HOUSTON, Aug. 08, 2019 (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, 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.
As of June 30, 2019, we had the following financial derivative contracts in place with members of our bank group or third-party counterparties under an unsecured line of credit with no margin call provisions. These contracts represent approximately 52% and 74% of our currently forecasted remaining 2019 natural gas and crude oil production from proved developed reserves (“PDP”), respectively, as well as 58% and 68% of our currently forecasted 2020 PDP natural gas and crude oil production, respectively.
|Natural Gas||Jul-19||Swap||600,000 MMBtus||$||2.75 (1)|
|Natural Gas||Aug 2019 - Oct 2019||Swap||100,000 MMBtus||$||2.75 (1)|
|Natural Gas||Nov 2019 - Dec 2019||Swap||500,000 MMBtus||$||2.75 (1)|
|Oil||July 2019 - Dec 2019||Collar||7,000 Bbls||$||50.00 - 58.00 (2)|
|Oil||July 2019 - Dec 2019||Collar||4,000 Bbls||$||52.00 - 59.45 (3)|
|Oil||Jul-19||Swap||6,000 Bbls||$||66.10 (3)|
|Oil||July 2019||Swap||12,000 Bbls||$||72.10 (3)|
|Oil||Aug 2019 - Oct 2019||Swap||9,000 Bbls||$||72.10 (3)|
|Oil||Nov 2019 - Dec 2019||Swap||12,000 Bbls||$||72.10 (3)|
|Oil||July 2019 - Dec 2019||Swap||2,400 Bbls||$||61.72 (3)|
|Natural Gas||Jan 2020 - March 2020||Swap||425,000 MMBtus||$||2.84 (1)|
|Natural Gas||April 2020 - July 2020||Swap||400,000 MMBtus||$||2.53 (1)|
|Natural Gas||Aug 2020 - Oct 2020||Swap||40,000 MMBtus||$||2.53 (1)|
|Natural Gas||Nov 2020 - Dec 2020||Swap||375,000 MMBtus||$||2.70 (1)|
|Oil||Jan 2020 - June 2020||Swap||22,000 Bbls||$||57.74 (3)|
|Oil||July 2020 - Dec 2020||Swap||15,000 Bbls||$||57.74 (3)|
- Based on Henry Hub NYMEX natural gas prices.
- Based on Argus Louisiana Light Sweet crude oil prices.
- Based on West Texas Intermediate crude oil prices.
In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI - Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was an $84 thousand loss as of June 30, 2019.
Selected Financial and Operating DataThe following table reflects certain comparative financial and operating data for the three and six months ended June 30, 2019 and 2018:
|Three Months Ended||Six months ended|
|June 30,||June 30,|
|Offshore Volumes Sold:|
|Oil and condensate (Mbbls)||10||18||-44||%||23||37||-38||%|
|Natural gas (Mmcf)||1,325||1,695||-22||%||2,960||3,991||-26||%|
|Natural gas liquids (Mbbls)||58||59||-2||%||124||137||-9||%|
|Natural gas equivalents (Mmcfe)||1,736||2,156||-19||%||3,847||5,033||-24||%|
|Onshore Volumes Sold:|
|Oil and condensate (Mbbls)||117||133||-12||%||230||255||-10||%|
|Natural gas (Mmcf)||303||584||-48||%||561||1,201||-53||%|
|Natural gas liquids (Mbbls)||34||52||-35||%||66||99||-33||%|
|Natural gas equivalents (Mmcfe)||1,206||1,698||-29||%||2,330||3,325||-30||%|
|Total Volumes Sold:|
|Oil and condensate (Mbbls)||127||151||-16||%||253||292||-13||%|
|Natural gas (Mmcf)||1,628||2,279||-29||%||3,521||5,192||-32||%|
|Natural gas liquids (Mbbls)||92||111||-17||%||190||236||-19||%|
|Natural gas equivalents (Mmcfe)||2,942||3,854||-24||%||6,177||8,358||-26||%|
|Daily Sales Volumes:|
|Oil and condensate (Mbbls)||1.4||1.7||-16||%||1.4||1.6||-13||%|
|Natural gas (Mmcf)||17.9||25.0||-29||%||19.5||28.7||-32||%|
|Natural gas liquids (Mbbls)||1.0||1.2||-17||%||1.0||1.3||-19||%|
|Natural gas equivalents (Mmcfe)||32.3||42.4||-24||%||34.1||46.2||-26||%|
|Average sales prices:|
|Oil and condensate (per Bbl)||$||58.42||$||63.53||-8||%||$||54.78||$||63.16||-13||%|
|Natural gas (per Mcf)||$||2.37||$||2.57||-8||%||$||2.70||$||2.78||-3||%|
|Natural gas liquids (per Bbl)||$||16.01||$||26.84||-40||%||$||18.05||$||25.32||-29||%|
