where we stand where we are going

where we stand where we are going Third-Quarter 2018 Earnings Call October 26, 2018

Forward-Looking Statements and Other Disclaimers 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, 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, 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 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) 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. 2

Q3 2018 Highlights Daily equivalent production of 2,029 Mmcfe per day Net income of $122.3 million (or $0.28 per share); adjusted net income (non-gaap) of $108.9 million (or $0.25 per share) Net cash provided by operating activities of $242.2 million; discretionary cash flow (non- GAAP) of $298.8 million Free cash flow (non-gaap) of $28.6 million Return on capital employed (ROCE) (non- GAAP) of 10.8 percent for the trailing twelve months Returned $188.5 million of cash to shareholders through dividends and share repurchases Announced a 17 percent dividend increase, the Company s third dividend increase in the last 18 months Reduced debt by $237.0 million, resulting in annualized interest expense savings of $15.3 million Improved operating expenses per unit by 18 percent relative to the prior-year comparable quarter Q3 2018 Q2 2018 Q3 2017 Equivalent Production (Mmcfe/d) 2,029 1,895 1,843 Realized Gas Price (Incl. Hedges) ($/Mcf) $2.36 $2.15 $2.03 Realized Gas Price (Excl. Hedges) ($/Mcf) $2.36 $2.11 $2.01 Net Income ($mm) $122.3 $42.4 $17.6 Adjusted Net Income (non-gaap) ($mm) $108.9 $57.9 $32.0 Discretionary Cash Flow (non-gaap) ($mm) $298.8 $196.5 $207.2 EBITDAX (non-gaap) ($mm) $291.6 $232.1 $218.6 Operating Expenses 1 ($/Mcfe) $1.69 $1.85 $2.06 LTM Net Debt / EBITDAX (Non-GAAP) 0.9x 0.8x 1.0x 3 Note: See supplemental tables at the end of the presentation for a reconciliation of non-gaap measures 1 Includes direct operations, transportation and gathering, taxes other than income, exploration, DD&A, general and administrative, and interest expense

Cabot Oil & Gas Overview 2017 Year-End Proved Reserves: 9.7 Tcfe (13% year-over-year increase) 2017 Production: 1,878 Mmcfe/d (10% year-over-year increase) 2018E Production Growth: 7% - 8% (12% - 13% on a debt-adjusted per share basis) 2018E Capital Expenditures: $940 million 2019E Production Growth: 20% - 25% (25% - 30% on a debt-adjusted per share basis) 2019E Capital Expenditures: $800 - $850 million MARCELLUS SHALE ~3,000 Remaining Undrilled Locations Year-End 2017 Net Producing Horizontal Wells: 561 2018E Wells Placed on Production: 80 Net Wells Inventory Life Based on 2018E Activity: ~35 years 4

Cabot Oil & Gas Strategy Disciplined capital allocation focused on 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 Deliver growth in production and reserves per debt-adjusted share while generating positive free cash flow 2018E production growth of 7% - 8% (12% - 13% per debt-adjusted share) 2018E free cash flow generation of approximately $250 mm 1 2019E production growth of 20% - 25% (25% - 30% per debt-adjusted share) 2019E free cash flow generation of $650 mm - $700 mm 1 (~7% yield 2 ) Generate an improving return on capital employed (ROCE) that exceeds our cost of capital TTM Q3 2018 ROCE of 10.8%, an increase of over 500 basis points relative to TTM Q3 2017 2019E ROCE of over 20% 1 Increase the return of capital to shareholders through dividends and share repurchases Expected to return over $820 mm of capital in 2018, implying ~8.7% total shareholder yield 2,3,4 Increased dividend by 17 percent, the Company s third dividend increase in the last 18 months Repurchased approximately 30 million shares year-to-date 2018 4 Cabot is committed to returning >50% of free cash flow to shareholders annually through dividends and share repurchases Maintain a strong balance sheet to maximize financial flexibility Net debt / LTM EBITDAX of 0.9x as of 9/30/2018 Liquidity of ~$2.1 bn including cash on hand of $316 mm as of 9/30/2018 Paid down $237 mm of 6.44% senior notes in July 2018 1 Based on forward curves as of the week of 10/22/2018 2 Based on market capitalization as of October 25, 2018 5 3 Assumes year-to-date 2018 share repurchases and estimated full-year dividend payments 4 As of October 26, 2018 Note: See supplemental tables at the end of the presentation for a reconciliation of non-gaap measures

