AMR 4Q'18 IR Deck 2.25 · This presentation includes "forward-looking statements" within the...

ALTAMESA.NET Investor Presentation

ALTA MESA RESOURCES

Investor UpdateFebruary 25, 2019

ALTAMESA.NET Investor Presentation 2

FORWARD LOOKING STATEMENTS

FORWARD-LOOKING STATEMENTS

This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, including but not limited to, Alta Mesa Resources’ fourth quarter and year-end financial and operating results, 2019 outlook and guidance, including estimates with respect to capital budget, drilling plans, timing and amount of future production, throughput and produced water volumes, expenses, cost reductions, overhead and EBITDA, strategy, future operations, financial position, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words “could”, “should”, “will”, “plan”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “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 Alta Mesa Resources' current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Alta Mesa Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond its control, incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, commodity price volatility, low prices for oil and/or gas, global economic conditions, inflation, increased operating cost, lack of availability of drilling and production equipment and services, operating results, environmental risks, weather risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and other risks. Information concerning these and other factors can be found in Alta Mesa Resources' filings with the SEC, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the SEC's web site at http://www.sec.gov. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, Alta Mesa Resources’ actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may issue. Except as otherwise required by applicable law, Alta Mesa Resources disclaims any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation.

Non-GAAP and Other Financial Information

This presentation includes 2019 Estimated Adjusted Midstream EBITDA, which represents a current estimate of Kingfisher Midstream’s 2019 net income adjusted to exclude interest expense, income taxes, depreciation and amortization, as well as other adjustments. This is a forward-looking financial measure that is not presented in accordance with generally accepted accounting principles (“GAAP”). This non-GAAP financial measure is a numerical measure of financial performance that excludes or includes amounts so as to be different than the most directly comparable measure that would be presented in accordance with GAAP in Alta Mesa Resources’ income statement. Non-GAAP financial measures should not be considered in isolation or as a substitute for the most directly comparable GAAP measures. Alta Mesa Resources’ non-GAAP financial measures may be different from non-GAAP financial measures used by other companies. This forward-looking non-GAAP financial measure is intended to provide additional information to investors regarding Alta Mesa Resources’ current expectations surrounding the future outlook of the business. We do not attempt to reconcile this

measure with the most directly comparable GAAP financial measure because of the inherent difficulty in forecasting and quantifying certain amounts that are necessary for such reconciliations, including adjustments identified above, the amounts of which could be material.

Historic and future upstream production and reserves are reported assuming full ethane recovery of barrels. Actual NGL barrels recovered may vary based on optimization of economic recovery.


ALTA MESA RESOURCES OVERVIEW

3

Q4 Key Metrics

Market Capitalization1 ~$380mm

Enterprise Value1 ~$1.2bn

Q4 Net Production (BOE/d) 37,600

Q4 Net Production % Oil / % Liquids 50% / 73%

Q4 KFM System Gas Volume (MMCF/d) 124

Upstream Assets

Net STACK Surface Acres2 ~140,400

Operated STACK Hz. Wells Drilled 3 422

Kingfisher Midstream Assets

Gas Processing Capacity 350 MMCF/d4

Produced Water System Capacity ~157,000 BBLs/d

1 Equity share price as of 12/31/2018 close, the last trading day in the year, using aggregate Class A and Class C share count of 383 million2 Acreage as of 12/31/20183 Horizontal wells drilled as of 12/31/20184 Includes existing 90 MMCF/d offtake processing


RECENT UPDATES

4

PreliminaryFourth Quarter Update

Q4 production of 37,600 BOE/d (50% oil, 73% liquids)

December average production of 39,100 BOE/d (50% oil, 74% liquids)

Q4 midstream system gas volumes of 124 MMcf/d (82% Alta Mesa), produced water volumes of 100,370 Bbls/d and crude oil volumes of 5,936 Bbls/d

Management Transition

Activity Update

Reconstituted leadership team with significant public E&P company experience

New President and his team bring significant upstream operational and technical background with multi-decade experience developing onshore US assets

