Contango Oil & Gas 8K Contango Announces Fourth Quarter and Year Ended 2014 Financial Results | MCF 3 Mar 15

Exhibit 99.1

Contango oil & gas COMPANY

NEWS RELEASE

Contango Announces Fourth Quarter and Year Ended 2014 Financial Results

MARCH 2, 2015 – HOUSTON, TEXAS – 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, 2014.

Fourth Quarter Highlights

Production of 9.8 Bcfe for the quarter

Adjusted EBITDAX of $34.8 million for the quarter

Initiated pad drilling strategy on Chalktown acreage to enhance recovery and achieve cost efficiencies.

Commenced initial production on Elm Hill project in Fayette and Gonzales Counties, Texas

Spud initial horizontal well on new acreage in Natrona County, Wyoming, targeting the Mowry Shale.

Spud vertical pilot well in South Texas to evaluate the Eagle Ford.

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said “We reduced our drilling activity in the fourth quarter in response to the dramatic downturn in commodity prices. We did, however, continue drilling to test new formations and concepts and are optimistic about the initial results. We recently began production from three wells on our first downspaced multi-well pad drilling strategy at Chalktown, as well as from our first three wells in our Elm Hill project in Fayette and Gonzales Counties, Texas. We spud our initial well in our new FRAMS project in Natrona County, Wyoming targeting the Mowry Shale and will complete the well in March or April once the difficult winter conditions subside. We recently spud our initial well targeting the Muddy Sandstone formation in our North Cheyenne project in Weston County, Wyoming. Additionally, during the fourth quarter we drilled the Beeler Unit 24H as a vertical pilot well to evaluate the Eagle Ford and other formations in Zavala and Dimmit Counties. We are excited about the potential of our new plays, but will not embark on any development programs until commodity prices improve. Instead, we will limit our 2015 capital program to firm commitments and to certain wells designed to test new plays or formations. We anticipate that our capital program will be less than cash flow generated; therefore, that excess will be used to improve our already strong balance sheet. ”

Summary Fourth Quarter Financial Results

Net loss for the three months ended December 31, 2014 was $19.9 million, or $(1.05) per basic and diluted share, compared to net income of $6.4 million, or $0.34 per basic and diluted share, for the same period last year. Included in the current quarter figure is a $24.4 million impairment charge related to

unproved leases in non-core areas and performance declines and lower prices at two non-core producing fields. Other factors contributing to the decrease in net income were lower revenues and higher depreciation, depletion and amortization (“DD&A”) expense, partially offset by a decrease in G&A costs. 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 $34.8 million for the three months ended December 31, 2014, compared to $44.4 million for the same period last year, a decrease mainly attributable to a $16.7 million decrease in revenues, partially offset by a $5.3 million decrease in current quarter cash G&A costs.

Revenues for the three months ended December 31, 2014 were approximately $50.2 million compared to $66.9 million for the same period last year. This decrease was primarily due to slightly lower production and a 22% decrease in the weighted average equivalent sales price received, partially offset by an increase in revenues attributable to exercising a preferential right to purchase additional interests in our Dutch wells in December 2013, and the commencement of production from South Timbalier 17 in July 2014.

Production for the fourth quarter of 2014 was approximately 9.8 Bcfe, or 106.2 Mmcfe per day, approximately 4% less than production for the fourth quarter of 2013 due to minimal new production being added in the second half of 2014 as a result of our change to a multi-well pad drilling strategy in our Chalktown area late in the third quarter of 2014. The change to multi-well pad drilling provides drilling cost efficiencies and overall recovery enhancement; however, the related delay in initial production from the two new three-well pads drilled in September through December precluded us from reflecting an increase in production compared to the prior year quarter. One pad began producing in mid-January and the second pad is expected to begin production in early-March. Further impacting fourth quarter production, and expected production for 2015, was our reduction in drilling activity associated with the dramatic downturn in crude oil and natural gas prices during the fourth quarter. Partially offsetting this decrease in production was incremental production from additional interests in our Dutch wells acquired in December 2013 and new production from our 2013 discovery at South Timbalier 17 which began producing in July 2014. Crude oil and natural gas liquids production during the fourth quarter of 2014 was approximately 5,600 barrels per day, or 32% of total production, compared to approximately 6,300 barrels per day, or 34% of total production, in the fourth quarter of 2013, a decline related to lower capital expenditures in the fourth quarter and the deferral of initial production from fourth quarter drilling at Chalktown. Our first quarter 2015 production guidance of 95-105 Mmcfed reflects the impact of the reduced fourth quarter 2014 and first quarter 2015 capital program (as described herein) due to the low and uncertain commodity price environment.

