Contango Announces Second Quarter 2014 Financial Results and Provides Operations Update

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

Second Quarter 2014 Highlights

• Production of 10.6 Bcfe for the quarter.

• Net income of $4.6 million and Adjusted EBITDAX of $56.7 million for the quarter.
• Continued drilling success in the Woodbine play in Madison/Grimes counties and in the Buda play in Dimmitt/Zavala counties Texas.
• Acquisition of approximately 42,000 gross acres (18,000 net acres - 50% WI) in Fayette and Gonzalez counties, Texas for pursuit of multiple formations through horizontal drilling planned for the third and fourth quarters.
• Acquisition of the right to drill to earn approximately 119,500 gross acres (93,000 net acres - 80% WI) in Natrona County, Wyoming targeting multiple formations including the Mowry Shale through horizontal drilling.

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said “We had an exciting quarter from a capital perspective as we continued to post good results in our two main drilling areas, the Woodbine play in Madison and Grimes counties Texas, and the Buda play in Dimmitt County. We also added two new prospective resource plays to our portfolio in which we acquired (or acquired the right to earn) over 161,500 gross acres (111,000 net acres) and which may add an estimated 1,400 potential drilling locations to our unproved drilling inventory if those plays prove successful. We are excited about testing these new plays in the next few months, while continuing to delineate our existing positions in Madison, Grimes and Dimmitt counties. On the production front, we commenced initial production in July at South Timbalier 17, our 2013 offshore discovery; and we commenced compression installation in July for our Dutch and Mary Rose wells, and with that project scheduled to be completed in early September, we hope to enjoy consistent and sustained production from our biggest field for years to come.”

Summary Financial Results for the Quarter Ended June 30, 2014

The results for the three months ended June 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 June 30, 2013 include only the results of Contango.

Net income for the three months ended June 30, 2014 was $4.6 million, or $0.24 per basic and diluted share, compared to net income of $11.4 million, or $0.75 per basic and diluted share, for the same prior year period. Pre-tax income of $4.8 million for the current quarter includes pre-tax charges of $10.1 million in exploration expenses attributable to our unsuccessful Ship Shoal 255 exploratory well and $0.5 million of non-cash impairment expense related to unproved lease costs and production facilities related to the Ship Shoal 255 prospect. Exclusive of those costs, income before taxes would have been approximately $15.4 million, compared to income before taxes of $14.9 million in the prior year quarter. 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 $56.7 million for the three months ended June 30, 2014, compared to Adjusted EBITDAX for the same period last year of $24.3 million, a $32.4 million increase attributable primarily to the merger with Crimson.

Revenues for the three months ended June 30, 2014 were approximately $78.4 million compared to revenues of $30.7 million for the same period last year, a $47.7 million increase attributable primarily to the addition of Crimson’s operations, additional interests in our Dutch wells acquired in December 2013 and, to a lesser extent, revenue from our Vermilion 170 Field that was shut-in for most of the prior year quarter.

Production for the three months ended June 30, 2014 was approximately 10.6 Bcfe, or 116.0 Mmcfe per day, which was within our previously provided guidance. This represents an 87% increase over production for the same period last year, primarily attributable to our merger with Crimson, our exercise of a preferential right to purchase additional interests in our Dutch wells in December 2013 and higher production from our Vermilion 170 well. Crude oil and natural gas liquids production during the second quarter was approximately 7,000 barrels per day, or 36% of total production, up from approximately 2,300 barrels per day, or 22% of total production for the same period last year. The increase in crude and liquids production was 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 third quarter of 2014, we estimate our production will be 100 - 110 Mmcfed. Estimated third quarter production reflects the shut-in of our Dutch and Mary Rose wells at Eugene Island 10 to install compression facilities. The Dutch and Mary Rose wells, which were producing at an average rate of 61.1 Mmcfed, net to Contango, were shut-in on July 10, were restarted on July 30, and are slowly being brought up to full production. Guidance also includes the initiation of production at South Timbalier 17 that commenced on July 16, 2014.