Proven Track Record of Debt-Adjusted per Share Growth Daily Production Per Debt-Adjusted Share 2011 2012 2013 2014 2015 2016 2017 Year-End Proved Reserves Per Debt-Adjusted Share 2011 2012 2013 2014 2015 2016 2017 6 Note: Debt-adjusted share count is calculated as the sum of the annual weighted average shares outstanding plus the incremental debt shares by dividing total debt by the average annual share price.

Industry-Leading Cost Structure Continues to Improve $1.21 Total Company All-Sources Finding & Development Costs ($/Mcfe) $0.87 $0.55 $0.71 $0.57 $0.37 $0.35 2011 2012 2013 2014 2015 2016 2017 $0.65 Marcellus All-Sources Finding & Development Costs ($/Mcf) $0.49 $0.40 $0.43 $0.31 $0.26 $0.22 2011 2012 2013 2014 2015 2016 2017 7

Resulting in a Continued Reduction in Breakeven Prices Cash Operating Expenses ($/Mcfe) Operating Transportation¹ Taxes O/T Income Cash G&A² Financing³ Exploration 4 $1.88 $1.74 $1.31 $1.30 $1.30 $1.16 $1.13 $1.06 $0.99 $0.98 2011 2012 2013 2014 2015 2016 2017 Q1 2018 Q2 2018 Q3 2018 8 1 Includes all demand charges and gathering fees 2 Excludes stock-based compensation 3 Excludes non-cash interest expense associated with income tax reserves and amortization of deferred financing cost 4 Excludes dry hole cost

Cabot s 2019 Operating Plan is Expected to Deliver Continued Improvement in ROCE Return on Capital Employed (ROCE) >20% 10.8% 5.7% TTM Q3 2017 TTM Q3 2018 2019E¹ 9 Note: See supplemental tables at the end of the presentation for a reconciliation of non-gaap measures 1 Based on forward curves as of the week of 10/22/2018

and a Significant Expansion of Free Cash Flow Free Cash Flow ($ mm) $650 - $700 $250 ~7% free cash flow yield 2 $155 2017 2018E¹ 2019E¹ Note: See supplemental tables at the end of the presentation for a reconciliation of non-gaap measures 1 Based on forward curves as of the week of 10/22/2018 10 2 Based on market capitalization as of 10/25/2018

Cabot is Committed to Returning Capital to Shareholders Return of Capital to Shareholders ($mm) $1,000 $900 $800 Dividends Share Repurchases Remaining share repurchase authorization of 20mm shares 1 $700 $600 $500 $400 $300 $200 $100 $0 Commodity Price Downturn $710 Year-to- Date (as of Oct. 26, 2018) $165 $139 $124 $13 $17 $25 $33 $33 $36 $79 $111 2011 2012 2013 2014 2015 2016 2017 2018E Increased Increased Increased Increased Dividend Dividend Dividend Dividend 33% 100% 150% 40% Cabot is committed to returning >50% of free cash flow to shareholders annually through dividends and share repurchases 11 1 As of October 26, 2018 Note: The chart above excludes the Company s 2016 equity issuance

Cabot s Balance Sheet is Well-Positioned to Provide Financial Flexibility Through the Commodity Price Cycle Net Debt to LTM EBITDAX 2.5x Target Leverage Ratio: 1.0x 1.5x 1.8x 1.4x 1.4x 1.2x 0.9x 1.0x 0.9x 2011 2012 2013 2014 2015 2016 2017 Q3 2018 12 Note: See supplemental tables at the end of the presentation for a reconciliation of non-gaap measures