The weighted average equivalent sales price during the three months ended December 31, 2014 was $5.14 per Mcfe, compared to $6.60 per Mcfe for the same period last year, a decrease due to the decline in all commodity prices over the past few months and a slight decrease in the percentage that oil and liquids represented of total production for the quarter.

Operating expenses for the three months ended December 31, 2014 were approximately $10.8 million, or $1.11 per Mcfe, compared to $10.8 million, or $1.06 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, 2014 were approximately $8.6 million, or $0.88 per Mcfe, compared to approximately $8.5 million, or $0.84 per Mcfe, for the same period last year, a slight increase attributable

to incremental costs associated with compression added at Eugene Island 11 and the addition of South Timbalier 17.

DD&A expense for the three months ended December 31, 2014 was $41.3 million, or $4.22 per Mcfe, compared to $33.3 million, or $3.29 per Mcfe, for the same period last year. This increase is primarily attributable to additional wells brought on-line during the year, including the additional interests purchased in our Dutch wells and the commencement of production on South Timbalier 17.

Impairment and abandonment expense from oil and gas properties was $24.4 million for the three months ended December 31, 2014. Of this amount, $13.0 million was due to the impairment of certain unproved properties due to the estimated decline in the value of leases expiring in the near term and/or not likely to be drilled prior to expiration. The impairment relates primarily to certain portions of our Tuscaloosa Marine Shale acreage position and to our Gulf of Mexico exploratory acreage. Also recorded in the fourth quarter of 2014 was an impairment charge of $11.4 million related to producing properties at South Timbalier 17 and in the Tuscaloosa Marine Shale area, a charge necessitated by performance declines and lower oil and gas prices.

G&A expenses for the three months ended December 31, 2014 were $7.6 million, or $0.77 per Mcfe, compared to $14.9 million, or $1.47 per Mcfe, for the prior year quarter. G&A expenses for the current and prior year quarter, exclusive of $1.2 million and $3.2 million, respectively, in non-cash stock compensation expense, were $6.4 million and $11.7 million, respectively, as the prior year quarter included merger-related costs and costs related to the post-merger combination of staff and facilities of both companies. For the first quarter of 2015, we have provided guidance of $7.3 million to $7.8 million for general and administrative expenses, exclusive of non-cash stock compensation (“Cash G&A”).

2014 Capital Program

Capital expenditures incurred for the three months ended December 31, 2014 were approximately $46.0 million, of which $24.9 million was spent drilling in the Woodbine formation in Madison and Grimes Counties, Texas; $12.1 million spent drilling the Buda formation in Dimmit County, Texas; $4.4 million spent in Wyoming; $3.6 million invested in acreage positions primarily in new areas; and $1.0 million for other capital expenditures. We have previously provided guidance of a reduced 2015 capital budget of approximately $51 million; a budget that is focused on limiting capital expenditures to that determined to be warranted from a strategic perspective and improving our already strong financial position. See our release on February 17, 2015.

As of December 31, 2014, we had approximately $63.4 million of debt outstanding under our credit facility with Royal Bank of Canada and other lenders. The credit facility has a borrowing base of $275 million, which was reaffirmed on October 28, 2014 and through May 1, 2015.

2014 Year End Reserves

As previously disclosed in our February 17, 2015 operations update, proved reserves at December 31, 2014, 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 275.2 Bcfe, a 12% decrease over our proved reserves as of December 31, 2013, consisting of 179.7 billion cubic feet of natural gas, 8.4 million barrels of crude oil, and 7.5 million barrels of natural gas liquids, with a present value of proved reserves discounted at 10% (“PV-10”) of $796.9 million. Exclusive of an approximate 22.4 Bcfe negative revision of proved developed producing reserves at our Eugene Island 11 field, reserves would

have been approximately 5% lower than the prior year reserves, mainly attributable to normal production decline and limited reserve adds during the latter half of 2014 due to a reduction in drilling activity. As of December 31, 2014, 65% of our proved reserves were natural gas and 76% were proved developed. These estimates do not include net reserves of approximately 70.2 Bcfe (PV-10 of approximately $100.6 million) attributable to our 37% equity ownership investment in Exaro Energy III LLC ("Exaro") as of December 31, 2014.

