Mar 15, 2017

Contango Announces Fourth Quarter and Year Ended 2016 Financial Results

HOUSTON, March 15, 2017 (GLOBE NEWSWIRE) -- 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, 2016

Fourth Quarter Highlights

  • Production of 5.9 Bcfe for the quarter, or 64.3 Mmcfed
  • Adjusted EBITDAX, on a recurring basis, of $8.2 million for the quarter
  • Commenced drilling in our newly acquired Pecos County acreage in the Southern Delaware Basin, targeting the Upper Wolfcamp formation
  • Reduced year-end debt outstanding to $54.4 million, a 13% decrease from the third quarter outstanding balance and a 53% decrease from the year-end 2015 outstanding balance
  • Increased hedge position to approximately 50% of forecasted PDP natural gas production for 2017 and 54% of forecasted PDP crude production for 2017
  • Sold non-core onshore Colorado assets for $5.0 million.

Management Commentary

Allan D. Keel, the Company's President and Chief Executive Officer, said "While our reduced capital expenditure program in 2016 led to lower production, which coupled with low commodity prices impacted our results for the quarter, we are excited about the commencement of the development of our Southern Delaware Basin position acquired during the third quarter.  As previously disclosed, the results of our initial well are consistent with those producing in the vicinity, and based on our results on the first well, we have drilled two more wells that are awaiting completion, are currently drilling the fourth well and have exercised our rig option to drill our fifth well.  We will continue to monitor our results, and make appropriate adjustments to the drilling program for the remainder of the year as we go along.  As we noted at the beginning of the year, we possess the flexibility to be more aggressive in the area than our initial budget reflects, should our results and/or commodity prices make that strategy appropriate. The Delaware Basin is one of the few domestic plays that provide return-justified drilling opportunities in the current price environment; and we are optimistic that the increases in production, cash flow and reserves that could come from the development of our current 13,200 gross (6,600, net) operated Southern Delaware Basin position could be very impactful for our shareholders."

Summary Fourth Quarter Financial Results

Net loss for the three months ended December 31, 2016 was $16.8 million, or $(0.69) per basic and diluted share, compared to a net loss of $111.3 million, or $(5.85) per basic and diluted share, for the same period last year, with both quarters impacted by commodity price driven impairment charges. For the fourth quarter 2016, we recorded $6.3 million in impairment charges for non-core undeveloped acreage that we are not likely to drill prior to expiration and $0.4 million in impairment charges related to our 37% equity investment in Exaro Energy III LLC ("Exaro"). Fourth quarter 2015 results included a $48.2 million non-cash pre-tax impairment charge related to proved and unproved properties; a $30.0 million non-cash impairment related pre-tax loss related to Exaro and $5.6 million in other expense related to a forfeited deposit on an unsuccessful acquisition in the fourth quarter of 2015.  Excluding the impairment charges for both periods and the forfeited deposit, the net loss before income tax benefit, was $10.3 million in 2016 compared to a pre-tax net loss of $11.5 million in 2015. Average weighted shares outstanding were approximately 24.6 million and 19.0 million for the current and prior year quarters, respectively. 

The Company reported Adjusted EBITDAX, as defined below, of approximately $8.2 million for the three months ended December 31, 2016, compared to $7.5 million for the same period last year. The 2015 quarter was negatively impacted by the $5.6 million acquisition-related charge incurred during the fourth quarter. The current year quarter reflects a $1.6 million decrease in operating expenses that was more than offset by a $3.7 million increase in current quarter cash G&A costs (discussed below) and a $2.7 million increase in realized loss on derivatives.  Exclusive of the forfeited deposit, Adjusted EBITDAX would have been $13.1 million for the 2015 quarter.

Revenues for the three months ended December 31, 2016 were approximately $21.7 million compared to $21.5 million for the same period last year. Despite lower production during the current quarter, the 21%, 49% and 47% increases in crude oil, natural gas and natural gas liquids prices, respectively helped revenues remain relatively constant.

