Exhibit 99.1
Montage resources analyst day march 20, 2019 nyse: mr
Disclaimer Forward-Looking Statements This presentation contains “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. All statements, other than statements of historical fact included in this press release, regarding Montage Resources’ strategy, future operations, financial position, estimated revenues and income/losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words “plan,” “endeavor,” “will,” “would,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” “position,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Montage Resources’ current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in Montage Resources’ Annual Report on Form 10-K that was filed with the Securities and Exchange Commission on March 15, 2019, (the “2018 Annual Report”), in “Item 1A. Risk Factors” of Montage Resources’ Quarterly Reports on Form 10-Q and in Montage Resources’ other filings and reports with the Securities and Exchange Commission. Forward-looking statements may include, but are not limited to, statements about Montage Resources’ business strategy; reserves; general economic conditions; financial strategy, liquidity and capital required for developing its properties and timing related thereto; realized natural gas, NGLs and oil prices; timing and amount of future production of natural gas, NGLs and oil; its hedging strategy and results; future drilling plans; competition and government regulations, including those related to hydraulic fracturing; the anticipated benefits under commercial agreements; marketing of natural gas, NGLs and oil; leasehold and business acquisitions; the costs, terms and availability of gathering, processing, fractionation and other midstream services; the costs, terms and availability of downstream transportation services; credit markets; uncertainty regarding future operating results, including initial production rates and liquid yields in type curve areas; and plans, objectives, expectations and intentions contained in this press release that are not historical, including, without limitation, the guidance set forth herein. Forward-looking statements also may include statements relating to the combination with Blue Ridge, including statements regarding integration and transition plans, synergies, cost savings, opportunities, anticipated future performance, benefits of the transaction and its impact on Montage Resources’ business, operations, assets, results of operations, liquidity, and financial position, and any statements of assumptions underlying any of the foregoing. Montage Resources cautions you that all these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility and declines in the price of natural gas, NGLs, and oil, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in the 2018 Annual Report, in “Item 1A. Risk Factors” of Montage Resources’ Quarterly Reports on Form 10-Q and in Montage Resources’ other filings and reports with the Securities and Exchange Commission. In addition, forward-looking statements are subject to risks and uncertainties related to the combination with Blue Ridge, including, without limitation, failure to realize or delays in realizing expected synergies or other benefits of the transaction, difficulties in integrating the combined operations, disruption of management time from ongoing business operations due to the transaction, adverse effects on the ability of Montage Resources to retain and hire key personnel and maintain relationships with suppliers and customers, negative effects of consummation of the transaction on the market price of the Company’s common stock, transaction costs, unknown liabilities or unanticipated expenses. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement and are based on assumptions that Montage Resources believes to be reasonable but that may not prove to be accurate. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Montage Resources or persons acting on its behalf may issue. Except as otherwise required by applicable law, Montage Resources disclaims any duty to update any forward-looking statements to reflect new information or events or circumstances after the date of this press release. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. Cautionary Note Regarding Hydrocarbon Quantities The SEC permits oil and gas companies to disclose in their filings with the SEC only proved, probable and possible reserve estimates. Montage has provided proved reserve estimates that were independently engineered by Software Integrated Solutions (SIS) Division of Schlumberger Technology Corporation. Unless otherwise noted, proved reserves are as of December 31, 2018. Actual quantities that may be ultimately recovered from Montage’s interests may differ substantially from the estimates in this presentation. The Company may use the terms “resource potential,” “EUR” and “upside potential” to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are based on analogy to the Company’s existing models applied to additional acres, additional zones and tighter spacing and are the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules. EUR estimates, resource potential and identified drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations, which have been attributed to these quantities. 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, availability 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. Resource potential and EUR may change significantly as development of the Company’s oil and natural gas assets provide additional data. The Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. The type curve areas included in this presentation are based upon our analysis of available Utica Shale well data, including, but not limited to, information regarding initial production rates, Btu content, natural gas yields and condensate yields, all of which may change over time. As a result, the well data with respect to the type curve areas presented herein may not be indicative of the actual hydrocarbon composition for the type curve areas, and the performance, Btu content and natural gas and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in our area of operation. Cautionary Note Regarding Non-GAAP Financial Measure This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including Adjusted EBITDAX. While management believes such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of Adjusted EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix of this presentation.
INTRODUCTION & FOCUS FIVE STRATEGY John Reinhart President and Chief Executive Officer montage resources
Experienced Appalachian basin leadership team montage resources’ management team possesses significant Appalachia specific experience with an excellent track record execution prior companies experience (yrs) john reinhart president & ceo blue ridge ascent resources Chesapeake energy schlumberger 25 oleg tolmachev evp & coo eclipse Chesapeake energy Encana tm 20 michael hodges evp & cfo blue ridge mountain resources payrock enervy ii pr rex energy(r) chesapeake energy 18 paul Johnston evp & general counsel blue ridge mountain resources centex thompsons & knight impact attorneys and counselors 39 matthew rucker evp, resource development & planning blue ridge mountain resosurces Chesapeake energy 12 marty byrd svp, land eclipse resources Chesapeake energy bhpbilliton 40 4
Focus five small cap appalachia utica and marcellus operator rebranded and focused on maximizing shareholder value cash flows & returns arrest corporate outspend while facilitating disciplined growth optimize development plan for efficiency, delivering cost reductions, lower cycle times and improved cash turns cost structure improvement & integration financial & operational flexibility focus five portfolio optimization enhancing scale with disciplined growth accelerate merger upstream, midstream, downstream and corporate synergy realizations leverage activity and scale for further savings deliver attractive balance sheet and hedging portfolio enhance value through balanced operational and commercial agreements capture value enhancement through diverse well mix and stacked pay opportunities unlock value of high quality company assets through strategic partnerships and operational execution generate cash flow improvement and unit cost reductions through attractive scale achieve disciplined organic production growth while weighing accretive inorganic opportunities 5
Focus five small cap appalachia utica and marcellus operator rebranded and focused on maximizing shareholder value cash flows & returns arrest corporate outspend while facilitating disciplined growth optimize development plan for efficiency, delivering cost reductions, lower cycle times and improved cash turns cost structure improvement & integration financial & operational flexibility focus five portfolio optimization enhancing scale with disciplined growth accelerate merger upstream, midstream, downstream and corporate synergy realizations leverage activity and scale for further savings deliver attractive balance sheet and hedging portfolio enhance value through balanced operational and commercial agreements capture value enhancement through diverse well mix and stacked pay opportunities unlock value of high quality company assets through strategic partnerships and operational execution generate cash flow improvement and unit cost reductions through attractive scale achieve disciplined organic production growth while weighing accretive inorganic opportunities 5
Cycle time improvement Focused on accelerating cash flows by shifting to a low risk, repeatable program and optimizing capital allocation towards the wellbore with returns-based spending that possesses well mix optionality CASH FLOW & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE W/ DISCIPLINED GROWTH Average Lateral Length1 (Ft.) Average Cycle Time2 (Days) Cycle Time CF and Returns Comparison3 4 Well13K LL 4 Well 20K LL Cycle Time 7 Months 10 Months IRR 61% 54% Payback Period 20 Months 24 Months ~15,400 ~11,700 25% DECREASE ~11,700 2018 2019 2018 2019 ~220 20% decrease ~175 2019 cashflow time 4 Well Pad 13K LL 4 Well Pad 20K LL (1) Average lateral length of spuds within each year. (2) Spud date to turn-in-line date for TILs within each year. (3) Dry Gas North example run at flat pricing of $3.00 gas and $55 oil. 6
corporate integration contiguous acreage allows montage resources to leverage operational synergies; post-merger consolidation of headquarters and integration expected to achieve ~$15 million in g&a savings cash flow & returns cost structure improvement & integration financial & operational flexibility portfolio optimization enhancing scale w/ disciplined growth contiguous acreage & takeaway g&a per mcfe1 (1) cash g&a expense. 2019e is based on the midpoints of 2019 guidance for production and cash g&a, excluding merger-related expenses. cash g&a is a non-gaap financial measure, see appendix for details. 7
DRILLING & COMPLETIONS CAPITAL SYNERGIES Development plan integration was accelerated for Day 1 execution which allows Montage Resources to take advantage of synergies and incorporate cost reductions immediately CASH FLOW & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE W/ DISCIPLINED GROWTH SERVICE COST & DESIGN IMPROVEMENTS • Conducted aggressive RFP process • Optimized well designs and improved execution cycle times by combined engineering and operational excellence • Recycling of production equipment such as wellheads, compressors, dehys has significant savings in capital spend and LOE SERVICE COST & DESIGN IMPROVEMENTS • Water cost savings due to shared infrastructure and recycling of produced water • Utilization of existing construction infrastructure creates significant cost reductions • Shared gas gathering infrastructure allows running rigs and frac fleets on natural gas resulting in fuel savings INFRASTRUCTURE SYNERGIE (1) Weighted average of type curve costs based on 2019 estimated gross lateral feet spud by area.
