Edgar Filing: CONTANGO OIL & GAS CO

form8k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8–K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of Earliest Event Reported): November 10, 2014

CONTANGO OIL & GAS COMPANY

(Exact Name of Registrant as Specified in Charter)

Delaware

(State or Other Jurisdiction of Incorporation)

001-16317

(Commission File Number)

95-4079863

(IRS Employer Identification No.)

717 Texas Ave., Suite 2900, Houston Texas 77002

(Address of Principal Executive Offices)

(713) 236-7400

(Registrant’s telephone number, including area code)

_____________________________________________________________________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 14d-2(b))

[] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02

Results of Operations and Financial Condition.

On November 10, 2014, Contango Oil & Gas Company issued a press release providing its financial and operational results for the three and nine months ended September 30, 2014. A copy of the press release is attached hereto as Exhibit 99.1.

Contango Oil & Gas held an earnings conference call on November 11, 2014, to discuss financial and operational results for the third quarter ended September 30, 2014. A copy of the transcript of the earnings conference call is attached as Exhibit 99.2 to this current report on Form 8-K.

As provided in General Instruction B.2. of Form 8-K, the information furnished pursuant to Item 2.02 in this report on Form 8-K (including the press release attached as Exhibit 99.1 incorporated by reference in this report) shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01 Financial Statements and Exhibits.

(d)

Exhibits

Exhibit Number	Description
99.1	Press Release dated November 10, 2014
99.2	Transcript of Earnings Conference Call dated November 11, 2014 (furnished herewith)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.

	CONTANGO OIL & GAS COMPANY

Date: November 12, 2014	/s/ E. Joseph Grady
	E. Joseph Grady
	Senior Vice President and Chief Financial Officer

Exhibit Index

Exhibit Number	Description
99.1	Press Release dated November 10, 2014
99.2	Transcript of Earnings Conference Call dated November 11, 2014 (furnished herewith)

EXHIBIT 99.1

Contango Announces Third Quarter 2014 Financial Results and Provides Operations Update

November 10, 2014 - HOUSTON--(BUSINESS WIRE)-- Contango Oil & Gas Company (NYSE MKT: MCF) ("Contango") announced today its financial results for the three months ended September 30, 2014 and provided an operational update.

Third Quarter 2014 Highlights

·	Production of 9.4 Bcfe for the quarter

·	Net income of $3.7 million and Adjusted EBITDAX of $47.7 million for the quarter

·	Commenced initial production at South Timbalier 17, our 2013 offshore discovery

·	Installed compression at Eugene Island Block 11 for our Dutch and Mary Rose wells

·	Spud initial horizontal well in newly acquired 53,200 gross (23,700 net) acre position in our Elm Hill project in Fayette County, Texas

·	Acquisition of the right to earn approximately 49,000 gross (44,000 net) acres in our North Cheyenne project in Weston County, Wyoming, targeting multiple formations, including the Muddy Sandstone formation

·	Reaffirmed our borrowing base of $275 million, through May 1, 2015

Management Commentary

Allan D. Keel, the Company's President and Chief Executive Officer, said "We are excited to begin drilling in our new prospective resource plays. To date we have spud two wells in our new Elm Hill project in Fayette County, Texas and have just spud our initial well in our new FRAMS project in Natrona County, Wyoming targeting the Mowry Shale. We expect to spud our initial well targeting the Muddy Sandstone formation in our North Cheyenne project in Weston County, Wyoming in late December or early January 2015. We are excited about the potential from these plays as a complement to our liquids-focused resource strategy currently focused on the Woodbine and Buda in Madison and Dimmit Counties, Texas, respectively. Since the beginning of the quarter we have brought two wells on-line in the Woodbine and have initiated a downspaced pad concept at Chalktown, where an additional four wells are in various stages of drilling or completion. In the Buda, we have brought five wells on-line since the beginning of the quarter, while an additional two are in various stages of drilling or completion."

Summary Financial Results for the Quarter Ended September 30, 2014

The results for the three months ended September 30, 2014 include the effect of the Company's October 1, 2013 merger with Crimson Exploration Inc. ("Crimson"), while the results for the three months ended September 30, 2013 include only the results of Contango.

Net income for the three months ended September 30, 2014 was $3.7 million, or $0.19 per basic and diluted share, compared to net income of $19.7 million, or $1.30 per basic and diluted share, for the same period last year. Included in the prior year figure is a $15.6 million pre-tax gain from our investment in Alta Resources. The remaining decrease in net income was primarily attributable to a $29.0 million pre-tax increase in depreciation, depletion and amortization ("DD&A"), an $8.2 million increase in operating expenses and a $4.2 million increase in general and administrative

("G&A") costs associated with our expanded asset base and organization subsequent to our merger with Crimson, partially offset by a $32.8 million increase in revenues. Revenues for the current year quarter were negatively impacted by an estimated $12.1 million related to the shut-in of our Eugene Island 11 platform for compressor installation. Average weighted shares outstanding were approximately 19.1 million and 15.2 million for the current and prior year quarters, respectively.

The Company reported Adjusted EBITDAX, as defined below, of approximately $47.7 million for the three months ended September 30, 2014, compared to $26.6 million for the same period last year. Crimson's field operations contributed $33.8 million to the current quarter, offset in part by the above mentioned impact of the shut-in at Eugene Island 11 and higher post-merger G&A costs.

