Project Ozona Economic Technical Review 10-4-2017

The Fénix Petroleum Group
Project Ozona Technical Review
October 2017
Private and Confidential
1

Disclaimer
This “Presentation” and materials enclosed herein have been prepared solely for informational purposes using information supplied by Fénix Petroleum
Group, LLC (together with existing and to-be-created subsidiaries or affiliates may be referred to from time to time herein as the “Fénix Petroleum
Group” or the “Company”). The information contained herein is to be used by prospective investors in evaluating a potential investment with the
Company’s management team in current or to-be-created subsidiaries or affiliates.
The information contained herein is not, and may not be relied on in any manner as, legal, tax or investment advice or as an offer to sell or a solicitation
of an offer to buy an interest in any entity in any jurisdiction. A private offering of interests in any investment funds, entities or vehicles managed or
advised by the Fénix Petroleum Group (collectively, the “Fund”) will only be made pursuant to the definitive offering and governing agreement(s) of the
Fund and applicable subscription documents, which will be furnished to qualified investors on a confidential basis at their request for their consideration
in connection with such offering.
This Presentation may include certain forward-looking statements, estimates, and projections provided by the Company’s management with respect to
its value, anticipated future performance and the results of its future operations. Words such as “anticipate,” “can,” “could,” “will,” “intend,”
“continue,” “expect,” “achieve,” “strategy,” “future,” “estimated,” “should,” or other comparable words or phrases or the negatives of those words or
phrases, and other words of similar meaning indicate forward‐looking statements. Such forward‐looking statements are subject to various risks and
uncertainties. Accordingly, there are or will be important factors that could cause actual outcomes or results to differ materially from those reflected in
these materials. Further, such forward-looking statements, values, estimates, and projections reflect various assumptions by the Company’s
management concerning anticipated results, which have been included solely for illustrative purposes. No representations are made as to the accuracy
of such forward-looking statements, values, estimates, or projections with respect to any other information contained herein.
Certain information contained herein has been obtained from published and non-published sources. Such information has not been independently
verified. Except where otherwise indicated herein, the information provided herein is based on matters as they exist as of the month/year stated on the
cover page of this Presentation and not as of any future date, and will not be updated or otherwise revised to reflect information that subsequently
becomes available, or circumstances existing or changes occurring after the date hereof.
The information contained herein has been prepared to assist interested parties in making their own evaluation of the Company and its management
team and does not purport to be all-inclusive or to contain all of the information that a prospective sponsor may desire. The information and data
contained herein are not a substitute for the recipient’s own due diligence and independent evaluation. Each recipient should perform its own
independent investigation and analysis of the opportunity and its investment worthiness.
The information and data contained herein is strictly confidential and may not be divulged to any person or entity, in whole or in part, except to your
officers, directors, employees, and agents exclusively for use with evaluating the opportunity presented herein, or as required by applicable law, without
written consent from the Company. This Presentation does not create any rights, obligations or liabilities for any person or entity.
2

Project Ozona: General Overview
3

Fénix Proposed Acquisition: General Overview
Project Ozona Overview
■
■
■
■
■
Project Ozona is an asset that has been operated poorly and lacked sufficient
developmental capital; as such, it meets Fénix’s strategic criterion
▬ Breakeven price for new wells is ~$15 per flowing barrel of oil (1)
▬
Lots of low cost opportunities to enhance field through a robust maintenance
program, new drilling and secondary recovery effort
Currently negotiating the definitive purchase and sale agreement
Ozona asset overview:
▬
▬
▬
~6000 net acres located in Crockett County, Texas
30 active producing wells with 3 disposal wells & 7 shut-ins
~65 bbl/d of oil production (majority of production from the San Andres)
The robust asset includes 5 significant hydrocarbon-bearing formations producing
and/or identified within the lease area:
▬
▬
▬
▬
▬
Queen
Greyburg
San Andres
Wolfcamp
Ellenburger
Asset highlights include:
▬
▬
▬
▬
Significant inventory of additional San Andres drilling locations (at least 30 new
wells currently planned)
• Major areas on structure have NOT been drilled – substantially mitigating
depletion risk
• Offset waterflood has more than doubled oil produced and can be
replicated across the Ozona asset
Additional upside from Queen and Grey burg formations
Potential to acquire additional acreage providing extensive exposure to the
aforementioned formations and additional drilling locations
Shallow nature of producing formations (San Andres at ~1,400 ft.) keeps
drilling and completion costs low
• Anticipate drilling, completion and facilities costs at or below $150,000 per
well
Queen
Greyburg
San Andres
Wolfcamp
Ellenburger
Asset Location: Crockett County, TX
Crockett County Stratigraphy Column
1. This assumes a conservative 30 mbo EUR, which is well below EUR performance from offset producing wells
4

Fénix Proposed Acquisition: General Overview
Project Level Economic Overview (1)
Date 2017 Q1 Q2 Q3 Q4 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Well Count
Current Wells On-line 42 42 42 42 42 42 42 42 42 42 42 42 42 42 42
PUD Wells On-line 0 9 18 27 30 21 30 30 30 30 30 30 30 30 30
Total Wells On-line 42 51 60 69 72 63 72 72 72 72 72 72 72 72 72
Gross Production (Bbl/d)
PDP Production (Bbls/d) 59.7 58.8 57.9 57.1 56.2 57.5 54.1 51.0 48.0 45.2 42.6 40.1 37.7 35.5 33.5
Net Revenue Interest 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 75%
Net PDP (Bbls/d) 44.8 44.1 43.4 42.8 42.2 43.1 40.6 38.2 36.0 33.9 31.9 30.1 28.3 26.7 25.1
PUD Production (Bbls/d) - 111.2 283.0 433.8 512.3 335.1 412.3 308.9 283.3 266.7 251.2 236.5 222.7 209.7 197.4
Net Revenue Interest 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 75%
Net PUD Production (Bbls/d) - 83.4 212.3 325.3 384.2 251.3 309.3 231.7 212.4 200.0 188.4 177.4 167.0 157.3 148.1
Total Net Production (Bbls/d) 44.8 127.5 255.7 368.1 426.4 294.4 349.9 269.9 248.5 233.9 220.3 207.4 195.3 183.9 173.2
Oil Price $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00
Differential (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00)
Realized Oil Price 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00
Net Revenue $173,012 $483,234 $977,397 $1,420,994 $1,647,591 $4,529,216 $5,359,678 $4,148,709 $3,808,280 $3,585,964 $3,376,625 $3,188,417 $2,993,896 $2,819,121 $2,654,549
Lease Operating Expense (126,000) (143,000) (171,000) (198,000) (216,000) (728,000) (864,000) (864,000) (864,000) (864,000) (864,000) (864,000) (864,000) (864,000) (864,000)
Production Taxes (9,040) (25,249) (51,069) (74,247) (86,087) (236,652) (280,043) (216,770) (198,983) (187,367) (176,429) (166,595) (156,431) (147,299) (138,700)
Net Operating Income $37,972 $314,985 $755,328 $1,148,747 $1,345,505 $3,564,565 $4,215,635 $3,067,939 $2,745,298 $2,534,597 $2,336,196 $2,157,822 $1,973,465 $1,807,822 $1,651,849
Drilling & Completion Expense (581,250) (1,395,000) (1,395,000) (1,240,000) (38,750) (4,068,750) - - - - - - - - -
EBITDA $(543,278) $(1,080,015) $(639,672) $(91,253) $1,306,755 $(504,185) $4,215,635 $3,067,939 $2,745,298 $2,534,597 $2,364,721 $2,157,822 $1,973,465 $1,807,822 $1,651,849
Net Income to Investor $28,570 $246,938 $594,048 $904,148 $1,059,186 $2,804,322 $3,316,499 $2,410,997 $2,156,442 $1,990,204 $1,833,671 $1,692,939 $1,547,486 $1,416,798 $1,293,739
Yield to Investor 37.3% 44.1% 32.0% 28.7% 26.4% 24.4% 22.5% 20.6% 18.8% 17.2%
Estimated IDC Value to Investors $406,875 $2,848,125
Investor Break-even
34 months
Project Level IRR IRR 55%
MOIC 3.5x
Investor IRR IRR 38%
MOIC 2.7x
Assumptions
■ 30-Day Initial Production Rate: 20
bbls/d
■
Production Decline: 35% initial decline
for first 24 months, followed by a 6%
terminal decline
■ Price Deck: $45.00 flat with a $3.00
differential inclusive of transportation
expense
■
$1000/mo/well lease operating expense
■ Project Level Working Interest: 100%
■ Project Level Net Revenue Interest: 75%
■ Investor Non-operated Working Interest: 80%
■ FPG Working Interest Carried by Investor: 20%
■ 30 well drilling program that begins December, 2017
▬
▬
Spud-to-spud: 10 days
Spud-to-sales: 30 days
Source and Uses
Sources
Equity Contribution $7,525,750
Total Sources $7,525,750
Uses
Asset Acquisition $2,200,000
Additional Equity Requirement $5,325,750
Drilling & Completion Expense 4,650,000
Field Remediation 300,000
(2)
Deal Expense 375,750
Total Uses $7,525,750
1. Model does not include the positive impact the intangible drilling cost deduction will have on individual investor returns
2. Includes legal, title and environmental diligence expense & capital to meet bonding requirement and fees associated with capital raise
5

