HOUSTON, May 09, 2017 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE MKT:MCF) (“Contango” or the “Company”) announced today its financial results for the first quarter ended March 31, 2017 and provided an operational update.
First Quarter Highlights
- Production of 5.2 Bcfe for the quarter, or 57.6 Mmcfed
- Net income of $0.9 million for the quarter
- Adjusted EBITDAX, on a recurring basis, of $7.2 million for the quarter
- Commenced production from our Pecos County acreage in the Southern Delaware Basin, targeting the Upper Wolfcamp formation
Summary First Quarter Financial Results
Net income for the three months ended March 31, 2017 was $0.9 million, or $0.04 per basic and diluted share, compared to a net loss of $11.4 million, or $(0.60) per basic and diluted share, for the same period last year. This improvement was attributable primarily to higher revenues from higher prices, lower operating expenses from cost improvements, lower depreciation, depletion, and amortization (“DD&A”) expense and impairment expenses, a higher gain attributable to our investment in Exaro Energy III LLC (“Exaro”) and a gain from the sale of a non-core South Texas gas field. Average weighted shares outstanding were approximately 24.6 million and 19.1 million for the current and prior year quarters, respectively.
The Company reported Adjusted EBITDAX, as defined below, of approximately $7.2 million for the three months ended March 31, 2017, compared to $7.3 million for the same period last year. Cash flow for the current quarter was $6.4 million, or $0.26 per share, compared to $6.4 million, or $0.33 per share for the prior year quarter.
Revenues for the current quarter were approximately $19.4 million compared to $17.6 million for the 2016 quarter. Despite lower production during the current quarter, the dramatic increase in commodity prices was responsible for the increase in revenues.
Production for the first quarter of 2017 was approximately 5.2 Bcfe, or 57.6 Mmcfe per day, within our previously provided guidance, compared to 79.4 Mmcfe per day for the first quarter of 2016. This expected decline in production can be attributed to minimal new production added during 2016 and 2017 because of our reduced 2016 drilling program in response to the low and uncertain commodity price environment. Crude oil and natural gas liquids production during the first quarter of 2017 was approximately 2,700 barrels per day, or 28% of total production, compared to approximately 4,200 barrels per day, or 32% of total production, in the first quarter of 2016, a decline related to the lower capital expenditures in 2016. Our production guidance for the second quarter of 2017 is expected to be relatively flat with the first quarter, or 54 – 59 Mmcfed, as we start to add initial production from our Southern Delaware Basin drilling activity.
The weighted average equivalent sales price during the three months ended March 31, 2017 was $3.75 per Mcfe, compared to $2.43 per Mcfe for the same period last year, as we experienced increases of 72%, 48% and 78% in crude oil, natural gas and natural gas liquids prices, respectively compared to the prior year quarter.
Operating expenses for the three months ended March 31, 2017 were approximately $6.8 million, or $1.32 per Mcfe and within our previously provided guidance, compared to $7.6 million, or $1.05 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 $6.2 million, or $1.19 per Mcfe, for the current quarter compared to approximately $6.7 million, or $0.93 per Mcfe, for the prior year quarter. Our guidance for operating expenses for the second quarter of 2017, exclusive of production and ad valorem taxes, is between $6.2 to $6.8 million, higher than the recent quarter due to additional workovers scheduled for the upcoming quarter.
DD&A expense for the three months ended March 31, 2017 was $11.8 million, or $2.27 per Mcfe, compared to $16.5 million, or $2.29 per Mcfe, for the prior year quarter, a decrease primarily attributable to lower production during the quarter.
Impairment and abandonment expense of oil and gas properties was $30 thousand for the current quarter. Impairment and abandonment expense of oil and gas properties for the three months ended March 31, 2016 was $1.9 million. Of this amount, approximately $0.7 million was related to impairment of proved properties and $1.1 million was related to the impairment of unproved properties primarily in Fayette and Gonzales counties, Texas.
G&A expenses for the three months ended March 31, 2017 were $6.6 million, or $1.27 per Mcfe, compared to $5.9 million, or $0.82 per Mcfe, for the prior year quarter. G&A expenses for the current and prior year quarters include $1.5 million and $1.7 million, respectively, in non-cash stock compensation expense. Other items contributing to the increase in G&A costs for the current quarter were higher cash incentive bonus accruals for 2017 compared to no accruals in 2016; accrual of retention bonuses for certain non-executive employees in 2017 and lower cash compensation costs in the prior quarter due to the implementation of our salary replacement program in late 2015, where cash employee salaries and director’s retainer fees were reduced by 10%, with that amount to be paid at the end of 2016 in common stock. That program was discontinued in latter 2016. For the second quarter of 2017, we have provided guidance of $5.2 million to $5.8 million for general and administrative expenses, exclusive of non-cash stock compensation (“Cash G&A”).