FINANCIAL POSITIONING & FLEXIBILITY Strong balance sheet and capital discipline positions the company to opportunistically accelerate development and take advantage of strategic initiatives CASH FLOW & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE W/ DISCIPLINED GROWTH STRONG HEDGE BOOK1 ACCRETIVE FINANCIAL POSITION TARGETING CASH FLOW NEUTRALITY YE 2019 YE 2019 EXPECTED ~2.0X LEVERAGE3 2019 CAPITAL FUNDED BY CASH FLOWS4 ~80% NO DEBT MATURITIES UNTIL JULY 2023 YE 2018 PRO FORMA LIQUIDITY5 ~$338MM (1) Hedges as of March 15, 2019. (2) For the purposes of calculating three-way floor price, the higher put value was used. (3) Net Debt at YE 2019 to LTM pro forma 1+1 EBITDAX. (4) Based on the midpoints of guidance at $3.00 gas and $55 oil. (5) Reflects YE 2018 ECR liquidity of $171.5MM plus the $150MM increased borrowing base, $13.5MM reduction in LCs and BRMR YE cash balance, pro forma for $25MM BRMR term loan paid down at transaction close
OPERATIONAL FLEXIBILITY Balanced firm transportation portfolio along with limited operational commitments allow the company to focus on strategy and capital execution CASH FLOW & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE W/ DISCIPLINED GROWTH MARKETED PRODUCTION VS FT ADVANTAGEOUS COMMITMENTS FIRM TRANSPORTATION COMMITMENTS ~50-60% 2019 PRODUCTION1 LIMITED DRILLING COMMITMENTS SEG2 JV FINAL TILs mid-2019 MINIMAL LONG TERM SERVICE CONTRACTS HBP’d or LONG-TERM LEASEHOLD3 70-75% of TOTAL NET ACRES (1) Estimated gross marketed production. (2) Sequel Energy Group. (3) As of Q4 2018. Long-term leasehold represents leases with expirations in 2022 and beyond.
EFFICIENT CAPITAL DEPLOYMENT Over 90% of 2019 capital is allocated to drilling and completions spend in revenue accretive inventory with highest investment returns, maintaining flexibility in well mix depending on commodity environment CASH FLOW & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE W/ DISCIPLINED GROWTH 2019 CAPITAL ALLOCATION 2019 ACTIVITY in HIGHEST IRRs1 (1) Type curve IRRs based on $3.00 gas and $55 oil flat pricing and represent half-cycle returns which utilize commercial assumptions as shown in the appendix. (2) Marcellus TC IRRs assume stacked-pay capital infrastructure synergies. (3) Net locations based on 13,000’ type curve lateral lengths and Dry Gas North, Dry Gas South and Utica Rich Gas based on 1,000' well spacing, Utica Condensate, Marcellus North and Marcellus South based on 750' well spacing and Flat Castle based on 1,200' well spacing. 10% risked factor is utilized. Acreage as of Q4 2018.
PORTFOLIO OPTIMIZATION Montage Resources controls an economic core footprint that allows for development mix flexibility and scalability CASH FLOW & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE W/ DISCIPLINED GROWTH UNLOCKING VALUE OF HIGH QUALITY INVENTORY PROVED-UP FLAT CASTLE EUR ~2.2 BCFE/1,000’ ASSESSING OTHER ALTERNATIVES TO ACCELERATE VALUE 2019 GROSS SPUDS IN MARCELLUS STACKED-PAY ~33% STACKED PAY PROVIDES FURTHER LIQUIDS PRICE DIVERSIFICATION CONTINUOUS ACREAGE POSITION ALLOWS CAPITAL DEPLOYMENT FLEXIBILITY REMAINING INVENTORY of ~700 NET LOCATIONS OR ~27 Years1 (1) Assumes a two-rig development pace with ~80% average working interest.
ACHIEVING SCALE THROUGH DISCIPLINED GROWTH Significant reserve growth provides valuation uplift and increased liquidity CASH FLOW & RETURNS PORTFOLIO OPTIMIZATION FINANCIAL & OPERATIONAL FLEXIBILITY COST STRUCTURE IMPROVEMENT & INTEGRATION ENHANCING SCALE W/ DISCIPLINED GROWTH PROVED RESERVES1 PDP RESERVES 65% PROVED PV101 BRMR MERGER ADDED ~$324MM of PDP PV10 to 2018 2019 PRO FORMA PRODUCTION (1) Pro forma ECR + BRMR reserves at SEC pricing as of year-end 2017 and 2018 from independent engineering firms. (2) Preliminary unaudited estimates of pro forma ECR + BRMR 2018 production. (3) Growth rate reflects 12 months pro forma in 2019 vs ECR + BRMR in 2018. Note: PV10 is a non-GAAP financial measure, see appendix for details
APPALACHIA DIFFERENTIATORS Appalachia is the low cost operating gas basin with ~13 Bcf/d of downstream transportation capacity added over the past two years which possesses outlets to diverse markets with premium differentials DOMINION SOUTH BASIS TO NYMEX1 NORTHEAST TAKE AWAY ~40 Bcf/d2 of capacity out of the basin to premium markets 2019 take away capacity is ~20% higher than expected basin production allowing others to take advantage of 3rd party capacity (1) Current Dominion South basis as of March 7, 2019. (2) Source: J.P. Morgan North America Equity Research; December 2018
WHY MONTAGE? Montage Resources is a pure play Appalachia operator located in the core Marcellus and Utica fairway, adopting a low risk development plan executed by an experienced Appalachia team positioned for disciplined growth and substantially undervalued vs peers LOW LEVERAGE, GROWING, UNDERVALUED1 NET DEBT / LQA EBITDAX2 POISED FOR VALUE ENHANCEMENT New leadership focused on accelerating cash flows • Clean balance sheet with low leverage targeting cash flow neutrality by YE 2019 • Significantly undervalued vs peers1 • Balanced FT portfolio while basin take-away is over committed allowing for price enhancement opportunities • Increased liquidity and cash flows allows for accretive strategic growth opportunities • Stacked pay development in 2019 allows for further cost reductions • Improved NGL price realizations via access to MEII pipeline and Shell ethane cracker • Synergies as a result of merger decrease cost structure immediately (1) Peer group includes AR, CNX, COG, EQT, GPOR, RRC, SWN. (2) Based on company reported financials as of year-end 2018; MR based upon pro forma ECR + BRMR. (3) Based on 2019 company reported guidance. (4) Stock price as of March 1, 2019.