Fénix Proposed Acquisition: General Overview
Project Level Economic Sensitivities
Gross Wellhead Sensitivities
Project Level Sensativities
Net Investor Sensitivities
Investor Project Level Sensitivities
IRR Sensitivity (Price per Barrel vs. Initial Daily Rate of Production)
IRR Sensitivity (Price per Barrel vs. Initial Daily Rate of Production)
55% 23 Bbls/d 22 Bbls/d 21 Bbls/d 20 Bbls/d 19 Bbls/d 18 Bbls/d 17 Bbls/d 38% 23 Bbls/d 22 Bbls/d 21 Bbls/d 20 Bbls/d 19 Bbls/d 18 Bbls/d 17 Bbls/d
$60.00 113.7% 107.0% 100.4% 93.9% 87.5% 81.1% 74.9% $60.00 81.1% 76.2% 71.4% 66.6% 61.9% 57.2% 52.6%
$55.00 98.0% 92.1% 86.3% 80.5% 74.9% 69.2% 63.7% $55.00 69.7% 65.4% 61.1% 56.8% 52.6% 48.5% 44.3%
$50.00 82.9% 77.8% 72.7% 67.7% 62.7% 57.7% 52.9% $50.00 58.7% 54.9% 51.1% 47.3% 43.6% 39.9% 36.2%
$45.00 68.4% 64.0% 59.6% 55.2% 50.9% 46.6% 42.3% $45.00 48.0% 44.6% 41.3% 38.0% 34.8% 31.5% 28.2%
$40.00 54.5% 50.7% 46.9% 43.1% 39.4% 35.7% 32.0% $40.00 37.5% 34.6% 31.7% 28.9% 26.0% 23.1% 20.2%
$35.00 40.9% 37.7% 34.5% 31.3% 28.1% 24.9% 21.6% $35.00 27.2% 24.7% 22.2% 19.7% 17.1% 14.6% 11.9%
$30.00 27.7% 25.0% 22.2% 19.5% 16.7% 13.8% 11.0% $30.00 16.8% 14.6% 12.4% 10.2% 7.9% 5.5% 3.1%
IRR Sensitivity (Price per Barrel vs. Monthly Lease Operating Expense)
IRR Sensitivity (Price per Barrel vs. Monthly Lease Operating Expense)
55% $700 $800 $900 $1,000 $1,100 $1,200 $1,300 38% $700 $800 $900 $1,000 $1,100 $1,200 $1,300
$60.00 101.0% 98.6% 96.2% 93.9% 91.6% 89.3% 87.0% $60.00 71.9% 70.1% 68.4% 66.6% 64.8% 63.1% 61.3%
$55.00 87.4% 85.1% 82.8% 80.5% 78.3% 76.1% 73.8% $55.00 62.0% 60.3% 58.6% 56.8% 55.1% 53.4% 51.7%
$50.00 74.2% 72.0% 69.8% 67.7% 65.5% 63.3% 61.1% $50.00 52.4% 50.7% 49.0% 47.3% 45.6% 43.9% 42.2%
$45.00 61.6% 59.5% 57.3% 55.2% 53.1% 50.9% 48.8% $45.00 43.1% 41.4% 39.7% 38.0% 36.3% 34.6% 32.9%
$40.00 49.5% 47.4% 45.3% 43.1% 41.0% 38.9% 36.8% $40.00 34.0% 32.3% 30.6% 28.9% 27.1% 25.4% 23.6%
$35.00 37.7% 35.6% 33.5% 31.3% 29.2% 27.0% 24.7% $35.00 24.9% 23.2% 21.5% 19.7% 17.9% 16.0% 14.1%
$30.00 26.1% 23.9% 21.7% 19.5% 17.2% 14.8% 12.3% $30.00 15.8% 14.0% 12.1% 10.2% 8.2% 6.1% 3.8%
6

Fénix Proposed Acquisition: General Overview
2016 Historical Revenue Summary
Production Date Lease Bbls Lease Gross Lease Severance Owner Gross Owner Severance Owner Net Division of Interest
Jan-16 1,352.64 34,963.05 1,616.77 27,970.44 1,293.42 26,677.02 80.0%
1,352.64 34,963.05 1,616.77 764.82 35.37 729.45 2.2%
Feb-16 1,544.69 38,804.16 1,794.65 31,043.33 1,435.72 29,607.61 80.0%
1,544.69 38,804.16 1,794.65 848.84 39.26 809.58 2.2%
Mar-16 1,863.30 58,164.77 2,687.23 46,531.82 2,149.78 44,382.03 80.0%
1,863.30 58,164.77 2,687.23 1,272.35 58.78 1,213.57 2.2%
Apr-16 1,374.44 47,003.10 2,170.73 37,602.48 1,736.58 35,865.90 80.0%
1,374.44 47,003.10 2,170.73 1,028.19 47.48 980.71 2.2%
May-16 1,334.73 53,184.97 2,454.85 42,547.98 1,963.88 40,584.10 80.0%
1,334.73 53,184.97 2,454.85 1,163.42 53.70 1,109.72 2.2%
Jun-16 1,691.97 72,490.75 3,345.14 57,992.60 2,676.11 55,316.49 80.0%
1,691.97 72,490.75 3,345.14 1,585.74 73.17 1,512.56 2.2%
Jul-16 1,699.20 66,686.81 3,078.21 53,349.45 2,462.57 50,886.88 80.0%
1,699.20 66,686.81 3,078.21 1,458.77 67.34 1,391.44 2.2%
Aug-16 1,528.50 59,646.64 2,753.29 47,717.31 2,202.63 45,514.68 80.0%
1,528.50 59,646.64 2,753.29 1,304.77 60.23 1,244.54 2.2%
Sep-16 1,189.79 45,570.13 2,103.65 36,456.10 1,682.92 34,773.18 80.0%
1,189.79 45,570.13 2,103.65 996.85 46.02 950.83 2.2%
Oct-16 1,686.91 71,740.93 3,310.63 57,392.74 2,648.50 54,744.24 80.0%
1,686.91 71,740.93 3,310.63 1,569.33 72.42 1,496.91 2.2%
Nov-16 1,350.07 53,505.99 2,469.74 42,804.79 1,975.79 40,829.00 80.0%
1,350.07 53,505.99 2,469.74 1,170.44 54.03 1,116.42 2.2%
Dec-16 1,532.04 70,507.55 3,252.93 56,406.04 2,602.34 53,803.70 80.0%
1,532.04 70,507.55 3,252.93 1,542.35 71.16 1,471.19 2.2%
Total: 18,148.28 672,268.85 31,037.82 552,520.96 25,509.21 527,011.75
7