Revenues for the three months ended September 30, 2014 were approximately $67.6 million compared to $34.7 million for the same period last year. This increase was primarily due to the addition of Crimson's operations which contributed $41.9 million in additional revenues, partially offset by the estimated $12.1 million decrease in Contango's revenues due to the shut-in at Eugene Island 11.

Production for the three months ended September 30, 2014 was approximately 9.4 Bcfe, or 102.3 Mmcfed, which was within our previously provided guidance. This 42% increase over production for the same period last year, despite the shut in at Eugene Island 11 (estimated 17.9 Mmcfed impact for the quarter), was attributable primarily to the addition of Crimson's operations, new production from our 2014 drilling program, additional interests in our Dutch wells acquired in December 2013 and new production from our 2013 discovery at South Timbalier 17 that began producing in the current year quarter. Our Dutch and Mary Rose wells at Eugene Island were shut in completely for approximately three weeks during the current quarter to install compression, with reduced production rates over several days as the area was restored to full production at 99% of pre-shut in rates. Crude oil and natural gas liquids production during the third quarter was approximately 6,900 barrels per day, or 40% of total production, up from approximately 2,600 barrels per day, or 22% of total production for the same period last year, an increase attributable to the addition of the Crimson properties and the subsequent focus on the development of our oil and liquids-rich onshore resource plays. For the fourth quarter of 2014, we estimate our production will be 105 - 115 Mmcfed. Guidance for the fourth quarter is less than the shut-in adjusted actual production for the third quarter due to drilling-related interference in three wells in our Buda play and due to the Company initiating a pad drilling strategy in the fourth quarter in our Chalktown area, thereby resulting in no new production during the quarter from that drilling. When drilling from pads, three wells are drilled in succession, those wells are then completed in succession, and then all three are put on production simultaneously to maximize recovery. It is anticipated that initial production will occur in January 2015.

The weighted average equivalent sales price during the three months ended September 30, 2014 was $7.17 per Mcfe, compared to $5.24 per Mcfe for the same period last year. The increase in the weighted average equivalent prices resulted from a higher percentage mix of crude and liquids production to total production, as well as from an increase in natural gas prices, which accounted for 60% of our volumes. The impact from the increase in liquids mix and higher gas prices was partially offset by lower oil and condensate prices during the current quarter.

Operating expenses for the three months ended September 30, 2014 were approximately $13.8 million, or $1.47 per Mcfe, compared to $5.6 million, or $0.84 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, all of which increased as a result of our expanded operations and increased production subsequent to our merger with Crimson.

Lease operating expenses ("LOE"), transportation and processing costs and workover expenses for the three months ended September 30, 2014 were approximately $10.6 million, or $1.13 per Mcfe, compared to approximately $4.8 million, or $0.72 per Mcfe, for the same period last year. Current quarter expense was slightly outside of our previously provided guidance due to higher than expected offshore transportation costs.

Exploration costs for the three months ended September 30, 2014 included a $5.2 million credit related to the adjustment of estimated costs accrued in the previous quarter for our unsuccessful Ship Shoal 255 well, including credits negotiated with certain service providers.

DD&A expenses for the three months ended September 30, 2014 were $40.6 million, or $4.31 per Mcfe, compared to $11.5 million, or $1.71 per Mcfe, for the same period last year. This increase is primarily attributable to the incremental production from Crimson's properties, and an increase in the DD&A rate resulting from higher costs associated with onshore oil plays and the impact of purchase price accounting related to the merger.

Impairment and abandonment expense from oil and gas properties was $6.7 million for the three months ended September 30, 2014 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 prospects.

G&A expenses for the three months ended September 30, 2014 were $6.8 million, or $0.72 per Mcfe, compared to $2.7 million, or $0.40 per Mcfe, for the prior year quarter. G&A expenses for the quarter, exclusive of $1.2 million in non-cash stock compensation expense were $5.6 million, compared to $2.7 million for the same period last year, an increase due to the post-merger combination of the staffs and facilities of both companies. This was below our previously provided guidance due to lower than projected legal and compensation costs. For the fourth quarter of 2014, we have provided guidance of $6.5 million to $7.5 million for general and administrative expenses, exclusive of non-cash stock compensation ("Cash G&A").

Drilling Activity Update

Onshore Activity

Southeast Texas (Woodbine)

Chalktown Area, Madison County, Texas

Our drilling efforts in Madison and Grimes counties this quarter were concentrated in the Chalktown Area and focused on the Woodbine/Lewisville. Our quarterly results and current activity in the Chalktown Area consist of the following. We anticipate keeping two rigs in this area for the remainder of the year, and have commenced a pad drilling strategy on 500 foot spacing:

Well

WI%

Total Measured

Depth (ft.)

Lateral (ft.)

Frac Stages

Status/First

Production

30 Day Avg IP

(boed)

% Oil

Dean 1H

70%

16,194

6,737

July 2014

927

79%

Heath Unit A 1H

70%

16,358

7,050

Evaluating

not yet available

Vick Trust B 2H

68%

TBD

Drilled

TBD

Barr Unit A 2H

50%

TBD

Drilling - 9,300'

TBD

Vick Trust B 5H

68%

TBD

Drilling - 9,200'

TBD

* Previously reported

Iola/Grimes Area, Grimes County, Texas

We brought one well online in Grimes County during the quarter that was spud during the second quarter. We currently expect the arrival of a third rig (in addition to the two rigs in Chalktown) late in the fourth quarter that will target an extended lateral in the Woodbine in Grimes County.