|Total (per Mcfe)||$||4.34||$||4.79||-9||%||$||4.33||$||4.65||-7||%|
|Three Months Ended||Six Months Ended|
|June 30,||June 30,|
|Offshore Selected Costs ($ per Mcfe)|
|Lease operating expenses (1)||$||0.85||$||0.97||-12||%||$||0.79||$||0.88||-10||%|
|Production and ad valorem taxes||$||0.08||$||0.08||0||%||$||0.08||$||0.07||14||%|
|Onshore Selected Costs ($ per Mcfe)|
|Lease operating expenses (1)||$||2.95||$||2.09||41||%||$||2.92||$||2.21||32||%|
|Production and ad valorem taxes||$||0.43||$||0.39||10||%||$||0.32||$||0.38||-16||%|
|Average Selected Costs ($ per Mcfe)|
|Lease operating expenses (1)||$||1.72||$||1.46||18||%||$||1.59||$||1.41||13||%|
|Production and ad valorem taxes||$||0.22||$||0.22||0||%||$||0.17||$||0.19||-11||%|
|General and administrative expense (cash)||$||1.32||$||0.98||35||%||$||1.27||$||1.09||17||%|
|Adjusted EBITDAX (2) (thousands)||$||3,132||$||7,401||$||8,576||$||15,745|
|Weighted Average Shares Outstanding (thousands)|
- LOE includes transportation and workover expenses.
- Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income.
CONTANGO OIL & GAS COMPANYCONDENSED CONSOLIDATED BALANCE SHEETS(in thousands)
|June 30,||December 31,|
|Cash and cash equivalents||$||—||$||—|
|Accounts receivable, net||10,147||11,531|
|Other current assets||3,545||5,903|
|Net property and equipment||231,760||233,174|
|Investment in affiliates and other non-current assets||7,204||6,524|
|LIABILITIES AND SHAREHOLDERS' EQUITY|
|Accounts payable and accrued liabilities||47,966||39,506|
|Current portion of long-term debt||60,000||60,000|
|Other current liabilities||1,118||1,751|
|Asset retirement obligations||11,725||12,168|
|Other non-current liabilities||3,677||3,318|
|Total shareholders’ equity||128,170||140,389|
|TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY||$||252,656||$||257,132|
CONTANGO OIL & GAS COMPANYCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands)
|Three Months Ended||Six Months Ended|
|June 30,||June 30,|
|Oil and condensate sales||$||7,439||$||9,607||$||13,845||$||18,418|
|Natural gas sales||3,857||5,848||9,499||14,457|
|Natural gas liquids sales||1,466||2,993||3,429||6,010|
|Depreciation, depletion and amortization||7,573||9,498||15,129||19,983|
|Impairment and abandonment of oil and gas properties||1,247||777||1,834||4,104|
|General and administrative expenses||4,456||5,354||9,461||12,080|
|OTHER INCOME (EXPENSE)|
|Gain (loss) from investment in affiliates, net of income taxes||427||(475||)||457||232|
|Gain from sale of assets||421||1,370||409||10,817|
|Gain (loss) on derivatives, net||2,065||(2,610||)||(813||)||(3,642||)|
|Total other income (expense)||1,923||(2,974||)||(2,115||)||5,618|
|NET LOSS BEFORE INCOME TAXES||(4,534||)||(7,027||)||(13,125||)||(5,932||)|
|Income tax provision||(427||)||(151||)||(454||)||(309||)|
Non-GAAP Financial Measures
This news release includes certain non-GAAP financial information as defined by Securities and Exchange Commission (“SEC”) rules. Pursuant to SEC requirements, reconciliations of non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (GAAP) are included in this press release.
Adjusted EBITDAX represents net income (loss) before interest expense, taxes, depreciation, depletion and amortization, and oil and gas exploration expenses (“EBITDAX”) as further adjusted to reflect the items set forth in the table below and is a measure required to be used in determining our compliance with financial covenants under our credit facility. Recurring Adjusted EBITDAX represents Adjusted EBITDAX exclusive of non-recurring strategic advisory fees.
