Cabot Oil & Gas Corporation Announces Third Quarter 2017 Results, Provides 2018 Operating Plan and Three-Year Marcellus Shale Outlook

HOUSTON, Oct. 27, 2017 /PRNewswire/ -- Cabot Oil & Gas Corporation COG ("Cabot" or the "Company") today reported results for the third quarter of 2017.  

Third Quarter 2017 Strategic Highlights

• Received final approval for the Atlantic Sunrise project with construction beginning in mid-September
• Closed on the sale of the previously announced West Virginia divestiture, reducing year-to-date direct operations unit costs by 19 percent on a pro forma basis

Third Quarter 2017 Financial and Operating Highlights

• Equivalent daily production growth of 12 percent relative to the prior-year comparable quarter
• Net income of $17.6 million compared to a net loss of $10.3 million in the prior-year comparable quarter
• Adjusted net income (non-GAAP) of $32.0 million compared to an adjusted net loss of $16.7 million in the prior-year comparable quarter
• EBITDAX (non-GAAP) of $218.6 million, an increase of 57 percent relative to the prior-year comparable quarter
• Cash flow from operating activities of $189.1 million, an increase of 79 percent relative to the prior-year comparable quarter
• Generated positive free cash flow (non-GAAP) for the sixth consecutive quarter
• Natural gas price realizations improved by 16 percent relative to the prior-year comparable quarter
• Operating expenses per unit improved by four percent relative to the prior-year comparable quarter

See the supplemental tables at the end of this press release for a reconciliation of non-GAAP measures including adjusted net income (loss), EBITDAX, discretionary cash flow, free cash flow and net debt to adjusted capitalization ratio.

"Our disciplined approach to managing the business continued this quarter as we generated positive free cash flow despite lower than anticipated natural gas price realizations due to wider regional differentials," said Dan O. Dinges, Chairman, President and Chief Executive Officer. "We remain committed to delivering positive free cash flow in 2017 and beyond, while continuing to focus on improving our corporate returns and increasing our return of capital to shareholders through prudent capital allocation."

Third Quarter 2017 Financial Results

Equivalent production for the third quarter of 2017 was 169.5 billion cubic feet equivalent (Bcfe), consisting of 161.2 billion cubic feet (Bcf) of natural gas, 1,268.0 thousand barrels (Mbbls) of crude oil and condensate, and 124.7 Mbbls of natural gas liquids (NGLs). Natural gas production for the third quarter was at the low end of the Company's guidance range due to longer than anticipated downtime at third-party compressor stations and a delay in placing a seven-well pad on production due to weather-related pipeline construction delays. NGLs production was below the Company's guidance range due to downtime at a third-party processing plant in the Eagle Ford that was impacted by Hurricane Harvey.

Net income for the third quarter of 2017 was $17.6 million, or $0.04 per share, compared to a net loss of $10.3 million, or $0.02 per share, for the third quarter of 2016. Adjusted net income was $32.0 million, or $0.07 per share, compared to an adjusted net loss of $16.7 million, or $0.04 per share, for the third quarter of 2016. EBITDAX for the third quarter of 2017 was $218.6 million, compared to $139.2 million for the third quarter of 2016. Cash flow from operating activities for the third quarter of 2017 was $189.1 million, compared to $105.4 million for the third quarter of 2016. Discretionary cash flow (non-GAAP) for the third quarter of 2017 was $207.2 million, compared to $128.4 million for the third quarter of 2016. Free cash flow for the third quarter of 2017 was $4.0 million, compared to $36.7 million for the third quarter of 2016.

Natural gas price realizations, including the impact of derivatives, were $2.03 per thousand cubic feet (Mcf) for the third quarter of 2017, a 16 percent improvement compared to third quarter of 2016. Excluding the impact of derivatives, natural gas price realizations for the quarter were $2.01 per Mcf, representing a $0.99 discount to NYMEX settlement prices. Oil price realizations, including the impact of derivatives, were $45.53 per barrel (Bbl), an increase of 13 percent compared to the third quarter of 2016. NGL price realizations were $17.04 per Bbl, an increase of 35 percent compared to the third quarter of 2016.

Operating expenses (including financing) decreased to $2.06 per thousand cubic feet equivalent (Mcfe) in the third quarter of 2017, a four percent improvement compared to $2.14 per Mcfe in the third quarter of 2016. Cash operating expenses (excluding depreciation, depletion and amortization; stock-based compensation; exploratory dry hole cost; and amortization of debt issuance costs) decreased to $1.15 per Mcfe in the third quarter of 2017, a two percent improvement over the third quarter of 2016.