Fénix Proposed Acquisition: General Overview
2017 YTD Historical Revenue Summary
Production Date Lease Bbls Lease Gross Lease Severance Owner Gross Owner Severance Owner Net Division of Interest
Jan-17 1,710.82 78,791.82 3,635.11 63,033.46 2,908.09 60,125.37 80.0%
1,710.82 78,791.82 3,635.11 1,723.57 79.52 1,644.05 2.2%
Feb-17 1,533.58 71,507.78 3,298.95 57,206.22 2,639.16 54,567.06 80.0%
1,533.58 71,507.78 3,298.95 1,564.23 72.16 1,492.07 2.2%
Mar-17 1,696.25 73,493.44 3,391.29 58,794.75 2,713.03 56,081.72 80.0%
1,696.25 73,493.44 3,391.29 1,607.67 74.18 1,533.48 2.2%
Apr-17 1,893.85 84,513.07 3,899.43 67,610.46 3,119.54 64,490.91 80.0%
1,893.85 84,513.07 3,899.43 1,848.72 85.30 1,763.42 2.2%
May-17 1,539.19 65,036.94 3,001.32 52,029.55 2,401.06 49,628.50 80.0%
1,539.19 65,036.94 3,001.32 1,422.68 65.65 1,357.03 2.2%
Jun-17 1,869.13 73,976.43 3,414.56 59,181.14 2,731.65 56,449.50 80.0%
1,869.13 73,976.43 3,414.56 1,618.23 74.69 1,543.54 2.2%
Jul-17 1,713.52 70,163.52 3,238.26 56,130.82 2,590.61 53,540.21 80.0%
1,713.52 70,163.52 3,238.26 1,534.83 70.84 1,463.99 2.2%
Total: 11,956.34 517,483.00 23,878.92 425,306.34 19,625.49 405,680.85
8

Fénix Proposed Acquisition: General Overview
All Permian Basin transactions under $100mm (1)(2)
Announce Date Buyers Sellers Deal Value ($MM) $/Proved BOE $/Daily BOE $/Acre
9/6/2016 Apache Undisclosed Seller $91.00 $1,300.00
5/24/2017 Halcon Resources Corp Oxy $88.00 $40,000.00 $15,520.10
7/31/2016 WPX Energy Inc Mack Energy Corp $84.00 $8.30 $6,800.00
9/30/2016 Energen Undisclosed Seller $77.00 $22,647.10
1/26/2017 Apollo Global Management LLC EP Energy Corp $75.00 $20,000.00
1/31/2017 Zarvona Energy LLC Pioneer $63.00 $11,250.00
11/30/2016 Matador Resources Company Undisclosed Seller $62.50 $34,747.80 $4,441.40
11/15/2016 SM Energy Laredo Petroleum Inc $60.00 $20,689.70
11/15/2016 SM Energy QStar LLC $60.00 $50,000.00
3/31/2017 SM Energy Undisclosed Seller $59.60 $20,551.70
5/2/2017 Callon Crossing Rocks Energy LLC $52.50 $21,101.30
6/7/2017 Parsley Energy LP Enduro Resource Partners LLC $50.40 $8.98 $22,352.90 $12,583.70
2/9/2017 Energen Undisclosed Seller $50.00 $22,857.10
2/22/2017 Matador Resources Company Undisclosed Seller $49.20 $6,000.00
4/25/2016 Centennial Resources Development LLC Caird Energy LLC; Wheat Resources LLC $44.00 $35,280.00 $14,658.30
3/31/2017 WPX Energy Inc Undisclosed Seller $38.00 $2,122.90
6/14/2016 Boaz Energy II LLC Memorial Production Partners LP $37.40 $12.06 $31,166.70
11/2/2016 WPX Energy Inc Undisclosed Seller $37.20 $8,260.00
1/25/2017 Guidon Energy PrimeEnergy Corp $31.00 $19,343.80
6/30/2017 Jagged Peak Energy Inc Undisclosed Seller $25.70 $14,277.80
8/8/2016 RSP Permian Inc PrimeEnergy Corp; Vanguard Natural Resources LLC $25.60 $35,636.40 $12,774.20
7/13/2017 Energy Hunter Resources Inc Lubbock Energy Partners LLC $22.60 $2,400.90
2/28/2017 Halcon Resources Corp Undisclosed Seller $22.30 $35,125.00 $28,080.80
5/23/2017 Abraxas Devon Energy $20.90 $23,939.40 $10,617.70
7/19/2016 Contango Providence Energy Operators LLC $20.00 $4,000.00
4/30/2016 Energen Undisclosed Seller $20.00 $5,405.40
7/31/2016 Lani Petroleum Resources Inc Clayton Williams Energy $19.50 $34,777.80 $6,548.00
4/17/2017 Ring Energy Inc Forge Energy LLC $16.60 $503.00
3/31/2017 RSP Permian Inc Black Mountain Oil & Gas LLC; Undisclosed Seller $16.50 $21,428.60
12/31/2016 Energen Undisclosed Seller $15.80 $14,363.60
3/31/2017 Undisclosed Buyer Carrizo $15.30 $41,576.10
5/22/2017 Diamondback Energy Vanguard Natural Resources LLC $13.90 $18,348.30
6/30/2017 SM Energy Undisclosed Seller $12.70 $25,400.00
6/22/2016 Laredo Petroleum Inc Undisclosed Seller $10.80 $9,694.80
9/30/2016 RSP Permian Inc Undisclosed Seller $7.40 $23,125.00
7/31/2016 Energen Blake Oil and Gas Corp; Undisclosed Seller $5.10 $6,004.70
11/10/2016 Torchlight Energy Resources Inc McCabe Petroleum Corp $3.70 $663.90
6/30/2016 Abraxas Undisclosed Seller $0.10 $28,888.90
Average: $36.96 $9.78 $32,191.49 $14,592.78
Fenix Petroleum Group Project Ozona $2.20 $2.61 $20,000.00 $150.00
Project Ozona Single Well Acquisition Cost: San Andres vs. Wolfcamp/Spraberry
Wolfcamp (single bench) Spraberry (single bench) San Andres
10,000' lateral 10,000' lateral 1450' vertical
Average EUR 1,000,000 850,000 30,000
Dedicated Acreage per Location 256 256 20
Average Price Per Acre $14,592.78 $14,592.78 $150.00
Average Lease Cost per Wellbore 3,735,750 3,735,750 3,000
Average Price per barrel (EUR) $3.74 $4.40 $0.10
1. Only transactions since September, 2016 through September, 2017; includes only those transactions that have sufficient data to calculate relevant transaction metrics
2. Data provided by 1Derrick, an industry-leading provider of merger & acquisition data and statistics
9

Fénix Proposed Acquisition: General Overview
PHDWin Database: PDP-only & 1P inclusive of 30 PUD drilling program (1)
PDP-only Economic Projections
1P Economic Projections
1. All economic assumptions are the same as described on page 10 of this presentation except the database uses a commodity price tied to NYMEX strip as of 9/15/2017 as
opposed to a $45 flat price
10