Gain from affiliates for the three months ended March 31, 2017 was approximately $1.8 million, compared to a gain of $40 thousand for the same period last year, associated with our investment in Exaro.
2017 Capital Program
Capital costs incurred for the three months ended March 31, 2017 were approximately $19.3 million, including $3.0 million in paid and accrued leasehold acquisition costs and $16.1 million for the drilling and completion of wells in the Southern Delaware Basin in Pecos County, Texas. Our capital expenditure budget for 2017 was originally forecasted to be $46.3 million, including $36.6 million to drill and/or complete nine gross wells (4.0 net) on our Southern Delaware Basin acreage. We have revised our 2017 budget to include an additional $11.2 million in drilling and completion costs for one additional gross well (0.5 net), and anticipated increases in the cost of vendor and supplier goods and services, which increases our forecast for the year to a total of $57.5 million.
As of March 31, 2017, we had approximately $59.7 million of debt outstanding under our credit facility. Effective May, 4, 2017, the borrowing base under our facility was redetermined at $125 million, which reflects the impact of our limited drilling program in 2016 as well as no benefit from our 2017 drilling program as the borrowing base is redetermined based on year-end reserves.
Derivative Instruments
We have the following financial derivative contracts in place for the remainder of the year:
| Commodity | Period | Derivative | Volume/Month | Price/Unit (1) | |||||
| Natural Gas | Apr - July 2017 | Collar | 400,000 MMBtus | $ | 2.65 - 3.00 | ||||
| Natural Gas | Aug - Oct 2017 | Collar | 200,000 MMBtus | $ | 2.65 - 3.00 | ||||
| Natural Gas | Nov - Dec 2017 | Collar | 400,000 MMBtus | $ | 2.65 - 3.00 | ||||
| Natural Gas | Apr - July 2017 | Swap | 300,000 MMBtus | $ | 3.51 | ||||
| Natural Gas | Aug - Oct 2017 | Swap | 70,000 MMBtus | $ | 3.51 | ||||
| Natural Gas | Nov - Dec 2017 | Swap | 300,000 MMBtus | $ | 3.51 | ||||
| Oil | Apr - July 2017 | Swap | 9,000 Bbls | $ | 53.95 | ||||
| Oil | Aug - Oct 2017 | Swap | 6,000 Bbls | $ | 53.95 | ||||
| Oil | Nov - Dec 2017 | Swap | 8,000 Bbls | $ | 53.95 | ||||
| Oil | Apr - Dec 2017 | Swap | 9,000 Bbls | $ | 56.20 | ||||
(1) Commodity price derivatives based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable.
Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three months ended March 31, 2017 and 2016:
| Three Months Ended | |||||||||
| March 31, | |||||||||
| 2017 | 2016 | % | |||||||
| Offshore Volumes Sold: | |||||||||
| Oil and condensate (Mbbls) | 22 | 51 | -57 | % | |||||
| Natural gas (Mmcf) | 3,008 | 3,838 | -22 | % | |||||
| Natural gas liquids (Mbbls) | 84 | 113 | -26 | % | |||||
| Natural gas equivalents (Mmcfe) | 3,646 | 4,821 | -24 | % | |||||
| Onshore Volumes Sold: | |||||||||
| Oil and condensate (Mbbls) | 92 | 134 | -31 | % | |||||
| Natural gas (Mmcf) | 720 | 1,082 | -33 | % | |||||
| Natural gas liquids (Mbbls) | 44 | 86 | -49 | % | |||||
| Natural gas equivalents (Mmcfe) | 1,534 | 2,405 | -36 | % | |||||
| Total Volumes Sold: | |||||||||
| Oil and condensate (Mbbls) | 114 | 185 | -38 | % | |||||
| Natural gas (Mmcf) | 3,728 | 4,920 | -24 | % | |||||
| Natural gas liquids (Mbbls) | 128 | 199 | -36 | % | |||||
| Natural gas equivalents (Mmcfe) | 5,180 | 7,226 | -28 | % | |||||
| Daily Sales Volumes: | |||||||||
| Oil and condensate (Mbbls) | 1.3 | 2.0 | -38 | % | |||||
| Natural gas (Mmcf) | 41.4 | 54.1 | -24 | % | |||||
| Natural gas liquids (Mbbls) | 1.4 | 2.2 | -36 | % | |||||
| Natural gas equivalents (Mmcfe) | 57.6 | 79.4 | -28 | % | |||||
| Average sales prices: | |||||||||
| Oil and condensate (per Bbl) | $ | 48.71 | $ | 28.39 | 72 | % | |||
| Natural gas (per Mcf) | $ | 2.99 | $ | 2.02 | 48 | % | |||
| Natural gas liquids (per Bbl) | $ | 21.36 | $ | 11.99 | 78 | % | |||
| Total (per Mcfe) | $ | 3.75 | $ | 2.43 | 54 | % | |||