Well

WI%

Total Measured

Depth (ft.)

Lateral (ft.)

Frac Stages

Status/First

Production

30 Day Avg IP

(boed)

% Oil

Tommie Carroll 2H

46%

14,950

5,221

July 2014

648

81%

* Previously reported

South Texas (Buda), Zavala and Dimmit Counties

Our recent and current activity in the Buda in South Texas consists of the following:

Well

WI%

Total Measured

Depth (ft.)

Lateral (ft.)

Frac Stages

Status/First

Production

30 Day Avg IP

(boed)

% Oil

Beeler 19H

50%

14,290

7,096

n/a

July 2014

1,198

73%

Beeler C 20H

50%

16,574

9,474

n/a

July 2014

835

65%

Bruce Weaver 2H

12.5% (Non-Op)

13,290

6,386

n/a

July 2014

1,047

57%

Dunlap 4H

100%

12,570

5,518

n/a

August 2014

235

12%

Bruce Weaver 1H

12.5% (Non-Op)

10,530

3,918

n/a

August 2014

684

80%

Beeler Unit 26H

50%

TBD

Completing

TBD

Beeler Unit J 24H

50%

TBD

Drilling

TBD

* Previously reported

Since May of 2013, we have drilled or participated in 19 wells within the Buda trend and believe that we have defined the optimum spacing and productive sweet spot. Additional drilling into the Buda will be limited going forward as our attention will focus on the Eagle Ford's prospectivity over our 9,500 net acre position in Zavala and Dimmit Counties. We have drilled a pilot with whole core into the Eagle Ford and expect results in Q1 2015 from that analysis. Operators continue to drill wells with excellent productivity in the immediate area of our leasehold.

Fayette County, Texas (Elm Hill Project)

We commenced our drilling program in this area during the quarter, and our current activity in the Elm Hill project consists of the following:

Well

WI%

Total Measured

Depth (ft.)

Lateral (ft.)

Frac Stages

Status/First

Production

30 Day Avg IP

(boed)

% Oil

Janecka 1H

50%

11,758

6,000

Flowing back

not yet available

Vinklarek 1H

50%

TBD

Drilling - 9,800'

TBD

We anticipate drilling a total of four wells in this area by the end of the year, will evaluate results at that time, and then decide on a rig and development strategy for 2015. We and our partner have approximately 53,200 gross acres (23,700, net to the Company) in the area on which we may pursue a number of formations horizontally.

Wyoming (FRAMS Project and N. Cheyenne Project)

Last week we spud our initial well targeting the Mowry Shale in Natrona County, Wyoming. We originally acquired in May 2014 the right to earn an 80% working interest in approximately 119,500 gross acres (93,000 net acres) in the area on which to pursue the Mowry and other potential formations. We expect to spud our initial well targeting the Muddy Sandstone formation in Weston County, Wyoming in late December or early January 2015. We originally acquired in September 2014 the right to earn a 100% working interest in approximately 49,000 gross acres (44,000 net acres), where the prospect generator retains an option to participate for a 10% working interest, in the area on which to pursue the Muddy Sandstone and other potential formations.

2014 Capital Program & Liquidity

Capital expenditures incurred for the three months ended September 30, 2014 were $25.8 million, of which $8.6 million was spent drilling in the Woodbine formation in Madison and Grimes Counties, Texas; $9.1 million was spent drilling the Buda formation in Dimmit County, Texas; and $7.3 million was invested in acreage positions primarily in new areas.

We currently anticipate that our total capital expenditure program for 2014 will be in the $215 - $225 million range, funded primarily from internally generated cash flow.

As of September 30, 2014, we had approximately $54.4 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.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and nine month periods ended September 30, 2014 and 2013:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014		2013(1)		%		2014		2013(1)		%
Offshore Volumes Sold:
Oil and condensate (Mbbls)		57		91	-37	%		211		255	-17	%
Natural gas (Mmcf)		4,039		5,190	-22	%		14,302		13,985	2	%
Natural gas liquids (Mbbls)		121		148	-18	%		439		431	2	%
Natural gas equivalents (Mmcfe)		5,104		6,623	-23	%		18,201		18,100	1	%

Onshore Volumes Sold:
Oil and condensate (Mbbls)		335		-	n/a			919		-	n/a
Natural gas (Mmcf)		1,598		-	n/a			4,896		-	n/a
Natural gas liquids (Mbbls)		117		-	n/a			323		-	n/a
Natural gas equivalents (Mmcfe)		4,312		-	n/a			12,352		-	n/a

Total Volumes Sold:
Oil and condensate (Mbbls)		392		91	331	%		1,130		255	343	%
Natural gas (Mmcf)		5,637		5,190	9	%		19,198		13,985	37	%
Natural gas liquids (Mbbls)		238		148	61	%		762		431	77	%
Natural gas equivalents (Mmcfe)		9,416		6,623	42	%		30,553		18,100	69	%

Daily Sales Volumes:
Oil and condensate (Mbbls)		4.3		1.0	331	%		4.1		0.9	343	%
Natural gas (Mmcf)		61.3		56.4	9	%		70.3		51.2	37	%
Natural gas liquids (Mbbls)		2.6		1.6	61	%		2.8		1.6	77	%
Natural gas equivalents (Mmcfe)		102.3		72.0	42	%		111.9		66.3	69	%