Thickest Marcellus Section Across the Trend With Two Distinct, Incremental Reservoirs Separated by the Purcell Limestone Cabot is positioned in the thickest producing Marcellus interval in the basin ~290 470 feet of Marcellus section across Cabot s acreage position N Purcell Limestone a frac barrier that separates the Upper and Lower Marcellus reservoirs is 25 feet or thicker across 90% of Cabot s acreage position (up to 90 feet thick) Tully / Geneseo formations are 900 1,900 feet above the intervals shown in Bradford / Susquehanna Counties, PA 13

Cabot s Marcellus Position is the Most Prolific U.S. Onshore Natural Gas Resource Play Estimated Ultimate Recovery (EUR) Bcfe/1,000 Lateral Feet Based on Gen 4 / 5 completion designs 4.4 2.9 Based on older Gen 1 / 2 / 3 completion designs Represents >70% of the Lower Marcellus EUR per 1,000 lateral feet for comparable well design Plan to test Gen 5 design on a few Upper Marcellus wells in 2H 2018 Appalachian Gas Play Non-Appalachian Gas Play Peer Average: 2.17 Bcfe / 1,000 14 Source: Current investor presentations as of February 16, 2018. Peers include Antero Resources, Chesapeake Energy, Eclipse Resources, EQT Corporation, Gulfport Energy, Range Resources, and Southwestern Energy. For companies with multiple type curves, a weighted average was used based on location count or acreage, based on current allocation of drilling capital.

2018 is an Inflection Year for Cabot 1.05 Bcf/d Remaining capacity associated with Trains 2 & 3 160 Mmcf/d 150 Mmcf/d 250 Mmcf/d ~2.4 Bcf/d 350 Mmcf/d (COG transport capacity): 3.5 20 years 3.6 3.8 500 Mmcf/d (COG 2.4 transport capacity): 15 years 150 Mmcf/d (3 rd party transport capacity): 3 years 50 Mmcf/d (Long-term firm sales): 15 years ~4.0 Bcf/d Q3 2018 Gross Production Atlantic Sunrise (In service as of October 6, 2018) Lackawanna Energy Center Power Plant (Trains 1 & 2 online; Train 3 on schedule for December 2018) PennEast (2020) Leidy South (As early as Q4 2021) Future Gross Production Capacity Based on Firm Transport / Firm Sales Secured as of Q3 2018 Cabot continues to evaluate new opportunities to increase firm transport capacity / firm sales and remains confident it can organically grow its production base above 4.0 Bcf/d through the following opportunities: 1) additional sales on currently approved takeaway projects (i.e. PennEast) 2) incremental sales on potential future expansion projects 3) increasing in-basin market share 4) new in-basin demand projects 5) future greenfield takeaway projects (including Constitution Pipeline) 15 Note: COG firm transport capacity / firm sales are stated on a gross basis before royalties

16 Appendix

2018 and Preliminary 2019 Capital Budget and Operating Plan 2018E Production Growth: 7% - 8% (12% - 13% on a debt-adjusted per share basis) 2018E Total Program Spending: $940 mm (includes $70 mm of equity pipeline investments) Marcellus Shale Exploration Areas Pipeline Investments Corporate 2% 7% 8% Net Marcellus Wells Placed on Production Due to larger pad sizes in Q1 and the 2 nd completion crew not coming online until February 2018, no wells were placed on production during 0 Q1 20 Q1 2018 Q2 2018 Q3 2018E Q4 2018E 36 24 Net Production (Mmcfe/d) 1,884 1,895 2,029 ~2,225 2,275 83% Q1 2018 Q2 2018 Q3 2018 Q4 2018E Full-year 2019 production growth guidance of 20% - 25% (25% - 30% on a debt-adjusted per share basis) 2019E total program spending of $800 mm - $850 mm 17