The following table summarizes Contango’s total proved reserves as of December 31, 2014:


					Present Value
	OIL	NGL	Gas	Total	Discounted
Category	(MBbl)	(MBbl)	(Mmcf)	(Mmcfe)	at 10% ($000)
Developed	4,114	5,637	150,235	208,734	657,989
Undeveloped	4,301	1,872	29,416	66,459	138,882
Total Proved	8,415	7,509	179,651	275,193	796,871

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, 2014 and 2013:



		Three Months Ended					Year Ended
		December 31,					December 31,
		2014		2013	%		2014		2013 (1)	%
Offshore Volumes Sold:
Oil and condensate (Mbbls)		57		76	-25%		269		331	-19%
Natural gas (Mmcf)		5,140		5,010	3%		19,442		18,994	2%
Natural gas liquids (Mbbls)		132		155	-15%		571		584	-2%
Natural gas equivalents (Mmcfe)		6,273		6,396	-2%		24,474		24,489	0%

Onshore Volumes Sold:
Oil and condensate (Mbbls)		214		258	-17%		1,132		258	340%
Natural gas (Mmcf)		1,536		1,630	-6%		6,433		1,630	295%
Natural gas liquids (Mbbls)		113		93	22%		437		93	371%
Natural gas equivalents (Mmcfe)		3,498		3,736	-6%		15,849		3,731	325%

Total Volumes Sold:
Oil and condensate (Mbbls)		271		334	-19%		1,401		589	138%
Natural gas (Mmcf)		6,676		6,640	1%		25,875		20,624	25%
Natural gas liquids (Mbbls)		245		248	-1%		1,008		677	49%
Natural gas equivalents (Mmcfe)		9,771		10,132	-4%		40,323		28,220	43%

Daily Sales Volumes:
Oil and condensate (Mbbls)		2.9		3.6	-19%		3.8		3.6	6%
Natural gas (Mmcf)		72.6		72.2	1%		70.9		69.7	2%
Natural gas liquids (Mbbls)		2.7		2.7	0%		2.8		2.6	8%
Natural gas equivalents (Mmcfe)		106.2		110.2	-4%		110.5		107.8	2%

Average sales prices:
Oil and condensate (per Bbl)	$	70.71	$	94.78	-25%	$	92.98	$	101.21	-8%
Natural gas (per Mcf)	$	3.77	$	3.91	-4%	$	4.36	$	3.84	14%
Natural gas liquids (per Bbl)	$	24.26	$	37.40	-35%	$	33.27	$	37.26	-11%
Total (per Mcfe)	$	5.14	$	6.60	-22%	$	6.86	$	5.82	18%

(1) Results for the twelve months ended December 31, 2013 include nine months (January-September) of Contango prior to the Merger with

Crimson, and three months (October-December) of post-merger Contango.


	Three Months Ended			Year Ended
	December 31,			December 31,
	2014	2013	%	2014	2013 (1)	%
Offshore Selected Costs ($ per Mcfe):
Lease Operating Expenses (2)	$ 0.55	$ 0.59	-7%	$ 0.55	$ 1.12	-51%
Production and ad valorem taxes	$ 0.10	$ 0.08	25%	$ 0.10	$ 0.12	-17%
Depreciation and depletion expense	$ 2.39	$ 1.74	37%	$ 2.01	$ 1.77	14%

Onshore Selected Costs ($ per Mcfe):
Lease Operating Expenses (2)	$ 1.45	$ 1.27	14%	$ 1.41	$ 1.27	11%
Production and ad valorem taxes	$ 0.46	$ 0.46	0%	$ 0.57	$ 0.46	24%
Depreciation and depletion expense	$ 7.51	$ 5.95	26%	$ 6.74	$ 5.95	13%

Average Selected Costs ($ per Mcfe):
Lease Operating Expenses (2)	$ 0.88	$ 0.84	5%	$ 0.89	$ 1.14	-22%
Production and ad valorem taxes	$ 0.23	$ 0.22	5%	$ 0.28	$ 0.16	75%
Depreciation and depletion expense	$ 4.22	$ 3.29	28%	$ 3.87	$ 2.32	67%
General and administrative expense (cash)	$ 0.65	$ 1.16	-44%	$ 0.73	$ 0.83	-12%
Interest expense	$ 0.06	$ 0.12	-50%	$ 0.07	$ 0.04	75%

Adjusted EBITDAX (3) (thousands)	$ 34,808	$ 44,431		$ 197,275	$ 113,493

Weighted Average Shares Outstanding (thousands)
Basic	19,016	19,007		19,059	16,156
Diluted	19,016	19,015		19,059	16,158

(1) Results for the twelve months ended December 31, 2013 include nine months (January-September) of Contango prior to the Merger with Crimson, and three months (October-December) of post-merger Contango.