Average sales prices:
Oil and condensate (per Bbl)	$	96.05	$	110.37	-13	%	$	98.32	$	109.65	-10	%
Natural gas (per Mcf)	$	3.85	$	3.64	6	%	$	4.56	$	3.81	20	%
Natural gas liquids (per Bbl)	$	34.55	$	39.01	-11	%	$	36.17	$	37.02	-2	%
Total (per Mcfe)	$	7.17	$	5.24	37	%	$	7.40	$	5.37	38	%


(1)		Results for the three and nine months ended September 30, 2013 include only the results of Contango, prior to the merger with Crimson.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014		2013(1)		%		2014		2013(1)		%
Offshore Selected Costs ($ per Mcfe):
LOE (including transportation and workovers)	$	0.83	$	0.72	15	%	$	0.57	$	1.31	-57	%
Production and ad valorem taxes	$	0.11	$	0.12	-12	%	$	0.10	$	0.13	-26	%
Depreciation and depletion expense	$	2.39	$	1.71	40	%	$	1.88	$	1.78	6	%

Onshore Selected Costs ($ per Mcfe):
LOE (including transportation and workovers)	$	1.48	$	-	n/a		$	1.36	$	-	n/a
Production and ad valorem taxes	$	0.62	$	-	n/a		$	0.61	$	-	n/a
Depreciation and depletion expense	$	6.58	$	-	n/a		$	6.53	$	-	n/a

Average Selected Costs ($ per Mcfe):
LOE (including transportation and workovers)	$	1.13	$	0.72	57	%	$	0.89	$	1.31	-32	%
Production and ad valorem taxes	$	0.34	$	0.12	181	%	$	0.30	$	0.13	129	%
Depreciation and depletion expense	$	4.31	$	1.71	152	%	$	3.76	$	1.78	110	%
General and administrative expense (cash)	$	0.60	$	0.40	49	%	$	0.76	$	0.64	18	%
Interest expense	$	0.07	$	-	100	%	$	0.07	$	-	100	%

Adjusted EBITDAX (2) (thousands)	$	47,694	$	26,565			$	162,467	$	69,674

Weighted Average Shares Outstanding (thousands)
Basic		19,077		15,195				19,074		15,195
Diluted		19,122		15,195				19,074		15,195

(1)		Results for the three and nine months ended September 30, 2013 include only the results of Contango, prior to the merger with Crimson.
(2)		Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).

CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)

	September 30,		December 31,
	2014		2013
ASSETS
Cash and cash equivalents	$	-	$	-
Accounts receivable		35,990		60,613
Other current assets		7,940		5,504
Net property and equipment		767,637		791,023

Investments in affiliates and other non-current assets		59,885		53,164

TOTAL ASSETS	$	871,452	$	910,304

LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued liabilities		93,133		96,833
Other current liabilities		4,176		2,446
Long-term debt		54,415		90,000
Deferred tax liability		103,849		105,956
Asset retirement obligations		21,325		22,019
Total shareholders' equity		594,554		593,050

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	871,452	$	910,304


CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
		2014			2013			2014			2013

REVENUES
Oil and condensate sales	$	37,662		$	10,044		$	111,102		$	27,961
Natural gas sales		21,676			18,914			87,547			53,308
Natural gas liquids sales		8,214			5,764			27,579			15,948
Total revenues		67,552			34,722			226,228			97,217

EXPENSES
Operating expenses		13,797			5,553			36,426			26,025
Exploration expenses		(4,713	)		89			33,071			223
Depreciation, depletion and amortization		40,550			11,518			114,853			32,242
Impairment and abandonment of oil and gas properties		6,693			-			23,259			767
General and administrative expenses		6,821			2,657			26,485			11,622
Total expenses		63,148			19,817			234,094			70,879

OTHER INCOME (EXPENSE)
Gain from investment in affiliates (net of income taxes)		1,287			669			4,387			1,402
Interest expense		(672	)		(13	)		(2,077	)		(38	)
Gain (loss) on derivatives, net		1,734			-			(1,488	)		-
Other income (loss)		48			15,698			(148	)		25,573
Total other income (expense)		2,397			16,354			674			26,937

NET INCOME (LOSS) BEFORE INCOME TAXES		6,801			31,259			(7,192	)		53,275

Income tax benefit (provision)		(3,137	)		(11,519	)		5,244			(18,310	)

NET INCOME (LOSS)	$	3,664		$	19,740		$	(1,948	)	$	34,965

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					Nine Months Ended
	September 30,					September 30,
		2014			2013		2014			2013

Net income (loss)	$	3,664		$	19,740	$	(1,948	)	$	34,965
Interest expense		672			13		2,077			38
Income tax provision (benefit)		3,137			11,519		(5,244	)		18,310
Depreciation, depletion and amortization		40,550			11,518		114,853			32,242
Exploration expenses		(4,713	)		89		33,071			223
EBITDAX	$	43,310		$	42,879	$	142,809		$	85,778

Unrealized gain on derivative instruments	$	(1,963	)	$	-	$	(1,494	)	$	-
Non-cash equity-based compensation charges		1,217			-		3,333			-
Impairment of oil and gas properties		6,417			-		22,010			767