Cabot incurred a total of $175.5 million of capital expenditures during the third quarter of 2017 including $164.9 million of drilling and facilities capital associated with drilling 23 gross (20.4 net) wells and completing 30 gross (22.2 net) wells; $6.3 million of leasehold acquisition capital primarily associated with the Company's grassroots leasing efforts in two new exploratory operating areas; and $4.3 million of other capital. Additionally, the Company contributed $9.8 million to its equity pipeline investments in the Atlantic Sunrise and Constitution projects during the third quarter of 2017.

See the supplemental table at the end of this press release reconciling the capital expenditures for the quarter.

Year-To-Date 2017 Financial Results

Equivalent production for the nine-month period ended September 30, 2017 was 512.7 Bcfe, consisting of 491.2 Bcf of natural gas, 3,202.8 Mbbls of crude oil and condensate, and 380.6 Mbbls of NGLs.

For the nine-month period ended September 30, 2017, net income was $144.8 million, or $0.31 per share, compared to a net loss of $124.4 million, or $0.27 per share, for the nine-month period ended September 30, 2016. Adjusted net income was $185.1 million, or $0.40 per share, compared to an adjusted net loss of $102.2 million, or $0.23 per share, for the nine-month period ended September 30, 2016. EBITDAX for the nine-month period ended September 30, 2017 was $799.3 million, compared to $368.2 million for the nine-month period ended September 30, 2016. For the nine-month period ended September 30, 2017, cash flow from operations was $719.0 million, compared to $257.7 million for the nine-month period ended September 30, 2016. Discretionary cash flow was $736.0 million for the nine-month period ended September 30, 2017, compared to $297.1 million for the nine-month period ended September 30, 2016. Free cash flow was $125.8 million for the nine-month period ended September 30, 2017, compared to $27.9 million for the nine-month period ended September 30, 2016.

Natural gas price realizations, including the impact of derivatives, were $2.35 per Mcf for the nine-month period ended September 30, 2017, a 45 percent improvement compared to the nine-month period ended September 30, 2016. Oil price realizations, including the impact of derivatives, were $45.70 per Bbl, an increase of 27 percent compared to the nine-month period ended September 30, 2016. NGL price realizations were $18.08 per Bbl, an increase of 63 percent compared to the nine-month period ended September 30, 2016.

Operating expenses (including financing) decreased to $2.03 per Mcfe for the nine-month period ended September 30, 2017, an eight percent improvement compared to $2.21 per Mcfe for the nine-month period ended September 30, 2016. Cash operating expenses (excluding depreciation, depletion and amortization; stock-based compensation; exploratory dry hole cost; and amortization of debt issuance costs) decreased to $1.14 per Mcfe for the nine-month period ended September 30, 2017, a three percent improvement compared to the nine-month period ended September 30, 2016.

Cabot incurred a total of $582.8 million of capital expenditures during the nine-month period ended September 30, 2017 including $475.2 million of drilling and facilities capital associated with drilling 71 gross (62.5 net) wells and completing 81 gross (70.2 net) wells; $97.8 million of leasehold acquisition capital primarily associated with the Company's grassroots leasing efforts in two new exploratory operating areas; and $9.8 million of other capital. Additionally, the Company contributed $23.4 million to its equity pipeline investments in the Atlantic Sunrise and Constitution projects during the nine-month period ended September 30, 2017.

Third Quarter 2017 Operational Highlights

Marcellus Shale

During the third quarter of 2017, Cabot averaged 1,706 million cubic feet (Mmcf) per day of net Marcellus production (2,008 gross operated Mmcf per day). During the third quarter, the Company drilled and completed 13.2 net wells and placed 15.2 net wells on production. "We now have 49 fourth generation wells on production and the production data continues to support our 4.4 Bcf per 1,000 lateral feet type curve," noted Dinges. "Additionally, we have placed 12 fifth generation wells on production and the results to date are encouraging with an emphasis on increasing economics by lowering well costs without comprising recoveries."

Cabot is currently operating two rigs and utilizing one 24-hour completion crew in the Marcellus Shale and plans to remain at this level for the remainder of the year.

Eagle Ford Shale

Cabot's net production in the Eagle Ford Shale during the third quarter of 2017 was 15,656 barrels of oil equivalent (Boe) per day (87% oil), an increase of 19 percent sequentially compared to the second quarter of 2017. During the third quarter, the Company drilled 7.2 net wells and completed and placed on production 9.0 net wells. The nine wells placed on production during the quarter had an average lateral length of 10,163 feet, were completed with 1,938 pounds of proppant per foot, and had an average 30-day production rate of approximately 1,040 Boe per day.

