ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Our History and Organization
PetroShare Corp. ("we," "our," or "us") is an independent oil and natural gas company that was organized to investigate, acquire and develop
crude oil and natural gas properties in the Rocky Mountain or mid-continent region of the United States and produce oil, liquids and/or natural gas from those properties. We were incorporated under
the laws of the State of Colorado on September 4, 2012.
All
of our properties are located in Colorado. As of March 30, 2017, we had an interest in 95 gross (33.66 net) productive wells and 26,258 gross (7,967 net) acres of oil
and gas properties. As of December 31, 2016, we were producing hydrocarbons at the rate of approximately 294 BOE/D. At December 31, 2016, we had estimated 740 MBOE of proved developed
reserves and 5,568 MBOE of proved undeveloped reserves.
Our
strategy is to focus on acquiring and developing crude oil and natural gas properties in the DenverJulesburg Basin, or the DJ Basin, in northeast Colorado. We have
narrowed our current operating and leasing activities to those areas we consider as geo-mechanical sweet spots, including the southern-Wattenberg area of the DJ Basin, which we refer to as the
Southern Core area. We elected to concentrate on the Southern Core due to the high quality of hydrocarbon-bearing rock and the production from other, nearby wells. The Southern Core area contains the
Niobrara and Codell geologic formations, which tend to yield oil-weighted production that remains economic in the prevailing commodity price environment.
As
of March 30, 2017, all of the horizontal wells in which we have an interest are operated by independent third parties, although we expect to drill our first operated wells in
the Southern Core in mid-2017. We expect to have less than a 50% interest in any wells as we seek to conserve our capital and diversify risk.
We
completed our initial public offering ("IPO") in November 2015 at $1.00 per share and received gross proceeds of $4,174,000. During 2016, we raised additional capital in a private
placement and
established a new line of credit. We used the initial IPO proceeds and borrowing to acquire additional acreage in the Southern Core, participate as a non-operator in several drilling programs and pay
our general and administrative expenses. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for more information.
Our
executive and administrative offices are currently located at 9635 Maroon Circle, Suite 400, Englewood, CO 80112 and we maintain a website at www.petrosharecorp.com. We
became a reporting company under the Securities Exchange Act of 1934, as amended, or the Exchange Act, in February 2015, when a registration statement for our common stock was declared effective. You
may access and read our public filings through the U.S. Securities and Exchange Commission's, or the SEC's, website at www.sec.gov and on our website.
As
discussed below, during 2016 we acquired additional oil and gas assets, initiated operations on our own property base and participated as a non-operator with other oil and gas
companies active in the Southern Core. Our goal is to diversify risk and minimize capital exposure to development, drilling and completion costs. In any drilling, we expect that our retained working
interest will be determined based upon factors such as well costs and geologic and engineering risk.
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Table of Contents
Our Competitive Strengths
We believe we are well-positioned to capitalize on current conditions in the oil and natural gas industry as a result of the following
competitive strengths, in addition to the location of our properties.
Our Management
Our Chief Executive Officer, Stephen Foley, has over 15 years of experience as a real estate developer in Colorado, with an extensive
background in surface development in the areas in which we have acquired acreage. Our President, Frederick Witsell, and Chief Operating Officer,
William Lloyd, bring a long history in Colorado and depth of experience in the industry to our company. Mr. Witsell has over 36 years of experience in several facets of the oil and gas
industry, including prospect development, conventional and horizontal drilling and completion operations, project management, gathering and compression systems and marketing and risk management.
Mr. Lloyd also has over 36 years of experience in the industry, serving in engineering, management and senior leadership capacities. In addition to their experience, these individuals
bring valuable relationships with other recognized industry participants which have, and we believe will continue to, provide opportunities to our company.
Our Strategic Partnerships
Through relationships cultivated by our executive officers, we have formalized agreements with business partners that have, and we believe will
continue to, contribute significantly to our growth. In November 2014, we entered into a services agreement with Kingdom Resources, LLC ("Kingdom"), a lease broker in the Southern Core area
affiliated with a surface and mineral interest owner, through which Kingdom agreed to assist us in the identification of oil and gas leases and other property interests and resources. Our relationship
with Kingdom led to our first significant acquisition in the Southern Core in 2015. We continued to develop our relationship with Kingdom during 2016 as Kingdom and its affiliates assisted us in
several smaller acquisitions of oil and gas assets. We believe our relationship with Kingdom and its services will be pivotal as we seek additional acreage and surface access to drill sites.
In
May 2015, we entered into a participation agreement with Providence Energy Operators, LLC ("Providence"). Providence is an affiliate of Providence Energy Corp., a
privately-held multi-million dollar acquirer of oil and gas properties throughout the United States, and which currently owns and/or manages over two million net acres in 37 states with royalty or
working interests in over 10,000 wells. As discussed elsewhere in this report, Providence is also our primary lender through which we currently maintain a $5.0 million line of credit, which we
refer to as our initial line of credit, and the beneficial owner of 13.7% of our common stock. The participation agreement grants Providence the option to acquire up to a 50% interest and participate
in any oil and gas development on acreage we obtain through our Kingdom services agreement and any other leases we acquire within an area of mutual interest (AMI) in Adams County, Colorado. To date,
Providence has exercised its option under the participation agreement or otherwise participated or agreed to participate in all of our acreage acquisitions in the Southern Core.
We
believe our relationship with Providence is instrumental to our success. In addition to providing funding for our acquisition and development strategy, the relationship provides us
access to Providence's oil and gas expertise. We believe our relationship with Providence is strong, as evidenced by its participation in our Southern Core prospects, our borrowing arrangement, and
Providence's holdings in our common stock.
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Recent Developments
During 2016, we took important steps to improve our business by making several lease acquisitions, participating as a non-operator in the
drilling of 17 gross (2.9 net) horizontal wells in the Wattenberg, and completing the permitting process of our first planned operated wells in the Southern Core. Our leasing activities have been
focused on areas in northern Adams County and southern Weld County, Colorado in the Southern Core area. During 2016, we added 18,846 gross (6,936 net) acres and 93 gross (32.91 net) productive wells
to our inventory.
Supplemental Line of Credit
On October 13, 2016, we entered into a revolving line of credit facility agreement, which we refer to as the supplemental line of credit,
with Providence Energy Partners III, LP ("PEP III"). PEP III is an affiliate of Providence by virtue of having some common management personnel. The supplemental line of credit permitted us to
borrow up to $10.0 million to pay costs associated with our acquisition and development of oil and gas properties in the Wattenberg Field.
