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Cabot Oil & Gas Corporation Announces Fourth-Quarter and Full-Year 2017 Results, Expands Share Repurchase Program Authorization
Feb 23, 2018

HOUSTON, Feb. 23, 2018 /PRNewswire/ -- Cabot Oil & Gas Corporation (NYSE: COG) ("Cabot" or the "Company") today reported financial and operating results for the fourth-quarter and full-year ended December 31, 2017. Additionally, the Company announced an expansion of its share repurchase program authorization to 30 million shares (or approximately 6.5 percent of its current shares outstanding).

Full-Year 2017 Highlights

  • Net income of $100.4 million (or $0.22 per share); adjusted net income (non-GAAP) of $244.5 million (or $0.53 per share)
  • Net cash provided by operating activities of $898.2 million; discretionary cash flow (non-GAAP) of $976.1 million
  • Free cash flow (non-GAAP) of $154.5 million, marking the second consecutive year of positive free cash flow
  • Daily equivalent production growth of 10 percent year-over-year
  • Proved reserves growth of 13 percent year-over-year
  • Total company all-sources finding and development costs of $0.35 per thousand cubic feet equivalent (Mcfe) and Marcellus-only all-sources finding and development costs of $0.22 per thousand cubic feet (Mcf)
  • Returned $202.6 million of cash to shareholders through dividends and share repurchases
  • Improved operating expenses per unit by seven percent year-over-year
  • Capital expenditures (including investment in equity method investments) of $821.6 million, three percent below the full-year guidance
  • Improved return on capital employed (ROCE) (non-GAAP) by over 800 basis points
  • Announced the divestiture of three non-core assets for total proceeds of $836.3 million (subject to customary closing conditions and purchase price adjustments)

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, ROCE, pre-tax present value of future net cash flows (pre-tax PV–10) and net debt to adjusted capitalization ratio.

"2017 marked another positive year for Cabot Oil & Gas as we continued to execute on our strategy for creating long-term shareholder value by delivering debt-adjusted per share growth; generating positive free cash flow; improving corporate returns on capital employed; increasing return of capital to shareholders; and maintaining a strong balance sheet," commented Dan O. Dinges, Chairman, President and Chief Executive Officer. "Our strategy was rewarded in 2017 as Cabot delivered the highest total shareholder return in our peer group and outperformed the S&P 500 index. Given our relentless focus on delivering returns-focused per share growth, we have increased our share repurchase program authorization and modified the target metrics in our 2018 compensation program to focus on corporate returns and growth per debt-adjusted share, which are better-aligned with our disciplined capital allocation philosophy."

Full-Year 2017 Financial Results

Full-year 2017 equivalent production was 685.3 billion cubic feet equivalent (Bcfe), consisting of 655.6 billion cubic feet (Bcf) of natural gas, 4,440.9 thousand barrels (Mbbls) of crude oil and condensate, and 512.1 Mbbls of natural gas liquids (NGLs).

Full-year 2017 net income was $100.4 million, or $0.22 per share, compared to a net loss of $417.1 million, or $0.91 per share, in the prior-year period. Full-year 2017 adjusted net income (non-GAAP) was $244.5 million, or $0.53 per share, compared to an adjusted net loss of $97.3 million, or $0.21 per share, in the prior-year period. Full-year 2017 EBITDAX (non-GAAP) was $1,059.1 million, compared to $556.0 million in the prior-year period.

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:

Proved Reserves Reconciliation (in Bcfe)

Balance at December 31, 2016 

8,576

Revisions of prior estimates 

928

Extensions, discoveries and other additions 

1,236

Sales 

(329)

Production 

(685)

Balance at December 31, 2017 

9,726

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:

• Marcellus Shale: 
















$800 million

• Exploration Areas: 
















$75 million

• Pipeline Investments: 
















$60 million

• Corporate: 
















$15 million

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:

• Direct operations: 

$0.09 - $0.11 per Mcfe

• Transportation and gathering: 

$0.66 - $0.68 per Mcfe

• Taxes other than income: 

$0.02 - $0.03 per Mcfe  

• Depreciation, depletion and amortization: 

$0.50 - $0.60 per Mcfe

• Interest expense: 

$0.09 - $0.11 per Mcfe

• Cash general and administrative (ex. stock-based compensation): 

$60 million

• Exploration: 

$35 million



"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


Crude oil and condensate (Mbbl)

1,238.0



822.7



4,440.9



4,013.1


Natural gas liquids (NGLs) (Mbbl)

131.5



106.5



512.1



441.2


Equivalent production (Bcfe)

172.6



164.2



685.3



627.1










AVERAGE SALES PRICE








Natural gas, including hedges ($/Mcf)