RESOURCE DEVELOPMENT AND PLANNING Matthew Rucker EVP, Resource Development & Planning
2019 DEVELOPMENT PLAN OVERVIEW Greater than 90% of 2019 capital is allocated to low-risk D&C activity leading to pro forma 12 month year-over-year production growth of ~16% to ~545 – 570 Mmcfe per day (1) Metrics based on midpoint of guidance and based on timing of merger closing; revenue assumes $3 gas and $55 oil in 2019
2019 PLAN FOCUSES ON HIGH RETURNING AREAS Key development areas with balance of wet and dry well mix deliver attractive single well IRR’s and flexibility for liquids pricing upside Spuds TILs Gross 4 – 6 11 – 13 Net (WI) 3.9 – 5.9 10.5 – 12.4 Avg LL ~14,300’ ~13,200’ Spuds TILs Gross 18 – 20 17 – 19 Net (WI) 13.6 – 15.2 10.5 – 11.7 Avg LL ~12,100’ ~14,700’ Spuds TILs Gross 11 - 13 10 - 12 Net (WI) 10.6 – 12.6 9.6 – 11.6 Avg LL ~9,900’ ~9,500’ (1) IRR values represent half-cycle returns and utilize commercial assumptions as shown in the appendix
OPTIMIZED DEVELOPMENT PLANNING Development plan integration accelerated for Day 1 allowing Montage to begin execution of optimization immediately IMPROVED CYCLE TIMES OPTIMIZED PLANNING STACKED PAY FOCUS Optimizing initial wells per pad drilled Reducing lateral lengths and operational risk Shortening rig move distance Focusing activity in delineated areas with existing infrastructure Laterals in same direction to eliminate offset drainage effects and minimize future parent-child issues Engineered completion designs to improve economic return Low risk drilling plan in proven areas Shift to Marcellus drilling on existing Utica infrastructure Reduced per well costs increasing return on investment ACCELERATED & DE-RISKED CASH FLOW
2019 OPERATING EXPENDITURES Highly competitive operating cost structure provides for significant margin expansion through scale 2019 OPERATING EXPENSES1 OPEX VS APPALACHIAN PEERS1,2 Operating Cost ($/Mcfe) vs Daily Production (Mmcfe/d) Competitive operating costs compared to in-basin peers despite significantly less production (~75% lower than peer average) to distribute fixed costs (1) Operating costs include lease operating, transportation, gathering and compression, production and ad valorem taxes. (2) Includes Appalachian peers with at least 10% liquids production (AR, GPOR, RRC, SWN). Sourced from peers’ 2019 annual guidance press releases where available with Q1 guidance utilized as an annualized proxy for one of the peers.
RESERVES AND RESOURCE PORTFOLIO
SUBSTANTIAL PROVED RESERVE GROWTH Montage Resources has had significant proved reserves growth on a pro forma basis with ~265% increase in reserves and ~600% increase in PV10 over the last two years 2018 YE Pro Forma SEC Pricing Net Oil (Mbbls) Net NGL (Mbbls) Net Gas (Mmcf) Net Total (Mmcfe) Net PV-10 ($MM) PDP 8,295 30,693 835,794 1,075,722 $994 PNP/PBP 721 2,045 23,031 39,626 $48 PUD 13,801 17,071 1,103,082 1,288,319 $730 Total Proved 23,817 49,809 1,916,906 2,403,666 $1,772 PROVED RESERVES (BCFE) PDP RESERVES 65% YoY 2018 PROVED RESERVES PV10 ($MM) Note: All reserves metrics are pro forma ECR + BRMR; YE 2016, 2017 and 2018 Reserve Reports were prepared by independent reserve auditor. PV10 at SEC pricing. PV10 is a nonGAAP financial measure, see appendix for details.
. DIVERSE RESOURCE PORTFOLIO Attractive portfolio of diverse assets with an even split of wet and dry well inventory, providing optionality to a constantly evolving commodity price environment Utica and Marcellus Type Curve Areas Flat Castle Marcellus North Marcellus South Utica Condensate Utica Rich Gas Utica Dry Gas North Utica Dry Gas South Flat Castle Net Undeveloped Acres1 20,200 17,200 47,600 10,300 44,200 33,700 44,800 Approximate Remaining Net Locations2 80 70 185 30 130 100 105 EUR3 (Bcfe/1000’) 1.6 1.4 0.9 2.4 2.2 1.6 2.0 PV10 ($MM)4 $12.7 $7.3 $6.1 $6.2 $12.2 $4.6 $12.0 IRR4 77% 40% 44% 38% 62% 24% 60% (1) Acreage as of Q4 2018. (2) Net locations based on 13,000’ type curve lateral lengths and Dry Gas North, Dry Gas South and Utica Rich Gas based on 1,000' well spacing, Utica Condensate, Marcellus North and Marcellus South based on 750' well spacing and Flat Castle based on 1,200' well spacing. 10% risked factor is utilized. (3) EUR includes sold gas, oil, and NGL volume (4) Type curve economics are based on $3.00 gas and $55 oil flat pricing and represent half-cycle returns which utilize commercial assumptions as shown in the appendix
DE-RISKED OHIO MARCELLUS OPPORTUNITY Successful subsurface evaluation with proven well results allows the company to transition from delineation mode to full scale development mode, leading to value enhancement on stacked pay asset MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE Recent well results of the Herrick AM 1HM and David Stalder BM 16HM have significantly de-risked Montage’s Southeast Ohio Marcellus acreage — Improved understanding of condensate yields leads to more accurate reservoir fluid description mapping — Montage’s acreage position receives the added benefit of the gas-rich Geneseo formation laying directly above the Marcellus without frac barrier — Creates a thicker flow unit with similar OGIP as West Virginia Marcellus — Allows single well access to Upper Devonian package REGIONAL CROSS-SECTION LOCATOR MAP
MARCELLUS VALUE ATTRACTS CAPITAL ALLOCATION Initial delineation wells are outperforming type curve expectations, de-risking Ohio Marcellus acreage position for full scale development mode MARCELLUS UTICA CONDENSATE UTICA DRY GAS UTICA DRY GAS FLAT CASTLE David Stalder 16HM and Herrick 1HM in Monroe County, Ohio turned to sales in January 2018 with an average lateral of ~9,100 ft — Initial production results significantly de-risk Montage’s Marcellus acreage — Average gas IP rate of 6.7 Mmcf/d — Average initial condensate yield of ~70 Bbl/Mmcf — Marcellus North accounts for approximately 33% of gross spuds in 2019 — Value enhancing utilization of shared Utica infrastructure within the stacked-pay window Recent Marcellus North Performance David Stalder 16HM Herrick 1HM Marcellus N. Type Curve NGL Yield (BBL/MMCF) 70 70 70 Gas EUR (BCF/1,000 ft) 1.4 1.2 0.97 Cond. EUR (MBBL/1,000 ft) 22.5 32.8 27.3 EUR (BCFE/1,000 ft) 2.2 1.9 1.6 Post Processed % of Gas 64% 61% 61% (1) Normalized to 13,000’. Equivalent production calculations assumes processing with three-phase recovery (with ethane rejection).
UTICA CONDENSATE DELIVERS LOW-RISK REPEATABLE DEVELOPMENT Recent condensate wells are meeting or exceeding type curve expectation, providing low-risk development opportunities with increased liquids exposure MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE 5 Utica condensate pads turned to sales in 2018 — Recent condensate wells are meeting or exceeding Type Curve — Consistent well results provide low-risk development opportunities to optimize portfolio planning (1) Production normalized to 13,000’.
