10 value of $257.3 million as of December 31, 2017, a decrease attributable to production, performance revisions, divestitures and expired proved undeveloped reserves (“PUD”) as a result of the failure to drill those PUDs within five years of the initial booking as proved, as required by the SEC’s five-year rule.  This decrease was offset, in part, by the value of reserves added through our Southern Delaware Basin drilling program and price-related revisions attributable to the increase in commodity prices. The SEC-mandated prices used in determining our December 31, 2018 proved reserves and PV-10 value were $62.90/Bbl for oil and condensate, $3.02/Mmbtu for natural gas and $27.89/Bbl for natural gas liquids, compared with SEC prices of $47.41/Bbl for oil and condensate, $2.92/Mmbtu for natural gas and $18.59/Bbl for natural gas liquids used in estimating proved reserves as of December 31, 2017.

As of December 31, 2018, our independent third-party engineering firms estimated our proved oil and natural gas reserves to be approximately 131.9 Bcfe compared with 189.3 Bcfe of proved reserves as of December 31, 2017, a decline attributable to 16 Bcfe of production during the year, 25.2 Bcfe of divestitures and 51.7 Bcfe of negative revisions, the majority of which were related to a revision to our West Texas type curve resulting from analysis of longer term decline experience and our previously disclosed Eugene Island field as a result of new bottom hole pressure data gathered during the planned installation of compression. Partially offsetting those decreases were 35.5 Bcfe of additions from our Southern Delaware Basin drilling program, our Georgetown drilling program participation, and price-related revisions resulting from the impact of higher commodity prices on the volume and value of our proved reserves. The impact of our oil-weighted drilling program in the Southern Delaware is also reflected in the more balanced commodity profile of our reserve base at year-end 2018.  At the end of 2018, the composition of our proved reserves, volumetrically, was 41% natural gas, 43% oil and condensate and 16% natural gas liquids, compared to 48% natural gas, 34% oil and condensate and 18% natural gas liquids at December 31, 2017. These estimates were prepared in accordance with reserve reporting guidelines mandated by the Securities and Exchange Commission (“SEC”). 

Our proved developed reserves for the year ended December 31, 2018 were estimated at 79.2 Bcfe, compared to 123.9 Bcfe in the prior year. The decline in proved developed reserves can be attributed to approximately 16 Bcfe of production during the year, 17.7 Bcfe in property sales and 26.7 Bcfe in negative revisions, the majority of which were related to our Eugene Island field as described above. Partially offsetting those declines were 9.0 Bcfe in extensions and new discoveries, 3.9 Bcfe of reserves that were converted from proved undeveloped reserves and 2.8 Bcfe in positive price revisions due to the increase in commodity prices.

Our proved undeveloped reserves (“PUD”) for the year ended December 31, 2018 were 52.7 Bcfe, compared to 65.4 Bcfe at December 31, 2017.  The decrease in PUD reserves can be attributed to 7.6 Bcfe related to property sales, 3.9 Bcfe of PUDs converted to proved developed reserves, the reclassification of 5.6 Bcfe to unproved reserves as a result of the failure to drill those PUDs within five years of the initial booking as proved, as required by the SEC’s five-year rule and 19.3 Bcfe in negative revisions, the majority of which were associated with a revision to our West Texas type curve as discussed above. These decreases were offset, in part, by 22.5 Bcfe in extensions and new discoveries and 1.2 Bcfe price-related revisions resulting from the increase in commodity prices.

The above estimates do not include net proved reserves of approximately 26.6 Bcfe and 30.7 Bcfe attributable to our 37% equity ownership interest in Exaro Energy III LLC (“Exaro”) as of December 31, 2018 and 2017, respectively. The PV-10 value of the proved reserves attributable to our 37% interest in Exaro was approximately $21.0 million and $24.4 million at December 31, 2018 and 2017, respectively.

The following table summarizes Contango’s total proved reserves as of December 31, 2018 (1)

                     
                    Present Value
    OIL   NGL   Gas   Total   Discounted
Category   (MBbl)   (MBbl)   (Mmcf)   (Mmcfe)   at 10% ($000)
Developed   3,103   2,297   46,840   79,234   176,298
Undeveloped   6,331   1,220   7,366   52,677   44,209
Total Proved   9,434   3,517   54,206   131,911   220,507
  1. These estimates do not include net reserves of approximately 26.6 Bcfe (PV-10 of approximately $21.0 million attributable to our 37% equity ownership investment in Exaro as of December 31, 2018).

Derivative Instruments

As of December 31, 2018, we have the following financial derivative contracts in place with members of our bank group.  These contracts represent approximately 72% of our currently forecasted 2019 proved developed reserves (“PDP”) natural gas production and 68% of our currently forecasted 2019 PDP crude oil production.