Project Ozona: Single Well Economics
11

Project Ozona: Single Well Economics
Single Well Economic Overview
Date Q4 2017 Q1 Q2 Q3 Q4 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Gross Production (Bbl/d) 19.4 19.4 17.8 16.3 14.9 13.6 15.6 11.1 9.7 9.1 8.6 8.1 7.6 7.1 6.7 6.3
Net Revenue Interest 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%
Net Bbls/d 14.6 14.6 13.3 12.2 11.2 10.2 11.7 8.3 7.2 6.8 6.4 6.0 5.7 5.4 5.0 4.8
Oil Price $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00 $45.00
Differential (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00) (3.00)
Realized Oil Price 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00 42.00
Gross Revenue $56,286 $56,286 $50,384 $46,614 $43,136 $39,458 $179,593 $127,286 $111,302 $104,512 $98,411 $92,666 $87,501 $82,162 $77,366 $72,850
Lease Operating Expense (3000) (3000) (3000) (3000) (3000) (3000) (12000) (12000) (12000) (12000) (12000) (12000) (12000) (12000) (12000) (12000)
Production Taxes (2941) (2941) (2633) (2526) (2254) (2062) (9474) (6651) (5816) (5461) (5142) (4842) (4572) (4293) (4042) (3806)
Net Operating Income $50,345 $50,345 $44,751 $41,089 $37,882 $34,397 $158,119 $108,635 $93,487 $87,051 $81,269 $75,824 $70,929 $65,869 $61,324 $57,043
Net to Investor WI $39,088 $39,088 $34,675 $31,856 $29,255 $26,505 $122,290 $83,178 $71,226 $66,149 $61,587 $57,291 $53,429 $49,437 $45,850 $42,473
Well-head Break-even
Investor Break-even
11 months
15 months
Well-head IRR IRR 158%
MOIC 5.9x
Investor IRR IRR 98%
MOIC 4.5x
Assumptions
■ $155,000 to drill & complete (includes cost of facilities)
■
■
■
■
30-Day Initial Production Rate: 20 bbls/d
Production Decline: 35% initial decline for first 24 months, followed by
a 6% terminal decline
Price Deck: $45.00 flat with a $3.00 differential inclusive of
transportation expense
$1000/mo/well lease operating expense
■ Project Level Working Interest: 100%
■ Project Level Net Revenue Interest: 75%
■
■
■
Investor Working Interest: 80% (included is cost to carry FPG)
Spud-to-spud: 10 days
Spud-to-sales: 30 days
12

Project Ozona: Single Well Economics
Single Well Economic Sensitivities
Gross Wellhead Sensitivities
Wellhead Sensativities
Net Investor Sensitivities
Wellhead Sensativities
IRR Sensitivity (Price per Barrel vs. Initial Daily Rate of Production)
IRR Sensitivity (Price per Barrel vs. Initial Daily Rate of Production)
158% 23 Bbls/d 22 Bbls/d 21 Bbls/d 20 Bbls/d 19 Bbls/d 18 Bbls/d 17 Bbls/d 98% 23 Bbls/d 22 Bbls/d 21 Bbls/d 20 Bbls/d 19 Bbls/d 18 Bbls/d 17 Bbls/d
$60.00 418.4% 376.9% 338.5% 303.1% 270.4% 240.3% 212.6% $60.00 244.6% 222.2% 201.3% 181.7% 163.3% 146.2% 130.2%
$55.00 337.9% 305.5% 275.4% 247.5% 221.6% 197.5% 175.2% $55.00 200.9% 183.0% 166.1% 150.3% 135.4% 121.4% 108.3%
$50.00 269.3% 244.4% 221.1% 199.3% 179.0% 160.0% 142.3% $50.00 162.7% 148.5% 135.1% 122.4% 110.5% 99.2% 88.5%
$45.00 211.2% 192.2% 174.4% 157.7% 142.0% 127.3% 113.5% $45.00 129.4% 118.3% 107.8% 97.8% 88.3% 79.3% 70.8%
$40.00 162.0% 147.8% 134.5% 121.9% 110.0% 98.7% 88.1% $40.00 100.4% 91.9% 83.7% 76.0% 68.6% 61.5% 54.7%
$35.00 120.6% 110.3% 100.5% 91.2% 82.4% 74.0% 66.0% $35.00 75.2% 68.8% 62.6% 56.7% 51.0% 45.5% 40.2%
$30.00 85.9% 78.7% 71.7% 65.0% 58.6% 52.4% 46.5% $30.00 53.3% 48.6% 44.0% 39.5% 35.2% 30.9% 26.7%
IRR Sensitivity (Price per Barrel vs. Monthly Lease Operating Expense)
IRR Sensitivity (Price per Barrel vs. Monthly Lease Operating Expense)
158% $700 $800 $900 $1,000 $1,100 $1,200 $1,300 98% $700 $800 $900 $1,000 $1,100 $1,200 $1,300
$60.00 313.4% 309.9% 306.5% 303.1% 299.7% 296.4% 293.0% $60.00 189.3% 186.8% 184.2% 181.7% 179.1% 176.6% 174.1%
$55.00 256.6% 253.5% 250.5% 247.5% 244.5% 241.5% 238.6% $55.00 157.3% 154.9% 152.6% 150.3% 148.0% 145.7% 143.4%
$50.00 207.3% 204.6% 202.0% 199.3% 196.6% 194.0% 191.4% $50.00 128.8% 126.7% 124.6% 122.4% 120.3% 118.2% 116.2%
$45.00 164.8% 162.4% 160.1% 157.7% 155.3% 153.0% 150.6% $45.00 103.6% 101.7% 99.7% 97.8% 95.9% 93.9% 92.0%
$40.00 128.3% 126.1% 124.0% 121.9% 119.8% 117.7% 115.6% $40.00 81.4% 79.6% 77.8% 76.0% 74.2% 72.4% 70.7%
$35.00 96.9% 95.0% 93.1% 91.2% 89.3% 87.5% 85.6% $35.00 61.7% 60.0% 58.4% 56.7% 55.0% 53.4% 51.7%
$30.00 70.1% 68.4% 66.7% 65.0% 63.3% 61.6% 59.9% $30.00 44.3% 42.7% 41.1% 39.5% 37.9% 36.3% 34.7%
13