UTICA CONDENSATE TYPE CURVE EXPANSION MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE SUMMARY Core and petrophysical data indicate similar reservoir quality of the Point Pleasant south from Guernsey to Washington County, OH — Consistent net pay, porosity, pressure gradient, and reservoir fluid properties — Consistent geologic properties from north to south provide a better understanding of formation changes to significantly de-risk the position — Farley well performance is in-line with historical well performance in Guernsey County and type curve CROSS SECTION LOCATOR MAP
SUCCESSFUL WELL RESULTS IN WASHINGTON CO. Step-out test into the southern portion of Utica Condensate area generates results similar to the proven northern portion of Utica Condensate area MARCELLUS UTICA CONDENSATE UTICA DRY GAS U FLAT CASTLE 3 Farley wells turned to sales in January 2018 — Utica wells within a similar condensate yield window show no degradation in EUR/ft moving north to south — Recently turned-in-line 4 well Woodchopper pad offsetting the Farley and are currently evaluating results (1) Production normalized to 13,000 ft. Pad averages shown with wells filtered to match initial producing condensate yield of Farley pad. Private and public data combined. Assuming 10% gas shrink and NGL yield of 65 Bbl/Mmcf for public wells. All production normalized to 1,000 ft completed lateral length.
EXCEPTIONAL WELL PERFORMANCE IN DRY GAS NORTH Highly deliverable and repeatable Dry Gas North well results provide long term corporate production growth ability with attractive economics to allocate capital MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE 5 Dry Gas North pads turned to sales in 2018 in Monroe County, OH — 2018 turn-in-lines are meeting or exceeding type curve — Consistent well results provide low risk development opportunities to optimize portfolio planning (1) Production normalized to 13,000 feet.
UTICA DRY GAS EXPANSION INTO WEST VIRGINIA Successful delineation in West Virginia provides upside value potential with expansion of the Dry Gas North type curve area MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE SUMMARY Core and petrophysical data indicate similar reservoir quality of the Point Pleasant south from Ohio into West Virginia — Increased reservoir pressure in West Virginia drives productivity — Montage recently began production on a test well within its acreage block with promising results to date — Long term development planning underway to provide value opportunities CROSS SECTION LOCATOR MAP
SUCCESSFUL WEST VIRGINIA UTICA WELL RESULTS Second successful well test in West Virginia confirms performance expectations and creates opportunities for accretive value solutions MARCELLUS UTICA CONDENSATE UTICA dry gas flat castle company recently turned to sales the Spencer 1UH in Tyler County, WV — Test performed to offset existing 2014 Utica well with long term results and increase acreage valuation— Initial results indicate enhanced initial productivity in WV relative to OH Utica well results Analytical modeling supports well performance in WV, showing similar EUR’s to OH Utica type curve(1) Productions normalized to 13000 feet.
INDUSTRY WELL RESULTS FURTHER DELINEATE FLAT CASTLE Montage’s Flat Castle acreage sits at the center of the highest gas-in-place in the sub-basin and has been substantially delineated by strong surrounding well results drilled in lower gas-in-place areas 32 Note: Pad averages shown with the exception of the Painter 1H and Painter 2H.
MONTAGE FLAT CASTLE TYPE CURVES Two type curves for the Flat Castle Project Area have been developed: a base case and an upside case that was increased ~10% to reflect higher gas-in-place on Montage acreage as well as strong production results from offsetting wells MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE Montage has analyzed 24 producing industry wells within the project area to develop initial type curve expectations — The wells used to establish a type curve: — Landed in Montage’s target interval — Have sufficient production histories — Exist within a reasonable “control” radius — Base case type curve derived from well set in lower gas-in-place areas — Montage’s acreage sits on ~10% higher GIP than offset wells used for type curve, resulting in upside type curve(1) Production normalized to 13,000 feet.
UNLOCKING FLAT CASTLE Painter 2H is exceeding the base Flat Castle Type Curve of 2.0 BCF/1,000’ driven by engineered completion designs coupled with choke management techniques to enhance productivity 34 (1) GOPHER hydraulic fracture simulator. (2) Production normalized to 13,000 ft. UNLOCKING FLAT CASTLE — Painter 2H is producing 22 Mmcf/d on plateau with 2,700 PSI flowing surface pressure. Pressure decline indicates a plateau period as high as 7 months — Engineered completion techniques designed with 3D frac simulation1 utilized to connect single wellbore to both Indian Castle and Flat Creek formations — Based on Rate Transient Analysis, an analytical model was built to history match the last month (most recent) of pressure data. Probabilistic results show that P50 EUR is 2.2 BCF/1000’ MARCELLUS UTICA CONDENSATE UTICA DRY GAS FLAT CASTLE 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 0 5 10 15 20 25 30 35 40 9/22/2018 12/31/2018 4/10/2019 7/19/2019 10/27/2019 Casing Pressure(Psi) Gas Rate (MMcfd) 2 Gas Rate Forecast-P 50 Gas Rate-Type Curve Gas Rate Casing Pressure FLOWBACK STRATEGY AND BENEFITS — The Painter 2H was transitioned to choke management and production was reduced from 32 Mmcf/d to 22 Mmcf/d — Drastic response and increase in flowing pressure implies improvement to stimulated rock volume, likely: — Improvement of pressure dependent permeability — Enhanced frac conductivity — Slowed velocity through proppant pack to maintain integrity and prematurely closing fractures — Rate restriction directly increased productivity and EUR projections PAINTER 2H WELL PERFORMANCE MARCELLUS UTICA CONDENSATE UTICA DRY GAS
OPERATIONS OVERVIEW Oleg Tolmachev EVP & Chief Operations Office
MONTAGE OPERATIONAL EXECUTION Top performing Appalachia execution team delivering on cost reductions, lower cycle times and optimized well designs Continue to prioritize EH&S and regulatory performance • Utilization of operational practices to enhance vendor quality and heighten overall EH&S awareness Improve cycle times as a result of refining drilling execution processes for optimized lateral lengths • Design well pads to facilitate low cost subsequent pad development • Employ fit-for-purpose equipment, downhole tools, and technologies to decrease drilling costs Optimize completion designs through engineering expertise and data • Deliver frac cycle time reductions by enhancing vendor service performance and operational logistics • Reduce frac water costs by utilizing shared water infrastructure • Leverage scale and execution efficiencies to secure dramatically decreased stimulation costs Accelerate turn to sales timing by utilizing pre-fabricated equipment and standardized engineering design approach • Improve facility and maintenance cost by implementing pressure managed production methodology
EH&S DRILLING & CONSTRUCTION COMPLETIONS FACILITIES EH&S FOCUSED Safety driven execution team with a proven record of delivering operational results while maintaining best-in-basin environmental and safety record EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION 2018 EH&S TRACK RECORD EH&S STRATEGY IN 2019 1 ZERO REPORTABLE SPILLS ZERO ENVIRONMENTAL & SAFETY NOVs 100% VENDOR SELECTION WITH ISNET WORLDEH&S STRATEGY IN 20192018 EH&S TRACK RECORD EH&S STRATEGY IN 2019 1 Continue implementing Behavior Based Safety program • Remain actively involved with state and federal agencies in matters of regulation and law development Strictly vet all vendors through ISNet World Company safety performance tied to employee incentive structure Refine EH&S Best Management Practices developed for all areas of operations Refine EH&S Best Management Practices developed for all areas of operations (1) Stand-alone Eclipse 2018.
