Contango Announces Fourth Quarter and Year Ended 2015 Financial Results

March 14, 2016

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HOUSTON–(BUSINESS WIRE)–Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango” or the “Company”) announced today its financial results for the fourth quarter and year ended December 31, 2015.

Fourth Quarter Highlights

  • Production of 8.0 Bcfe for the quarter, or 86.7 Mmcfed; within guidance
  • Adjusted EBITDAX, on a recurring basis, of $11.1 million for the quarter
  • Completion of the Popham #1H well in our North Cheyenne prospect, in Weston County, Wyoming, testing at a peak 24-hour maximum rate of 970 BOEPD
  • Year-end debt of $115.4 million, substantially flat with the third quarter outstanding balance
  • Hedged approximately 60% of forecasted PDP natural gas production for 2016 with a floor price of $2.53/mmbtu

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said, “The current commodity price environment and lower production resulting from a reduced drilling program was responsible for the decrease in our revenues for the current quarter. The impact of lower commodity prices on the impact of reserves also forced us to take additional non-cash impairment charges during the quarter, all of which culminated with a large net loss for the quarter. Despite the challenges caused by these low commodity prices, we remain optimistic about the future of the Company. Before the downturn, and to a lesser extent, during the downturn, we tested new formations and concepts within our portfolio of opportunities and are optimistic about the initial results. We are excited about the potential of the drilling opportunities created, but will not commence any development programs until commodity prices improve. Instead, we will limit our 2016 capital program to very limited drilling and certain lease extensions, and repaying amounts outstanding under our revolver.”

Summary Fourth Quarter Financial Results

Net loss for the three months ended December 31, 2015 was $111.3 million, or $(5.85) per basic and diluted share, compared to a net loss of $19.9 million, or $(1.05) per basic and diluted share, for the same period last year. In addition to lower revenues from lower prices and production, included in the current quarter figure is a $48.2 million non-cash pre-tax impairment charge related to proved and unproved properties; a $30.0 million non-cash pre-tax loss related to our 37% equity investment in Exaro Energy III LLC (“Exaro”) and $5.6 million in other expense related to a forfeited deposit in an unsuccessful acquisition in the fourth quarter of 2015. Fourth quarter of 2014 results included $24.4 million in non-cash impairments. Partially offsetting the decrease in revenues in 2015 were the benefits from cost cutting initiatives on operating expenses, G&A costs and lower depreciation, depletion and amortization (“DD&A”) expense. Excluding the impairment charges for both periods and the forfeited deposit, the net loss, before income tax benefit, was $41.6 million in 2015 compared to a pre-tax net loss of $6.2 million in 2014. Average weighted shares outstanding were approximately 19.0 million for the current and prior year quarters.

The Company reported Adjusted EBITDAX, as defined below, of approximately $5.5 million for the three months ended December 31, 2015, compared to $34.8 million for the same period last year, a decrease mainly attributable to a $28.7 million decrease in revenues and a $5.6 million charge incurred in pursuit of the unsuccessful acquisition, partially offset by a $2.9 million decrease in operating expenses and a $4.2 million decrease in current quarter cash G&A costs. Exclusive of the forfeited deposit, Adjusted EBITDAX would have been $11.1 million for the 2015 quarter.

Revenues for the three months ended December 31, 2015 were approximately $21.5 million compared to $50.2 million for the same period last year. This decrease was primarily due to lower production and a 48% decrease in the weighted average equivalent sales price received.

Production for the fourth quarter of 2015 was approximately 8.0 Bcfe, or 86.7 Mmcfe per day, approximately 18% less than production for the fourth quarter of 2014, but within our previously provided guidance. This decrease in production can be attributed to minimal new production added in 2015 because of a reduced drilling program associated with the low commodity price environment. Crude oil and natural gas liquids production during the fourth quarter of 2015 was approximately 4,600 barrels per day, or 31.7% of total production, compared to approximately 5,600 barrels per day, or 32% of total production, in the fourth quarter of 2014, a decline related to lower capital expenditures in 2015. Our first quarter 2016 production guidance of 77 – 82 Mmcfed reflects the expected impact of a minimal 2016 capital program.

The weighted average equivalent sales price during the three months ended December 31, 2015 was $2.69 per Mcfe, compared to $5.14 per Mcfe for the same period last year, a decrease due to the decline in all commodity prices, as reflected herein.

Operating expenses for the three months ended December 31, 2015 were approximately $7.9 million, or $0.99 per Mcfe, compared to $10.8 million, or $1.11 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.

