ISSUES ENCOUNTERED IN OIL & GAS ASSET VALUATIONS Presented at - - PowerPoint PPT Presentation

2016 INEXS

ISSUES ENCOUNTERED IN OIL & GAS ASSET VALUATIONS

Craig Davis, President and CEO, 713 993 0676 , cdavis@Inexs.com Jeb Burleson, Engineer, 713 993 0676, jburleson@Inexs.com

Interactive Exploration Solutions Inc. (INEXS) A Geoscience and Engineering Consulting Firm

Presented at SPEGCS Mergers, Acquisitions, and Divestments (MA&D) Symposium

October 20, 2016

2016 INEXS

ASSET LEVEL IMPLEMENTATION

GUIDANCE

• Asset quality (geology, acreage, historic performance, upside)
• Characteristics to look for: conventional / unconventional (plus vs. minus)
• Economics (well and asset level – do assets fit company financial picture?)

ACTUAL

• TARGETED OBJECTIVES: Gas vs. Oil, PDP vs. Undrilled, Acreage Continuity, Proximity to Current Ops
• ASSET QUALITY: Basin, Reservoir, Acreage
• HISTORIC PERFORMANCE: Type Curve Generation, Sample Selection Criteria, Pitfalls
• CHARACTERISTICS: Economics, Breakeven Costs, D&C, Transportation, Processing, Basis Differentials, SWD

2016 INEXS

TARGETED OBJECTIVES

TARGETED OBJECTIVES: What is the company looking for and why?

• Gas vs. Oil
• Most companies have a preference on oil or gas focused reservoirs
• If they want gas assets, should it be wet gas or dry gas?
• What type of NGL yield are they looking for?
• Is there infrastructure in place?
• PDP vs. Undrilled
• When acquiring an asset, many focus on the upside potential
• How much of the acreage is undeveloped?
• What does the production decline look like for PDP assets?
• Acreage Continuity
• Is the acreage continuous or broken up in many different sections?
• Broken up acreage can result in fewer new drill opportunities
• Proximity to Current Ops
• Does the asset fit the company profile?
• Will they have to enter into a new basin?
• What are the costs of starting somewhere new?

2016 INEXS

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Source: naturalgasintel.com, ft.com (Financial Times)

ASSET QUALITY: BASIN BREAKEVEN ECONOMICS

2016 INEXS

ASSET QUALITY: BASIN, RESERVOIR, ACREAGE

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Source: DrillingInfo

• Stacked Reservoir Targets
• Tend to be Oil Rich
• Conventional Vertical Wells
• More Recent Horizontal Drilling
• Significant Uplift from Vert. to Horizontal
• Great Economics
• Complete Infrastructure
• Deep Bench of Sellers and Buyers
• High Level of Industry Focus
• High Volume Salt Water Disposal
• Relative Continuity of Acreage
• Acreage Status: HBP vs. Primary Term

and Remaining Lease Term

• How Many Type Curves Necessary
• Undrilled Acreage Characteristics

2016 INEXS

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Source: (Data) DrillingInfo Source: (Work) INEXS

Central Basin Platform Wolfcamp (Delaware Basin) 6 Month BOE Wolfcamp (Midland Basin) 6 Month BOE

HISTORIC PERFORMANCE: WOLFCAMP RESERVOIR 180 DAY IP MAPS

2016 INEXS

7 A B C D

Well selection criteria: Wolfcamp, horizontal, first production 2012-2015

Rank Area PV10 ROR (%) Payout (Years) 1 A $ 3,604,033 56.4% 1.6 2 B $ 1,180,117 19.5% 3.6 3 C $ (1,144,235)

• 8.0%

N/A 4 D $ (1,743,757)

