May 9, 2016

Contango Announces First Quarter 2016 Financial Results and Provides Operations Update

HOUSTON--(BUSINESS WIRE)-- Contango Oil & Gas Company (NYSE MKT: MCF) ("Contango" or the "Company") announced today its financial results for the three months ended March 31, 2016 and provided an operational update.

First Quarter Summary

  • Production of 7.2 Bcfe for the quarter, or 79.4 Mmcfed; within guidance
  • Adjusted EBITDAX of $7.3 million for the quarter and net loss of $11.4 million
  • Completion of the Christensen #1H well in our North Cheyenne prospect, in Weston County, Wyoming, with an initial 30 day IP of 483 Boe/d (96% oil)
  • Extended the maturity of our senior credit facility by two years to October 1, 2019 and redetermined borrowing base at $140 million, through November 1
  • Quarter-end debt balance of $112.2 million, a $3.3 million decrease from year-end
  • Hedged approximately 27% of forecasted PDP natural gas production for 2017 with a $2.65 x $3.00 costless collar

Management Commentary

Allan D. Keel, the Company's President and Chief Executive Officer, commented, "We continue to take a conservative approach to this low and uncertain price environment by protecting our financial position through reduced capex and cost reduction efforts. We continued to make progress in efficiencies and cost-cutting measures, as evidenced by a reduction in operating expenses and general and administrative costs for the quarter. Also noteworthy is that we have been successful at reducing our operating costs and general and administrative costs per Mcfe despite lower production. We believe that maintaining our liquidity and balance sheet strength is of utmost importance, and we remain committed to limiting our 2016 capital expenditures to strategic requirements and lease extensions. We will use our excess cash flow to reduce amounts outstanding under our revolver and maintain excess borrowing capacity to be positioned to take advantage of acquisition opportunities that may arise in this uncertain environment.

"We remain optimistic about the future of the Company. We recently began production from our third well targeting the Muddy Sandstone formation in Wyoming and have an inventory of new formations and concepts within our portfolio of opportunities we are anxious to drill once commodity prices improve."

Summary First Quarter Financial Results

Net loss for the three months ended March 31, 2016 was $11.4 million, or $0.60 per basic and diluted share, compared to a net loss of $18.6 million, or $0.98 per basic and diluted share, for the same period last year. This improvement was mainly attributable to cost cutting initiatives on operating expenses and G&A costs, lower exploration expenses and depreciation, depletion and amortization ("DD&A") expense, as well as a gain on derivatives attributable to natural gas hedges for 2016 and a reduction in impairment charges. For the three months ended March 31, 2016, we incurred $1.9 million in non-cash pre-tax impairment charge related to proved and unproved properties, compared to $2.3 million for the same period last year. Partially offsetting the benefits of our cost reduction efforts was a decline in revenues due to lower prices and production.

Excluding the impairment charges for both periods and the gain on derivatives for the current period, net loss, before income tax benefit, was $13.6 million in 2016 compared to a pre-tax net loss of $26.8 million in 2015. Average weighted shares outstanding were approximately 19.1 million and 18.9 million for the current and prior year quarters, respectively.

The Company reported Adjusted EBITDAX, as defined below, of approximately $7.3 million for the three months ended March 31, 2016, compared to $14.0 million for the same period last year, a decrease mainly attributable to a $13.1 million decrease in revenues, partially offset by a $2.3 million decrease in operating expenses and a $2.5 million decrease in current quarter cash G&A costs.

Revenues for the three months ended March 31, 2016 were approximately $17.6 million compared to $30.6 million for the same period last year. This decrease was primarily due to lower production and a 31% decrease in the weighted average equivalent sales price received.