Project Ozona: Single Well Economics
Historical Lease Operating Expense
2016 Lease Operating Expense
Expense Item Opex Intangible Exp. Equip. Exp. Monthly Average
MISCELLANEOUS EXPENSE $4,428.67 $0.00 $0.00 $369.06
EQUIPMENT REPLACE & REPAIR $13,626.03 $0.00 $0.00 $1,135.50
ADMINISTRATIVE OVERHEAD $0.00 $0.00 $0.00 $0.00
SALT WATER DISPOSAL $1,967.45 $0.00 $0.00 $163.95
WELL SERVICE & CIRCULATION $5,286.10 $0.00 $0.00 $440.51
POWER & FUEL $30,722.30 $0.00 $0.00 $2,560.19
PUMP REPAIR $17,252.74 $0.00 $0.00 $1,437.73
INSURANCE $1,920.00 $0.00 $0.00 $160.00
TANK BATTERY REPAIR $109.83 $0.00 $0.00 $9.15
TESTING $708.00 $0.00 $0.00 $59.00
AD VALOREM TAX $8,830.09 $0.00 $0.00 $735.84
ENGINE & MOTOR REPAIR $525.58 $0.00 $0.00 $43.80
LOCATION EXPENSE $0.00 $1,790.40 $0.00 $149.20
EQUIPMENT RENTAL $701.25 $0.00 $0.00 $58.44
OIL TREATMENT $750.00 $0.00 $0.00 $62.50
STEAMING & HOT OIL $0.00 $0.00 $0.00 $0.00
PRODUCTION CASING $0.00 $0.00 $0.00 $0.00
FRESH WATER/DISPOSAL WATER $0.00 $0.00 $0.00 $0.00
REPAIRS $0.00 $0.00 $0.00 $0.00
$86,828.04 $1,790.40 $0.00 $7,384.87
Total: $88,618.44
Average Month Cost per Well (40 active wells): $184.62
2017 YTD Lease Operating Expense
Expense Item Opex Intangible Exp. Equip. Exp. Monthly Average
MISCELLANEOUS EXPENSE $1,920.06 $0.00 $0.00 $240.01
EQUIPMENT REPLACE & REPAIR $26,033.23 $0.00 $0.00 $3,254.15
ADMINISTRATIVE OVERHEAD $0.00 $0.00 $0.00 $0.00
SALT WATER DISPOSAL $1,425.75 $0.00 $0.00 $178.22
WELL SERVICE & CIRCULATION $4,219.15 $0.00 $0.00 $527.39
POWER & FUEL $26,890.57 $0.00 $0.00 $3,361.32
PUMP REPAIR $3,771.78 $0.00 $0.00 $471.47
INSURANCE $2,040.00 $0.00 $0.00 $255.00
TANK BATTERY REPAIR $816.64 $0.00 $0.00 $102.08
TESTING $0.00 $0.00 $0.00 $0.00
AD VALOREM TAX $0.00 $0.00 $0.00 $0.00
ENGINE & MOTOR REPAIR $2,340.14 $0.00 $0.00 $292.52
LOCATION EXPENSE $0.00 $8,899.28 $0.00 $1,112.41
EQUIPMENT RENTAL $0.00 $0.00 $0.00 $0.00
OIL TREATMENT $0.00 $0.00 $0.00 $0.00
STEAMING & HOT OIL $1,193.46 $0.00 $0.00 $149.18
PRODUCTION CASING $0.00 $0.00 $34,858.24 $4,357.28
FRESH WATER/DISPOSAL WATER $0.00 $4,449.50 $0.00 $556.19
REPAIRS $0.00 $135.54 $0.00 $16.94
$70,650.78 $13,484.32 $34,858.24 $14,874.17
Total: $118,993.34
Average Month Cost per Well (40 active wells): $371.85
Note: LOE numbers exclude overhead charges and pumper expense. Fenix will charge $350
per well per month (total monthly charge of $14,000) for administrative overhead and
$275 (1) per well per month (total monthly charge of $11,000) for pumper expense.
1. Pumper expense is inclusive of truck, fuel and insurance expense
14

Project Ozona: Single Well Economics
Project Ozona Single Well Type Curve vs. Average Offset Well Type Curve (1)
Conservative Projected Single Well Economics (2)
Actual Offset Single Well Performance (2)(3)
1. All economic assumptions are the same as described on page 10 of this presentation except the database uses a commodity price tied to NYMEX strip as of 9/15/2017 as opposed to a $45 flat price
2. Curves are inclusive of total D&C costs (including facilities) AND full acquisition costs; price allocation assumes $30,000 per PUD location (assumes 30 total PUD locations)
3. Derived from analysis of 80 current or former active producing wells within the same field and formation
15

Project Ozona: Single Well Economics
Drilling & Completion AFE (not inclusive of estimated $5k of facilities cost per well) (1)
Drilling AFE
Drilling Costs
ACCT CODE DESCRIPTION ORIGINAL SUPPLEMENT TOTAL
220/15 Bits & Mills (12-1/4" & 7-7/8") $0 $/Bit No. $0 $0
220/20 Casing Crews & Equipment $4,000 $/Day 3 Days
220/25 Cement/Cementing Services (8-5/8") .
220/25 Cement/Cementing Services (5-1/2")
220/30 Contract Labor $350 $/Day 8 Days
220/35 Daywork $425 $/Hr 50 Hrs
220/40 Directional Drilling $7,100 $/Day 3 Days
220/45 Engineering Services $/Day Days $3,000
220/50 Equipment Rental $575 $/Day 8 Days
220/55 Inspect/Test/Repair/Replace $/Day Days
220/60 Fishing $/Day Days
220/65 Footage $28 $/Ft 1,500 Ft
220/70 Fuel/Lube/Oil/Grease $100 $/Day 8 Days
220/75 Coring $0 $/Day 0 Days
220/75 Core Evaluation
220/90 Location & ROW $5,000
220/110 Rig Move (RU & RD) + trucking $/Well 1 Ea
220/120 Service Rig $/Day Days
220/125 Snubbing/Coil Tubing Unit $/Day Days
220/135 Supervision
$1,500 $/Day 5 Days $7,500
220/140 Surface Damages .
220/145 Swabbing Services $/Day Days
220/150 Transportation $1,400 $/Day 8 Days
220/155 Turnkey . $70,000
220/160 Drilling Fluids $1,200 $/Day 8 Days
220/170 Well Testing $/Day Days
220/175 Wireline Services/Logging $8,200 $/Day 1 Days
Total Intangible Cost $85,500 $0 $0
240/10 Intermediate Casing/Liner $/Ft Ft
240/20 Labor $500 $/Day 2 Days
240/35 Misc Fittings/Equipment
240/40 8-5/8" 24 ppf LS Casing $10.01 $/Ft 850 Ft $8,509
240/40 5-1/2" 15.50 ppf LS Casing $6.81 $/Ft 1,500 Ft $10,215
240/50 Tangible Drilling Equipment
240/80 Wellhead Equipment
240/155 Turnkey Equipment
Total Tangible Cost $18,724 $0
Total Intangible + Tangible Cost $104,224 $0
Contingency $0 $0
Management Fee (10%) $0 $0
Taxes (8.25%) $8,598 $0 $0
TOTAL $112,822 $0 $0
Completion AFE
Completions Costs
ACCT CODE Intangible Cost
ORIGINAL
225/15 Bits and Mills $/Bit No.
225/20 Casing Crews & Equipment
225/25 Cement/Cementing Services
225/30 Contract Labor $/Day Days
225/35 Daywork $/Day Days
225/45 Engineering Service $/Day Days
225/50 Equipment Rental $/Day Days
225/55 Inspect/Test/Repair/Replace $/Day Days
225/60 Fishing $/Day Days
225/70 Fuel/Lube/Oil/Grease $/Day Days
225/75 Geo Steering/Micro Seismic
225/90 Location & Row (Electrification) $4,000
225/95 Misc Service/Expense/Equip
225/105 Overhead $/Day Days
225/105 Perforating Services $5,700
225/110 Rig Move
225/115 Road Work
225/120 Service Rig $/Hr Hours $2,400
225/125 Snubbing/Coil Tubing Unit $/Day Days
225/130 Stimulation Services $4,000
225/135 Supervision $1,500 $/Day 1 Days $1,500
225/145 Swabbing Services $/Day Days
225/150 Transportation $/Day Days
225/155 Turnkey
225/160 Water & Drilling Fluids $/Bbl Bbls
225/170 Well Testing $/Day Days
225/175 Wireline Services/Logging/ $3,750
225/790 Contingency
225/800 Non-Op IDC Completions
$21,350
ACCT CODE Tangible Cost
ORIGINAL
245/10 Compressor
245/15 Electrical
245/20 Labor $/Day Days
245/25 Line Pipe/Flowline $/Ft Feet $2,000
245/30 Metering Equipment
245/35 Misc Fittings/Equipment $2,500
245/40 Casing $/Ft Feet
245/45 Production Tubing $/Ft 1,600 Feet $5,000
245/50 Pumping Unit/Prime Mover (Refurbished) $2,500
245/55 Subsurface Equipment/Packers
245/60 Sucker Rods/Down Hole Pump $/Ft 1,600 Feet $5,000
245/60 Surface/Prod Equipment
245/70 Tangible LW & E
245/75 Production Tanks $/Tank No.
245/80 Wellhead Equipment
245/85 Separator Heater Treater
245/90 Pumping Unit/Prime Mover
245/110 Compressor
Total Tangible Cost $17,000
TOTAL $38,350
1. These AFEs are fully bid-out on a single well basis; cheaper AFEs are anticipated with the larger, PUD drilling program
16