$

2.18



$

1.94



$

2.31



$

1.70


Natural gas, excluding hedges ($/Mcf)

$

2.15



$

1.96



$

2.30



$

1.70


Crude oil and condensate, including hedges ($/Bbl)

$

54.54



$

42.94



$

48.16



$

37.30


Crude oil and condensate, excluding hedges ($/Bbl)

$

54.77



$

44.36



$

47.81



$

37.65


NGL ($/Bbl)

$

23.51



$

13.84



$

19.47



$

11.74










AVERAGE UNIT COSTS ($/Mcfe)








Direct operations

$

0.14



$

0.14



$

0.15



$

0.16


Transportation and gathering

0.69



0.69



0.70



0.70


Taxes other than income

0.04



0.03



0.05



0.05


Exploration

0.03



0.09



0.03



0.04


Depreciation, depletion and amortization

0.83



0.86



0.83



0.94


General and administrative (excluding stock-based compensation)

0.11



0.10



0.09



0.10


Stock-based compensation

0.05



0.02



0.05



0.04


Interest expense

0.12



0.12



0.12



0.14



$

2.01



$

2.05



$

2.02



$

2.17


















WELLS DRILLED(1)








Gross

20



12



91



40


Net

20.0



10.0



82.5



38.0










WELLS COMPLETED(1)








Gross

24



25



105



76


Net

24.0



25.0



94.2



76.0


____________________________________________

(1) 

Wells drilled represents wells drilled to total depth during the period. Wells completed includes wells completed during the period, regardless of when they were drilled.

 


  CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)



Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands, except per share amounts)

2017


2016


2017


2016

OPERATING REVENUES








Natural gas

$

353,989



$

311,580



$

1,506,078



$

1,022,590


Crude oil and condensate

67,810



36,496



212,338



151,106


Gain (loss) on derivative instruments

(29,427)



(37,664)



16,926



(38,950)


Brokered natural gas

4,957



4,152



17,217



13,569


Other

3,174



1,927



11,660



7,362



400,503



316,491



1,764,219



1,155,677


OPERATING EXPENSES








Direct operations

24,125



23,557



102,310



100,696


Transportation and gathering

119,530



113,659



481,439



436,542


Brokered natural gas

4,990



3,259



15,252



10,785


Taxes other than income

6,925



5,486



33,487



29,223


Exploration

4,903



14,553



21,526



27,662


Depreciation, depletion and amortization

143,128



141,218



568,817



590,128


Impairment of oil and gas properties and other assets(1)

414,256



435,619



482,811



435,619


General and administrative (excluding stock-based compensation)

19,022



15,489



63,745



59,665


Stock-based compensation(2)

7,863



2,952



34,041



25,968



744,742



755,792



1,803,428



1,716,288


Loss on equity method investments(3)

(96,500)



(2,685)



(100,486)



(2,477)


(Gain) loss on sale of assets

1,933



(1,089)



(11,565)



(1,857)


LOSS FROM OPERATIONS

(438,806)



(443,075)



(151,260)



(564,945)


Interest expense, net

20,410



20,515



82,130



88,336


Loss on debt extinguishment







4,709


Other expense (income)

18



402



(4,955)



1,609


Loss before income taxes

(459,234)



(463,992)



(228,435)



(659,599)


Income tax benefit(4)

(414,793)



(171,232)



(328,828)



(242,475)


NET INCOME (LOSS)

$

(44,441)



$

(292,760)



$

100,393



$

(417,124)


Earnings (loss) per share - Basic

$

(0.10)



$

(0.63)



$

0.22



$

(0.91)


Weighted-average common shares outstanding

462,371



465,150



463,735



456,847


____________________________________

(1)      

Includes the impairment of our Eagle Ford Shale oil and gas properties in south Texas in the fourth quarter of 2017. Includes the impairment of oil and gas properties and the related pipeline assets in West Virginia and Virginia in the fourth quarter of 2016.

(2)      

Includes the impact of our performance share awards and restricted stock.

(3)     

Includes the $95.9 million other than temporary impairment of our investment in Constitution.

(4)     

Includes the impact of the remeasurement of our net deferred income tax liabilities based on the new corporate income tax rate associated with the Tax Act in the fourth quarter of 2017. The remeasurement resulted in an income tax benefit of $242.9 million.