• 18.6%

N/A

HISTORIC PERFORMANCE: WOLFCAMP HORIZONTAL WELLS – 4 STUDY AREAS

2016 INEXS

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Daily Oil

HISTORIC PERFORMANCE: WOLFCAMP HORIZONTAL WELLS AREA D LOCATION

2016 INEXS

$2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $35.00 ($3,076,912) ($2,969,861) ($2,861,373) ($2,753,843) ($2,646,073) ($2,538,303) ($2,430,534) $40.00 ($2,717,299) ($2,607,099) ($2,495,757) ($2,385,176) ($2,274,404) ($2,163,633) ($2,052,861) $45.00 ($2,350,828) ($2,238,172) ($2,124,618) ($2,011,662) ($1,898,557) ($1,785,452) ($1,672,347) $50.00 ($1,988,929) ($1,873,355) ($1,757,161) ($1,641,380) ($1,525,496) ($1,409,612) ($1,293,728) $55.00 ($1,625,887) ($1,507,510) ($1,388,783) ($1,270,290) ($1,151,738) ($1,033,186) ($914,634) $60.00 ($1,262,845) ($1,141,665) ($1,020,406) ($899,200) ($777,980) ($656,761) ($535,541) $65.00 ($899,803) ($775,821) ($652,028) ($528,109) ($404,222) ($280,335) ($156,448) $70.00 ($536,760) ($409,976) ($283,651) ($157,019) ($30,464) $96,090 $222,645

PV-10 Gas Prices Oil Prices

Assumptions:

• Working Interest: 100%
• Net Revenue Interest: 80%
• Monthly LOE: $7,500/Month
• NGL Yield: 200 BBL/MMCF
• Dry Gas Left: 86%

Investment:

• Drilling and Completion: $4.5 MM
• Investment Life: 50 years

Expenses:

• Operating Costs: $2.0/BOE

Taxes:

• Ad Valorem: 4.25%
• Severance Oil: 7.5%
• Severance Gas: 4.6%

Price Differentials:

• Gas Differential/Transportation: $0.33/MCF
• Oil Differential/Transportation: $4.20/BBL
• Add Gathering: $0.50/MCF
• Water Hauling: $1.50/BBL

Prices:

• Oil and Natural Gas Price is NYMEX Strip Pricing
• Natural Gas Liquid Sales Price: 26% of Oil Price

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CHARACTERISTICS: BREAKEVEN COSTS, D&C, TRANSPORTATION, BASIS DIFFERENTIALS, SWD

2016 INEXS

Column1 All Wells Top Wells PV10 ($1,743,757) $3,744,057 ROR

• 18.60%

100.70% Payout (years) n/a 1 Project Life (years) 9.3 19 Column1 All Wells Top Wells Number of Wells 67 15 Average Lateral Length (ft.) 6,797 6,239 Oil EUR (Mbbls) 122.4 307 Oil b-factor 0.8 0.8 Oil Annual Effective Decline 0.89 0.92 Oil IP (Mbbls/Month) 9.9 23.9 Gas EUR (MMcf) 687.2 1,600 Gas b-factor 0.9 0.6 Gas Annual Effective Decline 0.75 0.6 Gas IP (MMcf/Month) 22.2 52.9 Water EUR (Mbbls) 224.2 254.5 Water b-factor 0.6 0.5 Water Annual Effective Decline 0.83 0.94 Water IP (Mbbls/Month) 22.1 35.3

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Top Producers # of Wells Laredo Petroleum 9 FDL Operating 4 Parsley Energy 1 Permian Resources 1

Wolfcamp Horizontal Wells Area D - Monthly Production

All Wells

Wolfcamp Horizontal Wells Area D Top Wells - Monthly Production

Top Wells

Assumptions:

• Working Interest: 100%
• Net Revenue Interest: 80%
• Fixed OPEX at $7,500/Month (Parsley)
• NGL Yield: 140 BBL/MMCF (EP)

Investment:

• Drilling and Completion: $4.5 MM (EP

Energy) Expenses:

• Operating Costs: $2.0/BOE (Parsley)

Taxes:

• Ad Valorem: 4.25%

Price Differentials:

• Gas Differential/Transportation:

$0.33/MCF (EIA)

• Oil Differential/Transportation:

$4.20/BBL (COP)

• Add Gathering: $0.50/MCF (EIA)
• Water Hauling: $1.50/BBL (EIA)

Prices:

• Oil and Natural Gas Price is NYMEX

Strip Pricing

• Natural Gas Liquid Sales Price: 26% of

Oil Price (RSP Permian)

