Permex Petroleum Limited Partnership

Transcription

Siddharth Rajeev, B.Tech, MBA, CFA
Analyst
December 11, 2013
Permex Petroleum Limited Partnership – Focus on Producing Oil and Gas Projects in North America
Sector/Industry: Junior Oil and Gas
Permex Petroleum Limited
Partnership
Issuer
Offering M emorandum
Date
03-Oct-13
Securities Offered
LP Units
Offering
No min / M ax of $20M
Unit Price
$1,000
M inimum Subscription
$10,000
Sales Commissions
8% + trailer fee of up to
2% p.a.
Expected Return for
Investors
Preferred return of 8% p.a.
+ 50% of profits above the
preferred return (monthly
distributions)
Auditor
Smythe Ratcliffe LLP
5% of the gross proceeds
raised upfront + Annual
management fee of up to
0.5% of NAV (paid
monthly) + 50% of
profits above preferred
return
M anagement Fee +
Performance Bonus
*all the figures in the report are in C$ unless
otherwise specified
FRC Rating
Base-Case IRR
N/A
Rating
3
Risk
4
www.energyresourcescorp.ca
Investment Highlights
 Permex Petroleum Limited Partnership is proposing to raise up to $20
million to acquire producing oil and gas projects across North America.
The target regions are Kentucky, Tennessee, Texas, Ontario, Alberta, and
Saskatchewan.
 The LP intends to hold a medium risk portfolio of producing oil and gas
projects, with potential for enhancement of production through
development.
 The LP has already identified two projects for acquisition – one in
Kentucky, and the other in Ontario. The two acquisitions total $9.2 million.
The project in Kentucky is currently producing at approximately 101 net
boepd (15% oil). This project also generates approximately $0.77 million
in annual revenues from the pipelines and equipment it owns. As the LP
does not have an exclusive option agreement with the seller, we identify the
project in Kentucky as “Project A” throughout this report, for
confidentiality reasons. The Ontario project (“Reef”) is not producing at
this time, but has the potential to be in production with Enhanced Oil
Recovery (“EOR”) techniques on already drilled wells.
 The LP was formed by N.A. Energy Resource Corp (“ERC”) - a
Vancouver, BC based private oil and gas company formed in 2010. ERC
also manages another fund, Kentucky Petroleum LP, which was also
formed in 2010.
 Management receives an annual management fee of 0.5% of the fair value
of assets. Management also receives 50% of the profits remaining after
investors are paid out a 8% preferred return.
 We believe Project A offers the LP an opportunity to attain exposure to low
to medium risk, stable cash flows, at a reasonable valuation.
Risks
 Volatility of commodity prices.
 Has yet to complete any acquisition.
 The LP has to significantly increase production from current levels in order
to realize the true potential of the identified projects.
 The offering has no minimum amount; capital raised might not be
sufficient to complete even one acquisition.
 There is no independent reserve report on the project in Kentucky.
 As the LP intends to hold projects in the U.S., investors will be exposed to
exchange rate risks.
 Redemption options are limited.
 The Reef project is highly speculative and capital intensive. The LP will
not be the operator of Reef.
*see back of report for rating definitions

 2013 Fundamental Research Corp.
“10 Years of Bringing Undiscovered Investment Opportunities to the Forefront “
www.researchfrc.com
PLEASE READ THE IMPORTANT DISCLOSURES AT THE BACK OF THIS REPORT
Page 2
Background
Permex Petroleum Limited Partnership, formed in September 2013, and officially launched
in November 2013, is proposing to raise up to $20 million. The objective of the LP is to hold
a medium risk portfolio of currently producing oil and gas projects, with potential for
enhancement of production through development. In order to keep risk levels medium, the
LP will not hold any pure exploration plays.
The LP has already identified two projects, covering approximately 34k acres, for
acquisition. The LP has signed an option agreement to acquire 100% of Project A in
Kentucky. The LP has also signed a Letter Of Intent (“LOI”) to acquire up to a 48.56%
interest in the Reef project in Ontario. In addition to the above two projects, the LP is also
currently seeking projects in Alberta, Tennessee, Saskatchewan and Texas. Management
expects the LP will have sufficient funds to acquire up to four projects, if the maximum
offering is raised. Management estimates that they need to raise at least $5 million to
complete one acquisition.
Management
The LP will be managed by Vancouver based private oil and gas company, N.A Energy
Resources Corporation, which was formed in 2010. ERC currently manages another fund,
Kentucky Petroleum LP, which has producing oil projects in Kentucky. This LP was formed
in October 2010.
Corporate Structure
Source: ERC
ERC's management uses the following key criteria for their acquisitions:

in production with stable current production rates;

moderate-to-long remaining production life (10 to 30 years or more);
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
low operating costs;

relatively fully developed;

situated onshore;

includes wells that have been in production for a sufficiently long period to
establish production characteristics;

portfolio should hold 50% of producing projects, and 50% of development stage
projects.