Production for the fourth quarter of 2016 was approximately 5.9 Bcfe, or 64.3 Mmcfe per day, compared to 86.7 Mmcfe per day for the fourth quarter of 2015, and within our previously provided guidance.  This decrease in production can be attributed to minimal new production added during the year because of dramatically reduced 2015 and 2016 drilling programs in response to the low and uncertain commodity prices during that period, and to a 1.6 Mmcfed impact on the 2016 quarter from the shut-in of two wells in our conventional Liberty County area for workovers.  Crude oil and natural gas liquids production during the fourth quarter of 2016 was approximately 3,080 barrels per day, or 28.8% of total production, compared to approximately 4,600 barrels per day, or 31.7% of total production, in the fourth quarter of 2015, a decline related to the lower capital expenditures in 2015 and 2016.  In February 2017, the compressor on our Eugene Island 11 platform experienced a sudden engine failure resulting in a loss of compression and reduced production from our Dutch and Mary Rose wells for 24 days.  Our first quarter 2017 production guidance of 57.4 - 62.4 Mmcfed reflects the estimated impact of the loss of compression. 

The weighted average equivalent sales price during the three months ended December 31, 2016 was $3.66 per Mcfe, compared to $2.69 per Mcfe for the same period last year.  As previously noted, stronger prices were realized for all commodities.

Operating expenses for the three months ended December 31, 2016 were approximately $6.3 million, or $1.07 per Mcfe, compared to $7.9 million, or $0.99 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, 2016 were approximately $5.9 million, or $1.00 per Mcfe, compared to approximately $6.9 million, or $0.87 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 $1.0 million, or 14% reduction in operating costs quarter over quarter, a 20% decrease compared to the recurring third quarter 2016, and the fact that expenses were below our previously provided guidance for the quarter.   

DD&A expense for the three months ended December 31, 2016 was $13.7 million, or $2.32 per Mcfe, compared to $21.1 million, or $2.65 per Mcfe, for the same period last year.  This decrease is primarily attributable to the decrease in production during the quarter. 

Impairment and abandonment expense from oil and gas properties was $6.3 million for the three months ended December 31, 2016, and was related primarily to the impairment of undeveloped leases in non-core areas. Impairment and abandonment expense from oil and gas properties for the three months ended December 31, 2015 was $48.2 million. Of this amount, $42.0 million was related to proved properties, primarily in Madison/Grimes and Zavala/Dimmit/Karnes counties in Texas and commodity price driven, $4.4 million was related to unproved properties primarily in South Texas, and $1.8 million was related to our Ship Shoal 263 platform that will be decommissioned in 2017.

G&A expenses for the three months ended December 31, 2016 were $8.0 million, or $1.36 per Mcfe, compared to $3.7 million, or $0.47 per Mcfe, for the prior year quarter.  G&A expenses for the current and prior year quarters include $2.1 million and $1.5 million, respectively, in non-cash stock compensation expense. The increase in non-cash stock compensation expense is due in part to the issuance of 2016 long-term incentive compensation to employees during the current quarter (issuance of 2015 long term incentive compensation was made in April 2016). Other items contributing to the increase in G&A costs for the current quarter were a $1.5 million cumulative cash incentive bonus accrual for 2016 and prorata accrual of retention bonuses for certain non-executive employees.  For the first quarter of 2017, we have provided guidance of $5.3 million to $5.9 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, 2016 was approximately $0.3 million, compared to a loss from affiliates of $30.0 million for the same period last year.  Included in the prior quarter results was a $43.6 million non-cash impairment associated with Exaro's proved oil and gas properties as a result of the decline in commodity prices.  

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

2016 Capital Program and Liquidity

Capital costs incurred for the three months ended December 31, 2016 were approximately $12.5 million, which was primarily related to the commencement of drilling in our Southern Delaware Basin acreage in Pecos County, Texas.  We have previously reported a total capital budget for 2017 of approximately $46.3 million, including $36.6 million for drilling/completing wells in Pecos County, Texas.  Consistent with our past philosophy, we plan to initially limit our 2017 capital expenditures to those that are generally funded by internally generated cash flow; however, to the extent that well performance exceeds our expectations, or commodity prices increase meaningfully, we possess the financial flexibility to expand our program during the year.  

As of December 31, 2016, we had approximately $54.4 million of debt outstanding under our credit facility, a 13% decrease from the 2016 third quarter balance and a 53% decrease from the year-end 2015 balance.  Effective October 28, 2016, our $140 million borrowing base under our facility was reaffirmed through May 1, 2017.

2016 Year End Reserves

As previously disclosed in our March 10, 2017 release on reserves and production, proved reserves at December 31, 2016, 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 151.8 Bcfe, a 19% decrease over our proved reserves as of December 31, 2015, consisting of 105.1 billion cubic feet of natural gas, 3.4 million barrels of crude oil, and 4.4 million barrels of natural gas liquids, with a present value of  proved reserves discounted at 10% ("PV-10") of $166 million.  As of December 31, 2016, 69% of our proved reserves were natural gas and 85% were proved developed.

