Nov 7, 2017

Contango Announces Third Quarter 2017 Financial Results and Provides Operational Update

HOUSTON, Nov. 07, 2017 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE MKT:MCF) ("Contango" or the "Company") announced today its financial results for the three and nine months ended September 30, 2017 and provided an operational update. 

Third Quarter Highlights

  • Production of 4.9 Bcfe for the quarter, or 53.2 Mmcfed.
  • Revenues of $18.8 million for the quarter.
  • Adjusted EBITDAX of $7.5 million for the quarter and net loss of $6.9 million.
  • Fourth well brought on production in the Southern Delaware Basin; fifth well awaiting completion.

Summary Third Quarter Financial Results

Net loss for the three months ended September 30, 2017 was $6.9 million, or $0.28 per basic and diluted share, compared to a net loss of $12.5 million, or $0.55 per basic and diluted share, for the same period last year. This improvement was attributable primarily to lower operating expenses due to cost reduction efforts, lower depreciation, depletion, and amortization ("DD&A") expense, no leasehold impairment expense for the current year quarter, and lower general and administrative expenses, partially offset by a decrease in revenues and a decrease in the mark to market valuation of our commodity price hedges. Average weighted shares outstanding were approximately 24.7 million and 22.9 million for the current and prior year quarters, respectively. 

Revenues for the current quarter were approximately $18.8 million compared to $19.6 million for the 2016 quarter, a slight decrease attributable to lower production resulting from a very limited 2016 drilling program and non-core property sales, partially offset by higher commodity prices.   

The Company reported Adjusted EBITDAX, as defined below, of approximately $7.5 million for the current quarter, compared to $4.6 million for the same period last year, an improvement attributable to a decrease in operating expenses, a decrease in cash G&A expenses, and a realized gain during the current quarter on our commodity price hedges, partially offset by the slight decrease in revenues.

Production for the third quarter of 2017 was approximately 4.9 Bcfe, or 53.2 Mmcfe per day, compared to 65.7 Mmcfe per day for the third quarter of 2016.  This decrease was attributable to a 12.9 Mmcfed decrease in production resulting from normal field decline and the limited 2016 drilling program; a 1.6 Mmcfed impact for the quarter from downtime associated with Hurricane Harvey, and a 1.2 Mmcfed impact from non-core property sales, offset in part by 3.2 Mmcfed of new production from our Southern Delaware Basin drilling program.

Crude oil and natural gas liquids production during the third quarter of 2017 was approximately 2,800 barrels per day, or 32% of total production, compared to approximately 3,200 barrels per day, or 29% of total production, in the third quarter of 2016. Natural gas production during the current quarter was approximately 36.0 Mmcf per day, or 68% of total production, compared to approximately 46.7 Mmcf per day, or 71% of total production, in the prior year quarter.  Our production guidance for the fourth quarter of 2017 is 50 - 55 Mmcfed, with the midpoint flat with the third quarter; however, we expect production from three new wells to commence in early 2018.

The weighted average equivalent sales price during the three months ended September 30, 2017 was $3.84 per Mcfe, compared to $3.24 per Mcfe for the same period last year, as we experienced increases of 11%, 4% and 52% in crude oil, natural gas and natural gas liquids prices, respectively compared to the prior year quarter. 

Operating expenses for the current year quarter were approximately $7.0 million, or $1.44 per Mcfe, compared to $8.2 million, or $1.35 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 $6.4 million, or $1.31 per Mcfe, compared to approximately $7.4 million, or $1.23 per Mcfe, for the prior year quarter, due to higher minimum volume charges in 2016 for an ongoing throughput deficiency in our Madisonville Field. Our guidance for operating expenses for the fourth quarter of 2017, exclusive of production and ad valorem taxes, is between $6.5 to $7.0 million, relatively flat with the most recent quarter.        

DD&A expense for the three months ended September 30, 2017 was $11.2 million, or $2.28 per Mcfe, compared to $15.2 million, or $2.51 per Mcfe, for the prior year quarter, a decrease primarily attributable to lower production during the quarter. 