may hedge 50% to 80% of the oil and gas produced

may use debt, which is typical for producing projects

revenues from the project should be able to support operating expenses and minor
enhancement
Source: Company
The above criteria clearly indicate management's focus on medium risk, relatively
advanced / lower cost projects, with development potential and minimum exploration.
For projects where they are the operator, management intends to use Eagle Well Services, a
subsidiary of Western Energy Services (TSX: WRG), for drilling and other field related
services.
Past of
Performance of
Other Fund
Under
Management
In their first LP, management contributed a project to the LP (at no cost), which they had
acquired for $0.26 million. The following table shows the performance of the LP, which we
extracted from audited 2011, and 2012 statements, and unaudited Q1-2013 statements.
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YE - Dec 31st
2011
2012
Q1-2013
$21,449
$97,902
$34,602
$3,378,505
$4,066,892
$4,509,660
$0
$0
$0
$3,875,000
$7,105,000
$7,670,000
Distributions
Distributions % Inv.
Capital
$314,795
$636,015
$147,000
8.1%
9.0%
7.7%
Revenues
$423,573
$494,937
$143,937
G&A Expenses
$229,620
$196,715
$1,296
$0
$1,716,658
$0
$9,886
$25,757
$0
$365
$3,082
-$1,443,828
$145,723
Cash
PNG Assets
Debt
Invested Capital
Development Costs
Depreciation
Interest Income
Net Income



$184,067
Distributions as a percentage of invested capital is approximate, as we used the total
capital raised at the end of each term for calculation.
YE – December 31st
G&A expenses were low in Q1-2013; management indicated that most of the expenses
in Q1 were reported in Q2.
The LP raised a total of $7.67 million (as of March 31, 2013), and invested $6.2 million in
property acquisition and development. The LP had revenues of $495k, and a net loss of
$1.44 million in 2012. The net loss was primarily due to a $1.72 million development
expense.
The LP paid distributions of $315k in 2011 (8.1% of invested capital), $636k in 2012 (9.0%
of invested capital), and $147k (annualized yield of 7.7% of invested capital) in Q1-2013.
All distributions were higher than operating cash flows (defined here as “Revenues minus
G&A expenses”) in those periods – see table below – indicating the distributions did not
entirely come from operations. Note, distributions greater than operating cash flows are
not sustainable in the long run for any business.
YE - Dec 31st
2011
2012
Q1-2013
Distributions
$314,795
$636,015
$147,000
Operating Income (Revenues G&A expenses)
$193,953
$298,222
$142,641
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Brief biographies of the team members, as provided by management, follow:
Mehran Ehsan - President, Chief Executive Officer, Treasurer and Director
As President of Permex Petroleum, Mehran Ehsan has developed it as an upstream oil & gas
company focused on acquisitions and divestitures. Over the last eight years Mr. Ehsan has
been involved as a manager in mergers, acquisitions & divestitures, financing arrangements
and investment with a specialty in oil and gas opportunities. He has been directly involved
and facilitated syndication of over $82 million in capital syndication and injection within
various investment markets. He is the President and Chief Executive Officer of the General
Partner. He is also the President and Chief Executive Officer of N.A Energy Resources
Corp. and Kentucky Petroleum Operating Ltd. Mr. Ehsan’s vast experience ranges from
private to public & government based oil and gas deals and projects; he has worked with Oil
& Gas companies such as Marun Oil & Gas Production, West Texas Investment Corp. Mr.
Ehsan comes from a background of corporate finance and business management. His
academic background ranges from a spectrum of marketing management, business
management, wealth management and petroleum based curriculum and programs. Mr. Ehsan
has authored various articles in the oil and gas industry, with presence as a guest speaker and
judge in both this industry and academia related events.
Barry Whelan, P.Geo - Chief Operating Officer, Director
Barry Whelan has more than 40 years' experience as a geologist, initially with Gulf Oil in
International Operations, then he has worked with companies such as KOS Energy Ltd.,
Next Millennium Commercial Corp., Opal Energy Ltd., Copper Creek Ventures Ltd., Avro
Energy, Polar Resources Ltd., ProAm Exploration Corporation, Voyageur Oil and Gas