We have included 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 Adjusted EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and therefore 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 Adjusted EBITDAX in the evaluation of companies, many of which present Adjusted 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 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.
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,|
|Income tax provision||427||151||454||309|
|Depreciation, depletion and amortization||7,573||9,498||15,129||19,983|
|Unrealized loss (gain) on derivative instruments||$||(1,568||)||$||1,792||$||2,078||$||2,311|
|Non-cash stock-based compensation charges||585||1,584||1,637||3,008|
|Impairment of oil and gas properties||596||793||1,079||3,890|
|Gain on sale of assets and investment in affiliates||(848||)||(895||)||(866||)||(11,049||)|
|Non-recurring strategic advisory fees||985||—||1,736||—|
|Recurring Adjusted EBITDAX||$||4,117||$||7,401||$||10,312||$||15,745|
In addition to Adjusted EBITDAX, we may provide additional non-GAAP financial measures because our management believes providing investors with this information gives additional insights into our profitability, cash flows and expenses.
Adjusted EBITDAX and other non-GAAP measures in this release are not presentations made in accordance with generally accepted accounting principles, or GAAP. As discussed above, we believe that the presentation of non-GAAP financial measures in this release is appropriate. However, when evaluating our results, you should not consider the non-GAAP financial measures in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net loss. For example, Adjusted EBITDAX has material limitations as a performance measure because it excludes items that are necessary elements of our costs and operations. Because other companies may calculate Adjusted EBITDAX differently than we do, Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.
Guidance for Third Quarter 2019
The Company is providing the following guidance for the third calendar quarter of 2019.
|Production||30,000 - 35,000 Mcfe per day|
|LOE (including transportation and workovers)||$4.7 million - $5.3 million|
|Production and ad valorem taxes (% of Revenue)||3.75% - 4.25%|
|Cash G&A||$3.5 million - $4.0 million|
|DD&A Rate||$2.40 - $2.65|
Contango management will hold a conference call to discuss the information described in this press release on Friday, August 9, 2019 at 8:00 am Central Daylight Time. Those interested in participating in the earnings conference call may do so by calling 1-877-692-8955, (International 1-234-720-6979) and entering participation code 4251487. A replay of the call will be available from Friday, August 9, 2019 at 11:00am CDT through Friday, August 16, 2019 at 11:55pm CDT by calling 1-866-207-1041, (International 1-402-970-0847) and entering participation code 1369794.
About Contango Oil & Gas Company
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. Information on our website is not part of this release.
Forward-Looking Statements and Cautionary Statements
This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are, based on Contango’s current expectations and includes statements regarding our estimates of future production, and other guidance (including information regarding production, lease operating expenses, cash G&A expenses, and DD&A Rate), the Company’s drilling program and capital expenditures, a new casing program and expected reduction in overall drilling cost, acquisitions and divestitures, future results of operations, the refinancing or replacement of the Company’s credit facility or other strategic initiatives, the 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. Words and phrases used to identify our forward-looking statements include terms such as “guidance”, "expects", “projects”, "anticipates", “believes”, "plans", "estimates", "potential", "possible", "probable", or "intends", or words and phrases 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; our ability to comply with financial covenants in our debt instruments, repay indebtedness and access new sources of indebtedness, including our ability to refinance and/or replace our existing credit facility, provide additional liquidity for future capital expenditures and/or continue as a going concern; fluctuations in oil and gas prices; risks associated with derivative positions; our ability to realize expected value from acquisitions and to complete strategic dispositions of assets and realize the benefits of such dispositions; the need to take impairments on properties due to lower commodity prices; the limited trading volume of our common stock and general market volatility; ability of our management team to execute its plans or to meet its goals; shortages of drilling equipment, oil field personnel and services; unavailability of gathering systems, pipelines and processing facilities; the possibility that government policies may change or governmental approvals may be delayed or withheld; and the other factors discussed under the “Risk Factors” heading in our annual report on Form 10-K for the year ended December 31, 2018 and our quarterly reports on Form 10-Q filed with or furnished to the SEC. Additional information on these and other factors which could affect Contango’s operations or financial results are included in Contango’s reports on file with the SEC. 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 speak only as of the date they were made and 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. Initial production rates of wells and initial indications of formation performance or the benefits of any transaction are not necessarily indicative of future or long-term results.
|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|