Top of Greyburg
Project Ozona: Single Well Economics
Greyburg through San Andres Cross Section (northern portion of property (Sec. 5, 61 & 84)
Vaughn #34, Sec. 5 Vaughn #9, Sec. 5 Vaughn #17, Sec. 61 Vaughn #16, Sec. 61 Vaughn #27, Sec. 84 Vaughn #28, Sec. 84
Well No. IP(BOPD) Comp date
Section 2
30 INJ May-75
5 INJ Sep-50
2 10 Jul-86
10 143 Oct-50
11 141 Oct-50
12 118 Jan-51
13 144 Feb-51
14 137 Mar-51
15 288 Apr-51
16 197 May-51
17 168 Jun-51
18 192 Jul-51
19 141 Aug-51
20 120 Oct-51
21 121 Sep-51
22 119 Nov-51
23 141 Sep-51
24 144 Aug-51
31 6 Mar-78
34 18 Dec-80
36 25 Dec-80
45 INJ Jun-86
30A INJ Sep-87
Well No. IP(BOPD) Comp date
Section 5
9 112 Apr-51
34 0 Apr-52
23 84 Sep-51
21 146 Sep-51
7 94 Mar-51
Initial Individual Well Results
Well No. IP(BOPD) Comp date
Section 61
V1 23 Nov-14
8 219 Mar-51
6 149 Feb-51
5 114 Mar-51
4 225 Jan-51
2 86 Nov-50
1 65 Oct-50
11 92 May-51
10 214 Apr-51
13 168 Jun-51
17 198 Jul-51
16 182 Jun-51
15 226 Jun-51
19 163 Aug-51
20 232 Aug-51
22 218 Sep-51
30 0 Jan-52
3 145 Dec-50
Well No. IP(BOPD) Comp date
Section 84
30 21 Nov-06
12 61 May-51
28 97 Nov-51
26 88 Nov-51
27 112 Dec-51
29 22 Jan-51
25 50 Oct-51
24 29 Oct-51
18 118 Jul-51
14 162 Jun-51
Well No. IP(BOPD) Comp date
Section 85
34 52 Jun-50
34 36 Apr-75
65 10 Jan-77
42 40 Jun-52
39 41 Mar-53
37 May-53
T-2 72 Jun-51
63 94 Dec-50
62 65 Dec-50
61 65 Jan-51
60 76 Feb-51
59 126 Apr-51
58 80 May-51
57 96 Jul-51
56 190 Jul-51
55 220 May-51
54 88 Feb-51
53 80 Mar-51
49 50 Oct-50
52 90 Mar-00
51 100 Jan-51
50 75 Oct-50
40 57 Aug-51
38 48 Aug-50
36 85 Apr-50
35 100 May-50
64 173 Jun-51
12 118 Jan-51
19 141 Aug-51
14 137 Mar-51
Cross Section Locations
Average Initial Rates of Production Far Exceed the 20 bopd IP Assumption Used in Economic Projections
17

Top of Greyburg
Project Ozona: Single Well Economics
Greyburg through San Andres Cross Section (southern portion of property (Sec. 82 & 88)
Pearson #4, Sec. 88 Bean #3, Sec. 88 Bean #2E, Sec. 88 Vaughn #40S, Sec. 82 Vaughn #44S, Sec. 82 Vaughn #43S, Sec. 82
Well No. IP (BOPD) Comp date
Section 81
3 13 Aug-54
1C 51 Apr-53
1 62 May-65
2 55 Nov-64
Initial Individual Well Results
Well No. IP (BOPD) Comp date
Section 82
40-S 120 Feb-55
39 105 Nov-54
44-S 88 Aug-55
43-S 0 Jul-55
39 105 Nov-54
18 43 Jul-65
17 33 Apr-65
16 61 Mar-55
15 77 Apr-55
14 47 Mar-55
11 70 Mar-55
13 195 Feb-55
12 45 Apr-55
10 135 Feb-55
9 77 Feb-55
8 50 Jan-55
7 208 Dec-54
5 179 Dec-54
4 184 Dec-54
3 67 Nov-54
2 112 Jan-55
1 0 Sep-53
41 44 Mar-55
Well No. IP (BOPD) Comp date
Section 88
B4 30 Nov-12
4 8 Nov-54
3 168 Jun-54
13-88 30 Jan-67
14-88 9 Aug-87
12 20 Jan-87
11 35 Jul-81
9 30 Nov-77
2 29 Sep-75
3 8 Sep-76
4 40 Jul-76
5 9 Dec-76
6 9 Apr-77
1 8 Nov-72
2 140 Oct-54
2 73 Nov-54
3 142 Dec-54
1 120 Jan-55
3 D&A Jan-55
Well No. IP (BOPD) Comp date
Section 89
4 15 Feb-17
1 D&A Jun-78
7 13 May-77
8 35 Nov-77
10 9 Feb-78
Cross Section Locations
Average Initial Rates of Production Far Exceed the 20 bopd IP Assumption Used in Economic Projections
18

Project Ozona: Acreage & EUR Overview
19

Project Ozona: Acreage & EUR Overview
Project Ozona Map
20

Project Ozona: Acreage & EUR Overview
Project Ozona Development Program
1 & 2
■
■
Map Overview
Area 1 & 2 (page 17 & 18): 32 producing San Andres wells with an average
EUR per well of 34.5 MBO
Area 3 (page 19): 3 producing San Andres wells with an average EUR per well
of 133 MBO
■
Area 5 (page 20): 4 producing San Andres wells with an average EUR per well
of 51 MBO
9
3
■ Area 6 (page 21): 1 recently drilled and producing San Andres well with a 30-
day IP of 11.5 bbl/d
■
Area 9 (page 22): 20 producing San Andres wells with an average EUR per
well of 64 MBO
11
6
5
13
■
■
Area 11 (page 23): 14 producing San Andres wells with an average EUR per
well of 43 MBO
Area 13 (page 24): 1 producing San Andres well with an average EUR per well
of 77 MBO
■
30 PUD ( ) locations
21

Project Ozona: Acreage & EUR Overview
Area 1
22

Project Ozona: Acreage & EUR Overview
Area 2
23

Project Ozona: Acreage & EUR Overview
Area 3
24

Project Ozona: Acreage & EUR Overview
Area 5
25

Project Ozona: Acreage & EUR Overview
Area 6
26

Project Ozona: Acreage & EUR Overview
Area 9
27

Project Ozona: Acreage & EUR Overview
Area 11
28

Project Ozona: Acreage & EUR Overview
Area 13
29

Fénix Proposed Deal Structure
30

Fénix Proposed Deal Structure
Indicative Deal Structure
■
Limited Partners: Fénix Petroleum Group, LLC will form the first limited partnership fund, FPG I, LP, targeting $50,000,000 of
equity capital to acquire and develop assets in the Fénix Petroleum Group’s pipeline of potential acquisition candidates
▬
Limited Partners participating in any Fénix Oil & Gas GP investment vehicle will be entitled to their respective share of the
following:
• All income derived from their 80% working interest ownership in assets less their obligations to the Fénix Petroleum Group’s
20% carried working interest
• Investors will be entitled to intangible drilling cost (“IDC”) deductions that will dramatically shield income from taxes
▬
IDC’s represent ~75% of the total cost to drill and complete each well and can be deducted in the year incurred or over a
60 month period
31