Production for the first quarter of 2016 was approximately 7.2 Bcfe, or 79.4 Mmcfe per day, approximately 17% less than production for the first quarter of 2015, but within our previously provided guidance. This decrease in production can be attributed to minimal new production added in 2015 and 2016 because of a reduced drilling program associated with the low commodity price environment. Crude oil and natural gas liquids production during the first quarter of 2016 was approximately 4,200 barrels per day, or 32% of total production, compared to approximately 5,200 barrels per day, or 32% of total production, in the first quarter of 2015, a decline related to lower capital expenditures in 2015 and 2016. Our second quarter 2016 production guidance of 74-79 Mmcfed reflects the expected impact of a minimal 2016 capital program.

The weighted average equivalent sales price during the three months ended March 31, 2016 was $2.43 per Mcfe, compared to $3.54 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 March 31, 2016 were approximately $7.6 million, or $1.05 per Mcfe, compared to $9.9 million, or $1.14 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 March 31, 2016 were approximately $6.7 million, or $0.93 per Mcfe, which was below our previously provided guidance, compared to approximately $8.8 million, or $1.01 per Mcfe, for the same period last year, a 24% reduction in costs, as we continue to find ways to reduce costs in the field and operate more efficiently. We also achieved an 8% decrease in operating costs per Mcfe, an accomplishment that is particularly noteworthy due to the fact that production was 17% lower and that the majority of our operating costs are fixed costs.

DD&A expense for the three months ended March 31, 2016 was $16.5 million, or $2.29 per Mcfe, compared to $35.1 million, or $4.05 per Mcfe, for the same period last year. This decrease is primarily attributable to the lower production during the quarter and to a decrease in DD&A expense per Mcfe as a result of the impairment of recorded historical costs in 2015.

Impairment and abandonment expense from oil and gas properties was $1.9 million for the three months ended March 31, 2016. Of this amount, approximately $0.7 million was related to impairment of proved properties and $1.1 million was related to impairment of unproved properties primarily in Fayette and Gonzales counties, Texas.

G&A expenses for the three months ended March 31, 2016 were $5.9 million, or $0.82 per Mcfe, compared to $7.8 million, or $0.90 per Mcfe, for the prior year quarter. G&A expenses for the current and prior year quarters include $1.7 million and $1.1 million, respectively, in non-cash stock compensation expense. Excluding the stock expense, cash G&A was 37% lower quarter over quarter. In August 2015, we reduced our staff by approximately 30% in our corporate office and in September 2015, we implemented a retainer fee and salary replacement program for our remaining corporate employees and directors, where each employee's base salary and each director's retainer fee were reduced by 10%. The amount of salary and fee reduction is to be replaced by an award of fully vested shares of common stock in the following year. For the second 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").

Gain from affiliates for the three months ended March 31, 2016 was approximately $40,000, compared to a gain from affiliates of $0.6 million for the same period last year.

2016 Capital Program

Capital costs incurred for the three months ended March 31, 2016 were approximately $3.4 million, which was primarily related to completing the Christensen #1H well in our North Cheyenne project targeting the Muddy Sandstone formation in Wyoming. We have previously announced a minimal 2016 capital budget focused on limiting capital expenditures to that determined to be warranted from a strategic perspective and 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.

Liquidity

As of March 31, 2016, we had approximately $112.2 million of debt outstanding under our credit facility with Royal Bank of Canada and other lenders. Effective May 6, 2016, as part of the regular redetermination schedule, the borrowing base under the RBC Credit Facility was redetermined at $140 million, which reflects the impact of a decline in commodity prices from those used in connection with the last redetermination and our limited capital drilling program. Also effective May 6, 2016, the RBC Credit Facility was amended to, among other things, extend the maturity date of the facility from October 1, 2017 to October 1, 2019, increase the LIBOR, U.S. prime rate and federal funds rate margins to 2.5% - 4.0% and increase the commitment fee to 0.5%, regardless of the amount of the credit facility that is unused.

Derivative Instruments

We have the following financial derivative contracts in place for the remainder of the year:

               
Commodity Period Derivative Volume/Month Price/Unit (1)
 
Natural Gas Apr 2016 - Jul 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.

