Cabot Oil & Gas Corporation Announces Fourth-Quarter and Full-Year 2017 Results, Expands Share Repurchase Program Authorization
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 Twelve Months Ended
December 31, 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 Twelve Months Ended
December 31, 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, December 31,
2017 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 Twelve Months Ended
December 31, 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 Twelve Months Ended
December 31, 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 Twelve Months Ended
December 31,
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 Twelve Months Ended
December 31, 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, December 31,
2017 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 Twelve Months Ended
December 31, 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, December 31,
2017 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