The following table summarizes Contango's total proved reserves as of December 31, 2016(1)

          Present Value
  OIL NGL Gas Total Discounted
Category (MBbl)  (MBbl) (Mmcf) (Mmcfe) at 10% ($000)
Developed   2,158 3,509 95,396 129,399 154,007
Undeveloped 1,266 850 9,657 22,351 12,221
Total Proved 3,424 4,359 105,053 151,750 166,228

(1) These estimates do not include net reserves of approximately 32.6 Bcfe (PV-10 of approximately $20 million) attributable to our 37% equity ownership investment in Exaro as of December 31, 2016.

Derivative Instruments

As previously disclosed in our January 9, 2017 operations update, in December we took advantage of a spike in commodity prices and entered into some additional derivative products, and as of December 31, 2016, had the following financial derivative contracts in place with members of our bank group.  These contracts represent approximately 50% of our forecasted 2017 PDP natural gas production and 54% of our forecasted 2017 PDP crude oil production.

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

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

Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three and twelve month periods ended December 31, 2016 and 2015:

  Three Months Ended  Year ended
  December 31 December 31
   2016 2015 % 2016 2015 %
Offshore Volumes Sold:                  
Oil and condensate (Mbbls)   31   42 -26%   137   191 -28%
Natural gas (Mmcf)   3,369   4,172 -19%   14,211   17,290 -18%
Natural gas liquids (Mbbls)    97   123 -21%   420   515 -18%
Natural gas equivalents (Mmcfe)   4,137   5,159 -20%   17,552   21,525 -18%
Onshore Volumes Sold:                 
Oil and condensate (Mbbls)   96   151 -36%   460   733 -37%
Natural gas (Mmcf)   846   1,282 -34%   3,892   5,325 -27%
Natural gas liquids (Mbbls)   60   105 -43%   296   452 -35%
Natural gas equivalents (Mmcfe)   1,779   2,821 -37%   8,430   12,436 -32%
Total Volumes Sold:                  
Oil and condensate (Mbbls)   127    193 -34%   597   924 -35%
Natural gas (Mmcf)   4,215   5,454 -23%    18,103   22,615 -20%
Natural gas liquids (Mbbls)   157   228 -31%   716    967 -26%
Natural gas equivalents (Mmcfe)   5,916   7,980 -26%   25,982   33,961 -23%
Daily Sales Volumes:                 
Oil and condensate (Mbbls)  1.4  2.1  -34%  1.6  2.5 -35%
Natural gas (Mmcf)  45.8  59.3 -23%  49.5  61.9 -20%
Natural gas liquids (Mbbls)  1.7  2.5 -31%  2.0  2.6 -26%
Natural gas equivalents (Mmcfe)   64.3   86.7 -26%   71.0   93.0 -23%
Average sales prices:                 
Oil and condensate (per Bbl) $ 46.08 $ 37.99 21% $ 38.52 $ 46.80 -18%
Natural gas (per Mcf) $ 2.98 $ 2.00 49% $ 2.42 $ 2.61 -7%
Natural gas liquids (per Bbl) $ 20.76 $ 14.09 47% $ 15.79 $ 14.68 8%
Total (per Mcfe) $  3.66 $ 2.69 36% $ 3.01 $ 3.43 -12%

  Three Months Ended  Year Ended
  December 31 December 31
  2016 2015  % 2016 2015 %
Offshore Selected Costs ($ per Mcfe)                 
Lease operating expenses (1) $ 0.66 $ 0.57 16% $  0.60 $ 0.63 -5%
Production and ad valorem taxes $ 0.05  $ 0.08 -38% $ 0.07 $ 0.08 -13%
Onshore Selected Costs ($ per Mcfe)                
Lease operating expenses (1) $ 1.77 $ 1.40 26% $ 1.81 $ 1.58 15%
Production and ad valorem taxes $ 0.13 $ 0.22 -41% $ 0.25 $ 0.25 0%
Average Selected Costs ($ per Mcfe)                
Lease operating expenses (1) $ 1.00 $ 0.87 15% $ 1.00 $ 0.97  3%
Production and ad valorem taxes $ 0.07 $ 0.12 -42% $ 0.13 $ 0.14 -7%
General and administrative expense (cash) $ 1.00 $ 0.28 257% $ 0.78 $ 0.59 32%
Interest expense $ 0.13 $ 0.11 18% $ 0.15 $ 0.09 67%
Adjusted EBITDAX (2) (thousands) $ 8,159 $ 7,526   $ 30,142 $  62,172  
Weighted Average Shares Outstanding (thousands)                
Basic   24,563   19,016     21,424   18,965  
Diluted   24,563   19,016     21,424   18,965  

