Strategic Combination of Eclipse Resources and Blue Ridge … · 2019-11-07 · The SEC permits oil and gas companies to disclose in their filings with the SEC only proved, probable

NYSE: MR

INVESTOR PRESENTATIONNovember 2019

DISCLAIMER

2

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 QuantitiesThe 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 MeasureThis 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.

Reserves Disclosure In this release, Montage Resources has provided a pre-tax PV-10 value of its proved developed producing reserves. The pre-tax PV-10 value presented is unaudited. Pre-tax PV-10 values are non-GAAP financial measures as defined by the SEC and are commonly used in the exploration and production industry by companies, investors and analysts. The pre-tax PV-10 value presented may not be comparable to similarly titled measurements used by other companies. Montage Resources believes that the presentation of pre-tax PV–10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV–10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies. Montage Resources believes that PV–10 estimates using strip pricing can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV–10 value using SEC pricing. The GAAP financial measure most directly comparable to pre-tax PV–10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). With respect to PV-10 calculated as of an interim date, it is not practical to calculate the taxes for the related interim period because GAAP does not provide for disclosure of Standardized Measure on an interim basis. Accordingly, no disclosure of Standardized Measure is included in this release. The Company expects to include a full reconciliation of pre-tax PV-10 to the Standardized Measure as of the year end in its Annual Report on Form 10-K for the year ending December 31, 2019.

YEAR-TO-DATE HIGHLIGHTS

3(1) LTM EBITDAX based on 12 months pro forma for merger.

609.0 607.5621.7

550.0

560.0

570.0

580.0

590.0

600.0

610.0

620.0

630.0

Consensus Guidance(midpoint)

Actual

3Q19 PRODUCTION (MMCFE/D)

25% increase in revenue Q3 2019 vs Q3 2018

Third quarter 2019 adjusted EBITDAX exceeded analyst consensus estimates by 4%

Per unit cash production costs of $1.23 / Mcfe, beating guidance and analyst consensus estimates by approximately 9%

Operational flexibility and increased capital efficiency has allowed the company to meaningfully reduce capex while increasing production guidance

Net Debt/LTM EBITDAX1 of 1.7x; top tier among Appalachian peers

Increase in borrowing base of 25% to $500MM (Fall 2019 redetermination)

Upgrade of high yield notes by Moody’s and S&P Global (Q1 2019)

3Q19 ADJUSTED EBITDAX ($ MM)

3Q19 CAPEX ($ MM)

$80.1

$83.6

$70.0

$72.0

$74.0

$76.0

$78.0

$80.0

$82.0

$84.0

Consensus Actual

FINANCIAL UPDATE

Spud to turn-in-line YTD cycle times improved by over 34% vs 2018

— Spud to turn-in-line for Q3 2019 averaged ~110 days per well

Completions cadence of approximately 9 stages per day in Q3 2019

Commenced drilling 4 gross (3.3 net) wells and turned to sales 16 gross (13.9 net) wells during Q3 2019

OPERATIONS UPDATE

$79.0 $65.4

$-

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

$70.0

$80.0

$90.0

Consensus Actual

$1.56 $1.57 $1.60 $1.62

$1.72 $1.74

$1.91

$2.00

$1.25

$1.35

$1.45

$1.55

$1.65

$1.75

$1.85

$1.95

$2.05

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 MR

Montage Resources screens better than peer averages on operating, leverage and reserve metrics vs Appalachian Peers

PEER COMPS COMPARISON

4Note: Appalachian peer group consists of AR, CNX, COG, EQT, GPOR, RRC, and SWN. (1) Based on company reported year-end 2017, 2018 and Q3 2019 financials where available (or Q2 2019 if Q3 not yet reported); MR based on 12 months pro forma for merger. (2) 2019 G&A per Mcfe is sourced from peers’ 2019 annual guidance releases where available with a combination of actuals thru Q3 and Q4 guidance utilized as an annual proxy for Peer 5. Peer 1, Peer 4, Peer 5, Peer 6 and MR reflect cash G&A. Peer 2 includes stock based compensation. Peer 3 and Peer 7 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.

Q3 NET DEBT TO LTM EBITDAX1

PROVED RESERVE GROWTH 2018 VS 20171 2019 G&A PER MCFE GUIDANCE2

$0.07$0.10

$0.12 $0.12

$0.17 $0.18 $0.19 $0.20

$-

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 MR Peer 6 Peer 7

Peer Average: $1.68

Peer Average: $0.14

(11%)

4% 5%

11% 11%

18% 19%

32%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%


Peer Average: 8%

0.7x

1.7x

2.2x 2.2x 2.4x 2.4x2.6x

3.2x

Peer 1 MR Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7

Peer Average: 2.3x

Montage expects G&A $/Mcfe inline with peers despite a significantly lower production profile (~80% lower Mmcfe/d in 2019)