DRILLING & CONSTRUCTION EFFICIENCY GAINS Operational experience drilling complex laterals applied to a low-risk development program drives down cost and cycle time EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION COST REDUCTIONS OPERATIONAL Drilling practices geared towards optimized lateral lengths to reduce cycle time and well cost • Employ fit-for-purpose rig and auxiliary equipment ‒ Enhanced centrifuge packages ‒ High pressure mud systems ‒ Hydraulic pipe handling • Utilize bi-fuel technology for diesel fuel savings • Apply dual mud system in combination with managed pressure drilling (MPD) • Advanced rotary steerable system minimizes doglegs, improves rates of penetration and facilitates single trip lateral runs • Strong in-house civil engineering team focused exclusively on Montage pad and road designs COST STRUCTURE • Reducing service cost by leveraging scale through an extensive RFP process OPERATIONAL EXECUTIONDRILLED FEET PER DAY VERAGE DAYS SPUD TO RIG RELEASE COST STRUCTURE • Reducing service cost by leveraging scale through an extensive RFP process
ENGINEERING FOCUSED COMPLETIONS DESIGN Enhanced completions designs through engineering and machine learning allows for more efficient capital deployment and reserve recovery EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION OPTIMUM COMPLETION DESIGN MECHANICAL SPECIFIC ENERGY MODEL MECHANICAL SPECIFIC ENERGY MODELS APPLIED TO OPTIMIZE RESERVIOR COVERAGE — Optimized perf placement results in the most efficient use of capital and improves well performance — Incorporate well spacing and orientation into planning to minimize parent-child adverse effects UTILIZE MACHINE LEARNING FOR WELL SPECIFIC COMPLETION DESIGNS IMPROVING WELL PERFORMANCE, CYCLE TIME & CAPEX — Machine learning algorithms optimize completions designs using the following neural network parameters — Localized Geology — Well Spacing — Frac Stage Spacing — Sand Volume — Drilling Operations ENGINEERED FOR FULL DEVELOPMENT 20,350 20,400 20,450 20,500 20,550 20,600 20,650 0 50,000 100,000 150,000 ENGINEERED FOR FULL DEVELOPMENT EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION Mechanical Specific Energy Depth (ft) Cluster - 1 Cluster - 2 Cluster - 3 Cluster - 4 DEPTH 20,527 20,483 20,439 20,395 MSE 42,154 49,804 52,991 53,089
COMPLETION COST & CYCLE TIME IMPROVEMENTS Through focus on service performance, enhanced logistics and the benefits of scale, Montage is substantially reducing completion costs EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION COST REDUCTIONS OPERATIONAL EXECUTION OPERATIONAL • Reduce SWD costs as a result of increase in operational scale allowing production and flowback water recycling • Utilize bi-fuel technology across all frac fleets for diesel fuel savings • Experienced substantial frac cycle time efficiencies year to date as a result of heightened focus on service performance and logistics COST STRUCTURE • Reducing service cost by leveraging scale through an extensive RFP process • Significant cost reductions realized prior to merger close (1) 2018 stages per day based on ECR wells completed in 2018. (2) Year-to-date cycle time results as of March 1, 2019.
MANAGED PRESSURE PRODUCTION Managed Pressure flowback and production incorporates tools such as the Critical Flow Velocity Model (CVFM) driving enhanced well performance and cost reductions EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION MANAGED PRESSURE PRODUCTION PAINTER 2H EXAMPLE Producing wells are continually monitored to ensure that proppant does not get re-mobilized in any phase of production — Engineering teams create a safe operating envelope for each well to target the appropriate pressure drawdown and protect the Stimulated Rock Volume integrity — Utilizing CVFM helps to avoid overbuilding production equipment and mitigate debris damage Dropping the Rate from 32 Mmcf/d to 22 Mmcf/d created ~1,000 psi higher bottom-hole pressure • Re-activated previously pinched off fracture network (indication of pressure dependent perm) • Slowed down velocity as pressure drops to maintain SRV
FACILITIES ENHANCEMENTS Accelerate turn-to-sales timing by utilizing pre-fabricated equipment and standardized engineering design approachEH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION FACILITY COST SAVINGS FACILITY BUILD CYCLE TIME (DAYS) REDUCE COST AND CYCLE TIME BY EMPLOYING PRE-FABRICATED FACILITY DESIGN APPROACH • Utilizing standardized design and fabrication of premanufactured equipment and flow lines for simple plug in. • Facilitates construction commencement during the completion phase IMPROVE FACILITY AND MAINTENANCE COST BY IMPLEMENTING PRESSURE MANAGED PRODUCTION METHODOLOGY — Reductions in facilities capital by avoiding overbuilding capacity — Creates further reductions in lease operated expenses as a result of reduced proppant flowback
D&C CAPITAL SAVINGS Montage Resources expects to achieve ~10% reduction in drilling and completion costs across the asset base in 2019 EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION EH&S COMPLETION FACILITIES DRILLING & CONSTRUCTION (1) Weighted average of type curve costs based on 2019 estimated gross lateral feet spud. (2) Cost savings calculated by multiplying year-over-year type curve deltas by estimated net lateral feet. 2019 WELL COST SAVINGS2 ~$36MM 2019 PLANNED NET LATERAL FOOTAGE MARCELLUS WET GAS DRY GAS TOTAL ~115,000 ~69,500 ~178,200 ~362,700 (1) Weighted average of type curve costs based on 2019 estimated gross lateral feet spud. (2) Cost savings calculated by multiplying year-over-year type curve deltas by estimated net lateral feet.
MIDSTREAM AND MARKETING Michael Hodges EVP and Chief Financial Officer
MIDSTREAM AND MARKETING STRATEGY Diversified marketing strategy provides flexibility and enhanced pricing dynamics — Ensure continuous sale of all products via exceptional FLOW ASSURANCE relationships with service providers — Transport current and future production to diverse portfolio of regions and indices, both domestically and internationally DIVERSIFICATION OPTIONALITY RISK MANAGEMENT PRICE ENHANCEMENT Negotiate contractual terms to create innovative and flexible solutions and enhance market access — Manage commodity price exposure with physical sales and financial hedges in order to meet fiscal goals Optimize pricing across all commodity sales and reduce rates/fees for services
MIDSTREAM AND MARKETING OVERVIEW Leveraging scale, diversified markets and low commitments to increase net back prices SCALE FACILITATES FLEXIBILITY & OPTIONALITY Synergies allow opportunity to negotiate lower costs and improved services • Volume profile provides operational flexibility and mitigates risk of deficiencies • Numerous processing solutions available to judiciously allocate capital to development plan TAKEAWAY OPTIONS GENERATE ACCESS TO DYNAMIC MARKETS & ALLOW DIVERSIFIED SALES STRATEGY YEAR-ROUND Subscribed capacity into premier Gulf Coast, Midwest, and Canadian markets • Ability to redirect flows based on fundamental research & market needs EXCESS EQUITY GAS OPTIMIZED THROUGH SALES TO OVER-FIRMED PEERS AT PREMIUMS Expect 2019 marketed production is ~50% – 60% higher than firm transportation leaving options to take advantage of underutilized capacity out of the basin to premium markets • Excess marketed production may provide corporate strategic options in future
DEMAND DRIVERS – NORTHEAST TAKEAWAY Appalachian basis differentials have narrowed as projects have come online and capacity exceeds production DEMAND DRIVERS – NORTHEAST TAKEAWAY NORTHEAST PRODUCTION VS PIPELINE TAKEAWAY1 2019 EXIT NE PRODUCTION2 ~20% LESS THAN BASIN TAKEAWAY CAPACITY APPALACHIAN BASIS IMPROVEMENT3 COMPARATIVE BASIN PRICING4 (1) Source: S&P Global Platts. (2) Includes basin production volumes already committed to sell in basin. (3) Based on Dominion South and Argus strip pricing as of March 7th, 2019. (4) Based on NGI pricing for balance of 2019 as of March 8th, 2019.