 


CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)


(In thousands)

December 31,
 2017


December 31,
 2016

ASSETS




Current assets

$

764,957



$

715,881


Properties and equipment, net (Successful efforts method)

3,072,204



4,250,125


Assets held for sale

778,855




Other assets

111,328



156,563



$

4,727,344



$

5,122,569






LIABILITIES AND STOCKHOLDERS' EQUITY




Current liabilities

$

630,050



$

257,812


Long-term debt, net (excluding current maturities)

1,217,891



1,520,530


Deferred income taxes

227,030



579,447


Liabilities held for sale

15,748




Other liabilities

112,720



197,113


Stockholders' equity

2,523,905



2,567,667



$

4,727,344



$

5,122,569


 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)



Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands)

2017


2016


2017


2016

CASH FLOWS FROM OPERATING ACTIVITIES








Net income (loss)

$

(44,441)



$

(292,760)



$

100,393



$

(417,124)


Deferred income tax benefit

(410,844)



(171,294)



(321,113)



(230,707)


Impairment of oil and gas properties and other assets

414,256



435,619



482,811



435,619


(Gain) loss on sale of assets

(1,933)



1,089



11,565



1,857


Exploratory dry hole cost

978



10,102



3,820



10,120


(Gain) loss on derivative instruments

29,427



37,664



(16,926)



38,950


Net cash received (paid) in settlement of derivative instruments

4,469



(4,886)



8,056



(1,682)


Income charges not requiring cash

248,231



148,029



707,496



623,670


Changes in assets and liabilities

(61,030)



(23,827)



(77,942)



(63,262)


   Net cash provided by operating activities

179,113



139,736



898,160



397,441










CASH FLOWS FROM INVESTING ACTIVITIES








Capital expenditures

(177,745)



(130,120)



(764,558)



(375,153)


Proceeds from sale of assets

82,733



1,351



115,444



50,419


Investment in equity method investments

(33,657)



(4,308)



(57,039)



(28,484)


   Net cash used in investing activities

(128,669)



(133,077)



(706,153)



(353,218)










CASH FLOWS FROM FINANCING ACTIVITIES








Net borrowings (repayments) of debt







(497,000)


Treasury stock repurchases

(55,486)





(123,741)




Sale of common stock, net







995,279


Dividends paid

(23,131)



(9,302)



(78,838)



(36,187)


Tax withholding on vesting of stock awards

(2,044)



(8)



(7,973)



(5,064)


Capitalized debt issuance costs







(3,223)


Other

8





50




   Net cash (used in) provided by financing activities

(80,653)



(9,310)



(210,502)



453,805










Net (decrease) increase in cash and cash equivalents

$

(30,209)



$

(2,651)



$

(18,495)



$

498,028



Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results, the results of our peers and of prior periods. In addition, we believe 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.

We have also included herein certain forward-looking non-GAAP financial measures. Due to the forward-looking nature of these non-GAAP financial measures, we 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, we are 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 our 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.


Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands, except per share amounts)

2017


2016


2017


2016

As reported - net income (loss)

$

(44,441)



$

(292,760)



$

100,393



$

(417,124)


Reversal of selected items:








Impairment of oil and gas properties and other assets(1)

414,256



435,619



482,811



435,619


Impairment of equity method investments(2)

95,945





95,945




(Gain) loss on sale of assets

(1,933)



1,089



11,565



1,857


(Gain) loss on derivative instruments(3)

33,896



32,778



(8,870)



37,268


Loss on debt extinguishment







4,709


Drilling rig termination fees







1,655


Stock-based compensation expense

7,863



2,952



34,041



25,968


Severance expense

21





3,213



209


OPEB curtailment

(67)





(4,917)




Tax effect on selected items

(203,211)



(174,567)



(226,787)



(187,443)


Impact of 2017 tax reform

(242,875)





(242,875)




Adjusted net income (loss)

$

59,454



$

5,111



$

244,519



$

(97,282)


As reported - earnings (loss) per share

$

(0.10)



$

(0.63)



$

0.22



$

(0.91)


Per share impact of selected items

0.23



0.64



0.31



0.70


Adjusted earnings (loss) per share

$

0.13



$

0.01



$

0.53



$

(0.21)


Weighted-average common shares outstanding

462,371



465,150



463,735



456,847


_____________________________________

(1)       

This amount represents the non-cash impairment of our Eagle Ford Shale oil and gas properties located in south Texas in the fourth quarter of 2017 and the non-cash impairment of our West Virginia and Virginia properties in the fourth quarter of 2016.

(2)      

This amount represents the non-cash other than temporary impairment of our investment in Constitution recorded in Loss on equity method investments in the Condensed Consolidated Statement of Operations.

(3)      

This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in Gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

Return on Capital Employed

Return on Capital Employed (ROCE) is defined as adjusted net income (loss) (defined above) plus after-tax net interest expense divided by average capital employed, which is defined as total debt plus stockholders' equity. ROCE is presented based on our belief that this non-GAAP measure is useful information to investors when comparing our profitability and the efficiency with which we have employed capital over time relative to other companies. ROCE is not a measure of financial performance under GAAP and should not be considered an alternative to net income.