2018 and Preliminary 2019 Guidance Full-year 2018 daily production growth guidance: 7% - 8% (12% - 13% on a debt-adjusted per share basis) Q4 2018 production guidance: 2,225 2,275 Mmcfe/d 2018 total program spending: $940 million 2018 Guidance Marcellus Shale: $780 million Exploration Areas: $75 million Pipeline Investments: $70 million Corporate: $15 million 2018 Marcellus Shale wells placed on production: 80 net wells 2018 income tax rate guidance: 24% Q4 2018E Natural Gas Price Exposure By Index NYMEX less ~($0.35) 28% Fixed Price (~$2.85) 20% Transco Z6 NNY less ~($0.65) 17% Leidy Line 10% TGP Z4 300 Leg 10% Power Pricing 6% Dominion 6% 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. 2018 deferred tax rate guidance: 100%+ (The Company expects to receive a refund in 2018 associated with the recent repeal of the corporate alternative minimum tax) Full-year 2019 daily production growth guidance: 20% - 25% (25% - 30% on a debt-adjusted per share basis) Preliminary 2019 Guidance 2019 total program spending: $800 - $850 million 2019 average differential to NYMEX: $0.30 per Mcf 1 2019 income tax rate guidance: 24% 2019 deferred tax rate guidance: 100% Q4 2018E Cost Assumptions ($/Mcfe, unless otherwise noted) Direct operations $0.08 - $0.09 Transportation and gathering $0.66 - $0.68 Taxes other than income $0.02 - $0.03 Depreciation, depletion and amortization $0.48 - $0.53 Interest expense $0.08 - $0.09 General and administrative ($mm) 2 $13 - $15 Exploration ($mm) 3 $5 - $6 (1) Based on forward curves as of the week of 10/22/2018 (2) Excluding stock-based compensation (3) Excluding exploratory dry hole costs; includes exploration administration expense and geophysical expenses

Financial Position and Risk Management Profile Debt Maturity Schedule ($mm) as of 9/30/2018 (Including Weighted Average Coupon Rate) $600 $500 $400 $300 $200 $100 $0 $237mm repaid in July 2018 $67 $87 $188 Q4 2018 2019 2020 2021 2022 2023 2024 2025 2026 $62 $575 $312 2018 Hedge Position 1 Capitalization / Liquidity Natural Gas (NYMEX) Swaps Total Volume (Bcf) Average Price per Mcf Natural Gas (NYMEX) Basis Swaps Total Volume - Leidy (Bcf) Average Price per Mcf (Leidy) Total Volume Transco (Bcf) Average Price per Mcf (Transco) 98.0 $2.87 34.1 ($0.68) 10.7 $0.41 As of 9/30/2018 $bn Cash and Cash Equivalents $0.3 Debt $1.3 Net Debt $1.0 Net Capitalization $3.1 Liquidity $2.1 Net Debt / Capitalization 31.7% Net Debt / LTM EBITDAX 0.9x 19 1 As of October 26, 2018 2 Based on the midpoint of the production guidance range

2018 2019 Hedge Summary 2018 Natural Gas Swaps # of Total $/Mcf Pricing Index Contracts Mcf/Day Fixed Price Duration LDS NYMEX 26 252,574 $2.93 Feb-18 Dec-18 LDS NYMEX 5 48,572 $3.10 Feb-18 Oct-18 2018 Natural Gas Basis Swaps # of Total $/Mcf Pricing Index Contracts Mcf/Day Fixed Price Duration Leidy 5 48,572 ($0.71) Jan-18 Dec-18 Leidy 5 48,572 ($0.68) Feb-18 Dec-18 Transco 3 26,143 $0.42 Jan-18 Dec-18 2019 Natural Gas Basis Swaps # of Total $/Mcf Pricing Index Contracts Mcf/Day Fixed Price Duration Leidy 15 145,716 ($0.55) Jan-19 Dec-19 Transco 3 29,143 $0.42 Jan-19 Dec-19 Note: As of October 26, 2018

Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share 21

22 EBITDAX Calculation and Reconciliation

23 Net Debt Reconciliation

24 Discretionary Cash Flow and Free Cash Flow Calculation and Reconciliation

25 Return on Capital Employed Calculation