Contango Announces Fourth Quarter and Six Months Ended December 31, 2013 Financial Results

HOUSTON--()--Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango”) announced today its financial results for the three and six months ended December 31, 2013.

Fourth Quarter 2013 Highlights

  • Consummation of the merger with Crimson Exploration Inc. on October 1, 2013
  • Production of 10.1 Bcfe for the quarter
  • Quarterly Adjusted EBITDAX of $44.4 million
  • Net income of $6.4 million, or $0.34 per basic and fully diluted share
  • Increased proved reserve PV-10 value to $987 million, a 66% increase as compared to December 31, 2012

Management Commentary

Allan D. Keel, President and Chief Executive Officer, commented, “We are pleased with our progress during the fourth quarter, thanks in large part to our merger with Crimson. This merger is an exciting transformational event for the shareholders of both entities and positions the combined company as a financially strong platform for long term growth. The Company now possesses the financial capacity, and opportunity set, to initiate an aggressive drilling program for the foreseeable future. We are off to a good start as we spud seven wells in the recently completed quarter, and completed five of them, with one in progress at year-end. With at least one continuous rig program planned for each of our Buda and Woodbine areas, initial wells in the James Lime formation in East Texas, new concept wells on existing and newly acquired acreage, and one or two exploratory wells in the shallow waters of the Gulf of Mexico, we are excited about the possibilities for 2014 and beyond.”

Summary Quarterly Financial Results

Since our merger closed on October 1, 2013, this is the first quarter reporting the combined results for Contango and Crimson. The results for the six months ended December 31, 2013 include six months of Contango activity (July – December), but only three months of post-merger Crimson activity (October – December). As previously announced, in connection with the merger, our board of directors changed our fiscal year end from June 30 to December 31; therefore, as required by SEC regulations, we have filed a Transition Report on Form 10-K reflecting the results of operations and cash flows for the six month periods ended December 31, 2013 and 2012. As soon as practicable, we intend to file an amendment on Form 10-K/A that will recast our audited financial statements for Contango for the twelve month periods ending December 31, 2013, 2012 and 2011. Since the quarter ended December 31, 2013 results include Crimson results, while the prior year quarter does not, we have taken a limited approach in this release on making period over period comparisons. Unless otherwise noted, the period over period changes for the quarter are primarily a result of the merger.

Net income for the three months ended December 31, 2013 was $6.4 million, or $0.34 per basic and diluted share, compared to net income of $2.6 million, or $0.17 per basic and diluted share for the same period in 2012, which demonstrates the accretive nature of the merger. Average shares outstanding were 19.0 million and 15.2 million for the recently completed and prior year quarters, respectively.

The Company reported Adjusted EBITDAX, as defined below, of $44.4 million for the three months ended December 31, 2013, compared to Adjusted EBITDAX for the same period in 2012 of $27.0 million.

Revenues for the three months ended December 31, 2013 were $66.9 million compared to revenues of $34.9 million for the same period in 2012, a $32.0 million increase attributable almost entirely to Crimson’s operations.

Production for the three months ended December 31, 2013 was approximately 10.1 Bcfe, or 110,200 Mcfe per day, within previously provided guidance. Crude oil and natural gas liquids production during this period was approximately 6,300 barrels per day, or 34% of total production, up from approximately 2,900 barrels per day, or 24% of total production, for the same period in 2012. Offshore production for the 2013 quarter declined by only 4% compared to the prior year quarter, while onshore properties added 3.7 Bcfe (approximately 56% oil/liquids) to the current quarter production totals. The increase in crude and liquids production was attributable to the addition of the Crimson properties and the related focus on the development of its oil and liquids-rich onshore resource plays.

The weighted average equivalent field sales price during the December 2013 quarter was $6.60 per Mcfe, compared to an average equivalent field sales price of $5.23 per Mcfe for the same period in 2012. Field gas prices were approximately 11% higher in the recently completed quarter, while crude oil prices were down by 12%; therefore, the increase in the weighted average prices resulted primarily from the higher percentage mix of crude and liquids production.

Lease operating expenses (“LOE”) for the quarter ended December 31, 2013 were $8.5 million, or $0.84 per Mcfe, compared to $4.1 million, or $0.62 per Mcfe, for the comparable 2012 quarter. The overall increase, and the slight increase in the unit cost, can be attributed to the addition of Crimson’s onshore properties. LOE was above the upper end of guidance due to the exclusion of $1.1 million in incurred offshore insurance costs from guidance. LOE guidance included in this release for the first quarter of 2014 includes LOE, transportation, and offshore insurance costs.

