Quarterly / Earnings Reports | Second Quarter (2Q) Update

Contango Details Q2 Results, Ops

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Contango Oil & Gas Co. reported its financial results for the second quarter ended June 30, 2019 and provided an operational update. 

Second Quarter Highlights

• Production of 2.9 Bcfe for the quarter, or 32.3 Mmcfe per day, approximate mid-point of guidance

• Net loss of $5.0 million and EBITDAX of $4.4 million for the quarter. Adjusted EBITDAX of $3.1 million for the quarter, or $4.1 million when excluding non-recurring items described herein
• 17% decrease in general and administrative ("G&A") costs for the quarter, or a 35% decrease when excluding non-recurring items described herein
• Drilled three wells in Pecos County, TX in the Southern Delaware Basin and a fourth well in July
• Sequential completion operations commenced in July on two wells (including one previously drilled in 2018), and is expected to commence in September for the remaining three wells

Wilkie S. Colyer, the Company's President and Chief Executive Officer, said "Our goal in the Southern Delaware Basin this year was to add five more wells to our production base, and we are well on our way to accomplishing that goal. The Ripper State #2H, a Wolfcamp B well that we drilled in December 2018, was the first well to be completed this year and began flowback in late-July. During the first six months of the year, we drilled three new wells in the Southern Delaware Basin, with a fourth well drilled in July, and recently began sequential completion operations on those wells. Our capital program this year remains on track to add production and cash flow in the second half of 2019, with the majority coming online in the fourth quarter as we flow back our NE Bullseye wells. As previously disclosed, during this period of commodity price instability, we will limit our capital expenditures to those necessary to meet leasehold obligations and focus on keeping our leverage at a manageable level. We are also excited about a new casing program that we employed on our latest well, the Old Ironside #1H, which lowered our overall drilling cost by 15%."

Mr. Colyer continued, "We continue to work with our existing lenders and other sources of capital regarding a refinancing or replacement of our existing credit facility to provide additional liquidity to pursue bolt-on opportunities for growth in this price environment and for our capital expenditures. Concurrently, we continue to work with our financial advisor to assist us in evaluating strategic initiatives, including a satisfactory resolution of our need to refinance our credit facility, which matures on October 1, 2019."

Summary Second Quarter Financial Results

Net loss for the three months ended June 31, 2019 was $5.0 million, or $0.15 per basic and diluted share, compared to a net loss of $7.2 million, or $0.29 per basic and diluted share, for the prior year quarter. This improvement is mainly attributable to a pre-tax $2.1 million gain on derivatives, compared to a $2.6 million loss in the prior year quarter, partially offset by a $2.4 million decrease in operating margin (i.e. revenues less expenses, before other income/expense), due to lower production and lower commodity prices. Average weighted shares outstanding were approximately 33.9 million and 24.9 million for the current and prior year quarters, respectively.

The Company reported Adjusted EBITDAX, as defined below, of approximately $3.1 million for the three months ended June 30, 2019, compared to $7.4 million for the same period last year, a decrease attributable primarily to lower revenues and $1.0 million in special costs associated with our pursuit of strategic initiatives. Recurring Adjusted EBITDAX (defined as Adjusted EBITDAX exclusive of non-recurring strategic advisory fees) was $4.1 million for the current quarter, compared to $7.4 million for the prior year quarter. Cash flow for the current quarter was $2.1 million, or $0.06 per share, compared to $6.1 million, or $0.25 per share for the prior year quarter.

Revenues for the current quarter were approximately $12.8 million compared to $18.4 million for the prior year quarter, a decrease attributable to lower production during the current quarter due to non-core asset sales, downtime associated with repair and maintenance of an offshore compressor and pipeline, and the temporary suspension of our West Texas drilling program from October 2018 through the first quarter of 2019 due to the unstable price environment, coupled with an 8% decrease in both crude oil and natural gas prices and a 40% decrease in natural gas liquids prices.

Production for the second quarter of 2019 was approximately 2.9 Bcfe, or 32.3 Mmcfe per day, approximately the mid-point of our previously provided guidance, compared to 42.4 Mmcfe per day for the second quarter of 2018. This overall decrease was largely due to a 0.7 Bcf decrease in natural gas production attributable to non-core asset sales in 2018, downtime associated with repair and maintenance of an offshore compressor and pipeline, and normal offshore field decline. Crude oil and natural gas liquids production also decreased during the second quarter of 2019 to approximately 2,400 barrels per day, compared to approximately 2,900 barrels per day in the prior year quarter, a decline attributable in large part to the non-core asset sales and the temporary suspension of our West Texas drilling program from October 2018 through the first quarter of 2019. Our production for the third quarter of 2019 is expected to be between 30 and 35 Mmcfed, or comparable to second quarter production as the commencement of production on the wells currently being completed in the Southern Delaware Basin is not expected to begin until the fourth quarter. The percentage of production from higher-value oil and natural gas liquids increased from 41% in the prior year quarter to 45% in the current quarter. As a result of our current plans to complete and bring to production five wells during the second half of the year, we expect overall quarterly production and the percentage of liquids production to show improvement during the fourth quarter.

The weighted average equivalent sales price during the three months ended June 30, 2019 was $4.34 per Mcfe, compared to $4.79 per Mcfe for the same period last year, as we experienced an 8% decrease in both crude oil and natural gas prices and a 40% decrease in natural gas liquids prices.