2018 EBITDAX MARGIN ($/MCFE)1

42% YoY cash G&A savings $0.13

2018 Pro forma: $0.31

$0

$2,000

$4,000

$6,000

$8,000

$10,000

2.0x 4.0x 6.0x 8.0x 10.0x

TEV

/ 20

19 M

cfe

per d

ay

TEV / 2019 EBITDAX

Montage Resources is currently trading at depressed levels relative to its peer groups and is positioned for multiple expansion given its low leverage, increase in reserves value and strong balance sheet

STOCK WELL POSITIONED FOR MULTIPLE EXPANSION

5

TRADING MULTIPLE PEER COMPARISON

TEV / 2019 EBITDAX1

Appalachian Peers Small Cap Peers

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

• ~50% below Appalachian and small cap peers based on 2019 EBITDAX multiple

• ~45% below Appalachian and ~80% below 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

2.6x

5.1x 5.1x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

MR AppalachianPeer Avg

Small CapPeer Avg

$1,437$2,510

$6,459

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000


Small CapPeer Avg

1.8x

2.6x3.1x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x


Small CapPeer Avg

Notes: Appalachian peers include AR, CNX, COG, EQT, GPOR, RRC, SWN. Small cap peers include BCEI, CRK, EPE, ESTE, HK, HPR, UNT; TEV includes stock price as of October 31, 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.

Highly competitive operating cost structure provides for significant margin expansion through scale

HIGHLY ADVANTAGED OPERATING COST STRUCTURE

6(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 guidance press releases. Peer 3 is based on Q1-Q3 actuals and Q4 2019 opex guidance as it does not provide full year opex guidance. (3) Q3 cash operating margins based on Q3 revenue net of hedges, operating costs and cash G&A per mcfe

OPEX1 VS APPALACHIAN PEERS2

Operating Cost ($/Mcfe) vs Daily Production (Mmcfe/d)Competitive operating costs compared to in-basin peers despite significantly less

production (~76% lower than peer average) to distribute fixed costs

$0.78$1.04

$1.33$1.66

$2.18

1,380

2,103

549

2,280

3,250

-

500

1,000

1,500

2,000

2,500

3,000

0

0.5

1

1.5

2

2.5

Peer 1* Peer 2* MR Peer 3 Peer 4

$1.47

$1.18$0.99

$0.89

$0.53

$-

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

MR Peer 1 Peer 2 Peer 3 Peer 4

Q3 2019 cash operating margins are ~65% higher than peers3

Q3 CASH OPERATING MARGINS3

*Companies exclude firm transportation from operating costs

MR

~218,00070-75% HBP’d or LT leasehold3

MONTAGE RESOURCES OVERVIEW

7(1) Reserves as of mid-year 2019, based on internal company estimates; PV10 at SEC pricing. (2) Acreage as of Q4 2018 pro forma for merger. (3) Long-term leasehold represents leases with expirations in 2022 and beyond. (4) Net remaining locations based on 13,000’ type curve lateral lengths; Dry Gas North, Dry Gas South and Utica Rich based on 1,000’ well spacing; Utica Condensate, Marcellus North and Marcellus South based on 750’ well spacing; Flat Castle based on 1,200’ well spacing; 10% Risked factor assumed. (5) Based on 12 months pro forma for merger.

SMALL CAP APPALACHIA UTICA & MARCELLUS OPERATOR

2019 PRODUCTION 545 – 552 Mmcfe/d

PROVED RESERVES1 1P : ~2.7 TcfePDP : ~1.3 Tcfe

NET UNDEVELOPED ACREAGE2

NET REMAINING LOCATIONS4 ~700

Q3 2019 LIQUIDITY ~$355 MM

Q3 NET DEBT / LTM EBITDAX5 1.7x

CORPORATE OFFICE IRVING, TX

NYSE TICKER

PROVED RESERVES PV101

1P : ~$2.0 BPDP : ~$1.2 B

2.3x

1.7x

~9%

~21%

~$2,100

~$1,270

Peer Avg.

NET DEBT / LTM EBITDAX2

26%BETTER

2019 PRODUCTION GROWTH3

Peer Avg.

134%BETTER

WHY MONTAGE?

8(1) Peer group includes AR, CNX, COG, EQT, GPOR, RRC, SWN. (2) Based on company reported Q3 2019 financials where available (or Q2 2019 if Q3 not yet reported); MR based on 12 months pro forma for merger. (3) Based on 2019 company reported guidance; MR based on 12 months pro forma for merger in both 2018 and 2019. (4) Stock price as of October 31, 2019.

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

TEV / Q3 2019 PRODUCTION2,4

Peer Avg.