Production and ad valorem tax expenses for the recently completed quarter were $2.3 million, or $0.22 per Mcfe, compared to $0.8 million, or $0.13 per Mcfe, for the comparable 2012 quarter, an increase resulting from higher post-merger revenues and higher tax rates paid on higher crude oil sales revenue.

Exploration costs for the 2013 quarter were $1.6 million, compared to $6.6 million for the same period in 2012 , as the prior year quarter included a portion of the cost of drilling two unsuccessful Gulf of Mexico wells during the third and fourth calendar quarters of 2012.

Depreciation, depletion and amortization (“DD&A”) expense was $33.3 million, or $3.29 per Mcfe, for the recently completed quarter compared to $10.8 million, or $1.60 per Mcfe, for the same period last year, with the increase attributable to the addition of Crimson’s properties and the impact of the purchase price adjustment for recording Crimson’s properties at fair market value.

Impairment of oil and gas properties was zero for the current quarter, compared to $5.7 million in the prior year quarter related to our Ship Shoal 263 property.

General and administrative expenses for the three months ended December 31, 2013 were $14.9 million, or $1.47 per Mcfe, compared to $2.8 million, or $0.42 per Mcfe, for the same period last year. General and administrative expenses, exclusive of $3.2 million in non-cash stock compensation expense and $3.2 million of non-recurring merger related costs, were $8.5 million for the three months ended December 31, 2013 compared to $2.8 million for the same period last year, an increase due to the post-merger combination of the staffs and facilities of both companies. We have provided first quarter 2014 guidance of $8.5 to $9.5 million for general and administrative expenses exclusive of non-cash stock compensation, as we will continue to incur integration costs; however, we expect quarterly costs to decline to $7.0 to $8.0 million for the latter half of 2014.

Gain on sale of assets was $6.3 million in the current quarter, the majority of which was recognizing a gain on the sale of an approximate 7% interest in our Madison/Grimes position to a private company for approximately $20.4 million.

2013 Capital Program

Capital expenditures for the December quarter were $51.6 million, of which $21.8 million was spent drilling the Woodbine formation in Madison County, Texas, $7.0 million was spent drilling the Buda formation in Dimmit County, Texas, $15.0 million was spent exercising a preferential right to acquire an additional interest in our operated offshore Dutch wells at Eugene Island 10, $0.6 million was incurred on completion facilities for our new 2013 offshore well at South Timbalier 17 and $3.6 million was incurred on drilling on our offshore Ship Shoal 255 exploratory prospect currently in process. The remaining $3.6 million was used to acquire and extend leases, and on preliminary work on new concept wells. The results of our quarterly activity were detailed in our February 11, 2014 operations update release.

2013 Year End Reserves

As previously disclosed in our operations update, proved reserves at December 31, 2013, 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 313.9 Bcfe, a 42% increase over our proved reserves as of December 31, 2012, consisting of 207.9 billion cubic feet of natural gas, 9.7 million barrels of crude oil, and 8.0 million barrels of natural gas liquids, with a present value of proved reserves discounted at 10% (“PV-10”) of $987.2 million. As of December 31, 2013, 66% of our proved reserves were natural gas and 81% were proved developed. These estimates do not include net reserves of approximately 41.7 Bcfe (PV-10 of approximately $64 million) attributable to our 37% equity ownership investment in Exaro Energy III LLC ("Exaro") as of December 31, 2013.

The following table summarizes Contango’s total proved reserves as of December 31, 2013:

  Net Reserves   Present Value
Oil   NGL   Gas   Total Discounted
Category (MBBL) (MBBL) (MMCF) (MMCFE) at 10% ($000)
Developed 5,223 6,453 185,535 255,591 794,758
Undeveloped 4,475 1,505 22,395 58,275 192,455
Total Proved 9,698 7,958 207,930 313,866 987,213
 

Liquidity and Capital Resources

In connection with the Crimson merger, we entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”) with an initial hydrocarbon-supported borrowing base of $275 million. The RBC Credit Facility replaced the Company's $40 million facility with Amegy Bank. Proceeds of the RBC Credit Facility may be used (i) to finance working capital and for general corporate purposes, (ii) for permitted acquisitions, and (iii) to finance transaction expenses in connection with the RBC Credit Facility and the merger. As of December 31, 2013, we had $90 million outstanding under the RBC Credit Facility and as of March 3, 2014, we had $70 million outstanding, providing us with approximately $203 million of available capacity (after outstanding letters of credit).