Corp., Bighorn Petroleum to name a few. Mr. Whelan has represented a diverse array of
energy market participants including oil, gas and other resources based companies with
clients ranging from global energy concerns to start-up companies. As a Geological
Consultant, Mr. Whelan has been active in natural resource and industrial development
companies with natural resource holdings in oil, gas and minerals, worldwide.
Responsibilities include: economic evaluations of properties; research and development of
projects which have economic potential; evaluation of projects and their requirements for
capital; presentations to management, financial institutions, and shareholders; economic
analysis of resource properties and coordination of acquisition, development and production
for resource properties; filing of V.S.E. reports, assessment reports and property evaluations
for petroleum and mining companies on resource properties. Mr. Whelan received his
Bachelor of Arts, Geology, from University of Western Ontario in 1961, Bachelors of
Science, Honours Geology, McMaster University, 1965. He is or has been also a member of
Geological Association of Canada, Association of Professional Engineers and Geoscientists
BC, Association of Professional Engineers, Geologists and Geophysicists of Alberta,
Canadian Society of Petroleum Geologists, Institute of Petroleum, London.
Wayne Needoba, Managing Director
Mr. Needoba has over 40 years of international petroleum industry planning, engineering
and team leader experience in all aspects of exploration and development, evaluation,
completion and well intervention operations, onshore and offshore, environments. Mr.
Needoba Joined Esso Ex (now Exxon Mobil) and worked internationally from 1974 to 1986
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as a drilling and completions / well testing engineer, operations supervisor. Voluntarily
separated in 1986 and founded a drilling and completions project management business in
Perth, Western Australia. In 1992 separated from the company and relocated to Bangkok
Thailand, and have been a consultant on a range of oil and gas projects to present time. Mr.
Needoba graduated with a diploma in Petroleum Technology from SAIT, Calgary Alberta in
1964 and worked with oil and gas production in Alberta until the end of 1965. Worked in
Australia with oil and gas operations from 1966 to 1969 and the in the Middle East as an oil
well cementing and stimulation supervisor. Attended the University of Tulsa from 1971 to
1973 and graduated with a BSc in Petroleum Technology 1973.
Dale Lee, Reservoir Advisor
Mr. Lee has more than 25 years' experience in the oil and gas sector. He is currently the
President & CEO of DL Petroleum & Engineering Consulting; some of his past notable
involvements and experiences include but are not limited to Petro Canada and Breaker
Energy as a Reservoir Engineer and Canadian Natural Resources as an Exploitation
Engineer. As a reservoir engineer, Mr. Lee has been active in natural resource and industrial
development companies with natural resource holdings in oil and gas worldwide.
Responsibilities include: Engineering focus to analyze partly depleted reservoirs to predict
the locations of underperforming wells based on statistical analyses of hydrocarbon
production. Evaluated wells using spatial statistics to locate underperforming wells or
regions within reservoirs. This goal is achieved by using known (measured) petro-physical
information from reservoirs and coupling this data with their production history
(production/injection flow and pressures). Spatial statistics including other statistical tools,
such as regression analysis, are used to evaluate the reservoir's performance with respect to
hydrocarbon production. In 1994 Dale earned his Professional Engineering status with The
Association of Professional Engineers, Geologists, and Geophysicists of Alberta
(APEGGA).
Sandey Wang, Controller
Ms. Wang (CGA, B. Eng.) has over 19 years of industry experience providing accounting
services to public and private companies. She was the CFO of two private O&G companies
in 2010 and is a controller of the other funds associated with the manager N.A Energy
Resources Corp. Some of the companies she has worked with include but are not limited to
Accend Capital Corp, American Uranium Corporation, Chesapeake Gold and Newbridge
Capital. She received her Bachelor of Engineering in 1988 and Certified General Accountant
(CGA) designation in 2000.
Independent Board of Advisors