New CFO brings additional public accounting experience to finance organization

Entire integrated team is focused on executing against market expectations in 2019

Began rig ramp down in December and ended January with no active rigs

Focused on executing completion of 16 additional DUCs by the end of Q2

Preparing to have two rigs working beginning in March, with a third rig in late Q2


NEAR TERM EXECUTION THEMES

5

Preserve liquidity and financial flexibility in an ~$50 oil price environment

Target significant reductions in D&C, lifting and overhead costs

Focus on developing the asset to better balance returns and inventory life

Reduce drilling pace with focus on optimal spacing and recoveries


16 of 17 Patterns Above 250 MBO TC at 30 days

2018 PATTERN RESULTS DEGRADED OVER TIME

6

Summary of 2018 Drilling Program

4 of 17 Patterns Above 250 MBO TC at 120 days

Drilled 175 wells and completed 174 wells in 2018

At year-end 2018 we had 17 patterns with 6-10 wells per section density with meaningful production results

While early pattern well results appear strong vs. the type curve, they have consistently degraded over time

Oil EUR for the average 2018 pattern well is ~120 MBO in the YE 2018 reserve report

2018 results driving management focus in 2019 on improved infill economics through:

– Upspacing and lateral placement

– Lowering D&C costs

– Lowering LOE and overhead

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5,000

10,000

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il

Initial Unit 250MBO Type Curve

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Initial Unit 250MBO Type Curve


Estimated Recoverable Oil Per Section

2019 PERSPECTIVES OF RECOVERABLE OIL PER SECTION

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Estimated Recoverable Oil Per Section Average EUR per section ~850 MBO for fully developed

sections with 6-10 wells per section

Upspacing is estimated to deliver ~775 - 875 MBO per section with forecast of 175 MBO per well on both siblings and infills

– 5 wells per section for undeveloped sections (875 MBO per section)

– 4 wells per section (3 infills) when an initial section well exists (fewer total wells per section due to higher initial recoveries from parent well)


COST SAVINGS FOCUS IN 2019

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Cost Reductions Drivers

Drilling & Completion

(D&C)

~$4.5mm / well(w/ ESP)

$3.2mm-$3.5mm / well

Utilize gas lift instead of ESPs

Revert to Gen 2 design (24 vs. 36 stages) and standardize on 100 mesh sand

Capture benefits of rebidding services contracts in current market

Lease Operating Expense(LOE)1

~ Target $7.50 - $8.50 / BOE in 2019

Re-evaluate use of chemicals, compression and other expenses

Focus on reducing fixed costs / well / month

Converting ESPs back to gas lift to further aid LOE

Upstream General &

Administrative(G&A)2

~$5.5mm / month

~$4mm / month

Initial reduction-in-force completed

Ongoing review of overhead continuing to match G&A with scale of business in 2019

1 LOE includes future water costs2 Overhead guidance does not reflect any potential severance or other costs associated with our recent reduction in force


Illustrative Infill / Sibling Well Economics

2019 ACTIVITY AND CURRENT PATTERN ASSUMPTIONS

9

Development Strategy and Testing for 2019

Near Term DUC Details

Rig and Completions Activity:

– Drilled 3 wells and completed 8 wells in January

– Targeting completion of 16 additional DUCs by end of Q2

– Preparing to run 2 rigs beginning in March and expect to add a third rig in late Q2

– Will evaluate adding additional rigs over the course of 2019 based on well costs, well results and commodity prices

Key Focus Areas:

– Test upspacing and lateral placement

– Provide further validation for 175 MBO type curve

– Materially lower well costs by decreasing completions intensity and capturing softening pricing in the market

Oil EUR 175 MBO 200 MBO

Oil / Gas | D&C $3.2MM $3.5MM $3.2MM $3.5MM

$50 / $2.75 12% 8% 20% 15%

$60 / $3.25 30% 24% 41% 33%

$70 / $3.25 48% 39% 63% 51%

Near term DUCs spaced at 4 WPS or less and will provide low incremental capital cost way to test spacing assumptions