No leasehold impairment expense was recorded for the current quarter.  Impairment and abandonment expense of oil and gas properties for the prior year quarter was $1.2 million, with substantially all of that related to non-core, unproved properties and prospects in Fayette and Gonzales counties, Texas.     

Total G&A expenses, inclusive of non-cash stock compensation expense, were $6.2 million, or $1.27 per Mcfe, for the current quarter, compared to $7.5 million, or $1.24 per Mcfe, for the prior year quarter.  G&A expenses for the current and prior year quarters, exclusive of $1.5 million and $1.3 million, respectively, in non-cash stock compensation expense, were $4.7 million and $6.2 million, respectively.  G&A expenses were higher for the prior year quarter due to payout of the terminated 2016 10% Salary Replacement Program and a catch-up bonus accrual as a result of improved actual results, i.e. vs goals, under the 2016 performance-based bonus plan. For the fourth 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) was approximately $0.5 million for the three months ended September 30, 2017 and 2016.   

2017 Capital Program

Capital costs incurred for the three months ended September 30, 2017 were approximately $10.8 million, primarily including $1.4 million in leasehold acquisition costs and $9.3 million for the drilling and completion of wells in the Southern Delaware Basin in Pecos County, Texas.  As of September 30, 2017, our capital  expenditure  forecast for  all of 2017 is projected to be between $45 and $50 million, including $36.4 million to drill and/or complete eight horizontal gross wells (3.7 net), a vertical pilot well, a saltwater disposal well and central facilities, all in our Southern Delaware Basin position.

As of September 30, 2017, we had approximately $79.2 million of debt outstanding under our credit facility. 

Derivative Instruments

We have the following financial derivative contracts in place at September 30, 2017:

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

Subsequent to the end of the current quarter, we entered into the following financial derivative contracts for a portion of our currently forecasted PDP production for 2018 and 2019:

Commodity Period Derivative Volume/Month Price/Unit (2)
Natural Gas  Jan 2018 - Jul 2018 Swap 370,000 MMBtu $3.07
Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtu $3.07
Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtu $3.07
Oil Jan 2018 - June 2018 Swap 20,000 Bbls $56.40
Oil July 2018 - Oct 2018 Collar 20,000 Bbls $52.00 - 56.85
Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $52.00 - 56.85
Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $50.00 - 58.00

(1) For our 2017 hedges, commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable. For our 2018 and 2019 hedges, commodity price derivatives are based on Henry Hub NYMEX natural gas prices and Argus Louisiana Light Sweet oil prices, as applicable. 

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

  Three Months Ended  Nine months ended
  September 30 September 30
  2017 2016 % 2017 2016 %
Offshore Volumes Sold:                 
Oil and condensate (Mbbls)   23   19 21%   78   106 -26%
Natural gas (Mmcf)   2,702   3,327 -19%   8,618   10,841 -21%
Natural gas liquids (Mbbls)   87   99 -12%   254   323 -21%
Natural gas equivalents (Mmcfe)   3,360   4,035 -17%   10,608   13,415 -21%
Onshore Volumes Sold:                 
Oil and condensate (Mbbls)   109   100 9%   310   364 -15%
Natural gas (Mmcf)   613   968 -37%   2,032   3,048 -33%
Natural gas liquids (Mbbls)   45   74 -39%   143   237 -40%
Natural gas equivalents (Mmcfe)   1,541   2,012 -23%   4,751   6,651 -29%
Total Volumes Sold:                 
Oil and condensate (Mbbls)   132   119 11%   388   470 -17%
Natural gas (Mmcf)   3,315   4,295 -23%   10,650   13,889 -23%
Natural gas liquids (Mbbls)   132   173 -24%   397   560 -29%
Natural gas equivalents (Mmcfe)   4,901   6,047 -19%   15,359   20,066 -23%
Daily Sales Volumes:                  
Oil and condensate (Mbbls)  1.4  1.3 11%  1.4  1.7 -17%
Natural gas (Mmcf)  36.0   46.7 -23%  39.0  50.6 -23%
Natural gas liquids (Mbbls)  1.4  1.9 -24%  1.5  2.0 -29%
Natural gas equivalents (Mmcfe)   53.2   65.7 -19%   56.3   73.2 -23%
Average sales prices:                 
Oil and condensate (per Bbl) $ 46.30 $ 41.63 11% $ 46.76 $ 36.49 28%
Natural gas (per Mcf) $ 2.92 $ 2.80 4% $ 3.00 $ 2.25 33%
Natural gas liquids (per Bbl) $ 22.98 $ 15.10 52% $ 21.26 $  14.40 48%
Total (per Mcfe) $ 3.84 $ 3.24 19% $ 3.81 $ 2.82 35%