                   
Commodity   Period   Derivative   Volume/Month     Price/Unit
Natural Gas   Jan 2019 - March 2019   Swap   600,000 MMBtus   $ 3.21 (1)
Natural Gas   April 2019 - July 2019   Swap   600,000 MMBtus   $ 2.75 (1)
Natural Gas   Aug 2019 - Oct 2019   Swap   100,000 MMBtus   $ 2.75 (1)
Natural Gas   Nov 2019 - Dec 2019   Swap   500,000 MMBtus   $ 2.75 (1)
                   
Oil   Jan 2019 - Dec 2019   Collar   7,000 Bbls   $ 50.00 - 58.00 (2)
Oil   Jan 2019 - Dec 2019   Collar   4,000 Bbls   $ 52.00 - 59.45 (3)
Oil   Jan 2019 - June 2019   Collar   12,000 Bbls   $ 70.00 - 76.25 (3)
                   
Oil   Jan 2019 - July 2019   Swap   6,000 Bbls   $ 66.10 (3)
                   
Oil   July 2019   Swap   12,000 Bbls   $ 72.10 (3)
Oil   Aug 2019 - Oct 2019   Swap   9,000 Bbls   $ 72.10 (3)
Oil   Nov 2019 - Dec 2019   Swap   12,000 Bbls   $ 72.10 (3)
  1. Based on Henry Hub NYMEX natural gas prices.
  2. Based on Argus Louisiana Light Sweet crude oil prices.
  3. Based on West Texas Intermediate crude oil prices.

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

                                 
    Three Months Ended   Year ended
    December 31,    December 31, 
    2018   2017   %   2018   2017   %
Offshore Volumes Sold:                                
Oil and condensate (Mbbls)     17     21   -19 %     73     99   -26 %
Natural gas (Mmcf)     1,769     2,571   -31 %     7,704     11,189   -31 %
Natural gas liquids (Mbbls)     76     76   0 %     287     330   -13 %
Natural gas equivalents (Mmcfe)     2,327     3,154   -26 %     9,865     13,762   -28 %
                                 
Onshore Volumes Sold:                                
Oil and condensate (Mbbls)     123     109   13 %     496     419   18 %
Natural gas (Mmcf)     358     689   -48 %     2,075     2,721   -24 %
Natural gas liquids (Mbbls)     41     44   -7 %     187     187   0 %
Natural gas equivalents (Mmcfe)     1,339     1,610   -17 %     6,174     6,361   -3 %
                                 
Total Volumes Sold:                                
Oil and condensate (Mbbls)     140     130   8 %     569     518   10 %
Natural gas (Mmcf)     2,127     3,260   -35 %     9,779     13,910   -30 %
Natural gas liquids (Mbbls)     117     120   -3 %     474     517   -8 %
Natural gas equivalents (Mmcfe)     3,666     4,764   -23 %     16,039     20,123   -20 %
                                 
Daily Sales Volumes:                                
Oil and condensate (Mbbls)     1.5     1.4   8 %     1.6     1.4   10 %
Natural gas (Mmcf)     23.1     35.4   -35 %     26.8     38.1   -30 %
Natural gas liquids (Mbbls)     1.3     1.3   -3 %     1.3     1.4   -8 %
Natural gas equivalents (Mmcfe)     39.8     51.8   -23 %     43.9     55.1   -20 %
                                 
Average sales prices:                                
Oil and condensate (per Bbl)   $ 53.25   $ 55.30   -4 %   $ 60.43   $ 48.90   24 %
Natural gas (per Mcf)   $ 3.87   $ 2.87   35 %   $ 3.05   $ 2.97   3 %
Natural gas liquids (per Bbl)   $ 25.78   $ 28.59   -10 %   $ 27.04   $ 22.97   18 %
Total (per Mcfe)   $ 5.10   $ 4.20   21 %   $ 4.80   $ 3.90   23 %
                                     

  

                                 
    Three Months Ended   Year Ended
    December 31,    December 31, 
    2018   2017   %   2018   2017   %
Offshore Selected Costs ($ per Mcfe)                                
Lease operating expenses (1)   $ 0.80   $ 0.61   31 %   $ 0.84   $ 0.72   17 %
Production and ad valorem taxes   $ 0.06   $ 0.06   0 %   $ 0.07   $ 0.06   17 %
                                 
Onshore Selected Costs ($ per Mcfe)                                
Lease operating expenses (1)   $ 2.43   $ 2.78   -13 %   $ 2.30   $ 2.32   -1 %
Production and ad valorem taxes   $ 0.39   $ 0.25   56 %   $ 0.39   $ 0.28   39 %
                                 