DUCs distributed across six patterns

1 3 stream volumes calculated using 72.5% shrink factor and 105.8 bbl/mmcf yield: 175 MBO EUR results in a 486 MBOE EUR and 200 MBO EUR results in a 560 MBOE EUR (36% Oil / 34% Gas / 30% NGLs)

Oil EUR 175 MBO 200 MBO

Oil / Gas | D&C $3.2MM $3.5MM $3.2MM $3.5MM

$50 / $2.75 31% 25% 41% 33%

$60 / $3.25 51% 41% 65% 53%

$70 / $3.25 72% 59% 90% 74%

Ups

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2019E UPSTREAM OUTLOOK

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2019E

Net Production 29,500 – 31,500 BOE/d

UpstreamCapital Expenditures $190mm - $210mm

Lease Operating and Workover Expense1 $7.50 - $8.50 / BOE

Marketing and Transportation Expense $5.10 - $5.70 / BOE

Production Tax 5% - 6% of Revenues

Upstream Overhead – G&A2 $4mm / month

Selected Commentary Production from current PDPs (including 8 wells

brought on-line YTD), 16 DUCs and ~30 wells from 2 rigs going to 3 rigs

– ~45% oil and ~70% liquids

– Declining production profile through the year

Capital costs assumes $3.2mm - $3.5mm D&C cost

– No funding from existing DrillCo assumed

Marketing and transportation expense reflects current contracts and expected mix of midstream offtake (KFM vs. legacy midstream dedications)

1 LOE includes future water costs2 Overhead guidance does not reflect any potential severance or other costs associated with our recent reduction in force


Capital Project Outlook for 2019

KINGFISHER MIDSTREAM UPDATE

11

Selected Commentary Q4 volumes in-line with guidance:

– 124 MMCF/d of Natural Gas (82% Alta Mesa)

– 100,370 Bbls/d of Produced Water1

– 5,936 Bbls/d of Crude

Suspending investment in Cimarron Express:

– Outlook for Alta Mesa volumes and third-party volume opportunities in the area significantly lower than initially projected

Third-party outlook in 2019:

– Expect to connect 30 – 40 wells across existing third-party acreage dedications

– Should lead to maintenance of current third-party volumes vs Q4

2019E

Plant Projects ~$20mm

Well Connects / Pipelines $35 - $40mm

Total Midstream Capital Expenditures $55 - $60mm

1 Produced water volumes reflect the average since the system was purchased by Kingfisher Midstream in November 2018.


2019E MIDSTREAM OUTLOOK

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2019E

System Gas Volumes 110 - 120MMcf/d

Produced Water Volumes 70,000 - 80,000Bbls/d

Crude Oil Volumes 6,000 - 6,500Bbls/d

Plant Operating Expense ~$0.30 / MMBTU

Gathering, Processing and Transportation Expense ~$700,000 / month

Water Operating Expense ~$0.37 / Bbl

Midstream Overhead – G&A1 ~$1mm / month

Adjusted Midstream EBITDA $55mm - $60mm

Midstream Capital Expenditures $55mm - $60mm

Gas, water, and crude volumes are representative of Alta Mesa Upstream plan to complete 16 DUCs and run 2 rigs going to 3 rigs in 2019 along with 30 – 40 third party wells connected to the KFM system

Primary drivers of capex are plant projects and well connect capital

Implies cash flow neutrality in 2019

Selected Commentary

1 Overhead guidance does not reflect any potential severance or other costs associated with our recent reduction in force