FIRM TRANSPORTATION Evaluate daily market economics and utilize asset management optimization Continue to review expansion projects, power plant and LNG supply deals, and short-term capacity release markets Currently selling excess production above firm capacity in basin 48 2019 FIRM TRANSPORTATION / MCFE $0.55 $0.45 COLUMBIA TCO POOL ROVER TRUNKLINE ROVER – DAWN R
REALIZATIONS AND MARKET ACCESS 2019 STRATEGY 2019 MARKET DIVERSITY & DIFFERENTIALS1 AIM TO ACHIEVE PREMIUMS TO IN-BASIN PRICING Optimizing third-party’s unutilized capacity by selling into supply zones for Rockies Express, Leach Xpress, Rover and NEXUS • Explore opportunities to address production in excess of take-away such as firm sales, capacity release market, new projects, etc. LOCK-IN FAVORABLE BASIS PRICING, PHYSICALLY AND/OR FINANCIALLY PRODUCTION AREA RICH GAS DRY GAS MIDSTREAM PROVIDER BLUE RACER EUREKA EUREKA PROCESSING BERNE NATRIUM I MOBLEY DRY GAS DOWNSTREAM PIPELINE ROVER TEXAS EASTERN NEXUS DOMINION TCO (RESIDUE) EQUITRANS TCO (LEACH XPRESS) TEXAS EASTERN ROCKIES EXPRESS DOMINION ROVER (1) Production and differentials based on sale of total gross production forecasted in 2019; Differentials are based on March 7, 2019 strip and on an MMBtu basis and therefore exclude value uplift due to ethane
OHIO & WEST VIRGINIA MIDSTREAM SUMMARY UTICA DRY GAS (EUREKA MIDSTREAM) Existing gas gathering agreements with Eureka offering attractive terms and complementary acreage positions — Firm gathering capacity with pipeline connections directly to the well pad — Access to premium markets with delivery points to all major transmission lines UTICA RICH GAS (BLUE RACER MIDSTREAM) Existing gas gathering and processing contracts with Blue Racer offer similar terms, synergistic acreage positions and TIK options on residue and NGL’s — Potential to sell or exchange certain existing company gathering assets to 3 rd party midstream provider — Access to international NGL markets through new MEII capacity UTICA DRY GAS (EUREKA MIDSTREAM) — Existing production processed by Mark West through firm capacity and fixed ethane rejection capabilities — Undedicated acreage positioned near multiple processors with available capacity for competitive cost structure and access to premium markets UTICA RICH GAS (BLUE RACER MIDSTREAM) — Existing gas gathering agreements with Eureka offering attractive terms and complementary acreage positions — Firm gathering capacity with pipeline connections directly to the well pad — Access to premium markets with delivery points to all major transmission lines MARCELLUS RICH GAS (UNDEDICATED)
PENNSYLVANIA MIDSTREAM SUMMARY Existing marketing options for Flat Castle area provide initial sales outlets FAVORABLE MARKET ACCESS FLAT CASTLE PROJECT AREA Currently selling into Dominion North Point market and achieving price levels similar to Dominion South Point — Assessing options to utilize current FT portfolio — Alternative future options include deliveries into Tennessee, National Fuel and others for mid to long term sales — With pipeline expansion projects coming online in the area, possibility for future enhancement FAVORABLE MARKET ACCESS FLAT CASTLE PROJECT AREA Historical Averages: 2016: $(0.02) 2017: $(0.02) 2018: $(0.00) $(0.200) $(0.150) $(0.100) $(0.050) $- $0.050 $0.100 $0.150 $0.200 DOM NORTH TO DOM SOUTH DIFFERENTIALS1 (1) Pricing based on Platts' historical Gas Daily indices.
LIQUIDS MARKETING Diversification of liquids marketing portfolio allows for avoidance of potential economic hardship involved with single market outlet MARKWEST MOBLEY MARINER EAST II – PROPANE / BUTANE — Renegotiated legacy contract to eliminate volume commitment and corresponding shortfall — Dedicating 50% of propane and butane with Montage holding decision to increase election on annual basis — Ability to evaluate domestic and international market to determine optimum forward strategy REMAINING NATRIUM BBLS — 50% of remaining propane and butane and 100% of natural gasoline barrels to be taken in-kind beginning April 2019 BLUE RACER NATRIUM NO ETHANE RECOVERY RESULTING IN ENHANCED BARREL COMPOSITION PREMIUM NETBACKS FROM LEGACY LONG-TERM CONTRACT (1) Based on 2018 ECR standalone %WTI. (2) Based on mid-point of guidance. (3) Based on current forward prices.
LIQUIDS MARKETING MARINER EAST II PROPANE / BUTANE MARKETING Mariner East II provides access to premium markets for propane and butane, and offers Montage the added benefit of diversifying its pricing portfolio — Montage has contracted 50% of propane and butane originating from Natrium to MEII ETHANE MARKETING Full ethane rejection at MarkWest Mobley — 20-30% recovery at Blue Racer Natrium with ability to increase as market dynamics shift — All recovered ethane pathing to Shell cracker beginning mid-2021 — Expect ~$0.12/Gal or ~180% increase in net ethane price at this time CONDENSATE MARKETING Legacy contracts sell for $6.50 - $7.50 below WTI — Planning to leverage scale of combined portfolio to achieve premium pricing moving forward (1) Based on Far East Asia & Mont Belvieu Index as of March 11, 2019
MIDSTREAM AND MARKETING SUMMARY Strategic midstream portfolio provides diverse market optionality across all products FIRM TRANSPORT PORTFOLIO NATURAL GAS PRICE REALIZATIONS Production growth allows for continued fulfillment of firm transportation commitments FIRM TRANSPORT PORTFOLIO NATURAL GAS PRICE REALIZATIONS MIDSTREAM SOLUTIONS NGL NETBACKS — Ability to evaluate future projects and select additional takeaway options based solely on economic upside — Midstream counterparties provide access to major transmission lines Excess production being sold in-basin at premium netbacks due to surplus of takeaway capacity Strategic midstream portfolio provides diverse market optionality across all products MIDSTREAM AND MARKETING SUMMARY 54 — Production growth allows for continued fulfillment of firm transportation commitments FIRM TRANSPORT PORTFOLIO NATURAL GAS PRICE REALIZATIONS MIDSTREAM SOLUTIONS NGL NETBACKS — Ability to evaluate future projects and select additional takeaway options based solely on economic upside — Midstream counterparties provide access to major transmission lines — In-service and planned transport lines allowing egress from NE alleviating weakness on in-basin prices — Price enhancement via sales to over-subscribed competitors Production in excess of MVC commitments allows additional flexibility for company drilling plans — Long-term partnerships with midstream providers allow opportunities for synergies with legacy contracts, access to additional field services, expanded marketing options — Contracted firm sales into new MEII pipeline providing direct access to Asian markets — NGL take in-kind rights allow for diversification of markets and takeaway options
FINANCE