• New leadership focused on accelerating cash flows

• Clean balance sheet with low leverage

• Significantly undervalued vs peers1

• Condensate production differentiation among peers1

• Balanced FT portfolio while basin take-away is over committed allowing for price enhancement opportunities

• Stacked pay development in 2019 allows for further cost reductions

• Diversified NGL economics via access to MEII pipeline and Shell ethane cracker

• Synergies as a result of merger decreased cost structure with accelerated realization

POISED FOR VALUE ENHANCEMENTLOW LEVERAGE, GROWING, UNDERVALUED1

40%DISCOUNT

MONTAGE STRATEGY SHIFT

9

• Generate cash flow improvement and unit cost reductions through attractive scale

• Achieve disciplined organic production growth while weighing accretive inorganic opportunities

• 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

• Accelerate merger upstream, midstream, downstream and corporate synergy realizations

• Leverage activity and scale for further savings

Small cap Appalachia Utica and Marcellus operator rebranded and focused on maximizing shareholder value

• Arrest corporate outspend while facilitating disciplined growth• Optimize development plan for efficiency, delivering cost

reductions, lower cycle times and improved cash turnsCASH FLOWS & RETURNS

COST STRUCTURE IMPROVEMENT & INTEGRATION

FINANCIAL & OPERATIONAL FLEXIBILITY

PORTFOLIO OPTIMIZATION

ENHANCING SCALE WITH DISCIPLINED GROWTH

FOC

US

FIVE

~220

~150

2018 2019

CYCLE TIME IMPROVEMENT

10(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.

ENHANCING SCALE W/ DISCIPLINED

GROWTH

CASH FLOW & RETURNS


FINANCIAL & OPERATIONAL

FLEXIBILITY

COST STRUCTURE IMPROVEMENT &

INTEGRATION

Cycle Time CF and Returns Comparison3

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

~15,400

~11,700

2018 2019

25%DECREASE

32%DECREASE

Average Lateral Length1 (Ft.) Average Cycle Time2 (Days)4 Well 13K LL 4 Well 20K LL

Cycle Time 7 Months 10 Months

IRR 61% 54%

Payback Period 20 Months 24 Months

($70)

($50)

($30)

($10)

$10

$30

$50

$70

0 5 10 15 20

Cash

flow

Time

4 Well Pad 13K LL 4 Well Pad 20K LL

Q3 Realized Average = 108

HQ consolidationto Irving, TX

$0.31

$0.18

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Pro formaECR + BRMR 2018

MR 2019e

CORPORATE INTEGRATION

11(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.

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

CONTIGUOUS ACREAGE & TAKEAWAY


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

G&A PER MCFE1

42%DECREASE 2018 TO 2019

DRILLING & COMPLETIONS CAPITAL SYNERGIES

12(1) Weighted average of type curve costs based on 2019 estimated gross lateral feet spud by area.

~$745

~$810

~$950

~$870

~$825

~$870

~$1,080

~$975

500 600 700 800 900 1000 1100 1200

Marcellus

Condensate

Dry Gas

2019 Plan

2018 13,000' TC $/ft 2019 13,000' TC $/ft

• 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 SYNERGIES


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

Development plan integration was accelerated for Day 1 execution which allows Montage Resources to take advantage of synergies and incorporate cost reductions immediately

CAPEX PER FOOT DRILLED

~10%FROM 2018

2019 Plane1

AVG. FLOOR2

~$53.87 / Bbl

AVG. CEILING

~$62.23 / Bbl

FINANCIAL POSITIONING & FLEXIBILITY

13(1) Hedges as of November 6, 2019; % of Q4 2019 hedged based on midpoint of guidance. (2) For the purposes of calculating three-way floor price, the higher put value was used. (3) Net Debt at YE 2019 to LTM 12 months pro forma for merger. (4) Based on the midpoints of guidance at $2.70 gas and $57 oil.

Strong balance sheet and capital discipline positions the company to opportunistically accelerate development and take advantage of strategic initiatives

STRONG HEDGE BOOK1

AVG. FLOOR2

~$2.73 / MMBtu

~65%of

Q4 2019 gas hedged

AVG. CEILING

~$2.92 / MMBtu

~65%of

Q4 2019 oil hedged


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

ACCRETIVE FINANCIAL POSITION

TARGETING CASH FLOW NEUTRALITY

YE 2019YE 2019 EXPECTED

~2.0X LEVERAGE3

2019 CAPITAL FUNDED BY CASH FLOWS4

~90%NO DEBT MATURITIES UNTIL

JULY 2023

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

Q1 2019 Q2 2019 Q3 2019 Q4 2019

MM

Btu/

dOPERATIONAL FLEXIBILITY

14(1) Estimated gross marketed production. (2) As of Q4 2018. Long-term leasehold represents leases with expirations in 2022 and beyond.