  Three Months Ended  Nine Months Ended
  September 30  September 30
  2017 2016 %  2017 2016 %
Offshore Selected Costs ($ per Mcfe)                
Lease operating expenses (1) $ 0.83 $ 0.75 11% $ 0.75 $ 0.58 29%
Production and ad valorem taxes $ 0.05 $ 0.06 -17% $ 0.06 $ 0.07 -14%
Onshore Selected Costs ($ per Mcfe)                
Lease operating expenses (1) $ 2.36 $ 2.18 8% $ 2.17 $ 1.83 19%
Production and ad valorem taxes $ 0.30  $ 0.25 20% $ 0.30 $ 0.28 7%
Average Selected Costs ($ per Mcfe)                
Lease operating expenses (1) $ 1.31 $  1.23 7% $ 1.19 $ 1.00 19%
Production and ad valorem taxes $ 0.13 $ 0.12 8% $ 0.13  $ 0.14 -7%
General and administrative expense (cash) $ 0.97 $ 1.02 -5% $ 0.92 $ 0.72 28%
Interest expense $ 0.23 $ 0.16 44% $ 0.18  $ 0.15 20%
Adjusted EBITDAX (2) (thousands) $ 7,489  $ 4,617   $ 24,874 $ 21,983  
Weighted Average Shares Outstanding (thousands)                 
Basic   24,708   22,881     24,662   20,370  
Diluted   24,708   22,881     24,662   20,370  

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

(in thousands)

  September 30 December 31
  2017 2016
ASSETS (unaudited)
Cash and cash equivalents $ — $ —
Accounts receivable, net   11,757   16,727
Other current assets   2,226   2,327
Net property and equipment   342,615   340,382
Investment in affiliates and other non-current assets   19,196   17,078
TOTAL ASSETS $ 375,794 $ 376,514
Accounts payable and accrued liabilities   45,401   55,135
Other current liabilities   4,098   7,754
Long-term debt   79,226   54,354
Asset retirement obligations   18,082   22,618
Other non-current liabilities   248   248
Total shareholders' equity   228,739   236,405

(in thousands)

  Three Months Ended  Nine Months Ended
  September 30 September 30
  2017  2016  2017  2016 
Oil and condensate sales $ 6,109  $ 4,946  $ 18,134  $ 17,164 
Natural gas sales   9,681    12,011    31,956    31,283 
Natural gas liquids sales   3,040    2,619    8,440    8,073 
Total revenues   18,830    19,576    58,530     56,520 
Operating expenses   7,041    8,158    20,203    22,782 
Exploration expenses   315    444    690    1,088 
Depreciation, depletion and amortization   11,193    15,166    35,678    49,586 
Impairment and abandonment of oil and gas properties   84    1,165    1,515    4,268 
General and administrative expenses   6,219    7,486    18,648    18,772 
Total expenses   24,852    32,419    76,734     96,496 
Gain from investment in affiliates, net of income taxes   525    467    2,475    1,802 
Gain (loss) from sale of assets   (184)   11    2,336    11 
Interest expense   (1,138)   (989)   (2,822)   (3,045)
Gain (loss) on derivatives, net   (9)   913     4,574    736 
Other income (expense)   —    7    (27)   (303)
Total other income (expense)   (806)   409    6,536    (799)
NET LOSS BEFORE INCOME TAXES   (6,828)   (12,434)   (11,668)   (40,775)
Income tax provision   (88)   (51)   (397)   (410)
NET LOSS $ (6,916) $ (12,485) $ (12,065) $ (41,185)