(2) LOE includes transportation and workover expenses.

(3) Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income (loss).

CONTANGO OIL & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)



		December 31,		December 31,
		2014		2013
ASSETS
Cash and cash equivalents	$	—	$	—
Accounts receivable, net		25,309		60,613
Other current assets		5,731		5,504
Net property and equipment		748,623		791,023
Investments in affiliates and other non-current assets		63,752		53,164

TOTAL ASSETS	$	843,415	$	910,304

LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued liabilities		92,892		96,833
Other current liabilities		4,123		2,446
Long-term debt		63,359		90,000
Deferred tax liability		93,952		105,956
Asset retirement obligations		21,623		22,019
Total shareholders’ equity		567,466		593,050

TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY	$	843,415	$	910,304

CONTANGO OIL & GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)



		Three Months Ended				Year Ended
		December 31,				December 31,
		2014		2013		2014		2013 (1)

REVENUES
Oil and condensate sales	$	19,136	$	31,655	$	130,238	$	59,608
Natural gas sales		25,148		25,973		112,695		79,289
Natural gas liquids sales		5,946		9,275		33,525		25,224
Total revenues		50,230		66,903		276,458		164,121

EXPENSES
Operating expenses		10,810		10,761		47,236		36,784
Exploration expenses		316		1,642		33,387		1,811
Depreciation, depletion and amortization		41,264		33,284		156,117		65,529
Impairment and abandonment of oil and gas properties		24,434		-		47,693		776
General and administrative expenses		7,560		14,891		34,045		26,512
Total expenses		84,384		60,578		318,478		131,412

OTHER INCOME (EXPENSE)
Gain from investment in affiliates (net of income taxes)		2,536		907		6,923		2,310
Interest expense		(581)		(1,197)		(2,658)		(1,171)
Gain (loss) on derivatives, net		1,335		(1,132)		(153)		(1,132)
Other income (loss)		272		6,323		124		31,785
Total other income (expense)		3,562		4,901		4,236		31,792

NET INCOME (LOSS) BEFORE INCOME TAXES		(30,592)		11,226		(37,784)		64,501

Income tax benefit (provision)		10,666		(4,830)		15,910		(23,139)

NET INCOME (LOSS)	$	(19,926)	$	6,396	$	(21,874)	$	41,362

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,
		2014		2013		2014		2013 (1)

Net income (loss)	$	(19,926)	$	6,396	$	(21,874)	$	41,362
Interest expense		581		1,197		2,658		1,171
Income tax provision (benefit)		(10,666)		4,830		(15,910)		23,139
Depreciation, depletion and amortization		41,264		33,284		156,117		65,529
Exploration expenses		316		1,642		33,387		1,811
EBITDAX	$	11,569	$	47,349	$	154,378	$	133,012

Unrealized gain on derivative instruments	$	363	$	1,132	$	(1,131)	$	1,132
Non-cash equity-based compensation charges		1,182		3,180		4,515		3,180
Impairment of oil and gas properties		24,386		-		46,396		767
Loss (gain) on sale of assets and investment in affiliates		(2,692)		(7,230)		(6,883)		(24,598)
Adjusted EBITDAX	$	34,808	$	44,431	$	197,275	$	113,493

Guidance for First Quarter 2015

The Company is providing the following guidance for the first calendar quarter of 2015.


First quarter 2015 production	95,000 – 105,000 Mcfe per day

LOE (including transportation and workovers)	$8.3 million – $8.8 million

Production and ad valorem taxes	4.7%
(% of Revenue)
Cash G&A	$7.3 million – $7.8 million

DD&A rate	$4.00 – $4.25

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Tuesday, March 3, 2015 at 9:30am CST. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-389-5997, (International 1-719-325-2332) and entering the following participation code: 7092162. A replay of the call will be available from Tuesday, March 3, 2015 at 12:30pm CST through Tuesday, March 10, 2015 at 12:30pm CDT by dialing toll free 1-888-203-1112, (International 1-719-457-0820) and asking for replay ID code 7092162.

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.

Contact:

Contango Oil & Gas Company

E. Joseph Grady – 713-236-7400Sergio Castro – 713-236-7400

Senior Vice President and Chief Financial OfficerVice President and Treasurer

Contango Oil & Gas (MCF) 8-KContango Announces Fourth Quarter and Year Ended 2014 Financial Results