Balanced firm transportation portfolio along with limited operational commitments allow the company to focus on strategy and capital execution


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

FIRM TRANSPORTATION COMMITMENTS

~50-60% 2019 PRODUCTION1

MINIMALLONG TERM SERVICE CONTRACTS

HBP’d or LONG-TERM LEASEHOLD2

70-75% of TOTAL NET ACRES

ADVANTAGEOUS COMMITMENTS

Gross Marketed Firm Transport

MARKETED PRODUCTION VS FT

LIMITEDDRILLING COMMITMENTS

EFFICIENT CAPITAL DEPLOYMENT

15(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.

Over 95% 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

DRY D&C

WET D&C

Category 1

77%

44%40% 38%

62% 60%

24%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

MarcellusNorth

Condensate MarcellusSouth

Rich Gas Dry GasNorth

Flat Castle Dry Gas South

2019 ACTIVITY in HIGHEST IRRs1

>95% TO DRILL

BIT

LAND/OTHER

D&C APPROX.

SPLIT 55% WET / 45% DRY

2019 CAPITAL ALLOCATION

$345 - 370 MM

~ Net Remaining Locations3

80 185 70 30 130 105 100

~40% OF 2019 Gross TILs in highest IRR1 dry gas

type curves

~60% OF 2019 Gross TILs in highest IRR1 liquids

rich type curves


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

DRY GASLIQUIDS RICH

2 2


16(1) Assumes a two-rig development pace with ~80% average working interest.

Montage Resources controls an economic core footprint that allows for development mix flexibility and scalability


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

UNLOCKING VALUE OF HIGH QUALITY INVENTORYPROVED-UP FLAT CASTLE EURPAINTER 2H: ~2.4 BCFE/1,000 ftASSESSING OTHER ALTERNATIVES TOACCELERATE VALUE

2019 GROSS SPUDS IN MARCELLUS STACKED-PAY~43%

STACKED PAY PROVIDES FURTHER LIQUIDS PRICE DIVERSIFICATION

CONTINUOUS ACREAGE POSITION ALLOWSCAPITAL DEPLOYMENT FLEXIBILITYREMAINING INVENTORY of ~700 NET LOCATIONS OR ~27 Years1

Montage generates a significant portion of its revenue from condensate, providing commodity price diversification and attractive cash margins relative to its Appalachian peer group

17(1) Peer group includes AR, CNX, COG, EQT, GPOR, RRC, SWN. Based on company reported financials as of Q3 2019 financials where available (or Q2 2019 if Q3 not yet reported). (2) Using consensus EBITDAX estimates and total expected oil production for 2019, excludes impact of NGL revenue, excludes impact of hedging; oil production based on midpoints of guidance where available and Q3 actuals as proxy when full year guidance is not provided. (3) Based on full year guidance and actuals thru Q3.

ACCELERATING PEER-LEADING OIL EXPOSURE

Over 50% of 2H19 net TILs are in liquids rich acreage, leading to a significant increase in oil production versus 1H19

Significant liquids rich inventory limits Montage’s leverage to challenged natural gas prices— ~365 net remaining locations remain, representing ~ 52% of

total available drilling inventory

A $5/bbl increase in WTI would increase Montage’s EBITDAX by ~6%, leading its Appalachian peers — Montage’s cash flows are less levered to gas prices than

its Appalachian peers

OIL AS % of Q3 TOTAL REVENUE1

EBITDAX LEVERAGED TO OIL2

MONTAGE’S INCREASING OIL EXPOSURE3

1,167 Mbbls

~1,750 Mbbls

1H19 2H19

~50%INCREASE

0.0% 0.0% 0.9% 3.9%7.5%

9.4% 9.6%

27.8%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%


Assuming a $5/bbl increase in WTI

0.0% 0.1% 0.2%1.4% 1.5%

2.1%2.4%

5.5%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%


480Mmcfe/d

400

420

440

460

480

500

520

540

560

580

600

2018 1H 2019e 2H 2019e 2019e

$1.8B

~$2.0B

YE 2018 Q2 2019

2.4 Tcfe

~2.7 Tcfe

YE 2018 Q2 2019

ACHIEVING SCALE THROUGH DISCIPLINED GROWTH

18(1) Pro forma for merger, reserves at SEC pricing as of year-end 2018 are from independent engineering firms and reserves at SEC pricing as of mid-year 2019 are based on internal company estimates. (2) PDP PV10 at NYMEX strip pricing as of 6/30/2019 is based on internal company estimates. (3) Enterprise value as of October 31, 2019 stock price and Q3 2019 net debt. (4) Growth rate reflects 12 months pro forma for merger for 2019 and 2018. Note: PV10 is a non-GAAP financial measure, see disclosure for details.