Loss (gain) on sale of assets and investment in affiliates			(1,287	)			(16,314	)			(4,191	)			(16,871	)
Adjusted EBITDAX		$	47,694			$	26,565			$	162,467			$	69,674

Guidance for Fourth Quarter 2014

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

			Fourth quarter 2014 production			105,000 - 115,000 Mcfe per day

			LOE (including transportation and workovers)			$9.5 million - $10.0 million

			Production and ad valorem taxes			4.7%
			(% of Revenue)

			Cash G&A			$6.5 million - $7.5 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, November 11, 2014 at 8:00am CST. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-888-337-8192, (International 1-719-325-2332) and entering the following participation code: 6281005. A replay of the call will be available from Tuesday, November 11, 2014 at 11:00am CST through Tuesday, November 18, 2014 at 11:00am CST by dialing toll free 1-888-203-1112, (International 1-719-457-0820) and asking for replay ID code 6281005.

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 State. 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

Sergio Castro, 713-236-7400

Vice President and Treasurer

EXHIBIT 99.2

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CONTANGO OIL & GAS COMPANY

Moderator: Joe Grady

November 11, 2014

8:00 am CT

Operator: Please stand by we’re about to begin. Good day and welcome to the Contango Oil & Gas Company Third Quarter 2014 Results conference call. Today’s conference is being recorded.

At this time, I would like to turn the conference over to Joe Grady. Please go ahead, sir.

Joe Grady: Thank you. I would like to welcome everyone to Contango’s regular earnings call for the quarter ending September 30, 2014, this morning. I’d like to start by reminding everyone that the results for the three-month and nine-month periods ending September 30, 2014, reflect a merger with Crimson Exploration that was effective October 1, 2013. So 2013 results reflect - or for the comparable periods in 2013 reflect pre-merger standalone Contango.

On the call today are myself, Allan Keel, our President and CEO; Steve Mengle, our Senior VP of Engineering; Tommy Atkins, our Senior VP of Exploration; and Carl Isaac our Senior VP of Operations.

I’ll give a brief overview of financial results. I’ll turn it over to Allan who’ll give you a brief overview of current operations. And then we’ll follow that with a Q&A. And as we usually do, we’ll limit

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questions from the audience to those from analysts that follow our stock closely as we believe that that is most constructive and productive use of everyone’s time and especially in the case of today as we’re on a short fuse and present the Jeffrey’s conference right after this call.

Before we begin, I want to remind everyone that the earnings Press Release in the discussion this morning may contain forward-looking statements as defined by the Securities and Exchange Commission which may include comments and assumptions concerning Contango’s strategic plans, expectations and objectives for future operations. Such statements are based on assumptions we believe to be appropriate and under the circumstances. However those statements are just estimates are not guarantees of the future performance or results and therefore should be considered in that context.

Starting with the review of financial results we reported net income of $3.7 million for the quarter or 19 cents per basic and diluted share compared to a net loss of or sorry net income of $19.7 million or $1.30 per basic share for the pre-merger quarter last year. Major items contributing to this variance were included in the 2014 quarter results were approximately $6 million and pre-tax income contributed by Crimson offset by the production and eruption related to the compressor installation at Eugene Island 11 which we’ve estimated at $12 million pre-tax impact.

About 2013 results included an approximate $16 million pre-tax gain on the sale related to the - our interest in all the resources.

Adjusted EBITDAX as defined in our release and which excludes exploration expense was approximately $48 million for the current quarter compared to approximately $27 million for the prior year quarter. A 78% increase that could have been considerably better had we not had the production interruption at Eugene Island for the compressor installation. Adjusted EBITDAX pre share for the current quarter was $2.54 for diluted share $2.54 per diluted shared compared to

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consistent estimates of $2.46 per share on a cash flow basis which are from a practical standpoint the same.

Production for the current quarter was approximately 9.4 Bcfe or approximately 102 million per day equivalent compared to 72 million per day in the pre-merger prior year quarter. As previously guided production for this quarter was below the second quarter due to the impact which we estimated $18 million a day for the quarter of the Eugene Island 11 installation. Guidance of $105 to $115 million equivalents per day for the fourth quarter includes restoration of Eugene Island production at roughly 99% in the pre-shut in rates.

But also assumes no meaningful new production coming online during the quarter as we have gone to pad drilling in the Chalktown area for the fourth quarter. Historically we have drilled completed and commenced production and sequence for each new well while pad drilling for the fourth quarter anticipates the drilling of three wells and sequence completing those wells in sequence and then commencing production for all three at one time probably in the first quarter of 2015.

Total operating cost for the current quarter including direct LOE production taxes, transportation costs, interest and cash GNA were $2.14 per Mcfe compared to $1.24 per Mcfe in the 2013 quarter with the increase primarily reflecting the post merger increase of the size of the asset base in the organization. While that per unit rate is higher than recent quarters due to the shut in impacted production total cash costs were approximately $1.4 million less than the mid point of guidance we gave for the quarter due primarily to lower cash G&A cost.

Guidance on total cash operating cost for the fourth quarter is comparable to third quarter experience. Impairment costs were $6.7 million for the current year quarter as we impaired

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unproved lease costs related to portions of our TMS acreage and our GOM prospects in accordance with our policy on impairment of unproved cost. While most of this quarter’s expense relates to TMS acreage expires - that expires in early 2015 under our policy requirements we may have quarterly amortization of GOM prospects as much as approximately $900,000 per quarter for the next two years.

