Contango Announces Second Quarter 2018 Financial Results and Provides Operational Update

HOUSTON, Aug. 09, 2018 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE American: MCF) (“Contango” or the “Company”) announced today its financial results for the second quarter ended June 30, 2018 and provided an operational update. 

Summary Second Quarter Financial Results

Net loss for the three months ended June 30, 2018 was $7.2 million, or $0.29 per basic and diluted share, compared to a net loss of $6.0 million, or $0.24 per basic and diluted share for the same period last year. Operating earnings (i.e. revenues less expenses, before other income/expense) improved from a loss of $6.3 million in the 2017 quarter to a net loss of $4.1 million in the current quarter.  That improvement was overshadowed by a net loss on our outstanding derivatives during the current quarter compared to a gain in the 2017 quarter.  Average weighted shares outstanding were approximately 24.9 million and 24.7 million for the current and prior year quarters, respectively. 

The Company reported Adjusted EBITDAX, as defined below and on a recurring basis, of approximately $7.4 million for the three months ended June 30, 2018, compared to $10.2 million for the same period last year, a decrease attributable to lower revenues on lower production, and losses on our commodity price hedges in the current quarter compared to a gain in the prior year quarter.  Cash flow for the current quarter was $6.1 million, or $0.25 per share, compared to $9.3 million, or $0.38 per share for the prior year quarter. 

Revenues for the current quarter were approximately $18.4 million compared to $20.3 million for the 2017 quarter. We experienced a welcomed increase in crude oil and natural gas liquids prices during the quarter; however, a decline in natural gas prices, and lower production resulting from only one new well being added to production during the quarter and the Eugene Island 10 field being shut in for two weeks during the quarter for planned compression installation and maintenance, offset the benefit from liquids pricing.  Revenue from crude oil, however, increased to $9.6 million for the current quarter, compared to $6.5 million for the prior year quarter due to the increase in crude oil production resulting from our Southern Delaware drilling program and due to the higher crude oil prices.

Production for the second quarter of 2018 was approximately 3.9 Bcfe, or 42.4 Mmcfe per day, within our previously provided guidance, compared to 58.0 Mmcfe per day for the second quarter of 2017.  This expected year over year decline in equivalent production volumes is due to normal production declines, shutting in our offshore production for approximately two weeks to install compression and maintenance during the current quarter (loss of 4.2 Mmcfe/d) and the sale of our Eagle Ford Shale producing properties in Karnes County, Texas (loss of 0.7 Mmcfe/d). Our production guidance for the third quarter of 2018 is expected to be between 43 to 48 Mmcfed.   

The weighted average equivalent sales price during the three months ended June 30, 2018 was $4.79 per Mcfe, compared to $3.84 per Mcfe for the same period last year, as a decline in natural gas prices was offset by increases of 39% and 38% in crude oil and natural gas liquids prices, respectively, compared to the prior year quarter, and due to the increase in the higher percentage of oil and liquids in the production mix. 

Operating expenses for the three months ended June 30, 2018 were approximately $6.5 million, or $1.68 per Mcfe, compared to $6.3 million, or $1.20 per Mcfe, for the same period last year. Included in operating expenses are direct lease operating expenses, transportation and processing costs, workover expenses and production and ad valorem taxes. Operating expenses exclusive of production and ad valorem taxes were approximately $5.6 million, or $1.46 per Mcfe, for the current quarter, which was comparable to the prior year quarter and below our previously provided guidance for the current quarter. Our guidance for operating expenses for the third quarter of 2018, exclusive of production and ad valorem taxes, is consistent with the second quarter at between $5.2 to $5.8 million.        

DD&A expense for the three months ended June 30, 2018 was $9.5 million, or $2.46 per Mcfe, compared to $12.7 million, or $2.41 per Mcfe, for the prior year quarter, a decrease primarily attributable to the lower production during the quarter. 

Impairment and abandonment expense of oil and gas properties was $0.8 million for the current quarter, as compared to $1.4 million for the prior year quarter.

Total G&A expenses, inclusive of stock compensation expense, for the three months ended June 30, 2018 were $5.4 million, compared to $5.8 million, for the prior year quarter.  Cash G&A expenses, i.e. G&A exclusive of stock compensation expense, was $3.8 million, or $0.98 per Mcfe for the current quarter, compared to $4.2 million, or $0.80 per Mcfe, respectively, for the prior year quarter.  For the third quarter of 2018, we have provided guidance of $4.25 to $4.75 million for cash general and administrative expenses.   