Significant reserve growth provides valuation uplift and increased liquidity

12%INCREASE

2019 PRO FORMA PRODUCTION


GROWTH

CASH FLOW & RETURNS



FLEXIBILITY


INTEGRATION

11%INCREASE

PROVED RESERVES1 PROVED PV101

PDP RESERVES ~20%

4

~23%YoY PRODUCTION

GROWTH4

(2H 2019 WEIGHTED)

MR ENTERPRISE VALUE~79% of STRIP PDP PV102,3

~580– 600

Mmcfe/d

PDP PV10at Strip of ~$1.0B2

MR EV of ~$788MM3

Greater than 95% of 2019 capital is allocated to low-risk D&C activity leading to pro forma 12 month year-over-year production growth of ~21% to ~580 – 600 Mmcfe per day

19(1) Metrics based on midpoint of guidance; revenue assumes $2.70 gas and $57 oil in 2019.

2019 DEVELOPMENT PLAN OVERVIEW

CAP

EX1

14%

10%

76%NGLsOilGas

PRO

DU

CTI

ON

1

14%

26%

60%

NGLsOilGasR

EVEN

UE1

~548.5Mmcfe/d

2019 Development Areas

Utica Dry and Marcellus

Utica Condensate

<5%~25%

~30% ~40%

Land & Other

Utica CondensateD&CMarcellus D&C

Dry D&C

~$357.5MM

Spuds TILs

Gross 14 – 16 10 - 12

Net (WI) 13.6 – 15.6 9.8 – 11.8

Avg LL ~10,800’ ~9,500’

Spuds TILs

Gross 11 – 13 19 – 21

Net (WI) 8.5 – 10.5 11.7 – 13.7

Avg LL ~12,500’ ~14,600’

Key development areas with balance of wet and dry well mix deliver attractive single well IRR’s and flexibility for liquids pricing upside

20(1) IRR values represent half-cycle returns and utilize commercial assumptions as shown in the appendix.

2019 PLAN FOCUSES ON HIGH RETURNING AREASU

TIC

A C

ON

DEN

SATE

UTI

CA

DR

Y

27%27%

46%

NGLsOilGas

Spuds TILs

Gross 4 – 6 11 – 13

Net (WI) 3.8 – 5.8 10.3 – 12.3

Avg LL ~14,000’ ~13,000’

MAR

CEL

LUS

NO

RTH

100%

NGLsOilGas

29%10%

61%

NGLsOilGas

Product Mix

Product Mix

Product Mix

IRR

1

Variable Oil ($/bbl) – Fixed gas $3.00/Mmbtu

IRR

1

Gas ($/Mmbtu)

IRR

1

66%77%

92%107%

$50 Oil $55 Oil $60 Oil $65 OilVariable Oil ($/bbl) – Fixed gas $3.00/Mmbtu

33%44%

59%72%

$50 Oil $55 Oil $60 Oil $65 Oil

47%54%

62% 68%

$2.80 Gas $2.90 Gas $3.00 Gas $3.10 Gas

Attractive portfolio of diverse assets with an even split of wet and dry well inventory, providing optionality to a constantly evolving commodity price environment

21(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.

DIVERSE RESOURCE PORTFOLIO

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 RemainingNet 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%

Flat CastleUtica and Marcellus Type Curve Areas

21%31%

33%

15%~700Remaining Net

Locations2

Approx. Net location %

by type curve

Initial delineation wells are outperforming type curve expectations, de-risking Ohio Marcellus acreage position for full scale development mode

22(1) Normalized to 13,000’. Equivalent production calculations assumes processing with three-phase recovery (with ethane rejection).

MARCELLUS VALUE ATTRACTS CAPITAL ALLOCATION

David Stalder 16HM and Herrick 1HM in Monroe County, Ohio turned to sales in January 2018 with an average lateral of ~9,100 ft. — Post-cleanup average equivalent IP rate of ~11.4 Mmcfe/d (3-stream)— Average initial condensate yield of ~70 Bbl/Mmcf

Montage has since turned-to-sales 3 new pads consisting of 11 total wells: — Pad 1: 4 wells with an average lateral length of ~9,800’ and a 30 day max IP of 13.4 Mmcfe/d, (3-stream)— Pad 2: 4 wells with an average lateral length of ~7,200’ and a 30 day max IP of 18.5 MMcfe/d, (3-stream)— Pad 3: 3 wells with an average lateral length of ~11,600’ and a 30 day max IP of 12.9 MMcfe/d, (3-stream)

Initial production results significantly de-risk Montage’s Marcellus acreage

Marcellus North accounts for approximately 33% of gross spuds in 2019

Value enhancing utilization of shared Utica infrastructure within the stacked-pay window

0

5

10

15

0 100 200 300 400 500 600 700Producing Days

Marcellus AverageType CurveMarcellus Average-Forecast

Nor

mal

ized

Equ

ival

ent

Prod

uctio

n (M

mcf

e/d)

1

MARCELLUS FLAT CASTLEUTICA DRY GASUTICA CONDENSATEMARCELLUS FLAT CASTLEUTICA DRY GASUTICA CONDENSATE

Recent Marcellus North PerformanceDavid Stalder

16HMHerrick

1HMMarcellus 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%

Similar Condensate Yield

Comparison Wells

Montage PDP Wells

Non-Op PDP Wells

Montage Acreage

0

1

2

3

4

5

-40.05 -40 -39.95 -39.9 -39.85 -39.8 -39.75 -39.7 -39.65 -39.6

Nor

mal

ized

200

Day

C

umul

ativ

e (B

CFE

)1

Step-out test into the southern portion of Utica Condensate area generates results similar to the proven northern portion of Utica Condensate area

23(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.