STRONG BALANCE SHEET Strong balance sheet provides financial flexibility and allows for organic growth Restated Borrowing Base Letters of Credit Revolver Balance Cash Balance Liquidity 1.0x 1.4x 1.5x 2.0x 2.2x 2.2x 2.3x 3.1x Peer 1 Peer 2 MR Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Strong balance sheet provides financial flexibility and allows for organic growth STRONG BALANCE SHEET 56 (1) Liquidity reflects YE 2018 ECR liquidity of $171.5MM plus the $150MM increased borrowing base, $13.5MM reduction in LCs and BRMR YE cash balance, net of debt pay off. (2) Pro forma Net Debt at YE 2018 over LTM pro forma 1+1 EBITDAX. (3) Peer group includes AR, CNX, COG, EQT, GPOR, RRC, SWN. (4) Based on peer company reported 2019 guidance. YE 2018 PRO FORMA1 NET DEBT TO LTM EBITDAX2 Increased BB by $150MM Reduced LCs outstanding by ~50% from $27 MM 20% 18% 16% 9% 6% 5% 1% 0% Peer 1 Peer 2 MR Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 2019 YoY PRODUCTION GROWTH4 1 YE 2019 target net debt to EBITDAX of 2.0x in-line with average of peers3 2019 production growth well above peers3
REVOLVING CREDIT FACILITY UPDATE 57 KEY TERMS AND CONDITIONS TRANSACTION OVERVIEW — Extended maturity by 4 years (was Feb 2020) — Strong interest (deal significantly oversubscribed) — Credit feedback regarding transaction was overwhelmingly positive — Removed certain historical restrictions within credit agreement DESCRIPTION KEY TERMS Facility Size $1.0 billion Borrowing Base $375 million Administrative Agent/JLA BMO/Key/Capital One Redeterminations Semi-Annual Maturity Feb. 28, 2024 Financial Covenants Net Debt : EBITAX < 4.0x Current Ratio > 1.0x Mortgage Coverage >85% of proved value UTILIZATION (bps) < 25% 25-50% 50-75% 75-90% >90% OLD spread to LIBOR 250 275 300 325 350 NEW spread to LIBOR 175 200 225 250 275 INTEREST RATE 7 New agreement provides increased flexibility, extends maturity and improved bank group profile BORROWING BASE $150MM Extend Maturity d 4 years Spring 2019 Redetermination Underway
PREMIER FINANCIAL POSITIONING BALANCE SHEET AND LIQUIDITY PRO FORMA CAPITALIZATION (12/31/18) Blue Ridge $25 million term loan retired at transaction close — Pro forma borrowing base of $375 million at transaction close — No near term debt maturities — Reduction of letters of credit of $13.5 million in 2019 — Credit rating upgrade by Moody’s on March 13, 2019 to B2 (CFR) PRO FORMA CAPITALIZATION (12/31/18) Capitalization Pro Forma Cash & Cash Equivalents2 $9 Revolving Credit Facility $33 8.875% Senior Unsecured Notes Due 2023 511 Total Debt $543 Market Value of Equity3 569 Enterprise Value3 $1,102 Credit Statistics Total Debt / Q4 2018 LQA EBITDAX4 1.1x Total Debt / Q4 2018 Proved Reserves ($/Mcfe) 5 $0.23 Total Debt / Q4 Proved Developed Reserves ($/Mcfe) 5 $0.49 Q4 Proved Reserves PV10 / Total Debt5 3.3x Total Debt / Q4 2018 Daily Production ($/Mcfe/d) $867 Interest Coverage Ratio 5.8x Liquidity Pro Forma Borrowing Base1 $375 Plus: Cash2 9 Less: Borrowings (33) Less: Letters of Credit6 (14) Liquidity $338 (1) Based on preliminary unaudited estimates. (2) Cash balance pro forma for $25MM of BRMR term loan paid down at transaction close. (3) As of March 1, 2019. (4) Based on Last Quarter Annualized (“LQA”) EBITDAX as of Q4 2018. (5) Based on audited Q4 2018 proved reserves. BRMR proved reserves adjusted for sold properties and include OH and WV assets only. (6) Pro forma for swap-out of ~$13.5 million of LOCs to surety bonds in 2019. Note: EBITDAX and PV10 are non-GAAP financial measures, see appendix for details.
HEDGING UPDATE Montage currently has a significant portion of its 2019 production hedged and plans to continue adding to its hedge positions at attractive prices to provide cash flow certainty and reduce commodity price risk Natural Gas Hedges — ~69% of natural gas production hedged in 2019 — Average floor1 price of $2.78 — Average ceiling price of $2.99 — ~122,500 MMBtu/d of natural gas hedged in 1H 2020 — Average floor1 price of $2.74 — Average ceiling price of $3.03 Gas Basis Hedges — ~39,800 MMBtu/d of Dom South Basis hedged in 2019 — Average hedge price of ($0.47) — ~25% of expected in-basin exposure — ~32,300 MMBtu/d of Dom South Basis hedged in 2020 — Average hedge price of ($0.54) Oil/Condensate Hedges — ~38% of condensate production hedged in 2019 — Average floor1 price of $52.20 — Average ceiling price of $61.28 — ~2,000 Bbl/d of oil hedged in 2020 — Average floor1 price of $58.30 — Average ceiling price of $68.24 NGL Hedges — ~620 Bbl/d of propane hedged in 2019 — Average hedge price of $36.05 OIL (BBL/D) NATURAL GAS (MMBTU/D) 1,000 1,000 1,000 500 500 500 500 1,000 1,000 500 500 500 500 2,000 2,000 2,000 2,000 2,000 2,000 $53.67 $50.00 $52.20 $52.20 $52.20 $59.70 $59.70 $54.10 - 1,000 2,000 3,000 4,000 5,000 6,000 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 Swaps Collars Three-Way Collars (1) Hedges as of March 15, 2019. For purposes of calculating three-way floor price, the higher put value was used.
2019 FULL YEAR GUIDANCE 60 (1) Excludes impact of hedges. (2) Excludes the cost of firm transportation. (3) Includes lease operating, transportation, gathering, and compression, production and ad valorem taxes. (4) Cash G&A is a non-GAAP financial measure, see appendix for details. 74%- 78% 12%- 15% 9%- 11% Gas NGL Oil PRODUCTION FORECASTED REALIZATIONS1 OPERATING COSTS 500 to 525 Mmcfe/d Natural Gas2 Differential to NYMEX (0.30) $/Mcf (0.20) $/Mcf Oil Differential to NYMEX (7.50) $/Bbl (6.50) $/Bbl NGL % of WTI 50% 40% High Low Cash Production Costs3 ($/Mcfe) $1.55 $1.65 $34MM Cash G&A4 $38MM $375MM to $400MM
PEER COMPS COMPARISON Montage Resources screens better than peer averages on operating, leverage and reserve metrics vs Appalachian Peers NET DEBT TO LQA Q4 EBITDAX1 2018 EBTIDAX MARGIN ($/MCFE) 1 RESERVE GROWTH 2018 VS 20171 2019 G&A PER MCFE GUIDANCE2 Montage expects G&A $/Mcfe inline with peers despite a significantly lower production profile (~80% lower Mmcfe/d in 2019) Note: Appalachian peer group consists of AR, CNX, COG, EQT, GPOR, RRC, and SWN. (1) Based on company reported financials as of year-end 2018 and 2017; MR based upon pro forma ECR & BRMR. (2) 2019 G&A per Mcfe is sourced from peers’ 2019 annual guidance releases where available with Q1 2019 guidance utilized as an annualized proxy for one of the peers. AR, CNX, COG and MR reflect cash G&A. GPOR includes stock based compensation. EQT and SWN do not state if guidance is cash only or inclusive of stock based comp. Cash G&A is a non-GAAP financial measure, see appendix for details.
STOCK WELL POSITIONED FOR MULTIPLE EXPANSION Montage Resources is currently trading at depressed levels relative to its peer groups and should be immediately positioned for multiple expansion given its larger scale and strong balance sheet TRADING MULTIPLE PEER COMPARISON TEV / 2019 EBITDAX1 TEV / 2019 PRODUCTION2 (MCFE/D) DEBT / 2019 EBITDAX1,3 Montage Resources is currently trading at a significant discount relative to peers despite more attractive debt metrics • ~33% and ~28% below Appalachian and small cap peers based on 2019 EBITDAX multiple • ~30% and ~65% below Appalachian and small cap peers based on 2019 production multiple • Montage should trade more in-line with the peer groups given its strong balance sheet, increased scale and growth profile Notes: Appalachian peers include AR, AHK, CNX, COG, EQT, GPOR, RRC, SWN. Small cap peers include AREX, BCEI, CRK, EPE, ESTE, HK, HPR, UNT, UPL; TEV includes stock price as of March 1, 2019. (1) 2019 EBITDAX based on consensus estimates. (2) Based on 2019 company reported guidance if provided and consensus estimates. (3) Gross debt as of year-end 2018.