Operating expenses for the three months ended June 30, 2019 were approximately $5.7 million, compared to $6.5 million 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 $5.0 million, and within our previously provided guidance, for the current quarter, compared to approximately $5.6 million for the prior year quarter, a decrease primarily attributable to the non-core asset sales. Our guidance for operating expenses for the third quarter of 2019, exclusive of production and ad valorem taxes, is between $4.7 and $5.3 million.

DD&A expense for the three months ended June 30, 2019 was $7.6 million, or $2.57 per Mcfe, compared to $9.5 million, or $2.46 per Mcfe, for the prior year quarter, a decrease attributable to lower production during the quarter.

Impairment and abandonment expense was $1.2 million for the current quarter, including approximately $0.2 million related to the impairment of certain proved properties, $0.4 million related to expiring leases and $0.6 million related to plug and abandonment expenses.

Total G&A expenses were $4.5 million for the three months ended June 30, 2019, compared to $5.4 million for the prior year quarter. Recurring G&A expenses (defined as G&A expenses exclusive of non-recurring strategic advisory fees of $1.0 million) were $3.5 million, or $1.18 per Mcfe for the current quarter, compared to $5.4 million, or $1.39 per Mcfe for the prior year quarter, an approximate 35% decline. The decrease relates primarily to $0.5 million in lower salaries and bonus expense during the current quarter due to a smaller administrative workforce and savings on office rent attained through a renewal of our corporate office lease. Recurring cash G&A (defined as G&A expenses exclusive of non-cash stock-based compensation of $0.6 million and non-recurring strategic advisory fees of $1.0 million) were $2.9 million for the current quarter, and below our previously provided guidance, compared to $3.8 million for the prior year quarter. For the third quarter of 2019, we have provided guidance of $3.0 to $3.5 million for cash general and administrative expenses, exclusive of non-recurring fees and costs.

Gain from affiliates (i.e., Exaro Energy III) for the three months ended June 30, 2019 was approximately $0.4 million, compared to a loss of $0.5 million for the same period last year.

Gain from sale of assets for the three months ended June 30, 2019 was approximately $0.4 million, which related to post-closing adjustments from non-core property sales during 2018 and 2019, compared to $1.4 million for the same period last year, which was related to the sale of our non-operated assets in Starr County, Texas.

Gain on derivatives for the three months ended June 30, 2019 was approximately $2.1 million. Of this amount, $0.5 million were realized gains while the remaining $1.6 million were non-cash, unrealized mark-to-market gains. Loss on derivatives for the three months ended June 30, 2018 was approximately $2.6 million, of which $0.8 million were realized losses while the remaining $1.8 million were non-cash, unrealized mark-to-market losses.

2019 Capital Program

Capital costs incurred for the three months ended June 30, 2019 were approximately $11.9 million, including $8.1 million for our drilling program in the Southern Delaware Basin in Pecos County, Texas. Our capital expenditure forecast for 2019 is approximately $35.1 million, including $29.2 million in the Southern Delaware Basin.

As of June 30, 2019, we had approximately $60 million of debt outstanding under our credit facility, with $13.1 million of availability, based on a borrowing base of $85 million, with an availability limit of $75 million, and we were in compliance with all but the Current Ratio covenant under our credit facility. We obtained a waiver for such non-compliance effective June 30, 2019. The Seventh Amendment to our credit agreement also set the next borrowing base redetermination to August 1, 2019, which currently is in progress.

Over the past several months, we have been in discussions with our current lenders and other sources of capital regarding a possible refinancing and/or replacement of our credit facility, which matures October 1, 2019. These discussions have included a possible new or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures and acquisitions. There is no assurance, however, that such discussions will result in a refinancing of the credit facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. While we expect to attain a favorable outcome on addressing the maturity date, these conditions raise substantial doubt about our ability to continue as a going concern.

Drilling Activity Update

Our recent Southern Delaware Basin activity consists of the following:

Ripper State #2H

The Ripper State #2H (49.6% WI, 37.2% NRI), targeting the Wolfcamp B formation and drilled in 2018 was recently completed and is currently flowing back.

American Hornet #1H

The American Hornet #1H (49.9% WI, 39.6% NRI), targeting the Wolfcamp A formation, was spud in April 2019. The well was drilled to a total measured depth of approximately 20,100 feet, including an approximate 9,800 foot lateral. Completion operations began in late-July 2019 and initial flowback is expected to begin later in the third quarter.

Iron Snake #1H

The Iron Snake #1H (50% WI, 37.5% NRI), targeting the Wolfcamp B formation, was spud in March 2019. The well was drilled to a total measured depth of approximately 20,500 feet, including an approximate 10,100 foot lateral. Completion operations are expected to begin in September, with initial flowback expected to begin in the fourth quarter.

Breakthrough State #1H

The Breakthrough State #1H (50% WI, 37.5% NRI), targeting the Wolfcamp A formation, was spud in June 2019. The well was drilled to a total measured depth of approximately 20,300 feet, including an approximate 9,800 foot lateral. Completion operations are expected to begin later this fall, with initial flowback expected to begin in the fourth quarter.

Old Ironside #1H

The Old Ironside #1H (49.7% WI, 37.3% NRI), targeting the Wolfcamp A formation, was spud in July 2019. The well was drilled to a total measured depth of approximately 20,400 feet, including an approximate 9,900 foot lateral. Completion operations are expected to begin later this fall, with initial flowback expected to begin in the fourth quarter.