SUCCESSFUL WELL RESULTS IN WASHINGTON CO.

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

North South

Farley Pad

MARCELLUS FLAT CASTLEUTICA DRY GASUTICA CONDENSATEMARCELLUS FLAT CASTLEUTICA DRY GASUTICA CONDENSATE

Woodchopper Pad

Montage has executed on engineered and pressure managed flowbacks of Utica Dry gas pads since merger in effort to preserve reservoir quality and improve single-well EUR’s

24

EXCEPTIONAL WELL PERFORMANCE IN DRY GAS NORTH

Montage has turned-to-sales 4 Ohio Utica dry gas pads (14 total wells) since the merger completed

Pressure managed rate profiles ensure preservation of reservoir quality and ultimately translates to improved well deliverability— Montage has improved Utica dry gas drawdowns by 50% while extending the length of time production is held flat— This leads to improved pressure dependent permeability and enhanced fracture conductivity

MARCELLUS FLAT CASTLEUTICA DRY GASUTICA CONDENSATE

Managed-Pressure Effects on Drawdown Improved Well Productivity


0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 2 4 6 8 10 12 14

Cas

ing

Pres

sure

(psi

)

Months

Post-Merger Avg. Flowing PressurePre-Merger Avg. Flowing PressureePost-Merger ∆P -23 psi/dPre-Merger ∆P -41 psi/d

Highly deliverable and repeatable Dry Gas North well results provide long term corporate production growth ability with attractive economics to allocate capital

25.

EXCEPTIONAL WELL PERFORMANCE IN DRY GAS NORTH

4 Utica Dry Gas North pads (14 gross wells) turned to sales in 2019 in Monroe County, OH to-date— 2019 turn-in-lines are meeting or exceeding type curve

expectations

Consistent well results provide low risk development opportunities to optimize portfolio planning


2019 TTS Wells

2018 TTS Wells

Montage PDP Wells

Non-Op PDP Wells

Montage Acreage


0

2

4

6

8

0 3 6 9 12

Cum

ulat

ive

Gas

(Bcf

)

Months

2019 Pad 12019 Pad 22019 Pad 32019 Pad 4Type Curve

Second successful well test in West Virginia confirms performance expectations and creates opportunities for accretive value solutions

26(1) Production Normalized to 13,000 feet.

SUCCESSFUL WEST VIRGINIA UTICA WELL RESULTS

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— Spencer 1UH EUR outperforming Dry Gas North type curve at

2.3 Bcfe/1,000’

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 Dry Gas North type curve


Spencer 1UHStewart Winland 1300U

Ormet 7-15UH


PAINTER 2H WELL PERFORMANCE

27

GAS RATE VS TIME

CUMULATIVE GAS VS TIME

Painter 2H is exceeding current type curve expectations by ~20% driven by engineered completion designs coupled with choke management techniques to enhance productivity— Painter 2H currently has an estimated EUR of

2.4 bcf/1,000(1)

The Painter 2H was transitioned to choke management and production was reduced from 32 Mmcf/d to 22 Mmcf/d

Stronger well performance leads to improved single well economics, continuing to unlock the value of our high quality inventory

LOCATOR MAP

(1) Full-field development EUR’s may differ from unbound single-well EUR’s. (2) Production Normalized to 13,000 feet.

• Subscribed capacity into premier Gulf Coast, Midwest, and Canadian markets

• Ability to redirect flows based on fundamental research & market needs

Leveraging scale, diversified markets and low commitments to increase net back prices

28

MIDSTREAM AND MARKETING OVERVIEW

• 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

SCALE FACILITATES FLEXIBILITY & OPTIONALITY

TAKEAWAY OPTIONS GENERATE ACCESS TO DYNAMIC MARKETS & ALLOW DIVERSIFIED SALES STRATEGY YEAR-ROUND

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

MONTAGE RESOURCES FOOTPRINT

0.7x

1.7x

2.2x 2.2x 2.4x 2.4x2.6x

3.2x

Peer 1 MR Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7

$500MM

$355MM

($29MM)($128MM)

$12MM

$0MM

$100MM

$200MM

$300MM

$400MM

$500MM

Borrowing Base Letters of Credit Revolver Balance Cash Balance Liquidity

Strong balance sheet provides financial flexibility and allows for organic growth

STRONG BALANCE SHEET

29(1) Net debt at Q3 2019; MR LTM EBITDAX is 12 months pro forma for merger. (2) Peer group includes AR, CNX, COG, EQT, GPOR, RRC, SWN. (3) Based on peer company reported 2019 guidance. MR growth rate reflects 12 months pro forma for merger for 2019 and 2018.