CONCLUDING REMARKS AND Q&A John Reinhart President and Chief Executive Officer
MONTAGE STRATEGY SHIFT Small cap Appalachia Utica and Marcellus operator rebranded and focused on maximizing shareholder value CASH FLOWS & RETURNS COST STRUCTURE IMPROVEMENT & INTEGRATION FINANCIAL & OPERATIONAL FLEXIBILITY PORTFOLIO OPTIMIZATION ENHANCING SCALE WITH DISCIPLINED GROWTH Arrest corporate outspend while facilitating disciplined growth • Optimize development plan for efficiency, delivering cost reductions, lower cycle times and improved cash turns Accelerate merger upstream, midstream, downstream and corporate synergy realizations • Leverage activity and scale for further savings Deliver attractive balance sheet and hedging portfolio • Enhance value through balanced operational and commercial agreements Capture value enhancement through diverse well mix and stacked pay opportunities • Unlock value of high quality company assets through strategic partnerships and operational execution Generate cash flow improvement and unit cost reductions through attractive scale • Achieve disciplined organic production growth while weighing accretive inorganic opportunities
APPENDIX
TYPE CURVE DETAILS As of 3/2019 2019 Marcellus North 2019 Marcellus South 2019 Utica Condensate 2019 Utica Rich Gas 2019 Utica Dry Gas North 2019 Utica Dry Gas South 2019 Flat Castle Type Curve Assumptions Inter-Lateral Spacing (ft.) 750 750 750 1,000 1,000 1,000 1,200 Lateral Length (ft) 13,000 13,000 13,000 13,000 13,000 13,000 13,000 Initial Gas Production Period (Mcf/d)1 8,000 8000 4,350 20,000 22,000 19,000 20,800 Flat Period (months) 6 3 10 9 8 3 7 Initial Decline (%) 50% 50% 60% 63% 63% 64% 60% B Factor 1.3 1.3 1.2 1.2 1.2 1.2 1.1 Terminal Decline (%) 6% 6% 6% 6% 6% 6% 6% Initial Sales Cond. Production (Bbl/d) 480 600 783 N/A N/A N/A N/A Initial GOR (Scf/Bbl) 16,667 13,333 5,556 N/A N/A N/A N/A Initial Cond. Yield (sales) (Bbl/MMcf) 60 75 180 N/A N/A N/A N/A Secondry Cond. Yield (Bbl/MMcf) N/A 35 85 N/A N/A N/A N/A Cond. Yield Transition Time (Mth) N/A 6 12 N/A N/A N/A N/A Terminal Cond. Yield (Bbl/MMcf) 20 15 65 N/A N/A N/A N/A Cond. Yield Transition Time (Mth) 20 20 24 N/A N/A N/A N/A Shrink 89% 92% 86% 92% N/A N/A 99% NGL Yield (Bbls/MMcf) 70 52 85 41 N/A N/A N/A Residue BTU 1,090 1,090 1,095 1,095 1,030 1,025 1,020 Post-Processed EUR (Bcfe/1,000')2 1.6 1.4 0.9 2.4 2.2 1.6 2.0 Post-Processed EUR (Bcfe)2 20.8 18.3 11.6 31.0 28.5 20.8 26.5 Oil (MBbl) 355 275 515 0 0 0 0 NGL (MBbl) 1000 705 530 1,150 0 0 0 Residue Gas (MMcf) 12,710 12,440 5,370 24,140 28,510 20,820 26,460 Differentials Gas ($/MMBtu off NYMEX) ($0.27) ($0.27) ($0.27) ($0.27) ($0.27) ($0.27) ($0.70) Condensate ($/Bbl off WTI) ($7.00) ($7.00) ($6.25) N/A N/A N/A N/A NGL (% WTI) 54% 54% 45% 45% N/A N/A N/A Operating Expenses Fixed Lifting Costs ($/well per month) $4,159 $2,954 $2,225 $3,679 $3,679 $3,679 $3,679 Variable Lifting Costs ($/Mcf) $0.14 $0.20 $0.04 $0.03 $0.03 $0.03 $0.04 Water Expenses ($/bbl) $6.73 $4.40 $4.77 $6.73 $6.73 $6.73 $6.73 GP&T ($/Mcf)3 $1.45 $1.43 $1.87 $1.53 $0.58 $0.58 $0.22 MEII Transporation ($/NGL Bbl) N/A N/A $4.71 $4.71 N/A N/A N/A Liquid Transportation & Stabilization ($/Bbl) $0.00 $0.00 $2.09 $0.00 $0.00 $0.00 $0.00 Production Tax 3.60% 3.60% 3.60% 4.10% 4.50% 4.50% 1.5 (1) Represents 24-hour rate well-head gas production. (2) Utica Condensate and Utica Rich Gas assume ethane recovery at 30% and Marcellus North and South assume 0% ethane recovery. (3) Includes gas gathering, compression, dehy, processing, fractionation , and firm transportation. (4) Cycle time assumption of 5 months spud to turn-in-line assumed for all type curve areas.
NON-GAAP RECONCILIATIONS EBITDAX Year Ended December 31, 2018 $ thousands ECR BRMR Pro Forma Net income (loss) from continuing operations $ 18,826 $ 27,561 $ 46,387 Depreciation, depletion and amortization 134,277 39,472 173,749 Exploration expense 49,563 11,454 61,017 Rig termination and standby — 1,010 1,010 Stock-based compensation 7,891 2,239 10,130 Bad debt expense — 458 458 Impairment of proved oil and gas properties — 6,033 6,033 Impairment of other assets — 673 673 Accretion of asset retirement obligations 663 1,393 2,056 (Gain) loss on sale of assets (1,815) (10,677) (12,492) (Gain) loss on derivative instruments 21,169 6,378 27,547 Net cash receipts (payments) on settled derivatives (26,985) (3,469) (30,454) Interest expense, net 53,990 3,228 57,218 Other (income) expense 1 82 83 Reorganization items — 1,444 1,444 Merger related expenses 4,017 3,409 7,426 Adjusted EBITDAX $ 261,597 $ 90,688 $ 352,285
NON-GAAP RECONCILIATIONS CASH G&A Year Ending December 31, 2018 Three Months Ending March 31, 2019 Year Ending December 31, 2019 $ thousands Year Ending December 31, 2018 Three Months Ending March 31, 2019 Year Ending December 31, 2019 General and administrative expenses, estimated to be reported $29,000-$38,000 $29,000-$38,000 $73,000-$90,000 Stock-based compensation expense (6,000-8,000) (6,000-8,000) (9,000-12,000) Cash general and administrative expenses $23,000-$30,000 $23,000-$30,000 $64,000-$78,000 Merger related expenses (15,000-20,000) (15,000-20,000) (30,000-40,000) Cash general and administrative expenses, excluding merger related expenses $8,000-$10,000 $8,000-$10,000 $34,000-$38,000 RESERVES PV101 Year Ended December 31, $ thousands 2018 2017 2016 Future net cash flows $ 3,692,144 $ 1,875,204 $ 433,489 Present value of future net cash flows: Before income tax (PV-10) $ 1,772,547 $ 881,009 $ 276,363 Income taxes (45,289) — — After income tax (standardized measure) $ 1,727,258 $ 881,009 $ 276,363 (1) YE 2016, 2017 and 2018 Reserve Reports were prepared by independent reserve auditor. PV10 based on SEC pricing.