As of September 30 we had approximately $54 million outstanding on our credit facility which is a $500 million facility with a current $275 million borrowing base that was recently reaffirmed through May 1, 2015. So we had a very strong liquidity position provides us the flexibility to withstand the current price environment to continue to pursue a balanced program with drilling a current perspective inventory and/or pursue acquisition opportunities in this low price environment.

That concludes the financial review and I will now turn it over to Allan for an operations update.

Allan Keel: Thanks Joe and good morning to everyone and thanks for being here today with us. I would like to share a few highlights about the information we provided in our operations release and where appropriate and meaningful add a few extra comments.

First of all I’d like to say that we do not have a definitive guidance we don’t have any definitive guidance on our 2015 cap work program as of yet. We’re probably a few weeks away from having that finalized and presenting that to our Board given the recent decline of ((inaudible)) and our view of staying within cash flow our focus most likely be on further delineating our existing positions primarily Madisonville, South Texas and the three new plays that we’ve got working now.

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And given our time constraints today I’ll limit my comments to a pretty high level for each area. In Madison and Grimes counties we concentrated our efforts this quarter on the Chalktown portion of our Woodbine play where we bought the Dean well online at a previously reported 30 day rate of 927 barrels equivalent per day and finalized the Heath well that’s so far has not lived up to expectations and we continue to test that.

Despite seasons chose during the drilling phase in the Heath well we really haven’t seen anything but water thus far. We’ll continue to evaluate the well and learn from it. And we also have three wells that are in process at the end of the quarter. We continue to be excited about the Chalktown areas evidenced by our addition of a second rig with the expectation that we will have two rigs operating in that area during 2015 utilizing a pad drilling approach.

In Grimes County he noted in our release that we previously reported a non-swell in the Tommie Carroll 2H at a 30 day rate of 648 barrels equivalent per day. We will be receiving a third rig in that area in the very near future. It’s in - it will spend most of its time in the Grimes County area for the 2015 timeframe.

Down in South Texas in the Buda play we continue to delineate this part of our portfolio during the quarter as we previously reported the commencement of production of five wells that averaged an initial 30-day rate of 800 barrels equivalent per day. As noted in the release we also had two more wells in process at the end of the quarter and we’ll report the results of those wells in the next quarterly release.

We believe that we have to define the optimum space unit productive sweet spot for Buda and we’ll most likely focus our 2015 activity on Eagle Ford formation on our or across our 95 hundred net acre position down in Zavala and Dimmit Counties.

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In terms of new plays as most of you know we acquired three new potential plays one in Texas and two in Wyoming over the last oh six to nine months. First of all we entered into a ground floor of 50/50 exploration agreement with a private company where we have acquired approximately 53,000 gross acres, 24,000 net in South Central Texas primarily in Fayette and Gonzales counties where we will target a number of different formations. We initiated drilling during the quarter have drilled two wells one is (cleaned up) and one’s awaiting completion or currently drilling the third well.

We will spud the fourth well after completion drilling on the third and we’ll announce well results and future strategy by early to mid first quarter. We’re excited about this play and given success in the initial targeted formation. We estimate that we could add an estimated 200 drilling locations to our portfolio based on 150 acre spacing.

Also very similar to our Texas play we’re very excited about our first play up in Wyoming where we acquired the ride to earn up to approximately 119,500 gross acres with an 80% work in interest in Natrona County, Wyoming where we will target the Mowry Shale along with other formations and this is called our FRAMS Project.

In addition to the FRAMS Project we’ve also acquired the right to earn approximately 49,000 gross acres 44,000 net in Weston County, Wyoming where we will pursue horizontal tasks in the muddy sandstone which is our North Cheyenne Project. And this North Cheyenne Project lies between two pretty large vertical muddy fields. So we’re excited about both of those. This past weekend we spud our first FRAMS well again back in Natrona County which will also be a pilot whole and include core analysis.

We expect to have reportable results on this well in the first quarter. Given success in this area we estimate we can have between 300 to 12 hundred gross locations to our portfolio from the

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Mowry alone depending on spacing. And once we’ve drilled the first well at FRAMS we’ll take that rig and move it up to the North Cheyenne prospect probably late in the year or early next year. And again given success there in the North Cheyenne prospect we could add potentially 200 locations in our inventory there.

That’s just a brief overview of our operations and what we’ve got going. As you can see this has been a very busy quarter and we will continue to keep that momentum going into 2015.

And then with that that concludes our prepared remarks this morning and we’ll open it up for questions.

Operator: Thank you. If you would like to ask a question please signal by pressing star 1 on your telephone keypad. Please make sure your mute function is turned off to allow your signal to reach our equipment. Again press star 1 if you wish to ask a question.

And we’ll take our first question from Neal Dingmann with Suntrust.

Neal Dingmann: Morning guys. Say Allan I know you haven’t obviously put out official guidance and you did mention that for next year. But just your thoughts sort of I guess in broad terms how, you know, between the Elm Hill the FRAMS and the Cheyenne project obviously a lot of upside there how you’ll balance that with obviously some of the existing Buda I’m just wondering more in sort of broad terms I mean is it, you know, existing, you know, acre or core acreage would that be, you know, three quarters of the budget versus, you know, a quarter for some of these newer plays?