HISTORIC PERFORMANCE: WOLFCAMP AREA D TYPE CURVE

2016 INEXS

10 100 1000 10000 100000 Jan-00 Jun-05 Dec-10 Jun-16 Nov-21 May-27 Nov-32 Apr-38 Oct-43 Apr-49

Production (BOE/month) Months of Production

Type Curve Improvements (2010-2016)

2010-2011 2012-2013 2014-2016

HISTORIC PERFORMANCE: TARGETED SINGLE OPERATOR PERMIAN (HORIZONTAL)

D&C¹: $5,475,000 PV 10²: $3,520,000 IRR: 40.7% 68 Wells (2014-2016) Observations

• There is a clear trend of

improved performance YOY starting in 2010

• Production improvements

mainly attributed to increased IP

• The number of wells drilled per

year also increase every year starting in 2010

• Wells perform consistently in the

three counties operated

• 2014-2016 type curve represents

76% of Operator’s total active horizontal wells in Permian

Source: DrillingInfo (1) Source: [redacted] ($630/Lateral ft.) (2) PV 10 Net Revenue, NYMEX Strip pricing, 100% WI, 80% NRI, $4.43 LOE/BOE, Taxes = 8.25%, G&T = $0.35/BOE , Water Disp. = $1.50/BBL, Oil Diff. = $4.20/bbl, ECL = 50 years

2010-2011 2012-2013 2014-2016 # of wells drilled 3 18 68

• Avg. Lateral

Length 3,994’ 7,130’ 8,691’ IPoil (BBL/mo) 6,853 14,629 20,969 Deoil (%) 97.27 95.16 99.07 b-factoroil 1.1 1.1 1.2 EURoil (BBL) 150,812 355,901 442,109 IPgas (MCF/mo) 16,407 24,473 45,436 Degas (%) 87.4 40.89 71.67 b-factorgas 1.1 0.8 1.0 EURgas (MCF) 551,942 1,536,354 1,907,280

Oil and Gas Type Curve (2010-2016)

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2016 INEXS

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HISTORIC PERFORMANCE: TYPE CURVE - MARCELLUS ACREAGE

2016 INEXS

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HISTORIC PERFORMANCE: TYPE CURVE - MARCELLUS THICKNESS

2016 INEXS

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HISTORIC PERFORMANCE: TYPE CURVE - MARCELLUS DEPTH

2016 INEXS

D&C¹: $5,750,000 PV 10²: $4,217,000 41 Wells Observations While the type curve for all these wells is fairly decent, it is important to break out certain areas and completion techniques to understand which wells are contributing the most to the curve.

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Source: DrillingInfo (1) Source: EQT (2) PV 10 Net Revenue after 25 years, $35.00 oil, $2.25 gas, 100% WI, $10,000 LOE/mo, 80% NRI, economic limit of 30 BOE/D NOTE: # of wells reported will differ from data shown on bubble map and type curve due to lack of information on publicly available data

HISTORIC PERFORMANCE: TYPE CURVE – MARCELLUS TYPE CURVE ALL WELLS

2016 INEXS

D&C¹: $5,750,000 PV 10²: $1,739,000 13 Wells Observations These wells North of the acreage have lower reservoir thickness as well as lower depth compared to the wells South of the acreage.

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Source: DrillingInfo (1) Source: EQT (2) PV 10 Net Revenue after 25 years, $35.00 oil, $2.25 gas, 100% WI, $10,000 LOE/mo, 80% NRI, economic limit of 30 BOE/D NOTE: # of wells reported will differ from data shown on bubble map and type curve due to lack of information on publicly available data

HISTORIC PERFORMANCE: TYPE CURVE – MARCELLUS TYPE CURVE NORTHERN WELLS

2016 INEXS

D&C¹: $5,750,000 PV 10²: $5,618,000 28 Wells Observations These wells South of the acreage have slightly greater depths and reservoir thickness than the wells to the North, which could explain the difference in IP and EUR.