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  Nine Months Ended
  September 30 September 30
   2017  2016  2017   2016 
  (in thousands)
Net loss $ (6,916) $ (12,485) $ (12,065) $ (41,185)
Interest expense   1,138    989    2,822    3,045 
Income tax provision   88    51    397    410 
Depreciation, depletion and amortization   11,193    15,166    35,678    49,586 
Exploration expense   315    444    690    1,088 
EBITDAX $ 5,818  $ 4,165  $ 27,522  $ 12,944 
Unrealized loss (gain) on derivative instruments $ 530  $ (1,532) $ (3,797) $ 2,400 
Non-cash stock-based compensation charges   1,482    1,337    4,560    4,315 
Impairment of oil and gas properties   —    1,125    1,400    4,137 
Gain on sale of assets and investment in affiliates   (341)   (478)    (4,811)   (1,813)
Adjusted EBITDAX $ 7,489  $ 4,617  $ 24,874  $ 21,983 

Drilling Activity Update

The derisking and development of our Southern Delaware Basin acreage in Pecos County, Texas continued through the third quarter of 2017.  Specific highlights, through the date of this release, were as follows:


As previously disclosed, the Gunner #2H well (50%WI, 37.5%NRI) was drilled to a TMD of 20,430 feet, including a 10,600 foot lateral into the Lower Wolfcamp A.  The well was completed with 50 stages of fracture stimulation in June, with initial flowback commencing in early August.  The well reached a gross maximum 3-stream 24-hour IP rate of 1,348 Boed (77% oil) with a 30 day average of 1,152 Boed (76% oil), which represents our best performance to date.  

We have now tested multiple landing points within the Wolfcamp A bench and believe we have proven at least two benches for development within the Wolfcamp A across our acreage position. Each well we have drilled has shown progressively better production performance than the previous due to enhancements to completion and flowback techniques. We will continue to evaluate and enhance our leasehold with an eye toward future drilling into the Bone Springs and the Wolfcamp B zone. We remain very optimistic about these future benches in light of recent activity around our position.


The Crusader #1H well (40%WI, 30.3%NRI) was spud in June 2017 targeting the Lower Wolfcamp A. The well was drilled to a TMD of 20,275 feet, including a 10,184 foot lateral. Completion operations with 50 stages of fracture stimulation are expected to commence in early January 2018

Ragin Bull

The Ragin Bull #1H (47.3%WI, 35.5% NRI) was spud in September 2017 targeting the Wolfcamp formation to satisfy lease considerations and we are currently in the lateral section.

Guidance for Fourth Quarter 2017

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

Production 50,000 - 55,000 Mcfe per day
LOE (including transportation and workovers) $6.5 million - $7.0 million
Production and ad valorem taxes (% of Revenue) 3.5% - 4.0%
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 Wednesday, November 8, 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: 1-877-830-2649, (International 1-785-424-1824) and entering the following participation code: 3051447.  A replay of the call will be available from Wednesday, November 8, 2017 at 12:30pm CST through Wednesday, November 15, 2017 at 12:30pm CST by clicking on the audio replay link here, and entering participation code 3051447.

Contango Oil & Gas Company is a Houston, Texas based, independent energy company whose business is to maximize production from its shallow offshore Gulf of Mexico properties and onshore properties in Texas and Wyoming, and to use that cash flow to explore, develop, exploit, produce and acquire crude oil and natural gas properties in the Texas and Rocky Mountain regions of the United States. Additional information is available on the Company's website at

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 - 713-236-7400Sergio Castro - 713-236-7400
Senior Vice President and Chief Financial OfficerVice President and Treasurer

Source: Contango Oil & Gas

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