Cabot is currently operating one rig and utilizing one 24-hour completion crew in the Eagle Ford Shale. The Company plans to maintain one rig for the remainder of the year and cease its completion activity for the year in mid-November.

Financial Position and Liquidity

As of September 30, 2017, Cabot had total debt of $1.5 billion and cash on hand of $510.3 million. The Company's net debt to adjusted capitalization ratio (non-GAAP) and net debt to last twelve months (LTM) EBITDAX ratio were 27.7 percent and 1.0x, respectively, compared to 28.5 percent and 1.8x as of December 31, 2016.

Total commitments under the Company's credit facility remain unchanged at $1.8 billion, with approximately $1.7 billion currently available to Cabot. The Company currently has no debt outstanding under the credit facility, resulting in approximately $2.2 billion of liquidity.

Fourth Quarter and Full-Year 2017 Guidance Update

Cabot has provided fourth quarter 2017 net production guidance of 1,775 to 1,850 Mmcf per day for natural gas (which reflects the divestiture of the West Virginia properties that closed in the third quarter); 13,250 to 14,250 Bbls per day for crude oil and condensate; and 1,350 to 1,450 Bbls per day for NGLs. "Our wider natural gas production guidance for the fourth quarter reflects the potential for price-related curtailments in the Marcellus due to the unfavorable prices we have witnessed in the daily cash market during the month of October," noted Dinges. "While we anticipate stronger pricing during November and December, we are committed to curtailing a portion of our production if the economics are value-destructive."

Based on the fourth quarter guidance, the Company has tightened its 2017 daily production growth guidance range to 9 - 11 percent. The Company has also reaffirmed its total 2017 program spending of $845 million.

2018 Operating Plan

The Company has initiated its 2018 daily production growth guidance range at 15 to 20 percent (17 to 22 percent pro forma for the West Virginia divestiture). This production growth is based on a capital budget range of $1.025 to $1.150 billion consisting of the following:

• Marcellus Shale:            $750 to $850 million
• Eagle Ford Shale:          $125 to $150 million
• Exploration Areas:         $75 million
• Pipeline Investments:    $60 million
• Corporate:                     $15 million

Cabot plans to operate three rigs and utilize two completion crews in the Marcellus Shale during 2018. The Company's capital allocation within this guidance range will ultimately be dependent on the timing of completion activity throughout the year, which will be driven by: the Company's outlook for realized natural gas prices; the corresponding level of operating cash flow generated; and the in-service timing of new infrastructure projects. "Our focus is on maximizing margins, returns and free cash flow and we firmly believe the flexibility in our current plan for 2018 will allow us to make the most prudent capital allocation decisions throughout the year in response to evolving market dynamics," commented Dinges.

While the Company's Marcellus growth profile in 2018 is expected to be weighted toward the second half of the year due to the timing of new infrastructure, the 2018 exit production rate is expected to be 35 percent higher than the 2017 Marcellus exit rate. The capital range for the Marcellus in 2018 will position Cabot for Marcellus production growth of 27 to 33 percent in 2019, subject to market conditions and infrastructure timing.

Cabot plans to operate one rig for the full-year and utilize one completion crew for a portion of the year in the Eagle Ford Shale during 2018. The Company's capital allocation within this guidance range will ultimately be dependent on our outlook for realized oil prices. At the current strip, the Company's Eagle Ford program would generate positive free cash flow and generate single-digit oil production growth in 2018.

The Company's exploration budget is comprised of the capital required for testing both exploratory areas during the first half of 2018. If the results from testing during the first half of the year warrant additional activity in the second half of the year, the Company anticipates it would fund the incremental spending with asset sales.    