Lease operating expenses (“LOE”), transportation and processing costs and workover expenses for the three months ended December 31, 2015 were approximately $6.9 million, or $0.87 per Mcfe, which was below our previously provided guidance, compared to approximately $8.6 million, or $0.88 per Mcfe, for the same period last year. We continue to find ways to reduce costs in the field and operate more efficiently, as evidenced by the $1.7 million, or 20% reduction in operating costs. We also managed a decrease in operating costs per Mcfe, an accomplishment that is particularly noteworthy due to the fact that the vast majority of our operating costs are fixed costs and production was 18% lower.

DD&A expense for the three months ended December 31, 2015 was $21.1 million, or $2.65 per Mcfe, compared to $41.3 million, or $4.22 per Mcfe, for the same period last year. This decrease is primarily attributable to the decrease in production during the quarter, and to a lesser extent the decrease in DD&A expense per Mcfe as a result of the recently recorded impairment costs.

Impairment and abandonment expense from oil and gas properties was $48.2 million for the three months ended December 31, 2015. Of this amount, $42.0 million was related to proved properties, primarily in Madison/Grimes and Zavala/Dimmit/Karnes counties in Texas, $4.4 million was related to unproved properties primarily in South Texas, and $1.8 million was related to our Ship Shoal 263 platform.

G&A expenses for the three months ended December 31, 2015 were $3.7 million, or $0.47 per Mcfe, compared to $7.6 million, or $0.77 per Mcfe, for the prior year quarter. G&A expenses for the current and prior year quarters include $1.5 million and $1.2 million, respectively, in non-cash stock compensation expense. In August 2015, we reduced our staff by approximately 30% in our corporate office and implemented a salary replacement program for the remaining employees, where 10% of all base salaries and cash board of director fees were reduced by 10%, and repaid at the end of the year in common stock.

Other items contributing to the reduction in G&A costs for the current quarter were reductions in estimated performance-based bonus payments and franchise taxes of approximately $1.3 million. Additionally, the prior quarter figure included $2.6 million in merger-related costs. For the first quarter of 2016, 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, 2015 was approximately $30.0 million, compared to a gain from affiliates of $2.5 million for the same period last year. Included in the current quarter results was a $43.6 million non-cash impairment associated with Exaro’s oil and gas properties as a result of the recent dramatic decline in commodity prices.

Other expense for the three months ended December 31, 2015 was primarily related to $5.6 million of costs incurred in the pursuit of an unsuccessful acquisition.

2015 Capital Program

Capital costs incurred for the three months ended December 31, 2015 were approximately $3.9 million, which was primarily related to completing the Popham #1H well and drilling the Christensen #1H well in our North Cheyenne project targeting the Muddy Sandstone formation in Wyoming. We have previously provided guidance of a minimal 2016 capital budget focused on limiting capital expenditures to that determined to be warranted from a strategic perspective and in reducing obligations outstanding under our revolver. We retain the financial and operating flexibility, and drilling inventory, to resume an active drilling program if commodity prices improve during the year. See our release dated March 2, 2016.

As of December 31, 2015, we had approximately $115.4 million of debt outstanding under our credit facility with Royal Bank of Canada and other lenders. The credit facility has a borrowing base of $190 million, which was reaffirmed on November 13, 2015 and is effective through May 1, 2016.

2015 Year End Reserves

As previously disclosed in our March 2, 2016 reserves and capital program update, proved reserves at December 31, 2015, as estimated by William M. Cobb & Associates, Inc. and Netherland, Sewell & Associates, Inc., Contango’s independent petroleum engineering firms, in accordance with reserve reporting guidelines mandated by the Securities and Exchange Commission (“SEC”), were 187.2 Bcfe, a 32% decrease over our proved reserves as of December 31, 2014, consisting of 126.1 billion cubic feet of natural gas, 4.8 million barrels of crude oil, and 5.4 million barrels of natural gas liquids, with a present value of proved reserves discounted at 10% (“PV-10”) of $249.4 million. As of December 31, 2015, 68% of our proved reserves were natural gas and 84% were proved developed.


The following table summarizes Contango’s total proved reserves as of December 31, 2015 (1):

Present Value
OIL NGL Gas Total Discounted
Category (MBbl) (MBbl) (Mmcf) (Mmcfe) at 10% ($000)
Developed 2,869 4,354 113,952 157,288 229,807
Undeveloped 1,922 1,040 12,176 29,950 19,599
Total Proved 4,791 5,394 126,128 187,238 249,406

These estimates do not include net reserves of approximately 38.7 Bcfe (PV-10 of approximately $31.3 million) attributable to our 37% equity ownership investment in Exaro as of December 31, 2015.