Q3

2019

LIQ

UID

ITY

NET DEBT TO LTM EBITDAX1

21%20%

17%

11%9%

4%1% 1%

MR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7

2019 YoY PRODUCTION GROWTH3

YE 2019 target net debt to EBITDAX of2.0x below peer2 average

2019 production growth well above peers2

Peer Average: 9%

Peer Average: 2.3x

2019 THIRD QUARTER AND UPDATED FULL YEAR GUIDANCE

30(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.

FY 2019Production MMcfe/d 545 - 552% Gas 74% - 78%% NGL 12% - 15%% Oil 9% - 11%Gas Price Differential ($/Mcf)1,2 $(0.20) - $(0.30)Oil Differential ($/Bbl)1 $(7.25) - $(7.75)NGL Prices (% of WTI)1 30% - 35%Cash Production Costs ($/Mcfe)3 $1.30 - $1.35Cash G&A ($MM)4 $37 - $38CAPEX ($MM) $345 - $370

APPENDIX

Montage Resources’ management team possesses significant Appalachia specific experience with an excellent track record of execution

EXPERIENCED APPALACHIAN BASIN LEADERSHIP TEAM

32

PRIOR COMPANIES EXPERIENCE(YRs)

John ReinhartPresident & CEO

25

Oleg TolmachevEVP & COO

20

Michael HodgesEVP & CFO

18

Paul JohnstonEVP & General Counsel

39

Matthew RuckerEVP, Resource Development & Planning

12

Marty Byrd

SVP, Land40

Timothy Loos

SVP, Accounting & Finance12

120,000 105,000 105,000 120,000 175,000 175,000

125,000 125,000

50,000 55,000 75,000 95,000

80,000 65,000

50,000 50,000

156,500 117,500 77,500

107,500 110,000

80,000

30,000 30,000

$2.90

$2.71 $2.70

$2.73 $2.67

$2.66

$2.60 $2.60

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020

Swaps Collars Three-Way Collars

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

HEDGING PORTFOLIO1

Natural Gas Hedges

~65% of natural gas production hedged in 20192

— Average floor3 price of $2.77— Average ceiling price of $2.97

~273,750 MMBtu/d of natural gas hedged in 2020— Average floor3 price of $2.64— Average ceiling price of $2.80

~56,250 MMBtu/d of natural gas hedged in 2021— Average floor3 price of $2.56— Average ceiling price of $2.76

Gas Basis Hedges

~39,800 MMBtu/d of Dom South Basis hedged in 2019— Average hedge price of ($0.46)— ~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

~50% of condensate production hedged in 20192

— Average floor3 price of $53.35— Average ceiling price of $61.74

~4,000 Bbl/d of oil hedged in 2020— Average floor3 price of $57.13— Average ceiling price of $62.47

~500 Bbl/d of oil hedged in Q1 2021— Average swap price of $53.10

NGL Hedges

~620 Bbl/d of propane hedged in 2019— Average hedge price of $36.05

OIL (BBL/D)

NATURAL GAS (MMBTU/D)

(1) Hedges as of November 6, 2019; Hedge percentages and tables do not include call, put or swaption transactions, see current 3rd quarter 10Q Financial Statements for a summary of all hedge contracts. (2) Based on midpoints of guidance. (3) For purposes of calculating three-way floor price, the higher put value was used. 33

1,000 -

1,500 1,500 1,500 1,500

2,750 2,750

-

2,000 2,000 1,000

500

1,000 1,000

2,000

2,000

2,000 2,000

2,000 2,000

$53.67

$50.00

$53.87 $53.87

$59.02 $58.90

$55.05 $55.05

-

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 2020Swaps Collars Three-Way Collars

7% Oil 6% Oil13% NGL

18% NGL 12% NGL82% Gas

75% Gas

82% Gas

660 Bcfe

1,816 Bcfe

2,404 Bcfe

YE16 YE17 YE18

$252 MM

$870 MM

$1,773 MM

YE16 YE17 YE18

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

34Note: All reserves metrics are pro forma for merger; YE 2016, 2017 and 2018 Reserve Reports were prepared by independent reserve auditor. PV10 at SEC pricing. PV10 is a non-GAAP financial measure, see appendix for details.

SUBSTANTIAL PROVED RESERVE GROWTH

32%Increase

175%Increase

104%Increase

245%Increase

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 $1,773

PROVED RESERVES (BCFE) PROVED RESERVES PV10 ($MM)

PDP RESERVES 65% YoY 2018

35(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.