Malcolm Fraser

Robert Jamieson

Gary Shroeder

David Mark
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
Kevin Redmond
Penalties, Sanctions and Bankruptcy
Mr. Whelan has been sanctioned by the British Columbia Securities Commission (BCSC) in
the past. In 2004, Barry Whelan entered into a settlement agreement with the BCSC.
Pursuant to the settlement agreement, Mr. Whelan, who was then the COO/Director of Hard
Creek Nickel Corp., agreed not "to prepare or disseminate mining disclosure required under
securities laws for two years without supervision and not to act as a director of a public
company until he successfully completes a course on the duties and responsibilities of
directors and officers." (Source: Offering Memorandum)
According to the BCSC, "Mr. Whelan is primarily an expert in oil and gas (not mineral
resources), did not draft the company’s mining technical disclosure, and that he was not
involved in postings on the company’s website or in preparing any of the private
placements. The BCSC also noted that he relied significantly on another director of the
company who was also sanctioned by the BCSC." (Source: Offering Memorandum)
The following section discusses the company's target projects:
Kentucky
Project
Ownership: In September 2013, the General Partner of the LP entered into an option
agreement to acquire a 100% WI (Net Royalty Interest – 87.50%), and all related assets
(including pipelines, offices, and equipment) of Project A. We have reviewed the option
agreement. The GP paid an option fee of $15k; the purchase price is $5 million; the option
expires in March 2014. The deadline can be extended by another 60 days by paying an
additional $10k. The seller is a private company based in Kentucky. We are not disclosing
the name of the seller for confidentiality reasons mentioned earlier in this report.
Management has contracted an oil and gas professional to conduct all project specific due
diligence in Kentucky.
Project Overview: Project A, which has been in production since 2002, covers over 30,000
acres of developed and undeveloped oil and gas leases in seven Kentucky counties (Knox,
Leslie, Bell, Harlan, Whitley, Laurel, and McCreary), and one Tennessee county
(Claiborne). Chesapeake Energy (NYSE: CHK) holds significant acreage in the area.
The project has 167 wells, 48 miles of gathering systems, two compressor stations, and
infrastructure/equipment in place such as drilling rigs, vehicles, tanks, tractors, etc.
The properties are located in Eastern Kentucky in the Appalachian Basin, and Utica Shale
play. The maps below show the location of the projects:
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Source: Seller of the project
The table below shows a summary of the projects.
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Area
Total
Acreage
Production # Wells
Acreage
Prod.
# Shut-in
Wells
Total #
of Wells
Approx. Feet
Pipelines
size/length
Compression
Knox County, KY
19,052
18,358
72
29
101
6&4 in./130,000 ft.
900 H.P. / 2MMCF
Cap.
Bell County, KY
2,397
1,793
9
11
20
8in& 6in./45,000 ft.
450 H.P / 2MMCF
Cap.
Whitley County, KY
2,016
1,976
4
5
9
4& 2 in./ 30,000 ft.
Laurel County, KY
1,396
950
2
2
4
6& 4 in./50,000 ft.
McCreary County, KY
658
0
0
0
0
0
Claiborne County, TN
41
41
1
0
1
0
Knox & Leslie County, KY
400
400
10
0
10
0
Bell & Harlan County, KY
4,652
4,652
16
6
22
0
30,612
28,170
114
53
167
Approx. 255,000 ft.
Total
As shown, of the 167 wells, 114 are currently producing at approximately 101 boepd net
with 53 wells shut-in.
The table below shows the production history of the project. The data was provided to ERC
by the seller. Net production has increased from 70 boepd (9% light oil) in 2009, to 101
boepd (15% light oil) in 2012. Production revenues increased from US$0.67 million
(2009) to US$0.88 million (2012).
As shown in the table above, commodity prices received have been close to WTI, and Henry
Hub prices.
According to management, some of the wells have been shut-in due to high gas association,
and no oil. They were shut-in when gas prices dropped below US$2.50/mcf. The other wells
were shut in as they require further work to commercialize. Of the 53 shut-in wells, 21 are
oil wells. Management estimates the total budget to bring all the shut-in wells into
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production is approximately $2.01 million, or $38k per well. We believe this is a reasonable
low-cost estimate.
In addition to production revenues, the project also generates revenues through the
following:
-
providing services to third-party oil and gas companies (through drilling rigs,
recompletion rigs, water trucks, etc owned by the project), termed as ‘Operating Fees’
in the table below.
-
from third-parties for using its pipelines for gas transportation, termed as
‘Transportation Revenues’ in the table below. According to management, senior
producers such as Chesapeake and Magnum Hunter Resources Corporation (NYSE:
MHR) use the project’s pipelines. The map below shows the pipelines in knox (totaling
130,000 ft).
Source: Seller of the project
Average revenues from transportation and operating fees, since 2009, are about $768k
per year. The total capacity of the pipelines is approximately 870 boepd; the current usage
is ~345 boepd. Therefore, the project has significant potential for generating additional
revenues from its pipelines.
The following figures in the table below, were provided to ERC by the seller during due
diligence.
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Project A
Operating Fee + Transportation
Revenues
Production Revenues
Total Revenues
2009
2010
2011
2012 2013 (Jan - May)
$753,288
$628,686
$694,208
$888,868
$436,945
$670,280
$543,889
$764,964
$1,423,568 $1,172,575 $1,459,172
$884,291
$1,773,159
$379,784
$816,729
Total Expenses
Operating Income
$590,675
$832,893
$629,649
$542,926
$636,008
$823,164
$817,120
$956,039
$356,731
$459,998
CAPEX
Net Cash Flows
$173,220
$659,673
$170,462
$372,464
$34,961
$788,203
$257,904
$698,135
$26,596
$433,402
Average annual revenues (2009-2013) from production and pipelines/operating fees
were approximately $1.49 million per year. Net cash flows averaged $677k per year. The
average operating income was $0.82 million. The acquisition price of $5 million reflects a
multiple of 6.1x times operating income. The average in the Oil and Gas Production
industry is 10.0x, while the average in the Natural Gas Pipeline industry is 22.2x; This
indicates to us that the $5 million valuation is reasonable for the project.
Management estimates that the equipment, trucks, rigs they will receive, from this
transaction, are worth approximately $1 million.
Reserve and NAV Estimate: There is no independent technical evaluation done on the
project. However, management has stated that they have begun their internal technical
evaluations, and will attain independent evaluations in 2014.
Plans after takeover: Management’s plans to - a) bring the 53 shut in wells into production
(total budget of $2 million), b) develop new wells (targets are yet to be identified), c)
increase pipeline contracts/revenues, and d) increase third party operating revenues
Management’s expected cash flow from the project is shown below. Management’s plan is
to bring a minimum of 4 wells per year of the shut-in wells online, and rework some of the
low producing current wells.
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Source: Management
As shown in the table, the average production is expected to increase from 107 boepd (14%
oil) in 2013, to 402 boepd (14% oil) by 2022. Management expects incremental production
of approximately 2-4 bopd (oil), and 100 – 150 mcfpd (gas) until 2018, and then 5 – 8 bopd,
and 150 – 300 mcfd from 2019 – 2022. We believe these estimates are optimistic, especially
considering that the current average net production per well is less than 1 boepd (101 net
boepd from 114 wells) . Our forecasts are presented later in this report.
Overall, we believe this transaction gives the LP an opportunity to take over a low to
medium risk cash-flowing project, with the potential for increased production through
development, at a reasonable valuation. Management is continuing with their due
diligence, but believes their due diligence so far has confirmed all the production
history, and other data provided to them by the seller.
Oil and Gas in
Kentucky
Kentucky has not been a significant oil and gas producer for the U.S. in the past. According
to the Energy Information Administration (EIA):