The weighted average equivalent sales price during the three months ended June 30, 2014 was $7.43 per Mcfe, compared to an average equivalent sales price of $5.42 for the same period last year. The increase in the weighted average equivalent prices resulted from a strong increase in natural gas prices, which accounted for 64% of our volumes, and from the higher percentage mix of crude and liquids production to total production.

Operating expenses for the three months ended June 30, 2014 were approximately $11.6 million, or $1.10 per Mcfe, compared to $10.7 million, or $1.89 per Mcfe, for the same period last year. Included in operating expenses are lease operating expenses, transportation and processing, workover costs and production and ad valorem taxes.

Lease operating expenses (“LOE”), transportation and processing, and workover costs for the three months ended June 30, 2014 were approximately $8.5 million, or $0.80 per Mcfe, which was at the lower end of our previously provided guidance, and compared to approximately $10.0 million, or $1.77 per Mcfe, for the prior year period. The prior year quarter included $6.1 million in workover expenses related to the Vermilion 170 Field. Workover expenses in the current quarter were $0.4 million.

Production and ad valorem tax expenses for the three months ended June 30, 2014 were $3.1 million, or $0.30 per Mcfe, compared to $0.7 million, or $0.12 per Mcfe, for the same period last year, an increase resulting from higher post-merger revenues and higher tax rates paid on higher crude oil sales revenue.

Exploration costs for the three months ended June 30, 2014 were $10.9 million, compared to less than $0.1 million for the prior year quarter, as the current quarter includes drilling costs for our unsuccessful Ship Shoal 255 exploratory well which was finalized in May 2014.

Depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2014 was $39.9 million, or $3.78 per Mcfe, compared to $10.2 million, or $1.81 per Mcfe, for the same period last year. This increase of $29.7 million is primarily attributable to the addition of Crimson’s properties as a result of the merger.

Impairment and abandonment of oil and gas properties for the three months ended June 30, 2014 was approximately $1.4 million, $0.5 million of which relates to platform costs associated with our dry hole at Ship Shoal 255.

General and administrative expenses for the three months ended June 30, 2014 were $9.2 million, or $0.87 per Mcfe, compared to $5.8 million, or $1.02 per Mcfe, for the prior year quarter. General and administrative expenses exclusive of $1.0 million in non-cash stock compensation expense was $8.2 million for the current quarter, which was within previously provided guidance, compared to $5.8 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 third quarter 2014 guidance of $7.2 million to $7.5 million for general and administrative expenses, exclusive of non-cash stock compensation (“Cash G&A”).

Drilling Activity Update

Gulf of Mexico

We completed development and production facilities on our 2013 South Timbalier 17 (75% WI) discovery during the current quarter, and commenced production in July. As of August 11, the well was producing at a rate of 7.2 Mmcfed (94% gas), net to Contango.

Onshore Activity

Our onshore activity during the second quarter consisted of the following:

Southeast Texas (Woodbine)

Force Area, Madison County, Texas

		Total Measured			First	30 Day Avg IP
Well	WI%	Depth (ft.)	Lateral (ft.)	Frac Stages	Production	(boed)	% Oil
Mosley B #2H	77%	15,296	5,903	23	May 2014	923	84%
Grace Hall C #2H	77%	14,881	5,663	22	May 2014	1061	87%
Crow Unit B #1H	72%	14,160	5,094	20	June 2014	260	65%

For the remainder of 2014, we expect to have a rig in the area to drill additional wells in the Force and Grimes areas.

Iola/Grimes Area, Grimes County, Texas

		Total Measured			First	30 Day Avg IP
Well	WI%	Depth (ft.)	Lateral (ft.)	Frac Stages	Production	(boed)	% Oil
Tommie Carroll #2H	46%	14,950	5,221	22	July 2014	648	81%

Additionally, during the first quarter of 2014, we drilled the Stokes #1H (93% WI) well to a depth of 10,300 feet. This is a vertical pilot well for which 400 feet of whole cores were recovered in the Eagle Ford and other formations. We are continuing to evaluate the cores to determine the viability of future drilling in those zones in the Madison and Grimes areas.