Derivative Instruments

As previously disclosed in our January 19, 2016 operations update, we recently entered into the following financial derivative contracts with a member of our bank group:

Commodity Period Derivative Volume/Month Price/Unit (1)
Natural Gas Feb 2016 – July 2016 Swap 1,300,000 MMBtu $2.53
Natural Gas Aug 2016 – Oct 2016 Swap 250,000 MMBtu $2.53
Natural Gas Nov 2016 – Dec 2016 Swap 1,300,000 MMBtu $2.53

(1) Commodity price derivatives based on Henry Hub NYMEX natural gas prices.


Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and twelve month periods ended December 31, 2015 and 2014:
Three Months Ended Year Ended
December 31, December 31,
2015 2014 % 2015 2014 %
Offshore Volumes Sold:
Oil and condensate (Mbbls) 42 57 -26 % 191 269 -29 %
Natural gas (Mmcf) 4,172 5,140 -19 % 17,290 19,442 -11 %
Natural gas liquids (Mbbls)   123   132 -7 %   515   571 -10 %
Natural gas equivalents (Mmcfe) 5,159 6,273 -18 % 21,525 24,474 -12 %
Onshore Volumes Sold:
Oil and condensate (Mbbls) 151 214 -29 % 733 1,132 -35 %
Natural gas (Mmcf) 1,282 1,536 -17 % 5,325 6,433 -17 %
Natural gas liquids (Mbbls)   105   113 -7 %   452   437 3 %
Natural gas equivalents (Mmcfe) 2,821 3,498 -19 % 12,436 15,849 -22 %
Total Volumes Sold:
Oil and condensate (Mbbls) 193 271 -29 % 924 1,401 -34 %
Natural gas (Mmcf) 5,454 6,676 -18 % 22,615 25,875 -13 %
Natural gas liquids (Mbbls)   228   245 -7 %   967   1,008 -4 %
Natural gas equivalents (Mmcfe) 7,980 9,771 -18 % 33,961 40,323 -16 %
Daily Sales Volumes:
Oil and condensate (Mbbls) 2.1 2.9 -29 % 2.5 3.8 -34 %
Natural gas (Mmcf) 59.3 72.6 -18 % 61.9 70.9 -13 %
Natural gas liquids (Mbbls)   2.5   2.7 -7 %   2.6   2.8 -4 %
Natural gas equivalents (Mmcfe) 86.7 106.2 -18 % 93.0 110.5 -16 %
Average sales prices:
Oil and condensate (per Bbl) $ 37.99 $ 70.71 -46 % $ 46.80 $ 92.98 -50 %
Natural gas (per Mcf) $ 2.00 $ 3.77 -47 % $ 2.61 $ 4.36 -40 %
Natural gas liquids (per Bbl) $ 14.09 $ 24.26 -42 % $ 14.68 $ 33.27 -56 %
Total (per Mcfe) $ 2.69 $ 5.14 -48 % $ 3.43 $ 6.86 -50 %
Three Months Ended Year Ended
December 31, December 31,
2015   2014   % 2015   2014   %
Offshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.57 $ 0.55 4 % $ 0.63 $ 0.55 15 %
Production and ad valorem taxes $ 0.08 $ 0.10 -20 % $ 0.08 $ 0.10 -20 %
Onshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.40 $ 1.45 -3 % $ 1.58 $ 1.41 12 %
Production and ad valorem taxes $ 0.22 $ 0.46 -52 % $ 0.25 $ 0.57 -56 %
Total Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.87 $ 0.88 -1 % $ 0.97 $ 0.89 9 %
Production and ad valorem taxes $ 0.12 $ 0.23 -46 % $ 0.14 $ 0.28 -50 %
General and administrative expense (cash) $ 0.28 $ 0.65 -57 % $ 0.59 $ 0.73 -19 %
Interest expense $ 0.11 $ 0.06 77 % $ 0.09 $ 0.07 29 %
Adjusted EBITDAX (2)(thousands) $ 5,528 $ 34,808 $ 62,172 $ 197,275
Weighted Average Shares Outstanding (thousands)
Basic 19,016 19,016 18,965 19,059
Diluted 19,016 19,016 18,965 19,059
(1)   LOE includes transportation and workover expenses.
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income (loss).



