First Quarter 2020 ResultsApril 30, 2020
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Forward-Looking Statements and Other Disclosures
This presentation 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, returns to shareholders, 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”, “target”, “predict”, “may”, “should”, “could”, “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the effects of the COVID-19 pandemic and the impact thereof on the Company’s business, financial condition and results of operations, 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, pipeline projects, 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 Form 10-Q 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 Cabot Oil & Gas (the “Company” or “Cabot”) 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.
This presentation may contain certain terms, such as resource potential, risked or unrisked resources, potential locations, risked or unrisked locations, EUR (estimated ultimate recovery) and other similar terms that describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and may not constitute “reserves” within the meaning of SEC rules and accordingly, are subject to substantially greater risk of being actually realized. These estimates are based on the Company’s existing models and internal estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availably of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. These estimates may change significantly as development of the Company’s assets provide additional data. Investors are urged to consider carefully the disclosures and risk factors about Cabot’s reserves in the Form 10‐K and other reports on file with the SEC.
This presentation also refers to Discretionary Cash Flow, EBITDAX, Free Cash Flow, Adjusted Net Income (Loss), Return on Capital Employed (ROCE), Net Debt calculations and ratios and Finding and Development Costs. These non-GAAP financial measures are not alternatives to GAAP measures, and should not be considered in isolation or as an alternative for analysis of the Company’s results as reported under GAAP. For additional disclosure regarding such non-GAAP measures, including definitions of these terms and reconciliations to the most directly comparable GAAP measures, please refer to Cabot’s most recent earnings release at www.cabotog.com and the Company’s related 8-K on file with the SEC.
3
First Quarter 2020 Highlights
• Net income of $53.9 million (or $0.14 per share); adjusted net income (non-GAAP) of $54.0 million (or $0.14 per share)
• Free cash flow (non-GAAP) of $49.8 million
• Return on capital employed (ROCE) (non-GAAP) for the trailing twelve months of 14.1 percent
• Daily equivalent production of 2,363 million cubic feet equivalent (Mmcfe) per day, an increase of four percent relative to the prior-year period
• Net debt / LTM EBITDAX (non-GAAP) of 0.9x and liquidity of ~$1.7bn as of 3/31/2020
Note: See supplemental tables at the end of the presentation for a reconciliation of non-GAAP measures1 Includes direct operations, transportation and gathering, taxes other than income, exploration, DD&A, general and administrative, and interest expense
Q12020
Q4 2019
Q1 2019
Equivalent Production (Mmcfe/d) 2,363 2,457 2,276
Realized Gas Price (Incl. Hedges) ($/Mcf) $1.72 $2.15 $3.35
Realized Gas Price (Excl. Hedges) ($/Mcf) $1.72 $2.05 $3.09
Net Income ($mm) $53.9 $147.0 $262.8
Adjusted Net Income (non-GAAP) ($mm) $54.0 $120.8 $307.8
Discretionary Cash Flow (non-GAAP) ($mm) $198.5 $277.5 $505.9
Free Cash Flow (non-GAAP) ($mm) $49.8 $109.5 $308.4
EBITDAX (non-GAAP) ($mm) $189.0 $300.3 $513.7
Operating Expenses1 ($/Mcfe) $1.46 $1.43 $1.48
LTM Net Debt / EBITDAX (non-GAAP) 0.9x 0.7x 0.6x
TTM ROCE (non-GAAP) 14.1% 22.2% 20.4%
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Cabot Oil & Gas Strategy• Generate financial returns that exceed our cost of capital by focusing on
disciplined capital investment and maintaining a low cost structure
• TTM Q1 2020 ROCE of 14.1%
Note: See supplemental tables at the end of the presentation for a reconciliation of non-GAAP measures1 Based on the current NYMEX futures curve as of the week of April 27, 2020
Focus on Financial Returns
Demonstrate Continued Cost Control
Maintain Financial Strength
Generate Positive Free Cash Flow
Return Capital to Shareholders
Increase Our Proved Reserve Base
• Low cost structure provides a competitive advantage, especially in a low natural gas price environment
• Q1 2020 operating expenses per unit (including interest expense and G&A) of $1.46 per Mcfe
• Net debt / LTM EBITDAX of 0.9x as of 3/31/2020
• Liquidity of ~$1.7bn as of 3/31/2020, including $202.8mm of cash on hand
• Expected to generate positive free cash flow for the fifth consecutive year1
• 2020 program is expected to generate enough free cash flow to fully fund the Company’s dividend1
• Minimum annual return of capital target of at least 50% of free cash flow