Chalktown Area, Madison County, Texas

		Total Measured			First	30 Day Avg IP
Well	WI%	Depth (ft.)	Lateral (ft.)	Frac Stages	Production	(boed)	% Oil
Barr B #1H	65%	15,055	5,622	22	June 2014	788	76%
Dean #1H	70%	16,194	6,847	27	July 2014	not yet available	-

While the Dean #1H has been producing for less than 30 days, early results have been better than the early results experienced for the Barr well. The Heath Unit A #1H is currently drilling the lateral section of the well. We anticipate keeping the current rig in this area for the remainder of the year and expect to bring in a second rig in late-third or early-fourth quarter.

South Texas (Buda), Zavala and Dimmit Counties

		Total Measured			First	30 Day Avg IP
Well	WI%	Depth (ft.)	Lateral (ft.)	Frac Stages	Production	(boed)	% Oil
Dunlap 1H	70%	12,172	5,178	n/a	May 2014	403	23%
Beeler A 9H	50%	12,310	5,000	n/a	Apr 2014	326	53%
Beeler 5H ST	50%	10,712	3,347	n/a	Apr 2014	122	52%
Beeler D 16H	50%	11,092	3,914	n/a	June 2014	723	78%
Beeler 17H	50%	12,785	5,259	n/a	June 2014	1109	87%
Beeler 19H	50%	14,290	7,096	n/a	July 2014	1198	73%
Beeler C 20H	50%	16,574	9,474	n/a	July 2014	not yet available	-
Bruce Weaver 2H	12.5% (non-op)	13,290	6,386	n/a	July 2014	not yet available	-

While the Beeler C #20H well has been producing for less than 30 days, early results have been consistent with early results experienced in the Beeler #17H and Beeler #19H wells. The average completed well cost for these wells has been approximately $2.6 million per well. We expect to continue to have one to two rigs active in the area for the remainder of 2014.

East Texas (James Lime), San Augustine County

		Total Measured			First	30 Day Avg IP
Well	WI%	Depth (ft.)	Lateral (ft.)	Frac Stages	Production	(boed)	% Oil
Fairway Farms #1H	50%	13,864	5,439	20	Apr 2014	586	75%

We will continue to monitor the results from our two James Lime wells drilled this year for several months, and if production decline rates and liquids yield continue to follow our type curve, we could drill additional James Lime wells later this year or in 2015.

New Frontier and Resource Plays

Fayette and Gonzalez Counties, Texas

As previously disclosed, in early 2014 we and our partner started acquiring leases in Fayette, Gonzalez, Caldwell and Bastrop counties, Texas, with a targeted goal of over 40,000 net acres. To date, we have purchased approximately 42,000 gross acres in this play. Given success, we estimate that we will add approximately 200 drilling locations to our potential inventory. We expect to spud our first of three test wells in late August 2014.

Mowry Shale – Natrona County, Wyoming

During the quarter, we also acquired from an unnamed private party the right to earn, through the drilling of wells, up to approximately 119,500 gross acres in Natrona County, Wyoming, targeting multiple formations, including the Mowry Shale. The Mowry Shale is a tight formation that has been producing for years from vertical wells in the area. We plan to initiate a vertical pilot well and subsequent horizontal test of the Mowry, with hydraulic fractured completions, similar to what has proven successful in so many other basins. We expect to drill our initial operated well in the fourth quarter, evaluate the results of that well and determine whether to proceed with future tests. We estimate that we could add up to 1,200 drilling locations to our drilling inventory if this play proves economical.

