Cabot Oil & Gas Corporation Announces Fourth-Quarter and Full-Year 2017 Results, Expands Share Repurchase Program Authorization

Full-year 2017 net cash provided by operating activities was $898.2 million, compared to $397.4 million in the prior-year period. Full-year 2017 discretionary cash flow (non-GAAP) was $976.1 million, compared to $460.7 million in the prior-year period. Full-year 2017 free cash flow (non-GAAP) was $154.5 million, compared to $57.1 million in in the prior-year period.

Full-year 2017 natural gas price realizations, including the impact of derivatives, were $2.31 per Mcf, a 36 percent improvement compared to the prior-year period. Excluding the impact of derivatives, full-year 2017 natural gas price realizations were $2.30 per Mcf, representing an $0.80 discount to NYMEX settlement prices. Full-year 2017 oil price realizations, including the impact of derivatives, were $48.16 per barrel (Bbl), an increase of 29 percent compared to the prior-year period. NGL price realizations were $19.47 per Bbl, an increase of 66 percent compared to the prior-year period. Full-year 2017 operating expenses (including financing) decreased to $2.02 per Mcfe, a seven percent improvement compared to the prior-year period.

Cabot incurred a total of $757.2 million of capital expenditures in 2017 including $637.2 million of drilling and facilities capital associated with drilling 91 gross (82.5 net) wells and completing 105 gross (94.2 net) wells; $102.3 million of leasehold acquisition capital primarily associated with the Company's grassroots leasing efforts in two new exploratory operating areas; and $17.7 million of other capital. Additionally, the Company contributed $57.0 million to its equity pipeline investments in 2017. See the supplemental table at the end of this press release reconciling the capital expenditures for the year.

Fourth-Quarter 2017 Financial Results

Fourth-quarter 2017 equivalent production was 172.6 Bcfe, consisting of 164.4 Bcf of natural gas, 1,238.0 Mbbls of crude oil and condensate, and 131.5 Mbbls of NGLs. On a divestiture-adjusted basis (which reflects the impact of the West Virginia disposition that closed in the third-quarter), Cabot's equivalent production increased four percent sequentially compared to the third-quarter. Natural gas production for the fourth-quarter came in on the lower end of the Company's guidance range primarily due to delayed in-service dates for two new third-party compressor stations, of which one was placed in-service in January 2018 and one that is expected to be in-service by the end of the first quarter.

Fourth-quarter 2017 net loss was $44.4 million, or $0.10 per share, compared to net loss of $292.8 million, or $0.63 per share, in the prior-year period. Fourth-quarter 2017 adjusted net income (non-GAAP) was $59.5 million, or $0.13 per share, compared to adjusted net income of $5.1 million, or $0.01 per share, in the prior-year period. Fourth-quarter 2017 EBITDAX (non-GAAP) was $259.8 million, compared to $187.8 million in the prior-year period.

Fourth-quarter 2017 net cash provided by operating activities was $179.1 million, compared to $139.7 million in the prior-year period. Fourth-quarter 2017 discretionary cash flow (non-GAAP) was $240.1 million, compared to $163.6 million in the prior-year period. Fourth-quarter 2017 free cash flow (non-GAAP) was $28.7 million, compared to $29.1 million in in the prior-year period.

Fourth-quarter 2017 natural gas price realizations, including the impact of derivatives, were $2.18 per Mcf, a 12 percent improvement compared to the prior-year period. Excluding the impact of derivatives, fourth-quarter 2017 natural gas price realizations were $2.15 per Mcf, representing a $0.78 discount to NYMEX settlement prices. Fourth-quarter 2017 oil price realizations, including the impact of derivatives, were $54.54 per Bbl, an increase of 27 percent compared to the prior-year period. NGL price realizations were $23.51 per Bbl, an increase of 70 percent compared to the prior-year period. Fourth-quarter 2017 operating expenses (including financing) decreased to $2.01 per Mcfe, a two percent improvement compared to the prior-year period.

Cabot incurred a total of $174.5 million of capital expenditures in the fourth-quarter of 2017 including $162.0 million of drilling and facilities capital associated with drilling 20 gross (20.0 net) wells and completing 24 gross (24.0 net) wells; $4.4 million of leasehold acquisition capital primarily associated with the Company's grassroots leasing efforts in two new exploratory operating areas; and $8.1 million of other capital. Additionally, the Company contributed $33.7 million to its equity pipeline investments in 2017. See the supplemental table at the end of this press release reconciling the capital expenditures during the fourth-quarter of 2017.