(In thousands)


2017


2016

Interest expense, net


$

82,130



$

88,336


Tax benefit on interest expense, net


(30,346)



(32,640)


After-tax interest expense, net (A)


51,784



55,696







As reported - net income (loss)


100,393



(417,124)


Adjustments to as reported - net income (loss), net of tax


144,126



319,842


Adjusted net income (loss) (B)


244,519



(97,282)







Adjusted net income (loss) before interest expense, net (A + B)


$

296,303



$

(41,586)







Total debt - beginning


$

1,520,530



$

2,016,139


Stockholders' equity - beginning


2,567,667



2,009,188


Capital employed - beginning


4,088,197



4,025,327







Total debt - ending


1,521,891



1,520,530


Stockholders' equity - ending


2,523,905



2,567,667


Capital employed - ending


4,045,796



4,088,197







Average capital employed - (C)


$

4,066,997



$

4,056,762







Return on average capital employed (ROCE) (A+B) / C


7.3%



(1.0)%


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 our 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 our 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.



Quarter Ended
 December 31,


Twelve Months Ended

December 31,

(In thousands)


2017


2016


2017


2016

Net cash provided by operating activities


179,113



139,736



898,160



397,441


Changes in assets and liabilities


61,030



23,827



77,942



63,262


Discretionary cash flow


240,143



163,563



976,102



460,703


Capital expenditures


(177,745)



(130,120)



(764,558)



(375,153)


Investment in equity method investments


(33,657)



(4,308)



(57,039)



(28,484)


Free cash flow


$

28,741



$

29,135



$

154,505



$

57,066



















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 our 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.


Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands)

2017


2016


2017


2016

Net income (loss)

$

(44,441)



$

(292,760)



$

100,393



$

(417,124)


Plus (less):








Interest expense, net

20,410



20,515



82,130



88,336


Loss on debt extinguishment







4,709


Other expense (income)

18



402



(4,955)



1,609


Income tax benefit

(414,793)



(171,232)



(328,828)



(242,475)


Depreciation, depletion and amortization

143,128



141,218



568,817



590,128


Impairment of oil and gas properties and other assets

414,256



435,619



482,811



435,619


Exploration

4,903



14,553



21,526



27,662


(Gain) loss on sale of assets

(1,933)



1,089



11,565



1,857


Non-cash (gain) loss on derivative instruments

33,896



32,778



(8,870)



37,268


Loss on equity method investments

96,500



2,685



100,486



2,477


Stock-based compensation

7,863



2,952



34,041



25,968


EBITDAX

$

259,807



$

187,819



$

1,059,116



$

556,034


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 we believe this ratio is useful to investors in determining our 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 we believe are also useful to investors since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire debt. Additionally, as we 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.

(In thousands)

December 31,
 2017


December 31,
 2016

Current portion of long-term debt

$

304,000



$


Long-term debt, net

1,217,891



1,520,530


Total debt

$

1,521,891



$

1,520,530


Stockholders' equity

2,523,905



2,567,667


Total capitalization

$

4,045,796



$

4,088,197






Total debt

$

1,521,891



$

1,520,530


Less: Cash and cash equivalents

(480,047)



(498,542)


Net debt

$

1,041,844



$

1,021,988






Net debt

$

1,041,844



$

1,021,988


Stockholders' equity

2,523,905



2,567,667


Total adjusted capitalization

$

3,565,749



$

3,589,655






Total debt to total capitalization ratio

37.6

%


37.2

%

Less: Impact of cash and cash equivalents

8.4

%


8.7

%

Net debt to adjusted capitalization ratio

29.2

%


28.5

%

Capital Expenditures



Quarter Ended
December 31,


Twelve Months Ended
December 31,

(In thousands)


2017


2016


2017


2016

Cash paid for capital expenditures


$

177,745



$

130,120



$

764,558



$

375,153


Change in accrued capital costs


(2,309)



(9,904)



(3,516)



7,168


Exploratory dry hole cost


(978)



(10,102)



(3,820)



(10,120)


Capital expenditures


$

174,458



$

110,114



$

757,222



$

372,201


Pre-tax Present Value of Future Net Cash Flows Calculation and Reconciliation

(In thousands)

December 31,
 2017


December 31,
 2016

Standardized Measure of Discounted Future Net Cash Flows

$

5,010,446



$

2,234,767


Plus: Future Income Tax Expenses, discounted at 10% annual rate

955,240



380,276


Pre-tax Present Value of Future Net Cash Flows, discounted at 10% annual rate

$

5,965,686



$

2,615,043


 

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SOURCE Cabot Oil & Gas Corporation