2014 Capital Program & Liquidity

Capital expenditures incurred for the three months ended June 30, 2014 were $56.2 million, of which $23.5 million was spent drilling in the Woodbine formation in Madison County, Texas; $11.4 million was incurred on Ship Shoal 255; $10.0 million was spent drilling the Buda formation in Dimmit County, Texas; and $9.4 million was invested for leased acreage in new areas.

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

As of June 30, 2014, we had approximately $66.0 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 effective May 1, 2014, with the next scheduled redetermination on November 1, 2014.

Selected Financial and Operating Data

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014		2013		%		2014		2013		%
Offshore Volumes Sold:
Condensate and crude oil (Mbbls)		74		73	1	%		155		164	-6	%
Natural gas (Mmcf)		4,893		4,428	11	%		10,263		8,795	17	%
Natural gas liquids (Mbbls)		152		133	14	%		318		283	12	%
Natural gas equivalents (Mmcfe)		6,250		5,662	10	%		13,098		11,477	14	%
Onshore Volumes Sold:
Condensate and crude oil (Mbbls)		307		n/a	-			583		n/a	-
Natural gas (Mmcf)		1,837		n/a	-			3,298		n/a	-
Natural gas liquids (Mbbls)		105		n/a	-			207		n/a	-
Natural gas equivalents (Mmcfe)		4,310		n/a	-			8,038		n/a	-
Total Volumes Sold:
Condensate and crude oil (Mbbls)		381		73	422	%		738		164	350	%
Natural gas (Mmcf)		6,730		4,428	52	%		13,561		8,795	54	%
Natural gas liquids (Mbbls)		257		133	93	%		525		283	86	%
Natural gas equivalents (Mmcfe)		10,560		5,662	87	%		21,136		11,477	84	%
Daily Sales Volumes:
Crude oil (Mbbls)		4.2		0.8	422	%		4.1		0.9	350	%
Natural gas (Mmcf)		74.0		48.7	52	%		74.9		48.6	54	%
Natural gas liquids (Mbbls)		2.8		1.5	93	%		2.9		1.6	86	%
Natural gas equivalents (Mmcfe)		116.0		62.2	87	%		116.8		63.4	84	%
Average sales prices:
Oil and condensate (per Bbl)	$	100.53	$	106.07	-5	%	$	99.52	$	109.25	-9	%
Natural gas (per Mcf)	$	4.64	$	4.15	12	%	$	4.86	$	3.91	24	%
Natural gas liquids (per Bbl)	$	34.40	$	34.47	0	%	$	36.91	$	35.99	3	%
Total (per Mcfe)	$	7.43	$	5.42	37	%	$	7.51	$	5.45	38	%

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014		2013		%		2014		2013		%
Offshore Selected Costs ($ per Mcfe):
LOE (including transportation and workovers)	$	0.41	$	1.77	-77	%	$	0.47	$	1.64	-72	%
Production and ad valorem taxes	$	0.10	$	0.12	-17	%	$	0.10	$	0.14	-4	%
Depreciation and depletion expense	$	1.69	$	1.81	-7	%	$	1.68	$	1.81	-7	%
Onshore Selected Costs ($ per Mcfe):
LOE (including transportation and workovers)	$	1.36		n/a	-		$	1.30		n/a	-
Production and ad valorem taxes	$	0.59		n/a	-		$	0.60		n/a	-
Depreciation and depletion expense	$	6.81		n/a	-		$	6.51		n/a	-
Average Selected Costs ($ per Mcfe):
LOE (including transportation and workovers)	$	0.80	$	1.77	-55	%	$	0.78	$	1.64	-52	%
Production and ad valorem taxes	$	0.30	$	0.12	140	%	$	0.29	$	0.14	105	%
Depreciation and depletion expense	$	3.78	$	1.81	109	%	$	3.52	$	1.81	95	%
General and administrative expense (cash)	$	0.77	$	1.02	38	%	$	0.83	$	0.78	38	%
Interest expense	$	0.07	$	-	100	%	$	0.07	$	-	100	%
Adjusted EBITDAX (1) (thousands)	$	56,742	$	24,296			$	114,771	$	43,109
Weighted Average Shares Outstanding (thousands)
Basic		19,074		15,195				19,073		15,195
Diluted		19,130		15,195				19,073		15,195