As
amended on March 30, 2017, we agreed to repay $3,552,500 in outstanding principal not later than April 13, 2017 and not to borrow additional funds in exchange for
PEP III extending the maturity date of the supplemental line of credit until June 13, 2017. As of the date of this report, we have $7.1 million plus accrued interest of
approximately $191,000 outstanding against our supplemental line of credit.
PDC Asset Acquisition
On June 30, 2016, we completed the acquisition of certain oil and gas assets from PDC Energy, Inc. ("PDC"). Simultaneous with the
closing of the acquisition, Providence exercised its option pursuant to the participation agreement and acquired 50% of our interest in the PDC assets. The PDC assets we acquired include oil and gas
leases covering approximately 3,652 gross (1,410 net) acres of lands located in Adams County, Colorado. All of the acreage is currently held by production. We also acquired from PDC an interest in 43
productive wells, 34 of which are currently producing from vertical wellbores and 9 of which are shut-in. There are an additional 30 wells that are either permitted or in the process of being
permitted on this acreage, all of which would be horizontal if and when drilled. Much of the acreage we acquired from PDC is within our Todd Creek Farms prospect in the Southern Core; the remainder is
located throughout Adams County and is prospective for formations other than the Niobrara and Codell. The PDC asset acquisition was effective April 1, 2016.
The
net purchase price for the PDC assets to our interest was $2,260,890 following allowances, post-closing adjustments and Providence's acquisition from us of its 50% interest in the
PDC assets. We paid the purchase price using a draw on our initial line of credit.
Following
the acquisition, we became the substituted operator for all of the wells we acquired from PDC. The acquisition allows us spacing to drill up to 30 additional horizontal wells,
including 8 currently-approved horizontal well permits on the Corcilius pad. Whether we ultimately drill any wells on the acreage is dependent on many of the factors discussed in this report,
including receipt of adequate working capital, current and projected prices of oil and gas, identification of compelling drill locations, and obtaining all required permits. We do not expect to drill
any wells on the acreage we acquired from PDC until at least 2018.
Crimson Asset Acquisition
On December 22, 2016, we completed the acquisition of certain oil and gas assets from Crimson Exploration Operating, Inc.
("Crimson"). Simultaneous with the closing of the acquisition, Providence acquired 50% of our interest in the Crimson assets. The Crimson assets we acquired include oil and
3
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gas
leases covering lands located in Adams, Arapahoe, Elbert, and Weld Counties, Colorado, covering approximately 15,514 gross (5,609 net) acres and an interest in approximately 38 oil and gas wells,
which includes 32 wells that are currently producing from vertical wellbores.
Following
a reconciliation of certain suspense and inventory accounts, the net purchase price to our interest for the Crimson assets was $2,538,945, which we paid on December 22,
2016, and which included an earnest money deposit of $500,000 that we paid on November 21, 2016. We paid the purchase price for the Crimson assets using a draw on our supplemental line of
credit.
Morning Gun Acquisition
On February 23, 2017, we entered into a purchase and sale agreement with Morning Gun Exploration LLC ("Morning Gun"), pursuant to
which we agreed to acquire certain oil and gas assets from Morning Gun, including oil and gas leases covering approximately 5,879 gross (2,930 net) acres on lands located in Adams and Weld Counties,
Colorado. Morning Gun reserved to itself all rights that exist below 50 feet above the top of the uppermost J Sand formation for any lands located in Township 7 North, Range 63 West in Weld County,
Colorado. Closing of the acquisition is scheduled for not later than April 3, 2017 and is subject to customary conditions, including environmental and title diligence. Providence has agreed to
acquire 50% of our interest in the Morning Gun assets simultaneous with the closing. If completed, the acquisition will be effective January 1, 2017.
The
total purchase price payable for the foregoing assets is $2,582,500, or $1,291,250 to our retained interest, which is subject to adjustment prior to the closing due to any title or
environmental defects. We paid 10% of the purchase price, or $258,250, as a deposit at the time of executing the purchase agreement. We have agreed with Morning Gun that we will pay $832,500 of the
purchase price through the issuance to Morning Gun of 450,000 shares of our common stock, valued at $1.85 per share. The remainder of the purchase price, less the deposit, is due and payable at
closing.
Non-Operated Drilling Participation
During 2016 and the first quarter of 2017, we participated in the drilling and completion of 17 gross (2.9 net) horizontal wells in the
Southern Core. All of these wells are being operated by operators with an established track record in the Wattenberg. Our most significant non-operated interest is the Jacobucci pad. In connection
with an acquisition in April 2016, we acquired the seller's right to participate in, and agreed to pay all of the seller's costs and expenses related to, the drilling, completion, equipping and
producing of 14 mid-range lateral horizontal wells on the Jacobucci pad operated by PDC. We are participating in the Jacobucci pad drilling program as a non-operator working interest partner. PDC
commenced drilling operations in April 2016 and as of the date of this report ten of the Jacobucci wells are on production and the remaining four wells are undergoing the final stages of completion
after being fracture stimulated.
We
also participated in one standard-range Codell horizontal well in which we have an approximate 11% interest. This well has been completed and is currently producing at a rate of
approximately 49 BOE/D net to our interest. We anticipate the additional wells in this proposed 11-well program will be drilled during the fourth quarter of 2017 or first half of 2018 depending on
improved pipeline access.
We
also participated as a non-operator in 2 extended-range Niobrara horizontal wells in which we have an approximate 15% interest. Both of these wells have been completed and are
currently producing at the combined rate of approximately 1,500 BOE/D (194 BOE/D net to our interest). We have an approximate 11.5% working interest in 12 additional undeveloped horizontal well sites
in this program, but as of the date of this report, none of those wells have been drilled. Subject to commodity prices and access to adequate gas gathering infrastructure, we anticipate the operator
will drill five additional wells in 2017 with the remaining wells to be drilled in 2018.
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Table of Contents
Oil and Gas Properties
DJ Basin and Wattenberg (Southern Core Area)
Our area of focus, the Southern Core area, is located within the Wattenberg Field, which is a part of the DJ Basin. Discovered in 1970, and
historically a gas field, the Wattenberg Field, which covers more than 2,000 square miles, now produces both crude oil and natural gas primarily from the Niobrara and Codell formations. The DJ Basin
generally extends from the Denver metropolitan area throughout northeast Colorado into parts of Wyoming, Nebraska, and Kansas. The majority of the DJ Basin lies in Weld County, but reaches into
Adams, Arapahoe, Boulder, Broomfield, Denver, and Larimer Counties.