Year-End 2017 Financial Position and Liquidity

As of December 31, 2017, Cabot had total debt of $1.5 billion and cash on hand of $480.0 million. The Company's net debt to adjusted capitalization ratio and net debt to trailing twelve months EBITDAX ratio were 29.2 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 the Company.  The Company currently has no debt outstanding under the credit facility, resulting in approximately $2.2 billion of liquidity.

Share Repurchase Program Update

During the fourth-quarter of 2017, Cabot repurchased 2.0 million shares at a weighted-average share price of $27.72. For the full-year 2017, the Company repurchased 5.0 million shares at a weighted-average share price of $24.52.

The Board of Directors has authorized an increase in the Company's share repurchase program to 30 million shares (or approximately 6.5 percent of its current shares outstanding).  All purchases will be made in accordance with applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may be discontinued at any time.  Based on the closing share price on February 22, 2018, the program implies approximately $720 million of potential share repurchases. "Subsequent to the closing of our Eagle Ford Shale divestiture (which is expected to close on February 28, 2018), we will have approximately $1.2 billion of cash on hand. This cash position, along with our anticipated free cash flow in 2018, provides us the financial flexibility to execute on an expanded share repurchase program while continuing to reinvest in returns-focused, organic growth from our existing asset base," stated Dinges.

Year-End 2017 Proved Reserves

Cabot reported year-end proved reserves of 9.7 trillion cubic feet equivalent (Tcfe), an increase of 13 percent over year-end 2016. Specific highlights from the Company's year-end reserve report include:

• Total company all-sources finding and development costs of $0.35 per Mcfe
• Marcellus-only all-sources finding and development costs of $0.22 per Mcf
• Total company all-sources reserve replacement of 316 percent
• Marcellus-only all-sources reserve replacement of 305 percent

The table below reconciles the components driving the 2017 reserve increase:

As of December 31, 2017, 96 percent of Cabot's year-end proved reserves were natural gas and 96 percent were located in the Marcellus Shale. Approximately 64 percent of the year-end proved reserves were classified as proved developed and 36 percent were classified as proved undeveloped (PUD), including eight percent of drilled and uncompleted PUDs.

Total costs incurred during 2017 were $761.0 million, which included $617.5 million for development costs, $41.2 million for exploration costs, and $102.3 million for lease acquisition costs.

The SEC prices used for reporting Cabot's year-end 2017 proved reserves, which have been adjusted for basis and quality differentials, were $2.33 per Mcf for natural gas and $49.26 per Bbl for crude oil, representing a 34 percent and 31 percent year-over-year increase, respectively. Assuming the SEC prices, the pre-tax PV–10 (non-GAAP) of the year-end 2017 proved reserves was $6.0 billion.

Tax Reform Impact

On December 22, 2017, the U.S. enacted tax legislation referred to as the Tax Cuts and Jobs Act (the "Tax Act"), which made significant changes to U.S. federal income tax law. These changes include, among others, a permanent reduction of the U.S. corporate income tax rate from a top marginal rate of 35 percent to a flat rate of 21 percent; elimination of the corporate alternative minimum tax (AMT); and immediate deductions for certain new investments instead of deductions for depreciation expense over time. Overall, the Company expects the provisions of the Tax Act to favorably impact its future effective tax rate, after-tax earnings, and cash flows.

As a result of the enactment of the Tax Act, Cabot recorded an income tax benefit of $242.9 million in the fourth-quarter of 2017 resulting from the remeasurement of the Company's net deferred tax liabilities based on the new lower corporate income tax rate. As of December 31, 2017, the Company had AMT credit carryforwards of $208.6 million, which do not expire and can be used to offset regular income taxes in future years. Under the new Tax Act, the Company may claim a refund of 50 percent of the remaining AMT credits (to the extent the credits exceed regular tax for the year) in 2018, 2019, and 2020. Any AMT credits remaining after 2020 will be refunded in 2021. The Company expects a net refund of $97.1 million related to 2018.