(in thousands)

December 31, December 31,
2015 2014


(in thousands)
Cash and cash equivalents $


Accounts receivable, net 20,504 25,309
Other current assets 1,768 5,731
Net property and equipment 379,205 748,623
Investments in affiliates and other non-current assets   15,279   63,752
TOTAL ASSETS $ 416,756 $ 843,415


Accounts payable and accrued liabilities 36,358 92,892
Other current liabilities 4,603 4,123
Long-term debt 115,446 63,359
Deferred tax liability

Asset retirement obligations 22,506 21,623
Total shareholders’ equity   237,843   567,466



(in thousands)

Three Months Ended Year Ended
  December 31,   December 31,
  2015     2014   2015     2014
(in thousands)
Oil and condensate sales $ 7,348 $ 19,136 $ 43,230 $ 130,238
Natural gas sales 10,928 25,148 59,058 112,695
Natural gas liquids sales   3,213   5,946   14,217   33,525
Total revenues   21,489   50,230   116,505   276,458
Operating expenses 7,921 10,810 37,840 47,236
Exploration expenses 165 316 11,979 33,387
Depreciation, depletion and amortization 21,109 41,264 133,380 156,117
Impairment and abandonment of oil and gas properties 48,210 24,434 285,877 47,693
General and administrative expenses   3,719   7,560   26,402   34,045
Total expenses   81,124   84,384   495,478   318,478
Gain (loss) from investment in affiliates (net of income taxes) (30,020) 2,536 (30,582) 6,923
Interest expense (849) (581) (3,164) (2,658)
Gain (loss) on derivatives, net 347 1,335 2,348 (153)
Other income (expense)   (5,181)   272   97   124
Total other income (expense)   (35,703)   3,562   (31,301)   4,236
NET LOSS BEFORE INCOME TAXES   (95,338)   (30,592)   (410,274)   (37,784)
Income tax benefit (provision)   (15,933)   10,666   75,226   15,910
NET LOSS $ (111,271) $ (19,926) $ (335,048) $ (21,874)

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, depletion and amortization, and oil & gas expenses. Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below, all of which will be required in determining our compliance with financial covenants under the RBC Credit Facility.

We have included EBITDAX and Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreements. We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results. Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreements. We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX. Non-compliance with the financial covenants contained in these credit agreements could result in a default, an acceleration in the repayment of amounts outstanding and a termination of lending commitments. Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:

  • the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
  • the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
  • our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
  • the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

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

Three Months Ended Year Ended
December 31, December 31,
2015 2014 2015 2014
(in thousands)
Net loss $ (111,271 ) $ (19,926 ) $ (335,048 ) $ (21,874 )
Interest expense 849 581 3,164 2,658
Income tax provision (benefit) 15,933 (10,666 ) (75,226 ) (15,910 )
Depreciation, depletion and amortization 21,109 41,264 133,380 156,117
Exploration expenses   165     316     11,979     33,387  
EBITDAX $ (73,215 ) $ 11,569   $ (261,751 ) $ 154,378  
Unrealized loss (gain) on derivative instruments $ (999 ) $ 363


$ (1,131 )
Non-cash stock-based compensation charges 1,508 1,182 6,516 4,515
Impairment of oil and gas properties 48,214 24,386 285,870 46,396
Loss (gain) on sale of assets and investment in affiliates   30,020     (2,692 )   31,537     (6,883 )
Adjusted EBITDAX $ 5,528   $ 34,808   $ 62,172   $ 197,275  

Guidance for First Quarter 2016

The Company is providing the following guidance for the first calendar quarter of 2016.
First quarter 2016 production 77,000 – 82,000 Mcfe per day
LOE (including transportation and workovers) $7.0 million – $7.5 million
Production and ad valorem taxes 4.5%
(% of Revenue)
Cash G&A $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 15, 2016 at 9:30am CDT. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-877-876-9177, (International 1-785-424-1666) and entering the following participation code: 6445139. A replay of the call will be available from Tuesday, March 15, 2016 at 12:30pm CDT through Tuesday, March 22, 2016 at 12:30pm CDT by dialing toll free 1-888-203-1112, (International 1-719-457-0820) and asking for replay ID code 6445139.

Contango Oil & Gas Company is a Houston, Texas based, independent energy company engaged in the acquisition, exploration, development, exploitation and production of crude oil and natural gas offshore in the shallow waters of the Gulf of Mexico and in the onshore Texas Gulf Coast and Rocky Mountain regions of the United 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.

Category: Oil & Gas