Average Selected Costs ($ per Mcfe)                                
Lease operating expenses (1)   $ 1.39   $ 1.34   4 %   $ 1.40   $ 1.22   15 %
Production and ad valorem taxes   $ 0.18   $ 0.12   50 %   $ 0.19   $ 0.13   46 %
General and administrative expense (cash)   $ 1.19   $ 0.83   43 %   $ 1.21   $ 0.90   34 %
Interest expense   $ 0.40   $ 0.27   48 %   $ 0.35   $ 0.20   75 %
                                 
Adjusted EBITDAX (2) (thousands)   $ 7,450   $ 10,213       $ 29,400   $ 35,087    
                                 
Weighted Average Shares Outstanding (thousands)                                
Basic     29,018     24,757         25,945     24,686    
Diluted     29,018     24,757         25,945     24,686    

__________________________

  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)
             
    December 31,    December 31, 
    2018   2017
         
ASSETS   (unaudited)
Cash and cash equivalents   $  —   $  —
Accounts receivable, net      11,531      13,059
Other current assets      5,903      2,714
Net property and equipment      233,174      345,957
Investment in affiliates and other non-current assets      6,524      19,723
             
TOTAL ASSETS   $  257,132   $  381,453
             
LIABILITIES AND SHAREHOLDERS' EQUITY            
Accounts payable and accrued liabilities      39,506      46,755
Current portion of long-term debt      60,000      —
Other current liabilities      1,751      3,782
Long-term debt      —      85,380
Asset retirement obligations      12,168      20,388
Other non-current liabilities      3,318      548
Total shareholders’ equity      140,389      224,600
             
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY   $  257,132   $  381,453
             


 
CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
                         
    Three Months Ended   Year Ended
    December 31,    December 31, 
    2018   2017   2018   2017
                         
    (unaudited)
REVENUES                        
Oil and condensate sales   $ 7,437     $ 7,213     $ 34,413     $ 25,347  
Natural gas sales     8,239       9,361       29,824       41,317  
Natural gas liquids sales     3,018       3,441       12,850       11,881  
Total revenues     18,694       20,015       77,087       78,545  
                         
EXPENSES                        
Operating expenses     5,765       6,980       25,552       27,183  
Exploration expenses     349       416       1,637       1,106  
Depreciation, depletion and amortization     8,821       11,537       41,657       47,215  
Impairment and abandonment of oil and gas properties     27,104       880       103,732       2,395  
General and administrative expenses     5,353       5,513       24,157       24,161  
Total expenses     47,392       25,326       196,735       102,060  
                         
OTHER INCOME (EXPENSE)                        
Gain (loss) from investment in affiliates, net of income taxes     (12,683 )     222       (12,721 )     2,697  
Gain (loss) from sale of assets     1,909       (56 )     13,224       2,280  
Interest expense     (1,466 )     (1,278 )     (5,548 )     (4,100 )
Gain (loss) on derivatives, net     6,900       (1,249 )     1,939       3,325  
Other income     67       1,302       1,306       1,275  
Total other income (expense)     (5,273 )     (1,059 )     (1,800 )     5,477  
                         
NET LOSS BEFORE INCOME TAXES     (33,971 )     (6,370 )     (121,448 )     (18,038 )
                         
Income tax benefit (provision)     168       792       (120 )     395  
                         
NET LOSS   $ (33,803 )   $ (5,578 )   $ (121,568 )   $ (17,643 )
                                 

Non-GAAP Financial Measures

This news release includes certain non-GAAP financial information as defined by Securities and Exchange Commission rules. Pursuant to SEC requirements, reconciliations of non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (GAAP) are included in this press release.

Adjusted EBITDAX represents net income (loss) before interest expense, taxes, depreciation, depletion and amortization, and oil and gas exploration expenses (“EBITDAX”) as further adjusted to reflect the items set forth in the table below and is a measure required to be used in determining our compliance with financial covenants under our credit facility. 

We have included 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 Adjusted EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and therefore 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 Adjusted EBITDAX in the evaluation of companies, many of which present Adjusted 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 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.

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

                         
    Three Months Ended   Year Ended
    December 31,    December 31, 
    2018   2017   2018   2017
                 
    (in thousands)
Net loss   $ (33,803 )   $ (5,578 )   $ (121,568 )   $ (17,643 )
Interest expense     1,466       1,278       5,548       4,100  
Income tax provision (benefit)     (168 )     (792 )     120       (395 )
Depreciation, depletion and amortization     8,821       11,537       41,657       47,215  
Exploration expense     349       416       1,637       1,106  
EBITDAX   $ (23,335 )   $ 6,861     $ (72,606 )   $ 34,383  
                         
Unrealized loss (gain) on derivative instruments   $ (7,972 )   $ 1,593     $ (5,421 )   $ (2,204 )
Non-cash stock-based compensation charges     994       1,540       4,766       6,100  
Impairment of oil and gas properties     26,989       385       103,164       1,785  
Loss (gain) on sale of assets and investment in affiliates     10,774       (166 )     (503 )     (4,977 )
Adjusted EBITDAX   $ 7,450     $ 10,213     $ 29,400     $ 35,087  
                                 

PV-10 at year-end is a non-GAAP financial measure and represents the present value, discounted at 10% per year, of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure of Discounted Net Cash Flows represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.