We currently forecast our 2014 capital expenditure program to be $216 million, which we expect to fund through projected cash flow from operations for the year; however, we do possess the capacity, through our RBC Credit Facility, to increase and/or accelerate drilling in any particular area should we determine that market and project economics so warrant. The substantial majority of our planned capital expenditures for 2014 are on acreage that is currently held by existing production, which preserves the flexibility of reducing our capital expenditures, if deemed appropriate. Our 2014 capital budget will be focused primarily on our onshore inventory of crude oil and liquids-rich projects in the Buda and Woodbine formations, complemented by one to two exploratory wells in the shallow waters of the Gulf of Mexico and a few initial tests in new areas and/or new formations in existing areas.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and six month periods ended December 31, 2013 and 2012:

  Three Months Ended   Six Months Ended
December 31, December 31,
  2013     2012   %   2013     2012   %
Offshore Volumes Sold:
Natural gas (Mmcf) 5,010 5,096 -2% 10,200 9,863 3%
Condensate and crude oil (Mbbls) 76 97 -22% 167 199 -16%
Natural gas liquids (Mbbls)   155   168 -8%   302   318 -5%
Natural gas equivalents (Mmcfe) 6,396 6,686 -4% 13,014 12,965 0%
 
Onshore Volumes Sold:
Natural gas (Mmcf) 1,630 n/a - 1,630 n/a -
Condensate and crude oil (Mbbls) 258 n/a - 258 n/a -
Natural gas liquids (Mbbls)   93   n/a -   93   n/a -
Natural gas equivalents (Mmcfe) 3,736 n/a - 3,736 n/a -
 
Total Volumes Sold:
Natural gas (Mmcf) 6,640 5,096 30% 11,830 9,863 20%
Condensate and crude oil (Mbbls) 334 97 244% 425 199 114%
Natural gas liquids (Mbbls)   248   168 48%   395   318 24%
Natural gas equivalents (Mmcfe) 10,132 6,686 52% 16,750 12,965 29%
 
Daily Sales Volumes:
Natural gas (Mmcf) 72.2 55.4 30% 73.1 53.7 20%
Crude oil (Mbbls) 3.6 1.1 244% 3.6 1.1 114%
Natural gas liquids (Mbbls)   2.7   1.8 48%   2.7   1.7 24%
Natural gas equivalents (Mmcfe) 110.1 72.7 52% 111.4 70.4 29%
 
Average sales prices:
Gas $ 3.91 $ 3.53 11% $ 3.79 $ 3.25 17%
Oil $ 94.78 $ 107.20 -12% $ 98.12 $ 105.99 -7%
NGLs $ 37.40 $ 39.04 -4% $ 38.07 $ 36.37 5%
Mcfe $ 6.60 $ 5.23 26% $ 6.07 $ 4.99 22%
 
   
Three Months Ended Six Months Ended
December 31, December 31,
  2013     2012   %   2013     2012   %
Offshore Selected Costs ($ per Mcfe):
Lease operating expenses $ 0.59 $ 0.62 -5% $ 0.66 $ 0.75 -12%
Production and ad valorem taxes $ 0.08 $ 0.13 -38% $ 0.10 $ 0.13 -23%
Depreciation and depletion expense $ 1.74 $ 1.60 9% $ 1.74 $ 1.57 11%
 
Onshore Selected Costs ($ per Mcfe):
Lease operating expenses $ 1.27 n/a - $ 1.27 n/a -
Production and ad valorem taxes $ 0.46 n/a - $ 0.46 n/a -
Depreciation and depletion expense $ 5.95 n/a - $ 5.95 n/a -
 
Average Selected Costs ($ per Mcfe):
Lease operating expenses $ 0.84 $ 0.62 35% $ 0.79 $ 0.75 5%
Production and ad valorem taxes $ 0.22 $ 0.13 69% $ 0.18 $ 0.13 38%
Depreciation and depletion expense $ 3.29 $ 1.60 106% $ 2.67 $ 1.57 70%
General and administrative expense (cash) $ 1.16 $ 0.42 176% $ 0.86 $ 0.42 105%
Interest expense $ 0.12 $ - 100% $ 0.07 $ - 100%
 
Adjusted EBITDAX (1) (thousands) $ 44,431 $ 26,989 $ 70,945 $ 47,872
 
Capital expenditures (thousands)
Property acquisition – proved $ 428,925 $ 101 $ 428,925 $ 102
Leasehold acquisitions $ 4,599 $ 5,443 $ 6,815 $ 14,811
Exploratory $ 5,451 $ 10,082 $ 12,950 $ 44,983
Development $ 27,522 $ 1,714 $ 30,472 $ 6,866
 
 
Weighted Average Shares Outstanding (000)
Basic 19,007 15,198 17,101 15,246
Diluted 19,015 15,198 17,105 15,246
 

(1)

Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).
n/a Not applicable, as the Company had minimal onshore operations prior to the merger with Crimson.
 