 

In April 2016, we entered into the following financial derivative contracts with a member of our bank group for 2017:

               
Commodity Period Derivative Volume/Month Price/Unit (2)
 
Natural Gas Jan 2017 - Jul 2017 Collar 400,000 MMBtu $2.65 x $3.00
Natural Gas Aug 2017 - Oct 2017 Collar 200,000 MMBtu $2.65 x $3.00
Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtu $2.65 x $3.00
 

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

 

Drilling Activity Update

We currently have three wells producing in Weston County, Wyoming, targeting the Muddy Sandstone formation. The third well, the Christensen #1H, was drilled to a total measured depth of 13,600 feet, including a 7,000 foot lateral, with 40 frac stages. The well began producing in March 2016 with a 30 day average IP of 483 Boe/d (96% oil), which exceeded the 30 day average IP of each of the first two wells, due to enhanced completion techniques and longer laterals for this well.

We will evaluate the results from these three wells for a number of months, as well as monitor commodity prices, before determining future drilling plans for this area.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three month periods ended March 31, 2016 and 2015:

         
Three Months Ended
  March 31,
2016 2015 %
Offshore Volumes Sold:
Oil and condensate (Mbbls) 51 54 -6%
Natural gas (Mmcf) 3,838 4,659 -18%
Natural gas liquids (Mbbls)   113   132 -14%
Natural gas equivalents (Mmcfe) 4,821 5,781 -17%
 
Onshore Volumes Sold:
Oil and condensate (Mbbls) 134 188 -29%
Natural gas (Mmcf) 1,082 1,211 -11%
Natural gas liquids (Mbbls)   86   91 -5%
Natural gas equivalents (Mmcfe) 2,405 2,883 -17%
 
Total Volumes Sold:
Oil and condensate (Mbbls) 185 242 -24%
Natural gas (Mmcf) 4,920 5,870 -16%
Natural gas liquids (Mbbls)   199   223 -11%
Natural gas equivalents (Mmcfe) 7,226 8,664 -17%
 
Daily Sales Volumes:
Oil and condensate (Mbbls) 2.0 2.7 -24%
Natural gas (Mmcf) 54.1 65.2 -16%
Natural gas liquids (Mbbls)   2.2   2.5 -11%
Natural gas equivalents (Mmcfe) 79.4 96.3 -17%
 
Average sales prices:
Oil and condensate (per Bbl) $ 28.39 $ 44.10 -36%
Natural gas (per Mcf) $ 2.02 $ 2.87 -30%
Natural gas liquids (per Bbl) $ 11.99 $ 14.01 -14%
Total (per Mcfe) $ 2.43 $ 3.54 -31%
 
         
Three Months Ended
March 31,
2016 2015 %
Offshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.51 $ 0.64 -20%
Production and ad valorem taxes $ 0.07 $ 0.08 -13%
 
Onshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.77 $ 1.76 1%
Production and ad valorem taxes $ 0.22 $ 0.23 -4%
 
Total Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.93 $ 1.01 -8%
Production and ad valorem taxes $ 0.12 $ 0.13 -8%
General and administrative expense (cash) $ 0.58 $ 0.77 -25%
Interest expense $ 0.12 $ 0.08 50%
 
Adjusted EBITDAX (2) (thousands) $ 7,264 $ 14,040
 
Weighted Average Shares Outstanding (thousands)
Basic 19,079 18,939
Diluted 19,079 18,939
 
(1) LOE includes transportation and workover expenses.
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income (loss).
 