Fénix Proposed Deal Structure
Proposed Organizational Structure
Fénix Petroleum
Group, LLC
70% ownership interest in Fénix Oil
& Gas GP, LLC
Fénix Petroleum
Partners, LLC
20%
Carried WI
Fénix Petroleum
Operating, LLC
FPP I SPV, LLC
Asset holding
company
FPP I, LP
Working interest
ownership holding
company
Equity
80% WI
Income
&
IDCs
Limited Partners
Targeting $50mm
32

The Fénix Petroleum Team Overview
33

The Fénix Petroleum Team Overview
A Differentiated Strategy & Team
■
■
■
■
Value Creation
▬ The Fénix Petroleum Group is a lean team with a focused effort on deploying capital to the highest return PUDs and prospects geared towards
providing investors with solid monthly cash flow – the Company does NOT rely on a “long-wait” monetization strategy to drive investor returns
▬ This team will NOT rely on a commodity price recovery to deliver significant returns to the capital providers, relying instead upon leveraging a
best-in-class operating team to optimize both the development and exploitation of neglected assets with low cost operations and at the wellhead
break-even prices at or below $20/bbl
▬ The Fénix Petroleum Group is targeting investor returns in the 20%+ range over a 10 year period with project level breakeven timeline between
36 and 48 months
Asset Selection
▬ Conventional assets have become “unconventional” as major investment and best-in-class operators have been reallocated to the resource plays
over the last decade, leaving opportunity that few teams are currently focused upon
▬ The Company has found, and will continue to find, conventional assets that have been poorly operated and neglected by capital that have PUDs
and recompletions which remain economic, even in today’s low commodity price environment
▬ The Company is focused on acquiring significant stacked-pay potential with unconventional and/or secondary recovery upside that provides
substantial opportunities for both new drill and recompletion opportunities, which its experienced operating team can exploit
Ability to Transact
▬ Relationships with both public and private operators are essential to identify potential acquisition opportunities before they are widely marketed
– the Fénix Petroleum Group team has strong relationships across most conventional and unconventional U.S. basins
▬ While the Company may engage in broader auction processes, the majority of the team’s effort will be to continue to identify situations that
have yet to be broadly marketed to avoid overly competitive processes that result in aggressive purchase prices, over-burdening project level
returns
Team Make-up
▬ The Fénix Petroleum Group team has the in-house expertise across engineering, finance, G&G and operations to efficiently develop conventional
and unconventional reserves, while exploring and exploiting upside potential
▬ The Company’s technical team members all have 25+ years of experience in both conventional and unconventional exploration and development
and have extensive experience working together in basins across Texas and the Southeast United States
▬ The team is confident that its experience at developing existing reserves and finding and developing new or by-passed zones with new
techniques and technology in conjunction with its A&D expertise will, in the current environment, allow the Company to create significant value
to its equity partners
34

The Fénix Petroleum Team Overview
Team Overview – Leadership
Stuart Imel
Co-Chief Executive Officer
Charles Rougeau
Co-Chief Executive Officer
Stuart Imel brings oil and gas finance and leadership experience that includes building upstream oil and
gas teams, sourcing A&D opportunities and raising and deploying capital. Prior to co-founding Fénix
Petroleum Group, Stuart founded and led Pedernales Petroleum, LLC, an ArkLaTx-focused upstream oil &
gas company. During his tenure as President at Pedernales, he identified and led the acquisition of that
company’s sole asset, a ~17,000 net acre, 154 producing wells property in East Texas. Within 90 days of
taking over operatorship, production was increased more than 20%, major marketing contracts
renegotiated for ~35% cost savings, and an aggressive recompletion program put in-place. Stuart also
negotiated a multimillion dollar farm-out to PetroQuest. Prior to Pedernales, Stuart was an investment
banker with Barclays Natural Resources Group in Houston, where he worked on ~$10 billion worth of
transactions that closed across public and private equity and debt capital markets and M&A&D. Prior to
investment banking, Stuart was a military intelligence officer with two tours in Iraq. Stuart earned his
MBA with a concentration in finance from the Massachusetts Institute of Technology and his BS in Arabic
studies with a minor in Systems Engineering from the United States Military Academy at West Point.
Charles Rougeau brings over 27 years of operations and leadership experience in the upstream oil and gas
industry. He most recently served as President of StableRock Energy, L.L.C. and is responsible for
identifying a Permian asset and raising $15 million for acquisition and implementation of secondary
recovery project. Charles began his career with Schlumberger in 1990 as an open and cased hole engineer
in the Gulf Coast Division and later becoming a Senior Field Engineer responsible for tough logging
conditions for U.S. Land operations. Managed Integrated Power System from 1993 to 2001 and built the
company from $2 million to $18 million of EBITDA, and later negotiated sale to NOV for ~3x EBITDA. In
2001 Charles was appointed V.P. of Rig Systems and Controls for National Oilwell, in which he managed
the manufacturing of Drilling Rig Systems and controls for both land and offshore drilling rigs. Charles
successfully managed a $85 million manufacturing budget while reducing cost 4 percent in the first year.
From 2008 through 2014 Charles has held lead consulting positions with Linc Energy, JX Nippon USA and
Maritech Resources advising on drilling, completions and abandonment programs totaling over $400
million in Capex obligations. Charles has his BS in Geological Resource Management from Centenary
College.
35

The Fénix Petroleum Team Overview
Team Overview Continued
Richard Coleman
VP of Engineering
Sheri Sullivan
Geology
Gary Stevenson
Operations Manager
Richard Coleman brings almost 41 years of upstream oil and gas engineering experience to Fénix. He was
most recently serving as Vice President of Engineering of StableRock Energy, LLC, a position he assumed in
early 2012. Prior to StableRock, Richard was the Vice President of Engineering at GMS Contract Services.
Before GMS he was at Black Elk Energy, where he served as Reservoir Engineering Manager and then as
the Central GOM Asset Manager. Richard started his career in 1977 with Amoco Production Company as a
drilling and operations engineer in the district office in Brownfield, Texas. He then held positions in
reservoir engineering of increasing responsibility at Home Petroleum, Williams Exploration, CSX Oil and
Gas, and Nerco Oil and Gas through 1993. His next assignment was at Hunt Petroleum, where he held
positions in reservoir and operations engineering, and then as Offshore Develop Manager through 2006.
Richard was then at Nippon Oil Exploration as General Manger of Engineering and General Manager of
Production through 2010. Richard holds a B.S. in Chemical Engineering from Texas A&M University. He is
a member of the Society of Petroleum Engineers, API and the Exploration Society of Great Britain. Richard
is a Registered Professional Engineer in Texas and Louisiana.
Sheri Sullivan brings 12 years of geology and geophysics expertise to the Fénix team. Her background
includes explorative and developmental geological modeling, seismic interpretation, seismic attribute
analysis and production enhancement. Sheri has spent her career working a diverse set of assets from
deep water Gulf of Mexico to shallow formations across the lower 48 states for industry standard-bearers
such as Freeport McMoran, Plains Exploration, Occidental Oil & Gas, and Murphy. Her wealth of
experience is ideal for the development and optimization of oil and gas assets. Sheri earned her BS in
Geological Science from Louisiana State University and her MS in Geophysics from the University of New
Orleans. She is a member of the AAPG, NOGS, SEG, SJGS and SPE.
Gary Stevenson brings over 40 years of oil and gas engineering and operations expertise. Currently Gary is
the President of GMS Contract Services that provides Professional Engineering and Project Engineering
services to the upstream oil & gas community with over 30 on-site field consultants. His experience
includes engineering and managing production, drilling, workovers, completions, and abandonments. He
was a leader in the development of harsh environment technologies at Baker Oil Tools. Gary’s primary
geographic focus areas include the Gulf Coast, shallow Gulf of Mexico and Texas.
36