| Three Months Ended | |||||||||
| March 31, | |||||||||
| 2017 | 2016 | % | |||||||
| Offshore Selected Costs ($ per Mcfe) | |||||||||
| Lease operating expenses (1) | $ | 0.93 | $ | 0.51 | 82 | % | |||
| Production and ad valorem taxes | $ | 0.13 | $ | 0.07 | 86 | % | |||
| Onshore Selected Costs ($ per Mcfe) | |||||||||
| Lease operating expenses (1) | $ | 1.81 | $ | 1.77 | 2 | % | |||
| Production and ad valorem taxes | $ | 0.13 | $ | 0.22 | -41 | % | |||
| Average Selected Costs ($ per Mcfe) | |||||||||
| Lease operating expenses (1) | $ | 1.19 | $ | 0.93 | 28 | % | |||
| Production and ad valorem taxes | $ | 0.13 | $ | 0.12 | 8 | % | |||
| General and administrative expense (cash) | $ | 0.99 | $ | 0.58 | 71 | % | |||
| Interest expense | $ | 0.15 | $ | 0.12 | 25 | % | |||
| Adjusted EBITDAX (2) (thousands) | $ | 7,154 | $ | 7,264 | |||||
| Weighted Average Shares Outstanding (thousands) | |||||||||
| Basic | 24,607 | 19,079 | |||||||
| Diluted | 24,641 | 19,079 | |||||||
| | |||||||||
| (1) LOE includes transportation and workover expenses. (2) Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income (loss). | |||||||||
| CONTANGO OIL & GAS COMPANY | ||||||
| CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||
| (in thousands) | ||||||
| March 31, | December 31, | |||||
| 2017 | 2016 | |||||
| ASSETS | (unaudited) | |||||
| Cash and cash equivalents | $ | — | $ | — | ||
| Accounts receivable, net | 11,825 | 16,727 | ||||
| Other current assets | 2,267 | 2,327 | ||||
| Net property and equipment | 344,642 | 340,382 | ||||
| Investment in affiliates and other non-current assets | 18,744 | 17,078 | ||||
| TOTAL ASSETS | $ | 377,478 | $ | 376,514 | ||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||
| Accounts payable and accrued liabilities | 52,958 | 55,135 | ||||
| Other current liabilities | 5,929 | 7,754 | ||||
| Long-term debt | 59,722 | 54,354 | ||||
| Asset retirement obligations | 19,949 | 22,618 | ||||
| Other non-current liabilities | 248 | 248 | ||||
| Total shareholders’ equity | 238,672 | 236,405 | ||||
| TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY | $ | 377,478 | $ | 376,514 | ||
| CONTANGO OIL & GAS COMPANY | ||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||
| (in thousands) | ||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2017 | 2016 | |||||||
| (unaudited) | ||||||||
| REVENUES | ||||||||
| Oil and condensate sales | $ | 5,542 | $ | 5,247 | ||||
| Natural gas sales | 11,140 | 9,935 | ||||||
| Natural gas liquids sales | 2,742 | 2,400 | ||||||
| Total revenues | 19,424 | 17,582 | ||||||
| EXPENSES | ||||||||
| Operating expenses | 6,833 | 7,604 | ||||||
| Exploration expenses | 91 | 320 | ||||||
| Depreciation, depletion and amortization | 11,771 | 16,545 | ||||||
| Impairment and abandonment of oil and gas properties | 30 | 1,851 | ||||||
| General and administrative expenses | 6,596 | 5,902 | ||||||
| Total expenses | 25,321 | 32,222 | ||||||
| OTHER INCOME (EXPENSE) | ||||||||
| Gain from investment in affiliates, net of income taxes | 1,784 | 40 | ||||||
| Gain from sale of assets | 2,940 | — | ||||||
| Interest expense | (759 | ) | (878 | ) | ||||
| Gain on derivatives, net | 3,096 | 4,204 | ||||||
| Other expense | (88 | ) | (40 | ) | ||||
| Total other income | 6,973 | 3,326 | ||||||
| NET INCOME (LOSS) BEFORE INCOME TAXES | 1,076 | (11,314 | ) | |||||
| Income tax provision | (191 | ) | (90 | ) | ||||
| NET INCOME (LOSS) | $ | 885 | $ | (11,404 | ) | |||
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 | ||||||||
| March 31, | ||||||||
| 2017 | 2016 | |||||||
| (in thousands) | ||||||||
| Net income (loss) | $ | 885 | $ | (11,404 | ) | |||
| Interest expense | 759 | 878 | ||||||
| Income tax provision | 191 | 90 | ||||||
| Depreciation, depletion and amortization | 11,771 | 16,545 | ||||||
| Exploration expense | 91 | 320 | ||||||
| EBITDAX | $ | 13,697 | $ | 6,429 | ||||
| Unrealized gain on derivative instruments | $ | (3,275 | ) | $ | (2,696 | ) | ||