The following table provides a reconciliation of our Standardized Measure to PV‑10 (in thousands):

             
    December 31,
    2018   2017
Standardized measure of discounted future net cash flows   $  218,944   $  255,907
Future income taxes, discounted at 10%      1,563      1,376
Pre-tax net present value, discounted at 10%   $  220,507   $  257,283
             

In addition to Adjusted EBITDAX and PV-10, we may provide additional non-GAAP financial measures because our management believes providing investors with this information gives additional insights into our profitability, cash flows and expenses.

Adjusted EBITDAX, PV-10 and other non-GAAP measures in this release are not presentations made in accordance with generally accepted accounting principles, or GAAP.  As discussed above, we believe that the presentation of non-GAAP financial measures in this release is appropriate.  However, when evaluating our results, you should not consider the non-GAAP financial measures in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss).  For example, Adjusted EBITDAX have material limitations as performance measures because it excludes items that are necessary elements of our costs and operations.  Because other companies may calculate Adjusted EBITDAX differently than we do, Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

Guidance for First Quarter 2019

The Company is providing the following guidance for the first calendar quarter of 2019.

     
Production   34,000 - 39,000 Mcfe per day
     
LOE (including transportation and workovers)   $4.7 million - $5.3 million
     
Production and ad valorem taxes (% of Revenue)   3.75 - 4.25%
     
G&A, exclusive of non-cash stock compensation   $4.0 million - $4.5 million
     
DD&A Rate   $2.40 - $2.65
     

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Tuesday, March 19, 2019 at 8:00 am Central Time.  Those interested in participating in the earnings conference call may do so by calling 1-800-230-1085, (International 1-612-234-9959) and entering participation code 465432.  A replay of the call will be available from Tuesday, March 19, 2019 at 10:00am CDT through Tuesday, March 26, 2019 at 11:59pm CDT by calling 1-800-475-6701, (International 1-320-365-3844) and entering participation code 465432.

About Contango Oil & Gas Company

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 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.

Receipt of Audit Opinion with Going Concern Emphasis

As previously disclosed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2018, which was filed with the Securities and Exchange Commission on March 18, 2019, the Company’s audited financial statements contained a going concern explanatory paragraph in the audit opinion from its independent registered public accounting firm. This announcement does not represent any change or amendment to the Company’s financial statements or to its Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Please read our Annual Report on Form 10-K for the year ended December 31, 2018 for more information.

Forward-Looking Statements and Cautionary Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are, based on Contango’s current expectations and includes statements regarding our estimates of future production, and other guidance (including information regarding lease operating expenses, cash G&A expenses, and DD&A Rate), acquisitions and divestitures, 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. Words and phrases used to identify our forward-looking statements include terms such as “guidance”, "expects", “projects”, "anticipates", "plans", "estimates", "potential", "possible", "probable", or "intends", or words and phrases 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; our ability to comply with financial covenants in our debt instruments, repay indebtedness and access new sources of indebtedness, including our ability to refinance and/or replace the existing RBC Credit Facility, provide additional liquidity for future capital expenditures and/or continue as a going concern; fluctuations in oil and gas prices; risks associated with derivative positions; our ability to realize expected value from acquisitions and to complete strategic dispositions of assets and realize the benefits of such dispositions; the need to take impairments on properties due to lower commodity prices; the limited trading volume of our common stock and general market volatility;  ability of our management team to execute its plans or to meet its goals; shortages of drilling equipment, oil field personnel and services; unavailability of gathering systems, pipelines and processing facilities; the possibility that government policies may change or governmental approvals may be delayed or withheld; and the other factors discussed under the “Risk Factors” heading in our annual report on Form 10-K for the year ended December 31, 2018 and our quarterly reports on Form 10-Q filed with or furnished to the Securities and Exchange Commission. Additional information on these and other factors which could affect Contango’s operations or financial results are included in Contango’s 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 speak only as of the date they were made and 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.

Cautionary Statements Regarding Reserves

The estimates and guidance presented in this release are based on assumptions of capital expenditure levels, prices for oil, natural gas and NGLs, current indications of supply and demand for oil, well results and operating costs. IP and other production rates included in this release might not be indicative of production over longer periods in the life of the well. The guidance provided in this release does not constitute any form of guarantee or assurance that the matters indicated will be achieved. While we believe these estimates and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and uncertainties and are subject to material revision. Actual results may differ materially from our estimates and guidance, and we undertake no duty to update these statements.

   
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