(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
  2016 2015
ASSETS (unaudited)
Cash and cash equivalents $ — $ —
Accounts receivable, net   16,727   20,504
Other current assets   2,327   1,768
Net property and equipment   340,382   379,205
Investment in affiliates and other non-current assets   17,078   15,279
TOTAL ASSETS $ 376,514 $ 416,756
Accounts payable and accrued liabilities   55,135    36,358
Other current liabilities   7,754   4,603
Long-term debt   54,354   115,446
Asset retirement obligations   22,618   22,506
Other non-current liabilities   248   —
Total shareholders' equity   236,405   237,843

(in thousands)
  Three Months Ended  Year Ended
   December 31 December 31
  2016  2015   2016  2015 
Oil and condensate sales $ 5,842  $ 7,348  $ 23,006  $ 43,230 
Natural gas sales   12,564    10,928    43,847    59,058 
Natural gas liquids sales   3,257    3,213    11,330    14,217 
Total revenues   21,663    21,489    78,183    116,505 
Operating expenses   6,329    7,921    29,111    37,840 
Exploration expenses   728    165    1,816    11,979 
Depreciation, depletion and amortization   13,737    21,109    63,323     133,380 
Impairment and abandonment of oil and gas properties   6,304    48,210    10,572    285,877 
General and administrative expenses   8,030    3,719     26,802    26,402 
Total expenses   35,128    81,124    131,624     495,478 
Gain (loss) from investment in affiliates, net of income taxes   (257)   (30,020)   1,545    (30,582)
Interest expense   (757)   (849)   (3,802)   (3,164)
Gain on derivatives, net   (2,368)   347    (1,632)   2,348 
Other income (expense)   (65)   (5,181)   (357)   97 
Total other income (expense)   (3,447)   (35,703)   (4,246)   (31,301)
NET LOSS BEFORE INCOME TAXES   (16,912)   (95,338)   (57,687)   (410,274)
Income tax benefit (provision)   68    (15,933)   (342)   75,226 
NET LOSS $ (16,844) $ (111,271) $ (58,029) $ (335,048)

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  Year Ended
  December 31 December 31
   2016  2015  2016   2015 
  (in thousands)
Net loss $ (16,844) $ (111,271) $ (58,029) $ (335,048)
Interest expense   757    849    3,802    3,164 
Income tax provision (benefit)   (68)   15,933    342    (75,226)
Depreciation, depletion and amortization   13,737    21,109    63,323    133,380 
Exploration expenses   728    165    1,816    11,979 
EBITDAX $ (1,690) $ (73,215) $ 11,254  $ (261,751)
Unrealized loss (gain) on derivative instruments $ 1,046  $ 999  $ 3,446  $ — 
Non-cash stock-based compensation charges   2,142    1,508    6,457    6,516 
Impairment of oil and gas properties   6,301    48,214    10,438    285,870 
Loss (gain) on sale of assets and investment in affiliates   360    30,020    (1,453)   31,537 
Adjusted EBITDAX $ 8,159  $ 7,526  $ 30,142  $ 62,172 

Guidance for First Quarter 2017

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

Production 57,400 - 62,400 Mcfe per day
LOE (including transportation and workovers) $6.4 million - $7.0 million
Production and ad valorem taxes (% of Revenue) 5.00%
Cash G&A $5.3 million - $5.9 million
DD&A Rate $2.30 - $2.55

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Thursday, March 16, 2017 at 9:30am Central Daylight Time.  Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-855-5837, (International 1-719-325-4856) and entering the following participation code: 7649977.  A replay of the call will be available from Thursday, March 16, 2017 at 12:30pm CDT through Thursday, March 23, 2017 at 12:30pm CDT by clicking in the audio replay link here, and entering participation code 7649977.

Contango Oil & Gas Company is a Houston, Texas based, independent energy company engaged in the acquisition, exploration, development, exploitation and production of crude oil and natural gas offshore in the shallow waters of the Gulf of Mexico and in the onshore Texas and Rocky Mountain regions of the United States. Additional information is available on the Company's website at

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 Officer Vice President and Treasurer

Primary Logo

Source: Contango Oil & Gas

News Provided by Acquire Media