TYPE CURVE DETAILSAs of 3/2019 2019 Marcellus North 2019 Marcellus South

2019 Utica Condensate

2019 Utica Rich Gas2019 Utica Dry Gas

North2019 Utica Dry Gas

South2019 Flat Castle

Type Curve AssumptionsInter-Lateral Spacing (ft.) 750 750 750 1,000 1,000 1,000 1,200Lateral 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 20,800Flat Period (months) 6 3 10 9 8 3 7Initial Decline (%) 50% 50% 60% 63% 63% 64% 60%B Factor 1.3 1.3 1.2 1.2 1.2 1.2 1.1Terminal Decline (%) 6% 6% 6% 6% 6% 6% 6%

Initial Sales Cond. Production (Bbl/d) 480 600 783 N/A N/A N/A N/AInitial GOR (Scf/Bbl) 16,667 13,333 5,556 N/A N/A N/A N/AInitial Cond. Yield (sales) (Bbl/MMcf) 60 75 180 N/A N/A N/A N/ASecondry Cond. Yield (Bbl/MMcf) N/A 35 85 N/A N/A N/A N/ACond. Yield Transition Time (Mth) N/A 6 12 N/A N/A N/A N/ATerminal Cond. Yield (Bbl/MMcf) 20 15 65 N/A N/A N/A N/ACond. 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 2.0Post-Processed EUR (Bcfe)2 20.8 18.3 11.6 31.0 28.5 20.8 26.5Oil (MBbl) 355 275 515 0 0 0 0NGL (MBbl) 1000 705 530 1,150 0 0 0Residue Gas (MMcf) 12,710 12,440 5,370 24,140 28,510 20,820 26,460

DifferentialsGas ($/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 ExpensesFixed Lifting Costs ($/well per month) $4,159 $2,954 $2,225 $3,679 $3,679 $3,679 $3,679Variable Lifting Costs ($/Mcf) $0.14 $0.20 $0.04 $0.03 $0.03 $0.03 $0.04Water Expenses ($/bbl) $6.73 $4.40 $4.77 $6.73 $6.73 $6.73 $6.73GP&T ($/Mcf)3 $1.45 $1.43 $1.87 $1.53 $0.58 $0.58 $0.22MEII Transporation ($/NGL Bbl) N/A N/A $4.71 $4.71 N/A N/A N/ALiquid Transportation & Stabilization ($/Bbl) $0.00 $0.00 $2.09 $0.00 $0.00 $0.00 $0.00Production Tax 3.60% 3.60% 3.60% 4.10% 4.50% 4.50% 1.50%

Well Cost Assumptions4

NRI (%) 82% 82% 82% 82% 82% 82% 82%Well Cost ($ MM) $9.7 $9.7 $10.5 $10.5 $12.4 $12.4 $12.4Well Cost per foot ($/ft) $745 $745 $810 $810 $950 $950 $950

36

NON-GAAP RECONCILIATIONS

EBITDAX

$ thousands 2019 2018 2019 2018Net income (loss) 4,284$ 3,998$ 17,698$ (17,662)$

Depreciation, depletion, amortization and accretion 45,456 34,439 113,950 98,672 Exploration expense 16,621 11,328 48,602 36,227 Rig termination and standby 1,221 — 1,221 — Stock-based compensation 1,061 2,171 7,614 6,131 (Gain) loss on sale of assets (733) 6 (731) (1,814) (Gain) loss on derivative instruments (15,812) 3,263 (40,620) 24,055 Net cash receipts (payments) on settled derivatives 11,818 (5,377) 11,072 (7,724) Interest expense, net 15,192 13,932 44,140 39,975 Other income (expense) — 1 (8) 1 Merger-related expenses 3,291 2,993 21,812 2,993 Income (loss) from discontinued operations 1,237 — (1,286) —

Adjusted EBITDAX 83,636$ 66,754$ 223,464$ 180,854$

Three Months Ended September 30,

Nine Months Ended September 30,

37(1) YE 2016, 2017 and 2018 Reserve Reports were prepared by independent reserve auditor. PV10 based on SEC pricing.

NON-GAAP RECONCILIATIONS

CASH G&A

RESERVES PV101

$ thousands 2018 2017 2016Future 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$

Year Ended December 31,

Guidance

$ thousands 2019 2018Year Ending

December 31, 2019

General and administrative expenses, estimated to be reported 14,580$ 12,937$ $68,000-$76,000Stock-based compensation (1,061) (2,171) (8,000-10,000)Cash general and administrative expenses 13,519$ 10,766$ $60,000-$66,000Merger-related expenses (3,291) (2,993) (24,000-28,000)Cash general and administrative expenses, excluding merger related expenses 10,228$ 7,773$ $36,000-$38,000

Three Months EndedSeptember 30,

Documents

Strategic Combination of Eclipse Resources and Blue Ridge … · 2019-11-07 · The SEC permits oil and gas companies to disclose in their filings with the SEC only proved, probable