Appendix

ALTA MESA RESOURCES


Debt Maturity Profile2

CURRENT BALANCE SHEET UPDATE

14

Borrowing Since Year End

As of 12/31/2018 Current1

Cash and Cash Equivalents2 $27 $27

Alta Mesa Holdings RCF $161 $278

Kingfisher Midstream RCF $174 $183

7.875% Senior Unsecured Notes $500 $500

Net Debt $808 $934

Availability on Alta Mesa Holdings RCF3 $217 $100

Availability on Kingfisher Midstream RCF $126 $117

Cash and Cash Equivalents2 $27 $27

Liquidity $370 $244

$700

$500

2019 2020 2021 2022 2023 2024

7.875% Senior Unsecured Notes

Undrawn Kingfisher Midstream RCF

Undrawn Alta Mesa Holdings RCF

Drawn Kingfisher Midstream RCF

Drawn Alta Mesa Holdings RCF

1 As of 02/22/20192 Cash and Cash Equivalents is shown as of 12/31/2018 for both periods displayed3 $21.9mm of outstanding letters of credit is shown of 12/31/2018 for both periods displayed against the $400mm borrowing base

Capitalization and Liquidity

AMH credit facility drawn $117mm since year end

Reducing negative net working capital was driver of

early 2019 draws


CRUDE OIL HEDGE POSITIONS

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1 Positions as of 02/22/19

Crude Oil (Benchmark to NYMEX WTI)1

1Q 2019 2Q 2019 3Q 2019 4Q 2019 FY 2020 FY 2021Swaps

Volume (BBL/d) 500 500 500 500 - - Weighted Average Price per BBL $63.03 $63.03 - -

Three-Way CollarsVolume (BBL/d) 7,400 7,400 7,400 7,400 1,600 -

Weighted Average Price per BBLCeiling $66.31 $66.31 $66.31 $66.31 $64.32 - Floor $54.05 $54.05 $54.05 $54.05 $53.91 - Short Put $42.91 $42.91 $42.91 $42.91 $42.19 -

Put SpreadsVolume (BBL/d) 500 500 500 500 2,600 -

Weighted Average Price per BBLCeiling $50.00 $50.00 $50.00 $50.00 $56.54 - Short Put $40.00 $40.00 $40.00 $40.00 $46.15 -


Natural Gas (Benchmark to NYMEX HH)1

1Q 2019 2Q 2019 3Q 2019 4Q 2019 FY 2020 FY 2021Swaps

Volume (MMBTU/d) 12,500 50,000 50,000 36,739 3,508 - Weighted Average Price per MMBTU $3.02 $2.67 $2.67 $2.68 $2.54 -

CollarsVolume (MMBTU/d) 17,500 - - - 2,878 1,479Weighted Average Price per MMBTU

Ceiling $3.30 - - - $2.94 $3.25Floor $2.96 - - - $2.50 $2.50

Three-Way CollarsVolume (MMBTU/d)

Ceiling 15,000 - - 16,576 7,708 - Floor 10,000 - - 16,576 7,708 - Short Put 10,000 - - 16,576 7,708 -

Weighted Average Price per MMBTUCeiling $3.47 - - $3.19 $3.29 - Floor $2.90 - - $2.70 $2.76 - Short Put $2.40 - - $2.20 $2.26 -

Put SpreadsVolume (MMBTU/d) - - - - 18,784 6,164Weighted Average Price per MMBTU

Floor - - - - $2.53 $2.65Short Put - - - - $2.03 $2.15

Panhandle Eastern Basis SwapsVolume (MMBTU/d) 50,000 60,000 60,000 26,848 2,486 - Weighted Average Price per MMBTU ($0.62) ($0.72) ($0.72) ($0.66) ($0.49) -

San Juan Basis SW SwapsVolume (MMBTU/d) 2,500 10,000 10,000 3,370 - - Weighted Average Price per MMBTU ($0.47) ($0.81) ($0.81) ($0.81) - -

OneOk Basis SwapsVolume (MMBTU/d) - - 2,500 2,500 - - Weighted Average Price per MMBTU - - ($0.93) ($0.93) - -

NATURAL GAS HEDGE POSITIONS

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1 Positions as of 02/22/19


ALTA MESA RESOURCES

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