Maybe if you and Joe could give a little color around that first.

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Allan Keel: So we have a lot of, you know, we have a lot of drilling to do in the Chalktown area for next year I’d say less so in the Buda down in South Texas. We do plan to drill some Eagle Ford wells down there but it’s really, you know, our acreage position is set up. We do have a partner in our project in Fayette Gonzales Counties. So we’ll have to work with them to figure out what our plan is going forward given success there.

But I would, you know, think that the majority of our budget would be, you know, directed towards Madison Grimes some at Eagle Ford and then subject to success and some of these other plays, you know, that’s where the remainder of the capital would go. We, you know, we’re still trying to, you know, our belief especially in these lower commodity price environment is to, you know, stay within cash flow with our budget.

However, it’s given, you know, if we had, you know, an outstanding success at one of our three new projects then that might change our view.

Neal Dingmann: Exactly and then one - okay - and then was wondering about, you know, in addition to the production you guys for fourth quarter you talked about the drill and related interference in three wells in the, you know, in the Buda play. Just your thoughts is that going to be - is that just for the limit to that area Allan or is that something that you’re, you know, potentially cautious on that could be more wide spread or just maybe some more details around that?

Allan Keel: Neal I think that was just an isolated incidence but remember we’re not going to be drilling that much in Buda in 2015 it’s going to be more Eagle Ford.

Neal Dingmann: No good point okay, okay. And then, you know, I think I know this as far as just, you know, going forth for the budget for next year Joe is it (for) - is it fair to say I guess for, you know, now with your two positions out West in addition to obviously the Fayette position just your

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thoughts as far as I mean leases and expenses on that would that be pretty minimal at least for the start of the year?

Joe Grady: In terms of new leasing?

Neal Dingmann: Yes sir.

Joe Grady: Well we will include in our 2015 budget a sizeable number, you know, similar to what we have in this year’s budget for the potential for new leases and new lease and new plays in 2015 in our efforts to continue to build our inventory.

Neal Dingmann: Okay. No it’s...

Joe Grady: As it...

Neal Dingmann: ...not...

Joe Grady: ...relates to the existing plays that we already have it’ll probably be more fill in kind of expenditures.

Neal Dingmann: ...okay, you know, I guess that’s where I was going. I saw that was out there but I was wondering just based on Allan’s comments if I guess if that could change or that’s still, you know, the plan I guess at this time that it is still to have, you know, spending on those kind of new leases and Joe is that fair?

Joe Grady: That’s correct.

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Neal Dingmann: Okay and then just lastly location at the Elm Hill project obviously there’s activity around you all in Fayette a lot of it looks - starting to look quite good. You know, your thoughts Allan at just how active you could get. I’m just specifically I’m interested in that area. After this is it sort of dependent on how this first well looks and that’ll sort of determine activity for the beginning of the year or just your thoughts around that?

Allan Keel: I think, you know, we’ve got, you know, we’re going to drill these four wells and we’ll test each one of those wells and subject or the results of those wells I think that’s going to be the driver for our level of activity. I mean in the event, you know, we have, you know, a large amount of success and very pleased with the results. I think that both us and our partner would be very anxious to get out there and, you know, get after it. But, you know, time will tell.

Neal Dingmann: Got it okay thank you all.

Allan Keel: Okay thanks.

Operator: And as a reminder if you’d like to ask a question please signal by pressing star 1.

And we’ll take our next question from Kyle Rhodes with Rbc Capital Markets.

Kyle Rhodes: Hi guys. Just on a strategic front how do you guys currently view the relative attractiveness of share repurchases to potential ((inaudible)) opportunities out there? Have you guys started to see any capitulation and asked prices just yet?

Allan Keel: Well we haven’t seen, you know, and the things that we’ve looked at thus far we haven’t seen anything that’s, you know, compelling enough to go, you know, to go run down but that’s obviously something that we’re very aware of and keeping our eyes on the market to see what

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opportunities might present themselves. So yes we’re, you know, we’re very engaged on that front.

Joe Grady: And Kyle I’ll add to that we’re gone down parallel paths here. We think that our stock is under valued and good investment so we’re out ((inaudible)) some capital to that but still keeping our eye on the bigger picture being continued building of inventory for our drilling program going forward.

Kyle Rhodes: Got it makes sense. And then just additional color ((inaudible)) on that Heath unit Chalktown well anything you saw on the drilling completion that has you, you know, concerned about the Southern Chalktown area just maybe some more color around that.

Male: It’s good and bad ((inaudible)).

Allan Keel: Well, you know, we’re, you know, it’s ((inaudible)) good news and bad news out there we’re, you know, we’re evaluating it still. We’re looking at the, you know, the (con) - the water, you know, what type of water we’re making load water versus formation water, you know, what the chlorides might be. So we’re doing some further investigation there. We’ll probably do some more scientific work out there in the near term to try to help us further determine that but it is an important well for us and it’s important for us to have a clear understanding of what’s actually going on there.

Kyle Rhodes: Got it. Thanks guys.

Allan Keel: Thank you.

Joe Grady: Thanks Kyle.

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Operator: And our next question is from Chad Mabry with Mlv and Company.