In 2009, Kentucky had oil reserves of 20 mm boe (0.1% of U.S. reserves) and gas
reserves of 2.78 tcf gas (1% of U.S. reserves).

In 2010, Kentucky produced 2.52 mm boe oil (ranked 20th in the U.S.; Texas was
ranked 1st with 427 mm boe of production).

In 2010, Kentucky produced 113 bcf gas (ranked 17th in the U.S.; Texas was ranked 1st
with 6.8 tcf of production)
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
Kentucky currently ranks third in the U.S. in coal production (behind Wyoming and
West Virginia)
Annual production in Kentucky dropped from an average of 6.6 mm boe in the 1980s (19801989), to 2.6 mm boe between 2000-2009, a 60% drop (shown in the chart below).
Production was 2.52 mm boe in 2010. At the same time, the average production in the U.S.
dropped by 22.9% from 27.71 mm boe to 21.36 mm boe.
Source: EIA
The primary reasons for the drop in production, we believe, are - a) most of the wells in
Kentucky have been relatively shallow (less than 2,000 feet), and as a result, deeper
formations have yet to be exploited, and b) Kentucky's oil and gas has been relatively
ignored, probably because of the more geographically challenging locations, and its known
reserve estimates (0.1% of U.S. reserves) are not significant compared to other areas.
Although we do not expect Kentucky to be a significant producer going forward, we believe
the lack of significant production in the past allows smaller players, such as Permex
Petroleum LP, to exploit the remaining reserves without much competition. However, note
that lack of significant production also leaves room for unknown risks.
Rock formations in the Appalachian Basin range from Pennsylvanian to Pre-Cambrian. The
surface topography consists of hilly, and mountainous terrain, with steep slopes and stream
valleys. The primary prospective formations in the basin are shown in the following (to a
depth of 3,600 feet) picture on the next page.
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Source: Management
The Knox, as shown above, at depths of 3,400 – 3,600 ft, has been an oil producer with
associated gas. Knox reservoirs are salt water driven. Knox has potentially two productive
pay zones. Typical knox wells produce for 20+ years at an average production of 20-30
boepd (20 bpd + 100 mcfpd).
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Another prospective zone is the Mississippian age Big Lime formation, which has been
producing oil and gas throughout eastern Kentucky. Two pay zones have been identified in
this formation.
A tertiary target is the Corniferous formation; this formation has been a large producer,
most notably in the Big Sinking Oil field, which the US Geological Survey classifies as a
giant oil field.
As per management, oil produced from Project A is mostly light/sweet, with wells
averaging depths of 3,200 – 3,900 feet.
Reef Project,
Ontario
Ownership: In September 2013, the GP entered into a non-binding LOI with Reef
Resources (TSXV: REE; market capitalization of $1.4 million) to acquire a 48.56% working
interest (WI) in the Reef Project in Ontario for $4.20 million. The LOI will be binding if and
when the GP pays a $200k deposit. Reef currently owns a 71.44% WI in the project, and
Solo Oil PLC (LSE: SOLO; market capitalization of US$17.4 million) owns the remaining
28.56%. The LP intends to acquire a 20% WI from Reef, plus another 28.56% from Solo
Oil, who is seeking to divest its investment.
Project Overview: The project covers 3,748 acres in Lambton County, in the Ausable Pool,
in Southern Ontario. The property has been producing since 2004. The map below shows the
location of the project.
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The Ausable reef is a Silurian Guelph pinnacle, with porosity varying from 3% to 12% in
the core facies, and 1-3% in the flanking debris apron. The reserves are shallow oil, natural
gas liquids, and natural gas, with typical well life of 20+ years.
Project Background: To date, a total of seven wells have been drilled (the first well was
drilled in 2004) into the reef, and the total production, from 2004 - 2010, was estimated at
6,600 bbls of oil, 160,700 mcf of gas, and 170 bbl of water (Source: Reef Resources). Of the
seven wells, five were in Ausable oil and NGL reef (including one horizontal), one in
Airport South gas and NGL reef, and one in Airport North gas and reef. All the wells are
currently shut-in. Locations of the wells are shown in the map below.
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* Ausable #2 is the horizontal well
The project is a gas recycling and enhanced oil recovery (EOR) play. The proposed
EOR program involves using natural gas for pressurizing the reef, followed by installing a
refrigeration plant to process and separate NGL. The refrigeration plant separates NGLs into
propane, butane and condensate.
Reef acquired the project in 2003. The company went public in 2007. Production from the
project has been intermittent, and not very significant. This is evident by the revenues
reported by Reef since it went public. Reef reported production revenues of $181k in
FY2007, $107k in FY2008, nil in FY2009 and FY2010, $156k in FY2011, and $18k in
FY2012.
In 2009, Reef announced it is planning to sell the assets. However, in 2010, Solo Oil made a
loan to Reef to finance the recommencement of production. Although production was