• Reduced weighted-average shares outstanding by 14% and increased dividend five times since 2017
• Increased proved reserves by 11% in 2019 at an all-sources F&D cost of $0.36 per Mcfe
• Over two decades of remaining drilling locations, including nine years of remaining Lower Marcellus inventory
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2020 Capital Program & Outlook
• Cabot’s 2020 maintenance capital program of $575 million is expected to deliver an average net production rate of 2,350 - 2,375 Mmcfe per day (flat production year-over-year)
– Program includes 60 – 70 net wells drilled, completed, and placed on production
– Approximately two-thirds of the capital program is expected to be incurred during the first half of 2020 based on the current drilling and completion schedule
– Approximately two-thirds of the 2020 wells are expected to be placed on production between mid-May and late August, resulting in a significant sequential production increase in Q3 2020
• Fourth quarter 2020 production is expected to be flat to the fourth quarter of 2019
• Based on the current NYMEX futures curve2, the program is expected to generate enough free cash flow to fully fund the Company’s dividend
92%
8%
Drilling / Completions / Facilities
Other Program Capital¹
2020 Capital Program: $575 million
1 Includes production equipment, lease acquisition, corporate, and GasSearch Drilling (GDS) capital 2 As of the week of April 27, 2020
0
50
100
150
200
250
300
350
400
450
Permian Eagle Ford CanaWoodford
Williston DJ/Niobrara
The Outlook for Natural Gas Markets Has Improved Significantly, Driven By Large Reductions in Operating Activity Across Both Gas-Focused and Liquids-Focused Basins…
6
0
10
20
30
40
50
60
70
Marcellus Haynesville Utica
Source: Baker Hughes Rig Count as of April 24, 2020
Gas-Focused Basins Liquids-Focused Basins
Horizontal Rig Count
Peak 2019 Rig Count Current Rig Count
54%decline
41%decline
55%decline 52%
decline55%
decline93%decline
59%decline
46%decline
82.0
84.0
86.0
88.0
90.0
92.0
94.0
96.0
U.S. Dry Gas Production (Bcf/d)
7Source: Genscape Forward Natural Gas Supply and Demand Forecast as of April 24, 2020
Dec. 2018: 88.0 Bcf/d
Dec. 2019: 94.3 Bcf/d
Dec. 2020E: 86.5 Bcf/d
Mar. 2021E: 84.1 Bcf/d
…Resulting in the Expectation for Material Declines in U.S. Dry Gas Production in 2020 and 2021…
8
Current:~$2.75
Source: J.P. Morgan Commodities as of 4/30/2020
$2.20
$2.30
$2.40
$2.50
$2.60
$2.70
$2.80
2021 NYMEX Futures Daily Settlements ($/Mmbtu)
…and Higher Natural Gas Prices Due to a Healthier Natural Gas Supply and Demand Balance
Appendix
2020 Guidance
~7% free cash flow
yield1,2~6%
free cash flow yield1,2
~5%free cash
flow yield1,2~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
~7% free cash flow
yield1,2
(1) Based on forward curves as of the week of April 27, 2020(2) Excluding exploratory dry hole costs; includes exploration administration expense and geophysical expenses
• 2020E production guidance: 2,350 - 2,375 Mmcfe per day
The midpoint of the production guidance range implies flat production levels year-over-year, with Q4 2020 exit volumes expected to be flat to Q4 2019
• Q2 2020E production guidance: 2,175 – 2,225 Mmcfe per day
As previously disclosed, the sequential production decline in Q2 2020 is primarily driven by a lighter turn-in-line schedule during the first four and a half months of the year with only thirteen wells expected to be placed on production between the beginning of the year and mid-May. This is primarily a result of longer cycle times for larger pads with longer laterals during Q1 and Q2 2020
Q2 2020 production guidance range also reflects the impact of unplanned downtime related to remedial work on one well on a large pad that resulted in the deferral of over 230 completed stages from Q1 2020 to Q2 2020, which led to lower capital spending levels in Q1 2020
Approximately two-thirds of the 2020 wells are expected to be placed on production between mid-May and late August, resulting in a significant sequential production increase in Q3 2020
• 2020E capital program: $575 million
Approximately two-thirds of the capital program is expected to be incurred during the first half of 2020 based on the current drilling and completion schedule
• 2020E weighted-average natural gas price differential1: ($0.30) to ($0.35) per Mcf
• 2020E wells drilled, completed, and placed on production: 60 – 70 net wells
• 2020E income tax rate guidance: 24%
• 2020E deferred tax rate guidance1: 125% - 135%
Q2 2020E Natural Gas Price Exposure By IndexNYMEX (less $0.43) 27%
Fixed Price ($~2.62) 19%
Transco Z6 NNY (less $0.65) 19%
Leidy Line 11%
TGP Z4 –300 Leg 9%
Power Pricing 8%
Dominion 4%
Millennium 3%
Note: Fixed price percentages above include volumes associated with sales agreements that have floor prices. An additional deduct of ~$0.05 per Mcf should be applied to account for fuel use.