Loss from affiliates (i.e. Exaro Energy III) for the three months ended June 30, 2018 was approximately $0.5 million, compared to a gain of $0.2 million for the same period last year, a decrease attributable to the decline in natural gas prices.  

Gain from sale of assets for the three months ended June 30, 2018 was approximately $1.4 million, which related to the sale of our non-operated assets located in Starr County, Texas.

Loss on derivatives for the three months ended June 30, 2018 was approximately $2.6 million.  Of this amount, $0.8 million were realized losses while the remaining $1.8 million were non-cash, unrealized mark-to-market losses.  Gain on derivatives for the three months ended June 30, 2017 was approximately $1.5 million.  Of this amount, $0.4 million were realized gains while the remaining $1.1 million were unrealized mark-to-market gains.

Capital Costs and Drilling Activity Update

Capital costs incurred for the three months ended June 30, 2018 were approximately $9.5 million, including $8.1 million for the drilling and completion of wells in the Southern Delaware Basin in Pecos County, Texas.
Our recent Southern Delaware Basin activity consists of the following:

Ragin Bull #2H

The Ragin Bull #2H (49% WI, 37% NRI), our second Wolfcamp B test, was spud in January 2018. Production began in April 2018 and achieved a 24-hour max IP rate of 805 Boed (68% oil) and a 30-day IP rate of 734 Boed (66% oil).  This well represents our fastest spud to total depth so far at 26.5 days. 

Sidewinder #1H / Gunner #3H

In July 2018, we brought two more wells on production which were drilled from a common pad, the Sidewinder #1H (49% WI, 37% NRI) targeting the Wolfcamp A formation and the Gunner #3H (47% WI, 35% NRI) targeting the Wolfcamp B. The Sidewinder was drilled to a TMD of 20,550 feet, including a 10,500 foot lateral, and had a maximum 30-day IP rate of 368 Boed (70% oil).  The Gunner #3H was drilled to a TMD of 20,167 feet, including a 10,067 foot lateral, and had a maximum 30-day IP rate of 773 Boed (78% oil).    

Fighting Ace #2H

On July 1, 2018, we spud the Fighting Ace #2H (50% WI, 38% NRI) targeting the Wolfcamp A which was drilled to a TMD of 20,560 feet, including a 10,598 foot lateral.  Completion operations on this well are expected to commence in mid-August, with initial production expected in mid-September.   

General Paxton #1H

On August 2, 2018, we spud the General Paxton #1H (50% WI, 38% NRI) in the southeast quadrant of our acreage position.  This well will target the Wolfcamp A formation and is expected to have a TMD of approximately 20,000 feet, including a lateral of approximately 10,000 feet.  From there, we expect to move the rig approximately five miles to the northwest and spud the River Rattler #4H. After that, we will evaluate our strategy for the remainder of the year, given the dramatic increase in the Midland-Cushing oil differentials in the area.

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer said “We now have ten Southern Delaware Basin wells on production, with the eleventh (Fighting Ace #2H) expected to begin production in September.  The Permian Basin is one of the most prolific oil basins in the U.S. with hundreds of operators pushing U.S. oil production to record levels.  It’s no surprise that all this production has overwhelmed available pipeline capacity and caused oil prices in Midland to trade at a double-digit discount to WTI in Cushing.   Once we finish drilling the River Rattler #4H, our plan is to evaluate this growing oil differential and decide the best strategy to take for the remainder of 2018 and beyond.”    

Derivative Instruments

We have the following financial derivative contracts in place at June 30, 2018:

Commodity		Period		Derivative		Volume/Month		Price/Unit
Natural Gas		July 2018		Swap		370,000 MMBtus		$	3.07 (1)
Natural Gas		Aug 2018 - Oct 2018		Swap		70,000 MMBtus		$	3.07 (1)
Natural Gas		Nov 2018 - Dec 2018		Swap		320,000 MMBtus		$	3.07 (1)
Oil		July 2018 - Oct 2018		Collar		20,000 Bbls		$	52.00 - 56.85 (2)
Oil		Nov 2018 - Dec 2018		Collar		15,000 Bbls		$	52.00 - 56.85 (2)
Oil		July 2018 - Dec 2018		Collar		2,000 Bbls		$	52.00 - 58.76 (3)
Oil		July 2018		Collar		6,000 Bbls		$	58.00 - 68.00 (2)
Oil		Nov 2018 - Dec 2018		Collar		5,000 Bbls		$	58.00 - 68.00 (2)
Oil		July 2018		Swap		6,000 Bbls		$	70.11 (3)
Oil		Aug 2018 - Oct 2018		Swap		3,000 Bbls		$	70.11 (3)
Oil		Nov 2018 - Dec 2018		Swap		6,000 Bbls		$	70.11 (3)
Oil		Jan 2019 - Dec 2019		Collar		4,000 Bbls		$	52.00 - 59.45 (3)
Oil		Jan 2019 - Dec 2019		Collar		7,000 Bbls		$	50.00 - 58.00 (2)
Oil		Jan 2019 - July 2019		Swap		6,000 Bbls		$	66.10 (3)