 
CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

 

     
 
March 31, December 31,
2016 2015

ASSETS

(in thousands)
Cash and cash equivalents $ $
Accounts receivable, net 13,200 20,504
Other current assets 4,092 1,768
Net property and equipment 364,774 379,205
Investments in affiliates and other non-current assets   15,168   15,279
 
TOTAL ASSETS $ 397,234 $ 416,756
 

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts payable and accrued liabilities 30,065 36,358
Other current liabilities 4,444 4,603
Long-term debt 112,182 115,446
Asset retirement obligations 22,830 22,506
Total shareholders' equity   227,713   237,843
 
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 397,234 $ 416,756
 
     
CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
 
Three Months Ended
  March 31,
2016 2015
(in thousands)
REVENUES
Oil and condensate sales $ 5,247 $ 10,694
Natural gas sales 9,935 16,823
Natural gas liquids sales   2,400   3,130
Total revenues   17,582   30,647
 
EXPENSES
Operating expenses 7,604 9,911
Exploration expenses 320 4,483
Depreciation, depletion and amortization 16,545 35,115
Impairment and abandonment of oil and gas properties 1,851 2,281
General and administrative expenses   5,902   7,828
Total expenses   32,222   59,618
 
OTHER INCOME (EXPENSE)
Gain from investment in affiliates (net of income taxes) 40 558
Interest expense (878) (695)
Gain on derivatives, net 4,204
Other expense   (40)   (5)
Total other income (expense)   3,326   (142)
 
NET LOSS BEFORE INCOME TAXES   (11,314)   (29,113)
 
Income tax benefit (provision)   (90)   10,549
 
NET LOSS $ (11,404) $ (18,564)
 

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
  March 31,
  2016   2015
(in thousands)
Net loss $ (11,404) $ (18,564)
Interest expense 878 695
Income tax provision (benefit) 90 (10,549)
Depreciation, depletion and amortization 16,545 35,115
Exploration expenses   320   4,483
EBITDAX $ 6,429 $ 11,180
 
Unrealized gain on derivative instruments $ (2,696) $
Non-cash stock-based compensation charges 1,699 1,140
Impairment of oil and gas properties 1,872 2,270
Gain on sale of assets and investment in affiliates   (40)   (550)
Adjusted EBITDAX $ 7,264 $ 14,040
 

Guidance for Second Quarter 2016

The Company is providing the following guidance for the second calendar quarter of 2016.

       
Second quarter 2016 production 74,000 - 79,000 Mcfe per day
 
LOE (including transportation and workovers) $6.2 million - $6.7 million
 
Production and ad valorem taxes 4.75%
(% of Revenue)
 
Cash G&A $4.0 million - $4.5 million
 
DD&A rate $2.30 - $2.60
 

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Wednesday, May 11, 2016 at 9:30am CDT. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-632-3384, (International 1-785-424-1675) and entering the following participation code: 8365124. A replay of the call will be available from Wednesday, May 11, 2016 at 12:30pm CDT through Wednesday, May 18, 2016 at 12:30pm CDT by registering at https://jsp.premiereglobal.com/webrsvp and using confirmation code 8365124.

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 http://contango.com.

This press release contains forward-looking statements regarding Contango that are intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995, based on Contango's current expectations and includes statements regarding acquisitions and divestitures, estimates of future production, future results of operations, quality and nature of the asset base, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance (often, but not always, using words such as "expects," "projects," "anticipates," "plans," "estimates," "potential," "possible," "probable," or "intends," or stating that certain actions, events or results "may," "will," "should," or "could" be taken, occur or be achieved). Statements concerning oil and gas reserves also may be deemed to be forward-looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those, reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters); uncertainties as to the availability and cost of financing; fluctuations in oil and gas prices; risks associated with derivative positions; inability to realize expected value from acquisitions, inability of our management team to execute its plans to meet its goals, shortages of drilling equipment, oil field personnel and services, unavailability of gathering systems, pipelines and processing facilities and the possibility that government policies may change or governmental approvals may be delayed or withheld. Additional information on these and other factors which could affect Contango's operations or financial results are included in Contango's other reports on file with the Securities and Exchange Commission. Investors are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking statements. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Contango does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.

Contango Oil & Gas Company
E. Joseph Grady, 713-236-7400
Senior Vice President and Chief Financial Officer
or
Sergio Castro, 713-236-7400
Vice President and Treasurer

Source: Contango Oil & Gas Company

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