 
CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
 
  December 31,   June 30,
  2013   2013

ASSETS

Cash and cash equivalents $ - $ 101,485
Accounts receivable 60,613 36,460
Other current assets 5,504 6,293
Net property and equipment 791,023 368,938
Other non-current assets   53,164   63,285
 
TOTAL ASSETS $ 910,304 $ 576,461

 

LIABILITIES AND STOCKHOLDERS' EQUITY

Accounts payable $ 64,314 $ 31,772
Other current liabilities 34,966 0
Long-term debt 90,000 -
Deferred tax liability 105,956 115,923
Other non-current liabilities 22,019 9,612
Total stockholders’ equity   593,049   419,154
 
TOTAL LIABILITIES & STOCKHOLDERS’ EQUITY $ 910,304 $ 576,461
 
 
CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
 
  Three Months Ended   Six Months Ended
December 31, December 31,
  2013     2012   2013     2012
 
OPERATING REVENUES
Natural gas sales $ 25,973 $ 17,970 $ 44,887 $ 32,047
Condensate and crude oil sales 31,655 10,411 41,699 21,093
Natural gas liquids sales   9,275   6,559   15,039   11,565
Total operating revenues   66,903   34,940   101,625   64,705
 
OPERATING EXPENSES
Lease operating expenses 8,500 4,124 13,282 9,801
Production and ad valorem taxes 2,261 849 3,029 1,634
Exploration expenses 1,642 6,629 1,687 51,614
Depreciation, depletion and amortization 33,284 10,770 44,804 20,336
Impairment and abandonment of oil and gas properties - 5,668 - 14,078
General and administrative   14,891   2,818   17,549   5,398
Total operating expenses   60,578   30,858   80,351   102,861
 
OTHER INCOME (EXPENSE)
Interest income (expense) (1,197) (13) (1,196) 86
Gain on sale of assets 6,323 - 21,961 (271)
Gain from investment in affiliates 907 344 1,577 508
Loss on derivative instruments and other   (1,132)   (160)   (1,132)   -
Total operating expenses   4,901   171   21,210   323
 

INCOME (LOSS) FROM OPERATIONS BEFORE INCOME TAXES

  11,226   4,253   42,484   (37,833)
 
Income tax benefit (provision)   (4,830)   (1,649)   (16,348)   12,888
 
NET INCOME (LOSS) ATTRIBUTABLE $ 6,396 $ 2,604 $ 26,136 $ (24,945)
 

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, 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   Six Months Ended
December 31, December 31,
  2013     2012   2013     2012
 
Net income (loss) $ 6,396 $ 2,604 $ 26,136 $ (24,945)
Interest expense (income) 1,197 13 1,196 (86)
Income tax provision (benefit) 4,830 1,649 16,348 (12,888)
Depreciation, depletion and amortization 33,284 10,770 44,804 20,336
Exploration expenses   1,642   6,629   1,687   51,614
EBITDAX $ 47,349 $ 21,665 $ 90,171 $ 34,031
 
Unrealized loss on derivative instruments $ 1,132 $ - $ 1,132 $ -
Non-cash equity-based compensation charges 3,180 - 3,180 -
Impairment and abandonment of oil and gas properties - 5,668 - 14,078
Loss (gain) on sale of assets or investment in affiliates   (7,230)   (344)   (23,538)   (237)
Adjusted EBITDAX $ 44,431 $ 26,989 $ 70,945 $ 47,872
 

Guidance for First Quarter 2014

The Company is providing the following updated guidance for the first calendar quarter of 2014.

First quarter 2014 production           110,000 – 118,000 Mcfe per day
 
LOE (including scheduled workovers) $8 million - $9 million
 
Production and ad valorem taxes 5%
 
Cash G&A $8.5 million - $9.5 million
 
DD&A rate $3.00 - $3.30
 

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Tuesday, March 4, 2014 at 9:30 a.m. CST. Those interested in participating in the earnings conference call may do so by calling the following phone number: 888-438-5519, (International 719-785-1765) and entering the following participation code 2607605. A replay of the call will be available from Tuesday, March 4, 2014 at 12:30pm CST through Tuesday, March 11, 2014 at 12:30pm CST by dialing toll free 888-203-1112, (International 719-457-0820) and asking for replay ID code 2607605.

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 Gulf Coast regions of the United States and Colorado. 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.

Contacts

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

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Contacts

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