Our
primary target in the Southern Core is the multiple benches in the Niobrara formation. We also intend to target the Codell formation in the Southern Core. The Niobrara formation is a
calcareous chalk, shale, and limestone rock formation varying from approximately 200 to 1,500 feet in thickness and extending from Canada to New Mexico, but the vast majority of the oil and natural
gas concentration is in Colorado and Wyoming. The formation generally slopes downward from east to west, from Kansas to western Colorado, from hydrocarbon producing depths of approximately
1,000 feet to 12,000 feet below the surface. The Codell formation is an oil and natural gas producing tight sandstone formation generally found at depths of approximately 7,000 to 8,000 feet
below the surface and located at the base of the NiobraraFort Hays limestone member.
The
Southern Core area covers areas in northwest Adams County and southwest Weld County. The Southern Core area saw significant development through vertical drilling in the preceding
decades, but modern horizontal drilling is relatively new for the area. The "northern core Wattenberg," located south of Greeley in west-central Weld County, has been the primary focus of oil and gas
producers for the past seven years. We believe the Southern Core area provides us compelling economics in the current price environment.
We
currently possess an inventory of approximately 164 gross potential horizontal drilling locations within our Southern Core area including 69 locations that are fully permitted or in
the final permitting stages. The remaining locations would result from drill spacing units expected to be established under applicable industry rules. We have not included certain of these potential
horizontal drilling locations in our proved undeveloped reserves because we have not yet established a development plan for those locations in accordance with SEC rules.
Todd Creek Farms
Within our Southern Core focus area, our primary prospect is Todd Creek Farms, which is located in northwest Adams County, Colorado. As of the
date of this report, we have final permits for 22 operated wells in the Todd Creek Farms prospect. Our first operated drilling program at Todd Creek Farms is expected to be the Shook pad on
which we have 14 wells permitted. Our working interest in the wells proposed on the Shook pad averages approximately 35%, and can reach up to 50% (approximately 40% net revenue interest) depending on
our success at acquiring additional working interest in the block. We have begun construction of the Shook pad location and plan to commence drilling operations in mid-2017. Our current plan is to
drill 14 and complete up to 7 initial wells on our Shook pad. Our intention is to bid-out the drilling and completion services to qualified contractors that already have equipment and crews active in
the Wattenberg Field.
South Brighton
Our South Brighton prospect is east of our Todd Creek Farms prospect and sits in northern Adams County and southern Weld County, Colorado. We
acquired the majority of this acreage in our transaction with Crimson during 2016. We have leaseholds encompassing 3,058 gross (1,166 net) acres
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in
the South Brighton prospect. We have eight (8) pending permits for extended length (2 mile) horizontal wells targeting the Niobrara and the Codell formations.
Runway
Our Runway prospect area is east of Todd Creek Farms and South Brighton and lies within Adams County, Colorado east of the Denver International
Airport. Assuming completion of
the Morning Gun acquisition, we will have leaseholds encompassing 13,835 gross (5,095 net) acres in the Runway prospect.
Buck Peak
We acquired our Buck Peak prospect acreage located in Moffat County on the western slope of Colorado during 2013. Our current interest at Buck
Peak is 5,276 gross (352 net) acres, which is where we drilled two wells in 2013 and 2014. We are the operator of the wells pursuant to participation and operating agreements with our working interest
partners. As of December 31, 2016, we had generated only nominal revenue related to the sale of oil from Buck Peak. Management has determined that further exploration at Buck Peak is currently
uneconomic due to the downturn in oil prices over the past two years and the nominal production rate of the initial two wells. The majority of our interest in Buck Peak is held by production and we
will maintain the rest of our interests in the prospect area through the terms of the existing leases. We intend to continue monitoring oil prices and the production rates of our wells, as well as
other development in the area, to determine further activities in that area.
Productive Wells
The following table sets forth the number of productive oil and natural gas wells in which we owned a working interest as of March 30,
2017:
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|
|
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|
|
|
|
|
|
|
|
|
|
Productive Wells(1)(2)
|
|
|
|
Crude Oil
|
|
Natural Gas(3)
|
|
Total(3)
|
|
Location
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|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Southern Core
|
|
|
34.00
|
|
|
9.30
|
|
|
59.00
|
|
|
23.61
|
|
|
93.00
|
|
|
32.91
|
|
Buck Peak
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|
|
2.00
|
|
|
0.75
|
|
|
|
|
|
|
|
|
2.00
|
|
|
0.75
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total productive wells
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|
|
36.00
|
|
|
10.05
|
|
|
59.00
|
|
|
23.61
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|
|
95.00
|
|
|
33.66
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|
-
(1)
-
Includes
a total of 13 gross (2.18 net) wells in which we are participating as a non-operator.
-
(2)
-
Does
not include 11 producing wells in which we now hold a working interest. PDC non-consented to the drilling and completion of the wells. We may receive revenue
from the production of those wells after the consenting interest holders receive a return equal to a multiple of their costs and expenses.
-
(3)
-
Includes
33 gross wells that are currently shut-in.
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Table of Contents
Developed and Undeveloped Acreage
The following table shows our developed and undeveloped acreage as of March 30, 2017:
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Acreage
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|
|
|
|
|
Developed
|
|
Undeveloped(1)
|
|
Total
|
|
Location
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Southern Core
|
|
|
19,244
|
|
|
7,108
|
|
|
1,738
|
|
|
507
|
|
|
20,982
|
|
|
7,615
|
|
Buck Peak
|
|
|
671
|
|
|
252
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|
|
4,605
|
|
|
100
|
|
|
5,276
|
|
|
352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total acreage
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|
|
19,915
|
|
|
7,360
|
|
|
6,343
|
|
|
607
|
|
|
26,258
|
|
|
7,967
|
|
|
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|
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|
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|
|
-
(1)
-
Undeveloped
acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial
quantities of oil and natural gas regardless of whether the leasehold interest is classified as containing proved reserves.