(1)	Based on Henry Hub NYMEX natural gas prices.
(2)	Based on Argus Louisiana Light Sweet crude oil prices.
(3)	Based on West Texas Intermediate crude oil prices.

Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three and six months ended June 30, 2018 and 2017: 

	Three Months Ended									Six months ended
	June 30,									June 30,
	2018			2017			%			2018			2017			%
Offshore Volumes Sold:
Oil and condensate (Mbbls)		18			33		-45	%			37			55		-33	%
Natural gas (Mmcf)		1,695			2,908		-42	%			3,991			5,916		-33	%
Natural gas liquids (Mbbls)		59			83		-29	%			137			167		-18	%
Natural gas equivalents (Mmcfe)		2,156			3,602		-40	%			5,033			7,248		-31	%
Onshore Volumes Sold:
Oil and condensate (Mbbls)		133			109		22	%			255			201		27	%
Natural gas (Mmcf)		584			699		-16	%			1,201			1,419		-15	%
Natural gas liquids (Mbbls)		52			53		-2	%			99			97		2	%
Natural gas equivalents (Mmcfe)		1,698			1,675		1	%			3,325			3,209		4	%
Total Volumes Sold:
Oil and condensate (Mbbls)		151			142		6	%			292			256		14	%
Natural gas (Mmcf)		2,279			3,607		-37	%			5,192			7,335		-29	%
Natural gas liquids (Mbbls)		111			136		-18	%			236			264		-11	%
Natural gas equivalents (Mmcfe)		3,854			5,277		-27	%			8,358			10,457		-20	%
Daily Sales Volumes:
Oil and condensate (Mbbls)		1.7			1.6		6	%			1.6			1.4		14	%
Natural gas (Mmcf)		25.0			39.6		-37	%			28.7			40.5		-29	%
Natural gas liquids (Mbbls)		1.2			1.5		-18	%			1.3			1.5		-11	%
Natural gas equivalents (Mmcfe)		42.4			58.0		-27	%			46.2			57.8		-20	%
Average sales prices:
Oil and condensate (per Bbl)	$	63.53		$	45.61		39	%		$	63.16		$	46.99		34	%
Natural gas (per Mcf)	$	2.57		$	3.09		-17	%		$	2.78		$	3.04		-9	%
Natural gas liquids (per Bbl)	$	26.84		$	19.50		38	%		$	25.32		$	20.40		24	%
Total (per Mcfe)	$	4.79		$	3.84		25	%		$	4.65		$	3.80		22	%

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2018			2017			%			2018			2017			%
Offshore Selected Costs ($ per Mcfe)
Lease operating expenses (1)	$	0.97		$	0.66		47	%		$	0.88		$	0.71		24	%
Production and ad valorem taxes	$	0.08		$	0.06		33	%		$	0.07		$	0.06		17	%
Onshore Selected Costs ($ per Mcfe)
Lease operating expenses (1)	$	2.09		$	1.94		8	%		$	2.21		$	2.07		7	%
Production and ad valorem taxes	$	0.39		$	0.29		34	%		$	0.38		$	0.29		31	%
Average Selected Costs ($ per Mcfe)
Lease operating expenses (1)	$	1.46		$	1.07		36	%		$	1.41		$	1.13		25	%
Production and ad valorem taxes	$	0.22		$	0.13		69	%		$	0.19		$	0.13		46	%
General and administrative expense (cash)	$	0.98		$	0.80		23	%		$	1.09		$	0.89		22	%
Interest expense	$	0.33		$	0.18		83	%		$	0.32		$	0.16		100	%
Adjusted EBITDAX (2) (thousands)	$	7,401		$	10,231					$	15,745		$	17,385
Weighted Average Shares Outstanding (thousands)
Basic		24,933			24,671						24,863			24,639
Diluted		24,933			24,671						24,863			24,639

(1)	LOE includes transportation and workover expenses.
(2)	Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income.

CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
	June 30,			December 31,
	2018			2017
ASSETS	(unaudited)
Cash and cash equivalents	$	—		$	—
Accounts receivable, net		10,927			13,059
Other current assets		1,701			2,714
Net property and equipment		339,953			345,957
Investment in affiliates and other non-current assets		19,867			19,723
TOTAL ASSETS	$	372,448		$	381,453
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued liabilities		42,111			46,755
Other current liabilities		4,160			3,782
Long-term debt		80,827			85,380
Asset retirement obligations		19,722			20,388
Other non-current liabilities		4,456			548
Total shareholders’ equity		221,172			224,600
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY	$	372,448		$	381,453

CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2018				2017				2018				2017
	(unaudited)
REVENUES
Oil and condensate sales	$	9,607			$	6,483			$	18,418			$	12,025
Natural gas sales		5,848				11,135				14,457				22,275
Natural gas liquids sales		2,993				2,658				6,010				5,400
Total revenues		18,448				20,276				38,885				39,700
EXPENSES
Operating expenses		6,478				6,329				13,405				13,162
Exploration expenses		394				284				863				375
Depreciation, depletion and amortization		9,498				12,714				19,983				24,485
Impairment and abandonment of oil and gas properties		777				1,401				4,104				1,431
General and administrative expenses		5,354				5,833				12,080				12,429
Total expenses		22,501				26,561				50,435				51,882
OTHER INCOME (EXPENSE)
Gain (loss) from investment in affiliates, net of income taxes		(475	)			166				232				1,950
Gain (loss) from sale of assets		1,370				(420	)			10,817				2,520
Interest expense		(1,262	)			(925	)			(2,671	)			(1,684	)
Gain (loss) on derivatives, net		(2,610	)			1,487				(3,642	)			4,583
Other income (expense)		3				61				882				(27	)
Total other income (expense)		(2,974	)			369				5,618				7,342
NET LOSS BEFORE INCOME TAXES		(7,027	)			(5,916	)			(5,932	)			(4,840	)
Income tax provision		(151	)			(118	)			(309	)			(309	)
NET LOSS	$	(7,178	)		$	(6,034	)		$	(6,241	)		$	(5,149	)

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 our 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 agreement.  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 agreement.  We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX.  Non-compliance with the financial covenants contained in our credit agreement 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,
	2018				2017				2018				2017
	(in thousands)
Net loss	$	(7,178	)		$	(6,034	)		$	(6,241	)		$	(5,149	)
Interest expense		1,262				925				2,671				1,684
Income tax provision		151				118				309				309
Depreciation, depletion and amortization		9,498				12,714				19,983				24,485
Exploration expense		394				284				863				375
EBITDAX	$	4,127			$	8,007			$	17,585			$	21,704
Unrealized loss (gain) on derivative instruments	$	1,792			$	(1,052	)		$	2,311			$	(4,327	)
Non-cash stock-based compensation charges		1,584				1,622				3,008				3,078
Impairment of oil and gas properties		793				1,400				3,890				1,400
Loss (gain) on sale of assets and investment in affiliates		(895	)			254				(11,049	)			(4,470	)
Adjusted EBITDAX	$	7,401			$	10,231			$	15,745			$	17,385

Guidance for Third Quarter 2018

The Company is providing the following guidance for the third calendar quarter of 2018.

Production	43,000 - 48,000 Mcfe per day
LOE (including transportation and workovers)	$5.2 million - $5.8 million
Production and ad valorem taxes (% of Revenue)	3.75% - 4.25%
Cash G&A	$4.25 million - $4.75 million
DD&A Rate	$2.30 - $2.55

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Thursday, August 9, 2018 at 8:00am Central Daylight Time.  Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-800-458-4148, (International 1-323-794-2597) and entering participation code 6006207.  A replay of the call will be available from Thursday, August 9, 2018 at 11:00am CDT through Wednesday, August 15, 2018 at 11:00am CDT by clicking in the audio replay link here and entering participation code 6006207.

Contango Oil & Gas Company is a Houston, Texas based, independent oil and natural gas company whose business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in West Texas, the Texas Gulf Coast and the 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 – 713-236-7400	Sergio Castro – 713-236-7400
Senior Vice President and Chief Financial Officer	Vice President and Treasurer

Source: Contango Oil & Gas