restarted in late 2010, commercial production levels were not achieved. Solo later converted
the loan to a WI in the project. Solo now has a 28.56% WI in the project. Reef had been
seeking funding partners to continue their development, which is when ERC stepped
in. Reef’s most recent financials (ended April 30th) showed cash of $3k, working capital of
negative $3 million, with no debt. Since then, they only raised $116k. On November 20,
2013, they announced that they are late to file their required filings and financial statements
due to delays in obtaining the funding necessary to retain an auditor and accounting services.
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All these, we believe, indicate that they are desperately in need of capital to stay afloat and
develop their projects.
According to Reef, gas storage rights and gas reinjection permits are in place. Reef’s
management believes that the Ausable wells can be put into production upon installation of a
gas plant and larger compressor. The total cost of the natural gas required for repressurization, the compressor, and the gas plant, is estimated at $5.4 million (Source: Reef
Resources). Adding two new horizontal wells, and a horizontal re-entry to the
compressor/gas plant, Reef proposes a work program of $9.59 million, as shown below.
Reef believes they can achieve production of 855 boepd, or $15 million in annual net
operating income, from this program.
Source: Reef Resources
Considering that Reef will only receive $3 million of the $4.2 million purchase price
($1.2 million will go to Solo for their 28.56% WI), Reef will be well short of the above
budget. However, Reef believes that they can split the above program into two phases, as
shown below. Phase 1 will require $2.3 million, and phase 2 will require $7.3 million.
Source: Reef Resources
Reserves: As of July 2012, the project had a 3P reserve of 565 mboe gross, and 495 mboe
net, with 94% light/medium oil. The after-tax NPV@10% was $10.17M – as per a report by
Deloitte & Touche LLP. This implies a 48.56% WI should be worth $4.93 million versus the
$4.20 million acquisition price. Considering that the acquisition price is close to 85% of the
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Page 19
independent valuation, whereas most deals in today’s market are done at a significant
discount to the independent valuation, we believe that the LP may be over paying for this
acquisition.
Overall, we believe the project has significant upside potential, but the risks are much
higher than Project A, especially because the development plan is highly capital
intensive. Considering management’s intended return-risk profile for the LP, we believe this
project carries higher risk, despite its high upside potential. Reef will continue to be the
operator, which implies that the LP will not have much control over operations. Also, Solo
Oil’s intention to exit from their investment also does not indicate they have a positive
outlook on the project. One of Solo’s management team members, who was also a director
of Reef, resigned from the board late last year.
Oil and Gas
Outlook
The consensus oil and gas price forecasts through 2022 are shown below:
Oil (WTI Cushing Oklahoma)
Source: GLJ and Sproule
Based on consensus forecasts, WTI prices are expected to range between US$92/bbl and
US105/bbl between 2014 and 2022.
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Natural Gas (Henry Hub - US$/mmbtu)
Source: GLJ and Sproule
Based on consensus forecasts, the henry hub spot price is expected to range between
US$3.9/mmbtu and US$5.8/mmbtu between 2014 and 2022.
Deal Structure
The following chart shows the structure of the offering:
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Source: OM
The assets will be held in Permex Petroleum Limited Partnership. The partnership will be
managed by the general partner – Permex Petroleum Operating Ltd., who will assume full
responsibility for the day-to-day management of the projects, and has unlimited liability.
The general partner is a wholly-owned subsidiary of N.A Energy Resources Corp., which is
wholly owned by Mehran Ehsan.
Investors can also purchase shares of Energy Resources Investment Corp. (“ERIC”). ERIC
uses the funds from investors to purchase LP units of Permex Petroleum LP. An investment
in ERIC may be eligible for registered plans.
Cash Distributions - Depending on the availability of cash, management expects to pay out
monthly cash distributions to investors at a preferred return of 8% p.a. All amounts above
the 8% p.a. mark are split between investors and the general partner on a 50:50 basis.
Preferred returns will be paid until the end of the seventh year, or until investors receive
100% of their capital, whichever comes earlier.
The following table shows the gross and net proceeds:
Sales fees – up to 8% of the gross proceeds, plus a trailer fee of up to 2% p.a paid to
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Page 22
certain agents based on management discretion. As per the LP agreement, the trailer fee
will only be paid after investors receive their 8% preferred return.
We believe the trailer fee is much higher than comparable offerings. A 2% annual trailer
fee will reduce investors` profit share component.
Management Fee / Performance Bonus: Management receives the following fees:



Upfront fee of 5% of the gross proceeds raised. As per the OM, these funds will be
used to cover legal, accounting and annual audits, and meet ongoing G&A expenses.
Management receives 0.5% of the fair market value (Net Asset Value) of the assets
under management, paid monthly. The fair market value will be determined by the
GP every year.
Management will also receive a 50% share of any amount above the 8% preferred
return.
We believe the management fee structure is reasonable.
Redemption: Redemptions are not allowed in the first year. Redemptions between year one
and two will have 15% taken off the fair value of the units. Redemptions between year two
and three will have 10% taken off the fair value. Also, the LP has no obligation to redeem
more than 5% of the total units in a year.
Financial
Analysis and
Projections
Our financial projections are based on the assumption that the LP acquires Project A. Due to
the highly speculative, and capital intensive nature of the Reef project, we do not
believe the Reef project is a good fit for the LP’s portfolio. Moreover, Reef Resources’
current financial situation makes the project even more vulnerable.
The following assumptions were used in our projections:
-
-
four wells per year of Project A are put back into production; cost per well - $50k
(management estimate - $38k)
the percentage of oil production is maintained at 15% of the total production
for conservatism, and as Project A does not have an independent reserve report, we have
not assumed any new wells
used the same commodity price forecasts as presented earlier in this report
operating cost of 44% of revenues (historical average)
pipeline + operating fee increases at 2% p.a.
the trailer fee of 2% p.a. will be paid for 100% of the capital raised (management
indicated that the trailer fee will only be paid to agents who meet the target raise set by
the GP)
15 year production life
The expected Internal Rate of Return (IRR) for investors is 9.26%. Note that our production
growth assumptions are very conservative. The following tables show our cash flow
projections.
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Page 24
The sensitivity of the IRR to commodity prices is shown below.
Oil Prices
Gas Prices