Following
industry standard, we generally acquire oil and gas leases without warranty of title, except as to claims made by, through, or under the transferor. Accordingly, we conduct due
diligence as to title prior to acquiring properties, but we cannot guarantee that there will not be losses resulting from title defects. We believe the title to our properties is good and defensible
in accordance with industry standards, subject to such exceptions that, in our opinion, are not so material as to detract from the use or value of our properties. Title to our properties generally
carry encumbrances, such as royalties, overriding royalties, contractual obligations, liens, easements, and other matters that commonly affect real property, all of which are customary in the oil and
gas industry. We intend to acquire additional leases by lease sale, farm-in, or purchase.
A
majority of our Buck Peak leaseholds are held under "paid-up" fee leases and a majority of our Wattenberg leaseholds are held by production. Leases that are held by production
generally remain in force so long as oil or gas is produced from the well on the particular lease. Leased acres that are not held by production may require annual rental payments to maintain the lease
until the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage. At the time oil or gas is produced from wells drilled on the leased acreage,
the lease is considered to be held by production. Unless production is established within the area covering our undeveloped acreage, the leases for such acreage eventually will expire. Our leases not
held by production are scheduled to expire, including potential extensions, from 2017 until 2020. If our leases expire in an area we intend to explore, we or our working interest partners will have to
negotiate the price and terms of lease renewals with the lessors. The cost to renew such leases may increase significantly and we may not be able to renew the lease on commercially reasonable terms,
or at all.
The
following table shows the calendar years during which our leases not currently held by production will expire unless a productive oil or gas well is drilled:
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Leased Acres
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|
|
|
|
|
|
Expiration of
Lease
|
|
|
|
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Gross
|
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Net
|
|
|
|
|
|
3,840
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|
|
50
|
|
|
2017
|
|
|
|
|
|
369
|
|
|
33
|
|
|
2018
|
|
|
|
|
|
1,740
|
|
|
377
|
|
|
2019
|
|
|
|
|
|
393
|
|
|
147
|
|
|
2020
|
|
|
7
Table of Contents
Drilling Results
The following table sets forth information with respect to the number of wells either drilled by us or in which we participated as a
non-operator during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the
number of productive wells drilled, quantities of reserves found or economic value.
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For the Year Ended December 31,
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2016(1)
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2015
|
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2014
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Gross
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Net
|
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Gross
|
|
Net
|
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Gross
|
|
Net
|
|
Development Wells
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Productive
|
|
|
17.0
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|
|
2.9
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Dry
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Exploratory Wells
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Productive
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
2.0
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|
|
0.5
|
|
Dry
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Total Wells
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|
|
|
|
|
|
|
2.0
|
|
|
0.5
|
|
Productive
|
|
|
17.0
|
|
|
2.9
|
|
|
|
|
|
|
|
|
2.0
|
|
|
0.5
|
|
Dry
|
|
|
|
|
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|
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|
|
|
|
-
(1)
-
All
non-operated wells.
Sales Data
The following table shows the net sales volumes, average sales prices, and average production costs for the periods presented:
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|
Years Ended December 31,
|
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2016
|
|
2015
|
|
2014
|
|
Sales volumes
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|
|
|
|
|
|
|
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|
|
Oil (Bbls)
|
|
|
4,902.7
|
|
|
36.6
|
|
|
91.5
|
|
Gas (Mcf)
|
|
|
26,058.6
|
|
|
|
|
|
|
|
NGLs (Bbls)
|
|
|
1,510.5
|
|
|
|
|
|
|
|
BOE
|
|
|
10,756.3
|
|
|
36.6
|
|
|
91.5
|
|
Average sales price
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
|
48.91
|
|
|
36.29
|
|
|
80.81
|
|
Gas ($/Mcf)
|
|
|
2.62
|
|
|
|
|
|
|
|
NGLs ($/Bbl)
|
|
|
16.55
|
|
|
|
|
|
|
|
BOE
|
|
|
30.97
|
|
|
36.29
|
|
|
80.81
|
|
Average production cost per BOE ($)
|
|
|
19.21
|
|
|
871.82
|
|
|
225.08
|
|
Oil Natural Gas and NGL Data
Proved Reserves
Estimation of Proved Reserves
Under SEC rules, proved reserves are those quantities of oil, natural gas and NGL, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs and under existing economic conditions, operating methods and government
regulationsprior
to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
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certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a
"high degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2016 (we had no proved reserves as of December 31, 2015) were estimated
using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas
and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of
estimating the quantities of recoverable oil, natural gas and NGL reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad
categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be
used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production
performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to
similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either
volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for
our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.
To
estimate economically recoverable proved reserves and related future net cash flows Cawley Gillespie & Associates, Inc. ("Cawley Gillespie") considered many factors and
assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing
requirements and forecasts of future production rates.
Under
SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous
reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has
been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish
reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with
consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and
operating expense data.
Summary of Oil, Natural Gas and NGL Reserves
The table below presents summary information with respect to the estimates of our net proved oil and gas reserves at December 31, 2016,
all of which are located in Colorado, based on a reserve report prepared by Cawley Gillespie.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(MBbls)
|
|
Natural Gas
(MMcf)
|
|
Natural Gas
Liquids
(MBbls)
|
|
MBOE
|
|
Proved Developed Producing
|
|
|
136.4
|
|
|
1,269.9
|
|
|
95.2
|
|
|
443.2
|
|
Proved Developed Non-Producing
|
|
|
123.9
|
|
|
519.0
|
|
|
86.5
|
|
|
296.9
|
|
Proved Undeveloped Reserves
|
|
|
2,500.9
|
|
|
9,704.0
|
|
|
1,449.5
|
|
|
5,567.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved Reserves
|
|
|
2,761.2
|
|
|
11,492.9
|
|
|
1,631.2
|
|
|
6,307.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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At December 31, 2016, we had estimated total proved reserves of 6,307.8 MBOE, consisting of 2,761.2 MBbls of crude oil, 11,492.9 MMcf of natural
gas, and 1,631.2 MBbls of natural gas liquids. Our proved reserves include only those amounts that we reasonably expect to recover in the future from known oil and gas reservoirs under existing
economic and operating conditions, at current prices and costs, under existing regulatory practices, and with existing technology and anticipated capital resources. Accordingly, any changes in prices,
operating and development costs, regulations, technology, or other factors could significantly increase or decrease estimates of our proved reserves. Estimates of volumes of proved reserves are
presented in MBbls for crude oil and MMcf for natural gas at the official temperature and pressure bases of the areas in which the gas reserves are located.