Chad Mabry: Thanks I wanted to drill down on Q4 guidance a little bit if I could and maybe get an idea of the offshore versus onshore split there specifically looking at Eugene Island 11 just curious how that’s performing now that you have a compression installed there.

Allan Keel: Carl.

A. Carl Isaac: This is Carl Isaac. I would say that Eugene Island 11 is performing as we expected post compression. We had a really good performance installing the compressor with about 21 days of shut in time. And the wells are back on now and performing as we generally expected. I think we’re going to be very close through the third quarter to what we’ve budgeted offshore for the year from our PDP production.

Chad Mabry: So this...

A. Carl Isaac: Okay then...

Chad Mabry: ...normal decline after that.

A. Carl Isaac: ...yes just normal decline.

Chad Mabry: Okay great and then going back to Fayette County with the four wells there just curious are you testing different formations, different concepts there or is that going to be one kind of horizon that we’re testing with those four wells?

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Thomas Atkins: Yes this is Tommy Atkins. You know, we’re testing a variety of different things formations, completions all that kind of stuff. Yes we’re trying to get a good knowledge on the spread of our acreage and we’re doing different things.

Chad Mabry: All right. That’s helpful thanks guys.

Joe Grady: Thanks Chad.

Operator: And our next question is from Michael Glick with Johnson Rice.

Michael Glick: Morning guys. Just a question on pad drilling. I mean kind of what’s the thought process with transition to that and what’s the go for kind of pad design that you’re targeting?

A. Carl Isaac: Carl Isaac again. I think there’s several things actually relative to pad drilling. We obviously get some capital efficiency to begin with. We’re moving rigs on the signed location in 12 hours versus moving from location to location in three or four days. So you can kind of start there. There’s capital efficiencies that are created by pad drilling but there’s also technical efficiencies that have been pretty well documented in most resource plays in terms of placing fracs on adequately spaced wells or down spaced wells or really any spacing you want to talk about.

At the same time prior to bringing adjacent wells on production. So we anticipate that we’ll have some production efficiencies some reservoir efficiencies capital efficiencies that all come to bear as we drill as we move to pad drilling. We’re pretty excited about it we’ve spend a lot of time kind of delineating our acreage on a well by well location by location basis. So this gives us an operational opportunity to finally start realizing some of the capital and production efficiencies that we’ve watched others enjoy.

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Michael Glick: Okay so I guess that sounds like the plan going forward and if so should we expect kind of some lumpiness in production?

A. Carl Isaac: Yes sir I think both lumpiness and production but also a little bit in the capital when we’re drilling wells at $2-1/2 or $3 million each three consecutively we don’t incur the $3 to $3-1/2 million completion cost as rapidly. So when we go back out and we complete three wells in a row that’s going to create some capital spikes as well relative to that specific asset. So we’ll see it both on the production and the capital side to some extent.

Michael Glick: And just real quick saw a process on any of the other formations in that Madison and Grimes County area.

Allan Keel: You take that.

A. Carl Isaac: What was the question?

Allan Keel: The section in Grimes County are there potential?

A. Carl Isaac: Oh yes, yes, we’ve always believed that there was a tremendous amount of opportunity and, you know, additional horizons and formations in Madison and Grimes County. So we’re currently working a lot of that stuff. We drove a pilot whole this year and took a core in a couple of zones so we’re looking at that.

There is a tremendous amount of activity all around Madison County. A matter of fact if you look at Madison County itself there’s a tremendous amount of activity in a multiple horizons Buda, Georgetown believing Glenn Rose, Edwards.

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So there’s a tremendous amount of opportunity up and down the section in Madison and Grimes County.

Michael Glick: Okay thank you very much.

A. Carl Isaac: Thanks Michael...

Allan Keel: Thanks Michael.

Operator: And we’ll now take a question from Curtis Trimble with Brean Capital.

Curtis Trimble: Thanks good morning everyone. Third quarter CAPEX a little shy of what I expected. I’m guessing based on Carl’s comment that that had to do with what’s called the lumpiness of completions.

Can you give us any color on what fourth quarter CAPEX might look like?

Joe Grady: Well the guidance that we’ve given for the year of 215 to 225 I think is still pretty good so fourth quarter will be an active quarter.

Curtis Trimble: Good deal and in terms of infrastructure around the place in Wyoming I’m going to ((inaudible)) to guess that you’ve got plenty of legacy infrastructure but are there any pressure considerations for new versus legacy production?

Joe Grady: I’m not sure I understand the second part of the question. The first part of the question as far as maturity of infrastructure and the - and what we call in North Cheyenne up in Weston County we’re between two large fields that actually have production in the zone that we’re looking at there one of the zones and so there’s some infrastructure there that’s mature.

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In Natrona County it’s not so much but we don’t really see that being a big problem at this point in time and I think that’s something that we’re getting our arms around right now and we’ll have a better feel for it as we progress through the project.

Curtis Trimble: And you’re expecting that to be a dominant oil play?

Joe Grady: I sure hope so and totally expect it will be.

Curtis Trimble: Thank you. I appreciate it.

Allan Keel: Thank you Curtis.

Operator: And this concludes today’s Question and Answer session. I’d like to turn the conference back to our speakers for any additional remarks.

Joe Grady: That’s all we have today and we appreciate everybody’s joining us on this third quarter call and look forward to updating you soon. Thanks a lot.

Operator: This concludes today’s conference thank you for your participation.

END