9.3%
-30%
-20%
-10%
0%
10%
20%
30%
-30%
5.80%
6.24%
6.66%
7.08%
7.49%
7.89%
8.29%
-20%
6.60%
7.01%
7.43%
7.83%
8.23%
8.62%
9.01%
-10%
7.36%
7.77%
8.16%
8.56%
8.94%
9.32%
9.70%
0%
8.10%
8.49%
8.88%
9.26%
9.64%
10.01%
10.38%
10%
8.82%
9.20%
9.58%
9.95%
10.31%
10.68%
11.03%
20%
9.51%
9.89%
10.25%
10.61%
10.97%
11.33%
11.68%
30%
10.19%
10.55%
10.91%
11.26%
11.62%
11.96%
12.30%
0% indicates our base-case assumptions
10% indicates a 10% change in our base-case assumptions
The sensitivity of the IRR to changes in the production years is shown below.
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Page 25
Risks
Years of
Production
IRR
10
3.47%
15
9.26%
20
11.24%
25
12.14%
The following risks, though not exhaustive, may cause our estimates to differ from actual
results:
 Revenues and profitability of the company depend heavily on future oil and natural gas
prices.
 The strength of the portfolio will depend heavily on the ability to acquire and develop
attractive projects.
 Production and development risks.
 The LP has yet to complete any acquisition.
 Our cash flow projections are highly sensitive to our production assumptions.
 The LP has to significantly increase production from current levels in order to realize the
true potential of the identified projects.
 There is no independent reserve report on Project A.
 As the LP intends to hold projects in the U.S., investors will be exposed to exchange rate
risks.
 The Reef project is highly speculative and capital intensive.
 The offering has no minimum amount; capital raised might not be sufficient to complete
even one acquisition.
 Redemption options are limited.
Rating
Overall, we believe Project A is a good fit for the portfolio. The project offers the LP an
opportunity to hold a producing, stable cash flowing project, with low to medium risks. The
expected IRR of 9.26% (net of management fees, sales fees, operating costs), we believe, is
appealing considering the risks associated with the project. However, the Reef project, if
acquired, will considerably increase the risk profile of the LP’s portfolio.
We are assigning an overall rating of 3, with a risk rating of 4, with the assumption
that management will not follow through with its plans to acquire a working interest in
Reef.
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Page 26
FRC Rating
Base-Case IRR
N/A
Rating
3
Risk
4
Our risk rating of 4 is based on the fact that this is a blind pool with no minimum offering
amount, and the LP has yet to identify/acquire assets. Readers should note that our overall
rating will drop if management decides to proceed with the Reef project.
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Page 27
Fundamental Research Corp. Rating Scale:
Rating – 1: Excellent Return to Risk Ratio
Rating – 2: Very Good Return to Risk Ratio
Rating – 3: Good Return to Risk Ratio
Rating – 4: Average Return to Risk Ratio
Rating – 5: Weak Return to Risk Ratio
Rating – 6: Very Weak Return to Risk Ratio
Rating – 7: Poor Return to Risk Ratio
A “+” indicates the rating is in the top third of the category, A “-“ indicates the lower third and no “+” or “-“ indicates the middle third of the category.
Fundamental Research Corp. Risk Rating Scale:
1 (Low Risk)
2 (Below Average Risk)
3 (Average Risk)
4 (Speculative)
5 (Highly Speculative)
Rating - 1
Rating - 2
Rating - 3
Rating - 4
Rating - 5
Rating - 6
Rating - 7
Suspended
0%
23%
52%
5%
5%
0%
0%
14%
FRC Distribution of Ratings
Risk - 1
Risk - 2
Risk - 3
Risk - 4
Risk - 5
Suspended
0%
0%
32%
46%
2%
20%
Disclaimers and Disclosure
The opinions expressed in this report are the true opinions of the analyst about this company and industry. Any “forward looking statements” are our best estimates and opinions based upon
information that was provided and that we believe to be correct, but we have not independently verified with respect to truth or correctness. There is no guarantee that our forecasts will
materialize. Actual results will likely vary. The analyst and Fundamental Research Corp. “FRC” does not own any shares of the subject company, does not make a market or offer shares for
sale of the subject company, and does not have any investment banking business with the subject company. Fees have been paid by the issuer to FRC to issue this report. The purpose of the
fee is to subsidize the high costs of research and monitoring. FRC takes steps to ensure independence including setting fees in advance and utilizing analysts who must abide by CFA Institute
Code of Ethics and Standards of Professional Conduct. Additionally, analysts may not trade in any security under coverage. Our full editorial control of all research, timing of release of the
reports, and release of liability for negative reports are protected contractually. Distribution procedure: our reports are distributed first to our web-based subscribers on the date shown on this
report then made available to delayed access users through various other channels for a limited time. The performance of FRC’s research is ranked by Investars. Full rankings and are available
at www.investars.com.
To subscribe for real-time access to research, visit http://www.researchfrc.com/subscription.htm for subscription options. This report contains "forward looking" statements. Forward-looking
statements regarding the Company and/or stock’s performance inherently involve risks and uncertainties that could cause actual results to differ from such forward-looking statements. Factors
that would cause or contribute to such differences include, but are not limited to, continued acceptance of the Company's products/services in the marketplace; acceptance in the marketplace of
the Company's new product lines/services; competitive factors; new product/service introductions by others; technological changes; dependence on suppliers; systematic market risks and other
risks discussed in the Company's periodic report filings, including interim reports, annual reports, and annual information forms filed with the various securities regulators. By making these
forward looking statements, Fundamental Research Corp. and the analyst/author of this report undertakes no obligation to update these statements for revisions or changes after the date of this
report. A report initiating coverage will most often be updated quarterly while a report issuing a rating may have no further or less frequent updates because the subject company is likely to be
in earlier stages where nothing material may occur quarter to quarter.
Fundamental Research Corp DOES NOT MAKE ANY WARRANTIES, EXPRESSED OR IMPLIED, AS TO RESULTS TO BE OBTAINED FROM USING THIS INFORMATION AND
MAKES NO EXPRESS OR IMPLIED WARRANTIES OR FITNESS FOR A PARTICULAR USE. ANYONE USING THIS REPORT ASSUMES FULL RESPONSIBILITY FOR
WHATEVER RESULTS THEY OBTAIN FROM WHATEVER USE THE INFORMATION WAS PUT TO.
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INVEST. WHETHER A STOCK SHOULD BE INCLUDED IN A PORTFOLIO DEPENDS ON ONE’S RISK TOLERANCE, OBJECTIVES, SITUATION, RETURN ON OTHER ASSETS,
ETC. ONLY YOUR INVESTMENT ADVISOR WHO KNOWS YOUR UNIQUE CIRCUMSTANCES CAN MAKE A PROPER RECOMMENDATION AS TO THE MERIT OF ANY
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not intended as being a complete description of the company, industry, securities or developments referred to in the material. Any forecasts contained in this report were independently prepared
unless otherwise stated, and HAVE NOT BEEN endorsed by the Management of the company which is the subject of this report. Additional information is available upon request. THIS
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and/or the analyst, when quoting information from this report.
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such use would be contrary to local regulations or which would require any registration requirement within such jurisdiction
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Permex Petroleum Limited Partnership

Transcription

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