First-Quarter and Full-Year 2018 Guidance Update

Cabot has provided first-quarter 2018 net production guidance of 1,775 to 1,825 million cubic feet (Mmcf) per day for natural gas; 7,500 to 8,000 Bbls per day for crude oil and condensate; and 700 to 800 Bbls per day for NGLs. This guidance range assumes a February 28, 2018 closing date for the Company's previously announced Eagle Ford divestiture and reflects the impact of the previously mentioned in-service delay for two new third-party compressor stations in the Marcellus.   

Cabot has reaffirmed its 2018 daily production growth guidance of 10 to 15 percent (18 to 23 percent on a divestiture-adjusted basis to reflect the impact of the previously announced Eagle Ford, East Texas, and West Virginia dispositions). "Our 2018 production growth is weighted toward the second half of the year driven by anticipated mid-year in-service dates for the Moxie Freedom power plant, Lackawanna Energy Center power plant, and Atlantic Sunrise pipeline," noted Dinges. "We anticipate sequential quarterly growth of approximately six, eleven and thirteen percent in the second, third, and fourth quarters, respectively, resulting in a divestiture-adjusted exit-to-exit production growth rate of over 35 percent."

The Company has also updated its capital budget to $950 million (consistent with the midpoint of the previously announced 2018 budget) as follows:

The Company plans to average three rigs and two completion crews in the Marcellus Shale during 2018, resulting in 85 net wells drilled and 95 net wells completed. The average lateral length for the 2018 Marcellus Shale drilling program is 8,300 feet and the expected average well cost is $8.3 million ($1,000 per foot) for drilling, completion and facilities. This average well cost incorporates anticipated cost inflation resulting from new service contracts, offset by efficiencies associated with implementing the Generation 5 well design across the majority of the program. "Our Generation 5 wells continue to track our 4.4 Bcf per 1,000 lateral feet type curve, which gives us the confidence to implement this well design across the majority of our program moving forward due to the improved economics from this more capital-efficient design," said Dinges.

Additionally, the Company has updated its 2018 operating expense guidance to the following to reflect the impact of the previously announced divestitures:

"Our forecasted operating expenses for the year are now expected to be below $1.60 per Mcfe, representing over a 20 percent improvement relative to 2017," highlighted Dinges. "This industry-leading cost structure will allow us to continue to generate profitability and deliver strong corporate returns on capital even at the lows of the natural gas price cycle. Our 2018 plan is expected to generate approximately $180 million of free cash flow at an average NYMEX price of $2.75 per Mmbtu and can still be self-funding and generate a double-digit ROCE at an average NYMEX price as low as $2.50 per Mmbtu."

For further disclosure on Cabot's natural gas pricing exposure by index and corporate tax guidance, please see the current Guidance slide in the Investor Relations section of the Company's website.

Updated Three-Year Outlook

As a result of the previously announced divestiture of the Eagle Ford properties and the recent change in U.S. federal income tax law, the Company has provided an updated three-year outlook for the total company including the impact of income taxes, corporate overhead and interest expense. From 2018 to 2020, the Company expects to deliver a three-year production compound annual growth rate (CAGR) of 17 to 21 percent (or 20 to 24 percent on a divestiture-adjusted basis). Based on a range of NYMEX prices of $2.75 to $3.25 per Mmbtu, the Company expects to deliver between $1.6 and $2.5 billion of after-tax cumulative free cash flow (non-GAAP) while delivering significant growth in net income, discretionary cash flow (non-GAAP), and ROCE (non-GAAP). "We believe the combination of growth, free cash flow and corporate returns expected during this three-year period are not only best-in-class in the exploration and production sector, but are extremely competitive when compared to the broader equity market," emphasized Dinges.

The Company assumed no capital was allocated to exploration in 2019 and 2020; however, this is subject to change based on the initial results from the ongoing testing in the Company's exploratory areas. For further disclosure on the Company's three-year plan assumptions, please see the current investor presentation in the Investor Relations section of the Company's website.

Conference Call Webcast and Supplemental Earnings Materials

A conference call is scheduled for Friday, February 23, 2018, at 9:30 a.m. Eastern Time to discuss fourth quarter and full-year 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", "outlook", "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

OPERATING DATA
	Quarter Ended December 31,								Twelve Months Ended December 31,
	2017				2016				2017				2016
PRODUCTION VOLUMES
Natural gas (Bcf)	164.4				158.6				655.6				600.4
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