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Source: DrillingInfo (1) Source: EQT (2) PV 10 Net Revenue after 25 years, $35.00 oil, $2.25 gas, 100% WI, $10,000 LOE/mo, 80% NRI, economic limit of 30 BOE/D NOTE: # of wells reported will differ from data shown on bubble map and type curve due to lack of information on publicly available data

HISTORIC PERFORMANCE: TYPE CURVE – MARCELLUS TYPE CURVE SOUTHERN WELLS

2016 INEXS

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Source: DrillingInfo PV 10 Net Revenue after 25 years, $35.00 oil, $2.25 gas, 100% WI, $10,000 LOE/mo, 80% NRI, economic limit of 30 BOE/D NOTE: # of wells reported will differ from data shown on bubble map and type curve due to lack of information on publicly available data

2011

• PV10: $6.4MM
• EUR: 10.6 BCF
• Avg. Lat. Length: 3,700 ft
• b-factor: 1.3

2010

• PV10: $1.7MM
• EUR: 7.3 BCF
• Avg. Lat. Length: 3,500 ft
• b-factor: 1.2

2012

• PV10: $8.8MM
• EUR: 12.3 BCF
• Avg. Lat. Length: 6,000 ft
• b-factor: 1.3

2013

• PV10: $16.1MM
• EUR: 17.4 BCF
• Avg. Lat. Length: 6,800 ft
• b-factor: 1.4

HISTORIC PERFORMANCE: TYPE CURVE – MARCELLUS TYPE CURVE (2010-2013)

2016 INEXS

2,000 4,000 6,000 8,000 10,000 12,000 14,000 30 60 90 120 150 180 Gas (MCF/D) Days

Haynesville Type Curves Normalized for 5,000' Lat. Length

Area is Haynesville Trend in Harrison, Panola and Rusk Counties, Texas

150 Days Original --------- INEXS EUR 4.1 BCF EUR 2.1 BCF

INEXS TYPE WELL CURVE USING LARGER SAMPLE OF 120 HAYNESVILLE WELLS WITH 24-36 MONTHS PRODUCTION

Wells used in INEXS analysis Wells used in Original analysis 19

HISTORIC PERFORMANCE: SAMPLE SIZE - TYPE CURVE VARIATION IN HAYNESVILLE

2016 INEXS

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Area is Haynesville Trend in Harrison, Panola and Rusk Counties, Texas Wells used in INEXS analysis Wells used in Original analysis

• SPEE defines the minimum sample size of analogue wells to sufficiently validate,

within 90% confidence, the P90, P50 and P10 distribution curves.

• When a sufficient sample of analogue wells is used, the degree of confidence in

achieving the statistical performance is high.

• A sufficient sample of analogue wells must be used to have a valid distribution. SPEE

recommends 75-100 wells for P10/90 ratio of 5-6 (low variability).

Table 2.1 Recommended Minimum Sample Size P10 / P 90 Ratio Recommended Sample Size Comments 2 15 Ratio not likely to be seen 3 35 Common Ratio 4 60 Common Ratio 5 75 Common Ratio 6 100 Common Ratio 8 130 Common Ratio 10 170 Possible data quality / analogy issues 15 290 Possible data quality / analogy issues 20 420 Possible data quality / analogy issues 30 670 Possible data quality / analogy issues Phase of Resource Play Development

Early Intermediate Statistical Mature Ratio of Analogous Producing Wells to Recommended Minimum Sample Size < 1 1 to 4 > 3 Very Large P10/P90 < 4, Approximate Well Count < 50 100 150 > 500 P10/P90 4 to 10, Approximate Well Count < 50-200 100-400 150-600 > 1000 P10/P90 10 to 30, Approximate Well Count < 200-700 200-1400 600-2100 > 4500

• Fig. 3.3 - Approximate Producing Well Count at Various Stages of Resource Play Development

Confidence in Achieving +/- 10% of the Mean vs. Sample Size Confidence in Achieving the Target Sample Size

• Fig. 3.3 - Approximate Producing Well Count at Various Stages of Resource Play Development

Source: SPEE Monograph 3 pg. 43

HISTORIC PERFORMANCE: SAMPLE SIZE - TYPE CURVE VARIATION IN HAYNESVILLE