Q2 2020E Cost Assumptions ($/Mcfe, unless otherwise noted)Direct operations $0.09 - $0.10
Transportation and gathering $0.66 - $0.68
Taxes other than income $0.02 - $0.03
Exploration2 $0.01 - $0.02
Depreciation, depletion and amortization $0.46 - $0.48
Interest expense $0.06 - $0.07
General and administrative ($mm, excluding stock-based compensation) $15.5 - $16.5
2020 Guidance
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Financial Position and Risk Management Profile
~7% free cash flow
yield1,2~6%
free cash flow yield1,2
~5%free cash
flow yield1,2
11
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
~7% free cash flow
yield1,2
$87$188
$62
$575
$312
6.54%
4.26%
6.25%
3.67%
4.17%
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
$0
$100
$200
$300
$400
$500
$600
2020 2021 2022 2023 2024 2025 2026
Senior Notes ($mm) Weighted-Average Coupon Rate
As of 3/31/2020 $bn
Cash and Cash Equivalents $0.2
Debt $1.2
Net Debt $1.0
Net Capitalization $3.2
Liquidity1 $1.7
Net Debt / Capitalization 31.9%
Net Debt / LTM EBITDAX 0.9x
Debt Maturity Schedule ($mm) as of 3/31/2020
Capitalization / Liquidity
1 As of closing of amended and restated unsecured revolving credit facility on April 23, 2020
2020 Hedge Summary
~7% free cash flow
yield1,2~6%
free cash flow yield1,2
~5%free cash
flow yield1,2
12
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
~7% free cash flow
yield1,2
Note: As of April 30, 2020
Natural Gas (NYMEX) Swaps
Total Volume (Mmbtu) Weighted-Average Price Duration
21,400,000 $2.27 April 2020 – October 2020
18,400,000 $2.10 May 2020 – October 2020
Natural Gas (NYMEX) Collars
Total Volume (Mmbtu) Weighted-Average Floor Price
Weighted-Average Ceiling Price
Duration
21,400,000 $2.15 $2.38 April 2020 – October 2020
73,600,000 $2.02 $2.20 May 2020 – October 2020
Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share
~7% free cash flow
yield1,2~6%
free cash flow yield1,2
~5%free cash
flow yield1,2
13
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
EBITDAX Calculation and Reconciliation
~7% free cash flow
yield1,2~6%
free cash flow yield1,2
~5%free cash
flow yield1,2
14
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
~7% free cash flow
yield1,2
Net Debt Reconciliation
~6% free cash
flow yield1,2~5%
free cash flow yield1,2
15
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
Discretionary Cash Flow and Free Cash Flow Calculation and Reconciliation
~7% free cash flow
yield1,2~6%
free cash flow yield1,2
~5%free cash
flow yield1,2
16
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
Return on Capital Employed Calculation
~6% free cash
flow yield1,2~5%
free cash flow yield1,2
17
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2
Finding and Development Costs Calculations
~6% free cash
flow yield1,2~5%
free cash flow yield1,2
18
~5% free cash flow
yield1,2
~6% free cash flow
yield1,2