July 2017 Investor Presentation July 28, 2017 A decade of progress - - PowerPoint PPT Presentation

A decade of progress and perseverance in the Marcellus Shale.

July 2017 Investor Presentation

July 28, 2017

Forward-Looking Statements and Other Disclaimers

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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, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “target”, “predict”, “may”, “should”, “could”, “will” and similar expressions are also intended to identify forward-looking

• statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic

basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (SEC) filings. See “Risk Factors” in Item 1A of the Form 10-K and subsequent public filings for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual

• utcomes 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, Net Income (Loss) Excluding Selected Items and Net Debt calculations and

• ratios. 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.

>3,000 Remaining Undrilled Locations Year-End 2016 Net Producing Horizontal Wells: 517 2017E Net D&C activity: 60 wells drilled / 51 wells completed Inventory Life Based on 2017E Activity: ~50 years

Cabot Oil & Gas Overview

2016 Production: 627 Bcfe (4% growth) 2016 Year-End Proved Reserves: 8.6 Tcfe (5% growth) 2017E Net D&C Activity: 95 wells drilled / 90 wells completed 2017E Production Growth: 8% - 12% 2017E Total Program Spending: $845 mm (includes $70 mm of pipeline investments and up to $125 mm of exploratory leasing / testing capital) 3

>1,100 Remaining Undrilled Locations Year-End 2016 Net Producing Horizontal Wells: 207 2017E Net D&C activity: 30 wells drilled / 39 wells completed Inventory Life Based on 2017E Activity: ~36 years

MARCELLUS SHALE EAGLE FORD SHALE

413.6 531.8 602.5 627.1

2013 2014 2015 2016 2017E

2017 Guidance: 8% - 12%

Proven Track Record of Production and Reserve Growth

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Annual Production (Bcfe)

5.5 7.4 8.2 8.6

2013 2014 2015 2016 2017E

Proved Undeveloped Proved Developed

Year-End Proved Reserves (Tcfe)

Industry-Leading Cost Structure Continues to Improve…

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$1.21 $0.87 $0.55 $0.71 $0.57 $0.37 2011 2012 2013 2014 2015 2016

Total Company All-Sources Finding & Development Costs ($/Mcfe) Marcellus All-Sources Finding & Development Costs ($/Mcf)

$0.65 $0.49 $0.40 $0.43 $0.31 $0.26 2011 2012 2013 2014 2015 2016

…Allowing Cabot to Successfully Navigate through All Commodity Prices

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$1.88 $1.74 $1.31 $1.30 $1.30 $1.16 $1.15 $1.12 2011 2012 2013 2014 2015 2016 Q1 2017 Q2 2017 Operating Transportation¹ Taxes O/T Income Cash G&A² Financing Exploration³

Cash Operating Expenses ($/Mcfe)

Cabot’s Drilling Efficiencies Continue to Drive Costs Lower Across Both Operating Areas

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Marcellus Drilling Costs / Foot

2014 2015 2016 1H 2017

Eagle Ford Drilling Costs / Foot

2014 2015 2016 1H 2017

Current Leverage Metrics Have Improved to Pre- Downcycle Levels

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Net Debt to LTM EBITDAX

1.4x 1.4x 0.9x 1.2x 2.5x 1.8x 1.3x 1.1x 2011 2012 2013 2014 2015 2016 Q1 2017 Q2 2017 Average net debt / EBITDAX ratio prior to the recent downcycle: 1.2x

Top-Tier Cash Flow Growth and Free Cash Flow Generation

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65% 60% 58% 57% 55% 51% 44% 40% 36% 34% 30% 30% 27% 26% 17% 14% 13% 9%

Consensus 2016 – 2018E Cash Flow Per Share CAGR Consensus 2017E Free Cash Flow Yield

2% 1% (0%) (1%) (1%) (1%) (2%) (3%) (3%) (3%) (4%) (4%) (4%) (4%) (4%) (7%) (11%) (18%)

Cabot’s Generation 4 Marcellus Wells Continue to Outperform

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50 100 150 200 250 300 350 20 40 60 80 100 Cumulative Production (Mmcf per 1,000 Lateral Feet) Days of Production COG Generation 4 Wells Generation 4 Type Curve (4.4 Bcf / 1,000')

4.4

Appalachian Gas Play Non-Appalachian Gas Play

Cabot’s Marcellus Position is the Most Prolific U.S. Onshore Natural Gas Resource Play

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Estimated Ultimate Recovery (EUR) – Bcfe/1,000 Lateral Feet

Cabot’s Marcellus Drilling Efficiencies

12 Drilling Days vs. Depth - Spud to Rig Release Drilling Cost Per Foot Drilled $324 $259 $233 $200 $153 <$140 2012 2013 2014 2015 2016 2017E 4,000 8,000 12,000 16,000 5 10 15 20 Total Measured Depth (Ft.) Days 2012 2013 2014 2015 2016

Upgraded rigs, lower contracted day rates and continued efficiency gains should lead to further reductions in drilling costs in 2017