Proved Undeveloped Reserves
At December 31, 2016, we had 5,568 MBOE of proved undeveloped reserves. We have included in our proved undeveloped reserves only those
locations for which we have established a
development plan and believe we can drill and complete within five years of the date of this report considering our existing and anticipated capital resources. We also have included certain
non-operated properties the operator of which has informed of us of planned development within the next five years and in which we have plans to participate.
To
date, no proved undeveloped reserves have been converted into proved developed reserves.
Independent Reserve Engineers
Our proved reserves estimate as of December 31, 2016 shown herein has been independently prepared by Cawley Gillespie, which was founded
in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Zane Meekins was the technical person within Cawley Gillespie
primarily responsible for preparing the estimates shown herein. Mr. Meekins has been practicing consulting petroleum engineering at Cawley Gillespie since 1989. Mr. Meekins is a
Registered Professional Engineer in the State of Texas (License No. 71055) and has approximately 30 years of practical experience in petroleum engineering, with approximately
28 years in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a B.S. in Petroleum Engineering. Mr. Meekins meets or exceeds the education,
training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The
report of Cawley Gillespie, dated March 23, 2017, which contains further discussions of the reserve estimates and evaluations prepared by Cawley Gillespie, as well as the
qualifications of Cawley Gillespie's technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this report.
Internal Controls Over Reserve Estimation Process
Our President, Frederick J. Witsell, and our Chief Operating Officer, William B. Lloyd, work closely with our independent reserve engineers to
ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process and are the technical persons within our company primarily
responsible for overseeing the preparation of our reserves estimates. Each of Mr. Witsell and Mr. Lloyd has over 36 years of industry experience. Both have evaluated numerous
properties throughout the United States with an emphasis on Colorado oil and natural gas production, as well as conventional and unconventional reservoirs, operations, reservoir development and
property evaluation. Mr. Witsell holds a B.S. in Geology, an M.B.A. in
Energy Management, and is an active member in the Society of Petroleum Engineers, American Association of Petroleum Geologists, and the Rocky Mountain Association of Geologists. Mr. Lloyd holds
a B.S. in Petroleum Engineering.
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During
relevant time periods, Mr. Witsell and Mr. Lloyd meet with representatives of our independent reserve engineers to review properties and discuss methods and
assumptions used in preparation of the proved reserves estimates. We do not have a formal committee specifically designated to review our reserve reporting and our reserves estimation process. A
preliminary copy of the reserve report was reviewed by Mr. Witsell with representatives of our independent reserve engineers and internal technical staff.
Regulatory Environment
The production and sale of oil and gas is subject to various federal, state, and local governmental regulations, which may be changed from time
to time in response to economic or political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of
wells, noise, unitization and pooling of properties, setbacks, taxation and environmental protection. Many laws and regulations govern the location of wells, the method of drilling and casing wells,
the plugging and abandoning of wells, the restoration of properties upon which wells are drilled, temporary storage tank operations, air emissions from flaring, compression, the construction and use
of access roads, and the disposal of fluids used in connection with operations. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate
of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Changes in these regulations could have a material adverse effect on our company.
The
failure to comply with any such laws and regulations can result in substantial penalties. In addition, the effect of all these laws and regulations may limit the amount of oil and
gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Although we believe we are in substantial compliance with current applicable laws and
regulations relating to our oil and natural gas operations, we are unable to predict the future cost or impact of complying with such laws and regulations because such laws and regulations are
frequently amended or reinterpreted.
As
an oil and gas operator, we are responsible for obtaining all permits and government permission necessary to drill the wells and develop our interests. We must obtain permits for any
new well sites and wells that are drilled.
In
February 2013, the Colorado Oil and Gas Conservation Commission ("COGCC") passed extensive rule changes providing perhaps the most stringent oil and gas regulations in the country,
including statewide requirements, commonly known as setbacks, from wells and production facilities, to various structures. In March 2017, the Colorado House of Representatives passed a bill that would
amend setback requirements and require oil and gas drilling facilities and wells to be located at least 1,000 feet from school property lines. The current rules measure the 1,000 foot setback from
school buildings rather than the property line. In cases in which schools are located on large parcels of property, such a change could materially decrease the areas in which drilling is possible in
Colorado. It is currently unknown whether the bill will receive sufficient support from the Colorado Senate and the Governor to become law.
In
February 2014, the Colorado Department of Public Health and Environment's Air Quality Control Commission, or AQCC, finalized regulations imposing stringent new requirements relating
to air emissions from oil and gas facilities in Colorado. The new rules impose significantly more stringent control, monitoring, recordkeeping, and reporting requirements than those required under
comparable federal rules. In addition, as part of the rule, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector.
On
January 25, 2016, the COGCC approved new rules enhancing local government participation in locating and planning for large scale oil and gas operations. The COGCC defined large
scale facilities
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as
(i) any location that proposes eight new horizontal, directional, or vertical wells, or (ii) cumulative hydrocarbon storage capacity of 4,000 Bbls or more, which are located within an
urban mitigation area as defined by COGCC rules. The new COGCC rules also include additional notice and consultation requirements for operators when planning such large scale facilities. We do not
believe that these new large scale facilities regulations impacted us during the year ended December 31, 2016 because our current well sites do not meet the definitions of large scale
facilities and we did not have more than eight wells or storage capacity of greater than 4,000 Bbls prior to the end of the current fiscal year.
In
March 2017, the Colorado Court of Appeals held that Colorado oil and gas regulations require the COGCC to grant permits for new oil wells on the condition that requisite levels of
environmental and public safety are met based on a determination by an independent third party. The Court of Appeals' holding invalidates the COGCC's prior balancing inquiry, which weighed interests
in oil and gas development against environmental and public safety factors. The case has been remanded to the lower
court for further findings. It remains unclear what impact this holding will have on the oil and gas industry.
Hydraulic Fracturing
We operate primarily in the Wattenberg Field of the DJ Basin where the rock formations are typically tight, and it is a common practice to
utilize hydraulic fracturing to allow for or increase hydrocarbon production. Hydraulic fracturing involves the process of injecting substances such as water, sand and additives (some proprietary)
under pressure into a targeted subsurface formation to create pores and fractures, thus creating a passageway for the release of oil and gas. Hydraulic fracturing is a technique that we likely will
employ extensively in future wells that we may drill and complete.