| Non-cash stock-based compensation charges | 1,456 | 1,699 | ||||||
| Impairment of oil and gas properties | — | 1,872 | ||||||
| Gain on sale of assets and investment in affiliates | (4,724 | ) | (40 | ) | ||||
| Adjusted EBITDAX | $ | 7,154 | $ | 7,264 | ||||
Drilling Activity Update
Our recent Southern Delaware Basin activity consists of the following:
Lonestar Gunfighter
The Lonestar-Gunfighter #1H, an Upper Wolfcamp test in the northwest portion of our acreage position, initiated flow back in January 2017, on a controlled flow basis, reaching a maximum 24-hour IP rate of 966 Boed (72% oil). The well was drilled to a Total Measured Depth (“TMD”) of 20,801 feet with a 10,074 foot lateral and 50 frac stages. For the past five days, since running tubing in preparation for artificial gas lift, the well has averaged 593 Boed (71% oil).
Rude Ram
The Rude Ram #1H was drilled from a common surface location with the Ripper State #1H one mile south of the Lonestar-Gunfighter, also targeting the Upper Wolfcamp. The well was completed in April 2017, with 30 day initial rate expected in late May. The well was drilled to a TMD of 20,804 feet with a 10,103 foot lateral and 50 frac stages.
Ripper State
The Ripper State #1H was drilled from a common surface location with the Rude Ram #1H one mile south of the Lonestar-Gunfighter, also targeting the Upper Wolfcamp. The well was completed in April 2017, with 30 day initial rate expected in late May. The well was drilled to a TMD of 20,898 feet with a 10,152 foot lateral and 50 frac stages.
Grim Reaper
The Grim Reaper #1H was initially drilled in February 2017 as a vertical pilot well through the Lower Wolfcamp, and after reaching a TMD of 12,508 feet in the Lower Wolfcamp and logging the well, casing problems in the intermediate hole section prohibited a sidetrack into the Upper Wolfcamp. It was therefore decided to perforate, frac and test several zones in the Lower Wolfcamp section that looked prospective on the logs and had hydrocarbon shows while drilling. These tests, which commenced in early May, could provide valuable knowledge about other potential opportunity levels across the leasehold.
Gunner
After drilling the Grim Reaper, the rig was moved to the Gunner location, approximately two miles southeast of the Lonestar-Gunfighter, also targeting the Upper Wolfcamp, and drilling is in progress. We expect completion operations to commence in early July.
Management Commentary
Allan D. Keel, the Company’s President and Chief Executive Officer, said “We continue to advance the de-risking and development of our Southern Delaware Basin acreage. To date we have brought three wells on production, the first of which we previously announced and the other two which have been on-line for less than 30 days. Upon completion of the Gunner, we will likely move the rig back to the Grim Reaper location to drill a new horizontal well, the Crusader #1, as we continue moving forward toward de-risking our position and maximizing our results.”
Guidance for Second Quarter 2017
The Company is providing the following guidance for the second calendar quarter of 2017.
| Production | 54,000 - 59,000 Mcfe per day | ||
| LOE (including transportation and workovers) | $6.2 million - $6.8 million | ||
| Production and ad valorem taxes (% of Revenue) | 5.00% | ||
| Cash G&A | $5.2 million - $5.8 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 Wednesday, May 10, 2017 at 9:30am Central Daylight Time. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-800-723-6604, (International 1-785-830-7977) and entering the following participation code: 9929003. A replay of the call will be available from Wednesday, May 10, 2017 at 12:30pm CDT through Wednesday, May 17, 2017 at 12:30pm CDT by clicking in the audio replay link here, and entering participation code 9929003.
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 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.