2018 is an Inflection Year for Cabot:

Cabot Has the Ability to Double Its Marcellus Production Based on Its Future Firm Transport / Firm Sales Additions

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~2.0 Bcf/d 2.0 2.1 2.3 2.5 3.5 ~3.7 Bcf/d 3.7 135 Mmcf/d 165 Mmcf/d 240 Mmcf/d 1 Bcf/d 150 Mmcf/d 500 Mmcf/d 2016 Gross Marcellus Production Exit Rate TGP Orion (December 2017) Moxie Freedom Power Plant (June 2018 - currently under construction) Lackawanna Energy Center Power Plant (June to December 2018

• currently

under construction) Atlantic Sunrise (Mid-2018) PennEast (2H 2018) Future Gross Production Capacity (Excluding Constitution Pipeline) Constitution Pipeline (As Early As 1H 2019)

• Continue to evaluate new opportunities to increase Cabot’s firm

transport capacity and firm sales

• The pace at which new takeaway capacity will be filled with

incremental production volumes (as opposed to rerouting existing production) will ultimately be dependent on realized prices and the corresponding economics / returns at those prices

• 350 Mmcf/d (COG transport capacity): 20 years
• 500 Mmcf/d (COG transport capacity): 15 years
• 150 Mmcf/d (3rd party transport capacity): 3 years

Best-in-Class Marcellus Capital Efficiency

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$0 $100 $200 $300 $400 $500 $600

Estimated Drilling, Completion and Facility Capital to Hold 3.7 Bcf/d of Gross Marcellus Production Flat ($mm) Average Annual Pre-Tax Marcellus Free Cash Flow at 3.7 Bcf/d Flat ($mm)

$872 $1,446 $2,020 $0 $500 $1,000 $1,500 $2,000 $2,500 $2.00 / Mcf Realized Price $2.50 / Mcf Realized Price $3.00 / Mcf Realized Price

Average Annual Maintenance Capital: ~$500mm

• income. Assumes 8,000’ lateral lengths, 7 wells per pad, and 29 wells drilled per rig year. Assumes cost inflation through 2020 and then well costs are held flat to 2020

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Significant Positive Free Cash Flow is on the Horizon, Providing Cabot With Options to Create Shareholder Value

Potential Uses of Positive Free Cash Flow

Accelerate Production and Cash Flow Growth via Increased Activity in Cabot’s Current High-Return Operating Areas Evaluate New Platforms for Future Growth that Compete for Capital (Identify Opportunities that Provide Competitive Full-Cycle Returns) Return a Portion of Cash Flow to Shareholders (Increase Dividend / Share Repurchase Program) Reduce Debt Levels

 Previously announced an increase in 2017 Eagle Ford capital in response to higher rates of return  Planning to ramp up Marcellus activity in 2018 in anticipation of new takeaway capacity / improved Marcellus price realizations  Currently evaluating new outlets for Marcellus production growth  Announced up to $125mm of capital in 2017 to lease and test new exploratory areas ($91mm spent through Q2 2017)  Focused on grassroots leasing in areas with low cost of entry and the ability to build sizable, contiguous acreage footprints similar to our Marcellus and Eagle Ford positions  Announced a 150 percent increase in quarterly dividend on May 3, 2017  Repurchased 3.0 million shares at an average price

• f $22.41 during Q2 2017 (7.1mm shares remaining

under the current share repurchase program)  Management continues to view further dividend increases and share repurchases as part of the long-term strategy for creating shareholder value  Absolute debt is ~$500mm lower today as compared to year-end 2015  Cabot’s leverage ratios continue to improve to pre- downcycle levels and the current forecast implies a significant de-leveraging over the coming years  The Company has ~$300mm of debt maturing in 2018

Appendix

2017 Program Overview

17 2017E Production Growth: 8% - 12% 2017E Oil Production Growth: 10% - 15% Net D&C Activity 2017E Total Program Spending: $845 mm

(includes $70 mm of equity pipeline investments and up to $125 mm of exploratory leasing / testing capital)

2017E D&C Capital1: $610 mm

8% 5% 15% 72% Equity Pipeline Investments Maintenance Leasing / Other Exploratory Leasing / Testing Drilling / Completion / Facilities 67% 33% Marcellus Eagle Ford

Drilled Uncompleted (DUC) Inventory Average Lateral Lengths (Ft.)