We
expect to outsource all hydraulic fracturing services to service providers with significant experience, and which we deem to be competent and responsible. Our service providers supply
all personnel, equipment, and materials needed to perform each stimulation, including the chemical mixtures that might be injected into our wells. We require our service companies to carry insurance
covering incidents that could occur in connection with their activities. In addition to the drilling permit that we are required to obtain and the notice of intent that we provide the appropriate
regulatory authorities, our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the relevant geographic location. We have not had any
incidents, citations, or lawsuits relating to any environmental issues resulting from hydraulic fracturing, and we are not presently aware of any such matters.
In
recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities have adopted or are considering new requirements for
this process. To the extent that these requirements increase our costs or restrict our development activities, our business and prospects may be adversely affected.
The
EPA has asserted that the Safe Drinking Water Act ("SDWA") applies to hydraulic fracturing involving diesel fuel, and in February 2014, it issued final guidance on this subject. The
guidance defines the term "diesel fuel," describes the permitting requirements that apply under SDWA for the underground injection of diesel fuel in hydraulic fracturing, and makes recommendations for
permit writers. Although the guidance applies only in those states, excluding Colorado, where the EPA directly implements the Underground Injection Control Class II program, it could encourage
state regulatory authorities to adopt permitting and other requirements for hydraulic fracturing. In addition, from time to time, Congress has considered legislation that would provide for broader
federal regulation of hydraulic fracturing under the SDWA. If such legislation were enacted, hydraulic fracturing operations could be required to meet additional federal permitting and financial
assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and provide for additional public disclosure of the chemicals used
in the fracturing process.
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The
EPA is also conducting a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft assessment of the potential impacts to
drinking water resources from hydraulic fracturing for public comment and peer review. The assessment concluded that while there are mechanisms by which hydraulic fracturing can impact drinking water
resources, there was no evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States. The EPA's science advisory board subsequently
questioned several elements and conclusions in the EPA's draft assessment. In December 2016, the EPA released the final report on impacts from hydraulic fracturing activities on drinking water,
concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified some factors that could influence these impacts.
Federal
agencies have also adopted or are considering additional regulation of hydraulic fracturing. On March 26, 2016, the U.S. Occupational Safety and Health Administration
("OSHA") issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to
sand in hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act ("TSCA") to obtain data on chemical substances and mixtures
used in hydraulic fracturing. In March 2015, the Bureau of Land Management ("BLM") issued a new rule regulating hydraulic fracturing activities involving federal and tribal lands and minerals,
including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water.
In
Colorado, the primary regulator is the COGCC, which has adopted regulations regarding chemical disclosure, pressure monitoring, prior agency notice, emission reduction practices, and
offset well setbacks with respect to hydraulic fracturing operations and may in the future adopt additional requirements for this purpose. As part of these requirements, operators must report all
chemicals used in hydraulically fracturing a well to a publicly searchable registry website developed and maintained by the Ground Water Protection Council and the Interstate Oil and Gas Compact
Commission.
Apart
from these ongoing federal and state initiatives, local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and gas operations. Some
local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of
agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently
prohibiting hydraulic fracturing. Since that time, however, local district courts have struck down the ordinances for certain of those Colorado cities, and such decisions were upheld by the Colorado
Supreme Court in May 2016. Nevertheless, there is a continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing activities and oil
and gas operations within their respective jurisdictions.
During
2014, opponents of hydraulic fracturing also sought statewide ballot initiatives that would have restricted oil and gas development in Colorado by, among other things,
significantly increasing the setback between oil and natural gas wells and occupied buildings. These initiatives were withdrawn from the November 2014 ballot in return for the creation of a task force
to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities.
During
2016, opponents of hydraulic fracturing again advanced various options for ballot initiatives restricting oil and gas development in Colorado. Proponents of two such initiatives
attempted to qualify the initiatives to appear on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a minimum distance of 2,500 feet between wells
and any occupied structures or "areas of special concern." If implemented, this proposal would have made the vast majority of the surface area of the state ineligible for drilling, including
substantially all of our planned future drilling locations. The second proposal would have amended the state constitution to give local
13
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governmental
authorities the ability to regulate, or to ban, oil and gas exploration, development, and production activities within their boundaries notwithstanding state rules and approvals to the
contrary. If implemented, this proposal could have resulted in us becoming subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans
on our activities in various jurisdictions. In August 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the
proposals had failed to collect enough valid signatures to have the proposals included on the ballot. However, similar proposals may be made in the future. Because all of our operations and reserves
are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the
outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves.
Adams County USR Process
On March 22, 2016, the Adams County Board of County Commissioners approved amendments to the county's oil and gas regulatory process,
which ended a temporary drilling moratorium previously imposed. The new regulations include an enhanced administrative review process for operators that share a Memorandum of Understanding, or MOU,
with Adams County, including a site-specific review of any oil and gas permit application. The regulations also require compliance with the USR approval process for oil and gas facilities governed by
an MOU between the
operator and Adams County. This approval process includes increased notice and submittal requirements. The USR process is designed to consist of a six-week administrative review of the application by
the county and appropriate agencies. The application can be approved, approved with conditions, denied or referred to the Board of County Commissioners for a public hearing. If denied, the applicant
can appeal to the Board of County Commissioners.
In
March 2016, we submitted a USR application for our Shook pad to Adams County, which was approved by the county in September 2016. The above newly-enacted regulations in Adams County
and any additional regulations that may result in the future may delay or prevent our drilling activities and increase our costs of development and production and limit the quantity of oil and gas
that we can economically produce.
Joint Operating Agreements
We are registered with the COGCC as an operator of oil and natural gas wells and properties in the State of Colorado and have posted the
appropriate bonds to support our activities. We have entered into operating agreements with our working interest partners that stipulate, among other things, that each partner is responsible for
paying its proportionate share of costs and expenses in connection with the wells we operate. As operator, we are an independent contractor not subject to the control or direction of our other working
interest partners except as to the type of operation to be undertaken as provided in the operating agreement. Further, we are responsible for hiring employees or contractors to conduct operations,
taking custody of funds for the account of all working interest partners, keeping books and records relating to operations, and filing operational notices, reports or applications required to be filed
with governmental bodies having jurisdiction over operations. Our liability to the other working interest partners for losses sustained or liabilities incurred are limited to losses incurred as a
result of our gross negligence or willful misconduct.