The Fénix Petroleum Group Overview
Current Personnel Overview
Charles Rougeau
Co-CEO
Stuart Imel
Co-CEO
Sheri Sullivan
Geology
Richard Coleman
VP Engineering
Gary Stevenson
Operations
Manager
Trinity Services
Land / Land
Management
Valerie Gallimore
Controller /
Accounting
Tommy Slocum
Regulatory/Compliance
Richard Willis
Facility/HSE
Supervisor
Billy Holle
CPA
Full Time Employee
Part Time Employee
37

Appendix
38

United States Tax Treatment for Oil & Gas
Intangible Drilling Cost and Other Deductions (1)
Oil and Gas investments in the United States have significant tax advantages relative to other industries. The motivation behind this
beneficial tax treatment is to encourage constant re-investment into the sector, which requires substantial capital expenditures to
maintain oil & gas production levels
■
Intangible Drilling Cost (IDC) Deduction
▬
▬
▬
Standard O&G Deductions
Normally represents ~75% of the total cost to drill and
complete a new well
These costs are deductible against active, passive and/or
portfolio income so long as the taxpayer has ownership in
real oil & gas properties
70% to 80% of IDCs are deductible in the first year the costs
are incurred, which provides a substantial tax shield when a
new producing well is at is peak production (primary revenue
producing year)
O&G Tax Advantage Example
■
Tangible Drilling Cost Deduction
▬
▬
Normally represents approximately 25% of the total cost to
drill and complete a new well
This amount can be deducted over a 5 year period
■
Depletion Allowance
▬
Currently, the depletion allowance provides for an additional
15% deduction.
• Thus, 15 cents of every income dollar is tax free, providing
tax-sheltered income
1. Please consult a tax expert regarding the aforementioned tax benefits, which may affect individual investor’s unique tax situation differently
39

Disclaimer
An investment in the Fund will involve significant risks, including risk of loss of the entire investment. There can be no assurance that the Fund’s investment strategy will produce favorable returns. An
investment in the Fund requires a long-term commitment, with little or no near-term cash flow available to its investors. The Fund’s investments will be highly illiquid, and there can be no assurance that the
Fund will be able to realize on its investments in a timely manner. The Fund’s contemplated exit strategies for its investments can be adversely affected by numerous factors, many of which may be unforeseen
or unexpected at the time the investment is made.
Prospective investors should bear in mind that there can be no assurance that the proposed Fund will be raised or that, if raised, it will achieve its objectives or avoid substantial losses.
In considering the performance information contained herein, recipients should bear in mind that past performance is not necessarily indicative of future results, and no assurance can be given that any of the
performance results or future events referred to herein, including disposition of investments, gain on investments, asset allocations or other transactions, will occur on the terms contemplated herein or at all.
Actual realized returns on unrealized investments presented herein will depend on, among other factors, future operating results, the value of the assets and market conditions at the time of disposition, any
related transaction costs, and the timing and manner of sale, all of which may differ from the assumptions and circumstances on which the valuations used in the investment information contained herein are
based. Market conditions may limit the liquidity of unrealized investments. Accordingly, the actual realized returns on these unrealized investments may differ materially from the preliminary results indicated
herein. There can be no assurance that the Fund’s investments will perform as well as any past investments referenced herein. Past performance is not indicative of future results, and there can be no
assurance that the Fund will achieve comparable results or be able to implement a similar strategy or achieve similar investment objectives due to available opportunities or market conditions or other factors.
The Fund will pay fees and expenses and other execution, leverage, administrative or operational costs whether or not it makes any profits. While it is difficult to predict the future expenses of the Fund, such
expenses may represent a substantial percentage of the Fund’s assets. The Fund must make substantial profits to avoid depletion or exhaustion of its assets from these fees and expenses. Further, a manager,
general partner or adviser’s share of carried interest distributions may create an incentive for such person(s) to select riskier or more speculative investments than would be the case in the absence of such
compensation.
Certain information contained in the Presentation discusses general market activity, industry or sector trends, or other broad-based economic market or political conditions and should not be construed as
investment advice.
The oil and gas industry is volatile. If commodity prices decline, certain properties in which the Fund may invest may become uneconomic and cause write downs of the value of its oil and natural gas
properties, which may adversely affect the financial condition of the Fund. The Fund’s revenues will depend upon oil and gas exploration, drilling and development, a business that often involves a high degree
of risk. The Fund may be indirectly subject to the risks inherent in acquiring or developing recoverable oil and natural gas reserves, including capital expenditures for the identification and acquisitions of
projects, the drilling and completing of wells and the conduct of development and production operations.
Oil and gas wells by their nature are depleting assets with respect to which production could last anywhere from a few months to more than 30 years. As a result, annual production will naturally decline over
the life of a well, and so too will returns to the Fund.
The Fund’s investments will be concentrated in direct real property rights and interests within the energy industry and specific geographic regions and will be subject to numerous risks that affect the energy
industry as a whole or the oil and gas sector of the industry or the regions of the Fund’s investments in particular. As a result, returns from an investment in the Fund may be subject to significantly greater risk
than an investment in a portfolio of investments that represents a broad range of industries, industry sectors or geographic focuses.
The Fund’s investments and returns may be adversely affected by environmental, financial, health and safety, production or other legislation or regulatory developments at the federal, state and local levels.
The investment performance of the Fund will be substantially dependent on the services of its manager, general partner or adviser and their respective principals and managers. In the event of the death,
disability, departure, insolvency or withdrawal of any of these principals, the performance of the Fund may be adversely affected.
The interests to be issued by the Fund are a new issue of securities for which there is no established trading market. An investor cannot expect to be able to resell any of its interests in the Fund readily, if at all.
In reliance upon exemptions that depend in part upon the accredited investor status and investment intent of its investors, the interests in the Fund are not being registered for public sale under federal or
state securities laws. The interests to be issued by the Fund will also have significant contractual restrictions on transfer, and any requested transfer will generally be subject to the approval of the general
partner or manager, which may withhold consent in its discretion.
The Fund will be required to indemnify Fénix and each of its affiliates and certain other related persons. The indemnification obligation of the Fund would be payable from the assets of the Fund, including the
commitments of investors. In the event the Fund’s assets are insufficient to meet its indemnification obligations, investors may be required to return distributions previously received by them.
An investment in the Fund may involve complex tax considerations that will differ for each investor depending on an investor’s particular circumstances. No assurance can be given that changes in tax law (or
in the interpretation or administration thereof by tax authorities) that are adverse to the Fund or to investors in the Fund will not occur.
Investors should be aware that there may be occasions when the general partner or manager and their respective affiliates, including the Fénix team members, may encounter potential conflicts of interest in
connection with the Fund’s activities. They may engage in activities involving the oil and gas industry including financial advisory activities and investment activities that are independent from, and may from
time to time conflict with, those of the Fund.
40