38 95 76 90 FY 2016 FY 2017E Wells Drilled Wells Completed 26 35 19 10 YE 2016 YE 2017E Eagle Ford Marcellus 6,854 6,187 8,000 6,970 10,805 8,779 9,000 8,800 FY 2016 Drilled FY 2016 Completed FY 2017E Drilled FY 2017E Completed Eagle Ford Marcellus

2017 Guidance

 Full-year 2017 total company production growth guidance: 8% - 12%  Full-year 2017 oil production growth: 10% - 15%  2017 exit-to-exit oil production growth: 40% - 50%  2017 total program spending (including equity pipeline investments): $845 million – 2017 E&P capital budget: $775 million

• 79% of E&P capital budget allocated to drilling, completion

and facilities

• Drilling, completion and facilities capital by operating area:

67% Marcellus Shale / 33% Eagle Ford Shale

• Includes up to $125 million of exploratory leasing / testing

capital ($91 million spent through Q2 2017) – 2017 equity pipeline investments: $70 million (assumes a July 1, 2018 in-service date for Atlantic Sunrise)  2017 drilling and completion activity guidance: – 95 net wells drilled (60 Marcellus / 30 Eagle Ford / 5 Exploration) – 90 net wells completed (51 Marcellus / 39 Eagle Ford)  2017 income tax rate guidance: 38%  2017 deferred tax rate guidance1: 90% Q3 2017 Net Production Guidance Natural Gas (Mmcf/d) 1,750 - 1,800 Oil (Bbls/d) 13,000 - 13,750 Natural Gas Liquids (Bbls/d) 1,350 - 1,450 Q3 2017 Natural Gas Price Exposure By Index Fixed Price (~$2.12) 42% Leidy Line Receipts 15% TGP Zone 4 – 300 Leg 15% NYMEX 13% Columbia 6% Dominion 5% Millennium East 4% Note: An additional deduct of ~$0.05 per Mcf should be applied to account for fuel use FY 2017 Cost Assumptions ($/Mcfe, unless otherwise noted) Direct operations $0.15 - $0.16 Transportation and gathering $0.70 - $0.71 Taxes other than income $0.05 - $0.06 Depreciation, depletion and amortization $0.85 - $0.95 Interest expense $0.12 - $0.13 General and administrative ($mm)2 $55 - $60 Exploration3 ($mm) $18 - $20

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Financial Position and Risk Management Profile

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Fixed Price (~$2.12) 42% TGP Zone 4 – 300 Leg 15% NYMEX 13% Millennium East 4% Columbia 6% $0 $100 $200 $300 $400 $500 $600 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 7.2% 6.5% 4.3% 6.2% 3.7% Natural Gas (NYMEX) Swaps Total Volume (Bcf) Average Price per Mcf Natural Gas (NYMEX) Collars Total Volume (Bcf) Average Floor Price per Mcf Average Cap Price per Mcf Oil (WTI) Collars Total Volume (Mmbbls) Average Floor Price per Bbl Average Cap Price per Bbl 51.7 $3.23 35.5 $3.09 $3.43 1.8 $50.00 $56.39 As of 6/30/2017 $bn Cash and Cash Equivalents $0.5 Debt $1.5 Net Debt $1.0 Net Capitalization $3.6 Liquidity $2.2 Net Debt / Capitalization 27.6% Net Debt / LTM EBITDAX 1.1x

Q3 2017 Natural Gas Price Exposure by Index 2017 Hedge Position Debt Maturity Schedule ($mm) (Including Weighted Average Coupon Rate) Capitalization / Liquidity

4.2% Leidy Line 15% Dominion 5%

2017 Hedge Summary

20 2017 Natural Gas Swaps # of Total $/Mcf Pricing Index Contracts Mcf/Day Fixed Price Duration LDS NYMEX 10 97,144 $3.12 Jan-17 Dec-17 TCO 5 48,572 $3.46 Feb-17 Dec-17 2017 Natural Gas Collars # of Total $/Mcf Pricing Index Contracts Mcf/Day Floor Ceiling Duration LDS NYMEX 10 97,144 $3.09 $3.43 Jan-17 Dec-17 2017 Oil Collars # of Total $/Bbl Pricing Index Contracts Bbls/Day Floor Ceiling Duration NYMEX (WTI) 5 5,000 $50.00 $56.39 Jan-17 Dec-17

Cabot’s Marcellus Infrastructure Update

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Atlantic Sunrise

• Construction on the mainline portion of

the project began in March 2017

• Following the receipt of all necessary

regulatory approvals, we anticipate beginning construction on the greenfield portion of the project in Q3 2017

• Major Permits Outstanding
• PADEP Chapter 102/105 Permits

(expected in August 2017)

• U.S. Army Corps 404 Permit

(expected in August 2017)

• FERC Notice to Proceed
• Greenfield construction is expected to

take ~10 months

• Cabot remains confident in a mid-2018

in-service date PennEast Pipeline

• Received final EIS on April 7, 2017
• Construction could take as little as seven

months

• Target in-service date: 2H 2018

Moxie Freedom and Lackawanna Energy Center Power Plants

• Currently under construction and on

schedule Tennessee Gas Pipeline (TGP) Orion Project

• Received FERC certificate on February 2,

2017

• Currently under construction
• Target in-service date: December 2017

Constitution Pipeline

• Awaiting the outcome of the appeal of the

NYDEC permit denial

Other Projects

EBITDAX and Net Debt Reconciliations

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Net Income (Loss) Excluding Selected Items and Discretionary Cash Flow Reconciliations

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A decade of progress and perseverance in the Marcellus Shale.