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Competition
We encounter significant competition from numerous other oil and gas companies in all areas of operations, including drilling and marketing oil
and natural gas; obtaining desirable oil and natural gas leases; obtaining drilling, pumping and other services; attracting and retaining qualified employees; and obtaining capital. International
developments may influence other companies to increase their domestic crude oil and natural gas exploration. Competition among companies for favorable prospects can be expected to continue and we
anticipate that the cost of acquiring properties will increase in the future. Most of our competitors possess larger staffs and greater financial resources than we do, which may enable them to
identify and acquire desirable producing properties and drilling prospects more economically. Our ability to acquire additional properties and to explore for oil and natural gas prospects in the
future depends upon our ability to conduct our operations, evaluate and select suitable properties, and consummate transactions in this highly competitive environment.
The
oil and gas industry is characterized by rapid and significant technological advancements and introduction of new products and services using new technologies. If one or more of the
technologies we use now or in the future become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and
cash flows could be materially adversely affected.
Market for Our Products
Currently, all of our produced oil and gas is sold under a variety of month to month contracts with local marketing companies. We have no
long-term marketing contract commitments at this time. The availability of a ready market for our oil and gas depends upon numerous factors beyond our control, including the extent of domestic
production and importation of oil and gas, the relative status of the domestic and international economies, the proximity of our properties to gas pipeline systems, the capacity of those systems, the
marketing of other competitive fuels, fluctuations in seasonal demand, and governmental regulation of production, refining, transportation, and pricing of oil, gas, and other fuels.
Employees
We currently have seven employees, including our Chief Executive Officer, President, and Chief Operating Officer. Our Chief Financial Officer
serves in his role as an independent contractor. We also engage a number of other independent contractors and consultants to supplement the services of our employees, including land services, geologic
mapping, reservoir and facilities engineers, drilling contractors, attorneys, and accountants.
Company Facilities
Our executive and administrative offices are currently located at 9635 Maroon Circle, Suite 400, Englewood, Colorado 80112, where
we lease approximately 4,223 square feet at a rate of $8,446 per month.
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ITEM 1A. RISK FACTORS
This report, including Management's Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking
statements that may be affected by several risk factors. The following information summarizes the material risks known to us as of the date of filing this report:
Risks Relating To Our Company
Since we are a new business with a limited operating history, investors have no basis to evaluate our ability
to operate profitability.
We were incorporated in September 2012 and our activities to date have been limited to organizational efforts, raising capital, developing our
business plan, assembling an initial lease inventory, participating as a non-operator in several drilling programs and limited drilling efforts. We face all of the risks commonly encountered by other
new businesses, including the lack of an established operating history, need for additional capital and personnel, and competition. Our business may not be successful or we may never operate
profitably. We may not be able to effectively manage the demands required of a new business in our industry, such that we may be unable to successfully implement our business plan or achieve
profitability.
We have limited revenue and cash flow and are dependent on improving operations, along with receipt of
additional working capital, to fund continued development and implementation of our business plan, and our failure to obtain this capital may cause the partial or total loss of your investment.
Our cash flow through December 31, 2016 is inadequate to fully implement our business plan. Since significant amounts of capital are
required for companies to participate in the business of exploration for and development of oil and natural gas resources, we are dependent on improving our cash flow and revenue, as well as receipt
of additional working capital, to fund continued development and implementation of our business plan. In addition to funds required for the development of our existing acreage, we will require capital
to acquire additional acreage as well as pay our administrative expenses, including salary and rent. Adverse developments in our business or general economic conditions may require us to raise
additional financing at prices or on terms that are disadvantageous to existing shareholders. We may not be able to obtain additional capital at all and may be forced to curtail or cease our
operations. We will continue to rely on equity or debt financing and the sale of working interests to finance operations until such time, if ever, that we generate sufficient cash flow. The inability
to obtain necessary financing may adversely impact our ability to develop our properties and to expand our business operations.
Our use of debt financing could have a material adverse effect on our financial condition.
We are subject to the risks normally associated with debt financing, including the risk that our cash flow will be insufficient to meet required
principal and interest payments and the long-term risk that we will be unable to refinance our existing indebtedness, or that the terms of such refinancing will not be as favorable as the terms of
existing indebtedness. If our debt cannot be paid, refinanced or extended, we may be required to divest our assets or file for bankruptcy. Further, if prevailing interest rates or other factors at the
time of a refinancing result in higher interest rates or other restrictive financial covenants upon the refinancing, then such refinancing would adversely affect our cash flow and funds available for
operation and development of our assets and properties.
We
are also subject to financial covenants under our existing debt instruments. Should we fail to comply with the covenants in our existing debt instruments, then we would not only be in
breach under the applicable debt instruments but we would also likely be unable to borrow any further amounts under our other debt instruments, which could adversely affect our ability to fund
operations. We may incur in the future indebtedness that bears interest at variable rates. Thus, if market interest rates
16
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increase,
so would our interest expense, which could reduce our cash flow and impair our ability to fund our operations.
We are highly leveraged and any default by us may cause us to forfeit all or a portion of our properties.
As of December 31, 2016, we had outstanding debt in excess of $14.0 million, approximately half of which is due in 2017. This
amount increased subsequent to year end by the sale of an additional $8.0 million of convertible notes in a private placement. If we are unable to repay any of this debt on a timely basis, we
may be forced to forfeit all or a portion of our properties.
Of
the total debt outstanding at December 31, 2016, approximately $12.1 million is secured by liens on our property. Of that amount, $3.55 million is due in April
2017 and $3.55 million is due in June 2017. Our ability to repay our lines of credit is dependent on our ability to generate sufficient revenue from operations or obtain cash from other
sources. If we are unable to repay the short term indebtedness or otherwise default under either of our lines of credit or our other indebtedness, the lender may foreclose on our assets. As a result,
we may not be able to develop as much property as we presently expect.
We have historically incurred losses and may not achieve future profitability.
We have incurred losses from operations during our history in the oil and natural gas business. We had an accumulated deficit of approximately
$9.9 million as of December 31, 2016. Our ability to be profitable in the future will depend on successfully addressing our near-term capital needs and implementing our acquisition,
development and production activities, all of which are subject to many risks beyond our control. Even if we become profitable on an annual basis, our profitability may not be sustainable or increase
on a periodic basis.
Our estimates of oil and gas reserves involve inherent uncertainty, which could materially affect the
quantity and value of our reported reserves and our financial condition.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and cash flows attributable to such reserves,
including factors beyond our reserve engineers' control. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner.