(1) 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)
	June 30,		December 31,
	2014		2013
ASSETS
Cash and cash equivalents	$	-	$	-
Accounts receivable		37,132		60,613
Other current assets		8,697		5,504
Net property and equipment		784,059		791,023
Other non-current assets		57,963		53,164
TOTAL ASSETS	$	887,851	$	910,304
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable		105,613		96,833
Other current liabilities		4,308		2,446
Long-term debt		65,977		90,000
Deferred tax liability		98,456		105,956
Other non-current liabilities		23,827		22,019
Total shareholders’ equity		589,670		593,050
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY	$	887,851	$	910,304

CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
REVENUES
Oil and condensate sales	$	38,340		$	7,743		$	73,440		$	17,917
Natural gas sales		31,244			18,381			65,871			34,394
Natural gas liquids sales		8,835			4,584			19,365			10,184
Total revenues		78,419			30,708			158,676			62,495
EXPENSES
Operating expenses		11,576			10,687			22,629			20,472
Exploration expenses		10,853			5			37,784			134
Depreciation, depletion and amortization		39,901			10,230			74,303			20,724
Impairment and abandonment of oil and gas properties		1,371			767			16,566			767
General and administrative		9,207			5,757			19,664			8,965
Total expenses		72,908			27,446			170,946			51,062
OTHER INCOME (EXPENSE)
Gain from investment in affiliates (net of income taxes)		1,478			1,880			3,100			733
Interest expense		(737	)		(13	)		(1,405	)		(25	)
Loss on derivatives, net		(1,263	)		-			(3,222	)		-
Other income (loss)		(196	)		9,722			(196	)		9,875
Total other income (expense)		(718	)		11,589			(1,723	)		10,583
NET INCOME (LOSS) BEFORE INCOME TAXES		4,793			14,851			(13,993	)		22,016
Income tax benefit (provision)		(212	)		(3,495	)		8,381			(6,791	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,581		$	11,356		$	(5,612	)	$	15,225

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net income (loss)	$	4,581		$	11,356		$	(5,612	)	$	15,225
Interest expense		737			13			1,405			25
Income tax provision (benefit)		212			3,495			(8,381	)		6,791
Depreciation, depletion and amortization		39,901			10,230			74,303			20,724
Exploration expenses		10,853			5			37,784			134
EBITDAX	$	56,284		$	25,099		$	99,499		$	42,899
Unrealized loss on derivative instruments	$	212		$	-		$	469		$	-
Non-cash equity-based compensation charges		1,028			-			2,115			-
Impairment of oil and gas properties		500			767			15,592			767
Loss (gain) on sale of assets or investment in affiliates		(1,282	)		(1,570	)		(2,904	)		(557	)
Adjusted EBITDAX	$	56,742		$	24,296		$	114,771		$	43,109

Guidance for Third Quarter 2014

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

Third quarter 2014 production	100,000 – 110,000 Mcfe per day
LOE (including transportation and workovers)	$10.0 million - $10.5 million
Production and ad valorem taxes	5.0%
(% of Revenue)
Cash G&A	$7.2 million - $7.5 million
DD&A rate	$3.90 - $4.10

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Tuesday, August 12, 2014 at 9:30am CDT. Those interested in participating in the earnings conference call may do so by calling the following phone number: 888-334-2997, (International 719-325-2275) and entering the following participation code 1322271. A replay of the call will be available from Tuesday, August 12, 2014 at 12:30pm CDT through Tuesday, August 19, 2014 at 12:30pm CDT by dialing toll free 888-203-1112, (International 719-457-0820) and asking for replay ID code 1322271.

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.