Based on current market indications for commodity prices at the time of this press release, Cabot expects its natural gas price realizations to average $0.45 to $0.50 below NYMEX for the full year of 2018. Based on current strip prices and these differential assumptions, the Company's 2018 program would deliver the following highlights:

• Double-digit, corporate-wide returns
• Positive free cash flow of over $200 million at the mid-point of the capital budget range
• Net debt to LTM EBITDAX below 1.0x at year-end 2018
• Production growth of 15 to 20 percent
• Positions the Company for significant growth in free cash flow and production in 2019 and beyond

Three-Year Marcellus Outlook

Based on the Company's current three-year plan in the Marcellus Shale, Cabot anticipates delivering a three-year Marcellus production compounded annual growth rate (CAGR) from 2017 to 2020 of 20+ percent and a three-year Marcellus discretionary cash flow CAGR of 25+ percent assuming current strip prices (which implies an average realized natural gas price of approximately $2.50 per Mcf during this period). Based on this plan, Cabot's Marcellus asset would generate approximately $2.5 billion of cumulative pre-tax free cash flow from 2018 to 2020 while averaging between $750 and $850 million of annual Marcellus capital expenditures over this period. This plan is subject to market conditions and infrastructure timing and only includes the benefit of our future infrastructure projects that are currently under construction (Atlantic Sunrise pipeline project, Moxie Freedom power generation plant, Lackawanna Energy Center power generation plant, and Tennessee Gas Pipeline's Orion Project).

Capital allocation outside of the Marcellus in 2019 and 2020 will ultimately be dependent on the outlook for oil prices and the outcome of testing in the Company's exploration areas; however, the Company plans to target a self-funding program in the Eagle Ford and utilize asset sales to fund initial asset-level outspend in the exploration areas assuming they are successful.

"We believe that Cabot will deliver top-tier corporate-wide returns, free cash flow generation, and per share growth over the next three years, while returning an increasing amount of capital to our shareholders," highlighted Dinges.

Conference Call Webcast

A conference call is scheduled for Friday, October 27, 2017, at 9:30 a.m. Eastern Time to discuss third quarter 2017 financial and operating results. To access the live audio webcast, please visit the Investor Relations section of the Company's website. A replay of the call will also be available on the Company's website.

Cabot Oil & Gas Corporation, headquartered in Houston, Texas, is a leading independent natural gas producer with its entire resource base located in the continental United States. For additional information, visit the Company's website at www.cabotog.com.

This press release includes forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect", "project", "estimate", "believe", "anticipate", "intend", "budget", "plan", "forecast", "target", "predict", "may", "should", "could", "will" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (SEC) filings. See "Risk Factors" in Item 1A of the Form 10-K and subsequent public filings for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.  Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not undertake any obligation to correct or update any forward-looking statement, whether as the result of new information, future events or otherwise, except as required by applicable law.

FOR MORE INFORMATION CONTACT
Matt Kerin (281) 589-4642

 

 

 

 

Explanation and Reconciliation of Non-GAAP Financial Measures

The Company reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, the Company believes certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results, the results of its peers and of prior periods. In addition, the Company believes these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations throughout this release of GAAP financial measures to non-GAAP financial measures for the periods indicated.

Management has also included herein certain forward-looking non-GAAP financial measures. Due to the forward-looking nature of these non-GAAP financial measures, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in capital. Accordingly, the company is unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant.

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) and Adjusted Earnings Per Share

Adjusted Net Income (Loss) and Adjusted Earnings per Share are presented based on management's belief that these non-GAAP measures enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. Adjusted Net Income (Loss) and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP.

Discretionary Cash Flow and Free Cash Flow Calculation and Reconciliation

Discretionary Cash Flow is defined as net cash provided by operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company's ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary Cash Flow is presented based on management's belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income.

Free Cash Flow is defined as Discretionary Cash Flow (defined above) less capital expenditures and investment in equity method investments. Free Cash Flow is an indicator of a company's ability to generate cash flow after spending the money required to maintain or expand its asset base. Free Cash Flow is presented based on management's belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income.

 

EBITDAX Calculation and Reconciliation

EBITDAX is defined as net income plus loss on debt extinguishment, interest expense, other expense, income tax expense, depreciation, depletion and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, loss on equity method investments, and stock-based compensation expense. EBITDAX is presented based on management's belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. EBITDAX is not a measure of financial performance under GAAP and should not be considered as alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

Net Debt Reconciliation

The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders' equity. This ratio is a measurement which is presented in our annual and interim filings and management believes this ratio is useful to investors in determining the Company's leverage. Net Debt is calculated by subtracting cash and cash equivalents from total debt. Net Debt and the Net Debt to Total Capitalization ratio are non-GAAP measures which management believes are also useful to investors since the Company has the ability to and may decide to use a portion of its cash and cash equivalents to retire debt. Additionally, as the Company may incur additional expenditures without increasing debt, it is appropriate to apply cash and cash equivalents to debt in calculating the Net Debt to Total Capitalization ratio.

 

 

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SOURCE Cabot Oil & Gas Corporation