The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and gas prices,
expenditures for future development and exploration activities, engineering and geological interpretations and judgment. In addition, accurately estimating reserves in shale formations, such as the
Niobrara and Codell, can be even more difficult than estimating reserves in more traditional hydrocarbon-bearing formations given the complexities of the projected decline curves and economics of
shale wells. Additionally, "probable" and "possible" reserve estimates are estimates of unproved reserves and may be misunderstood or seen as misleading to investors that are not experts in the oil or
natural gas industry.
As
such, investors should not place undue reliance on these estimates contained in this report. Reserves and future cash flows may be subject to material downward or upward revisions,
based upon production history, development and exploration activities and prices of oil and gas. In addition, different reserve engineers may make different estimates of reserves and cash flows based
on the same available data. Due to our smaller volume of reserves compared to our competitors, revisions in reserve estimate and future cash flows have a greater chance of being material to us.
Our Southern Core area assets may be less valuable to us than expected.
We have made several oil and gas acquisitions in the Southern Core area since January 1, 2016. Most significantly, effective
April 1, 2016, we acquired the PDC assets, and, effective December 1,
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2016,
we acquired the Crimson assets. Much of the acreage we acquired from PDC and Crimson is within our Southern Core focus areas, while the remainder of the acreage is located in outlying areas of
Adams, Weld and Broomfield Counties and is prospective for formations other than the Niobrara and Codell.
The
value of our Southern Core area assets, including the PDC and Crimson assets, is based in large part on our ability to develop the properties and increase proven and probable
reserves. This, in turn, requires us to make accurate estimates of our capital needs to implement and continue a development program for those properties, to obtain that capital and to successfully
drill the wells. We may not be able to obtain the capital necessary to develop these properties or our development efforts may not be successful. If we are unable to obtain the necessary capital or
successfully develop these properties, the price of our stock may decline and you may lose some or all of your investment.
The due diligence undertaken in connection with the acquisition of the PDC assets, the Crimson assets and
other recent acquisitions may not have revealed all relevant considerations or liabilities related to those assets, which could have a material adverse effect on our financial condition or results of
operations.
In addition to our acquisition of the PDC and Crimson assets, we have also entered into several asset purchase agreements to date, acquiring
certain oil and gas assets and surface rights and easements on lands located within the Southern Core. The due diligence undertaken by us in connection with the acquisition of the PDC assets, the
Crimson assets or other properties may not have revealed all relevant facts that may be necessary to evaluate such acquisitions. The information provided to us in connection with our diligence may
have been incomplete or inaccurate. As part of that process, we have also made subjective judgments regarding the results of operations and prospects of the PDC assets, the Crimson assets and other
assets. If the due diligence investigation has failed to correctly identify material issues and liabilities that may be present, such as title defects or environmental problems, we may incur
substantial impairment charges or other losses in the future. In addition, we may be subject to significant, previously undisclosed liabilities that were not identified during the due diligence
process and which may have a material adverse effect on our financial condition or results of operations.
Our lines of credit contain various covenants which, if not complied with, could accelerate our repayment
obligations, thereby materially and adversely affecting our liquidity, financial condition, and ability to remain in business.
The agreements governing our lines of credit require us to comply with certain financial and operational covenants so long as the loans are
outstanding. These covenants generally prohibit us without the lenders' consent from, among other things, incurring additional indebtedness or making loans to any third party, other than trade debt
incurred in the ordinary course of business and selling, leasing, or otherwise disposing of any material assets in excess of $100,000 in any calendar year. Our continued compliance with these
covenants depends on many factors and could be impacted by current or future economic conditions, and therefore we may not be able to continue to comply with these covenants. Failure to comply with
these covenants could result in a default which, if we were unable to obtain a waiver from our lenders, could accelerate our repayment obligations under the lines of credit and thereby have a material
adverse impact on our liquidity, financial condition, and ability to remain in business.
We have granted Providence the option to participate in certain of our acreage acquisitions, which may reduce
our ownership of certain assets and any resulting earnings, and which could have a material adverse effect on our financial condition or results of operations.
On May 13, 2015, we entered into a participation agreement with Providence. Under the terms of the participation agreement, we assigned
an undivided 50% interest to our right, title and interest in
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and
to our then existing leases in our Todd Creek Farms prospect. Providence agreed to pay its pro rata share of lease acquisition expenses and the expenses necessary to maintain the leases in full
force and effect. In addition, the participation agreement designates an area of mutual interest, or AMI, pursuant to which if either party acquires any lease in the AMI territory on or before
May 13, 2018, then the non-acquiring party shall have the right to acquire its proportionate 50% interest in and to such AMI leases. The AMI covers an area in Adams County, Colorado containing
all of Township 1 South, Range 67 West, consisting of approximately 23,100 gross acres, with an additional one-mile border around the defined AMI area, plus any other mutually agreeable areas. To
date, Providence has exercised its option to participate in all of our acreage acquisitions in the Southern Core area, including our recent acquisition of the PDC assets.
So
long as the participation agreement remains in full force and effect, any future acquisition of AMI leases will require us, upon Providence's exercise of its option, to assign a 50%
interest in and to the AMI leases. As a result, we may never wholly-own such AMI leases and any earnings we may achieve as a result of such acquisition will have to be shared proportionally with
Providence. Such division of earnings could have a material adverse effect on our financial condition or results of operations.
We have limited management and staff and will be dependent upon partnering arrangements and third-party
service providers.
We currently have seven employees, including our Chief Executive Officer, President, and Chief Operating Officer. Our Chief Financial Officer
serves in his role as an independent contractor. We also leverage the services of other independent consultants and contractors to perform various professional services, including engineering, oil and
gas well planning and
supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and
prospect leasing. Our dependence on third-party consultants and service providers creates a number of risks, including but not limited to:
-
-
the possibility that such third parties may not be available to us as and when needed; and
-
-
the risk that we may not be able to properly control the timing and quality of work conducted with respect to its projects.
If
we experience significant delays in obtaining the services of such third parties or they perform poorly, our results of operations and stock price could be materially adversely
affected.
Competition in the oil and natural gas industry is intense and many of our competitors have resources that
are substantially greater than ours.
Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore
for and produce oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay
more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional
properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In
addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and
future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our
operations and our profitability.
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Our substantial investment in a limited number of prospects and lack of diversification increases the risk to
investors that we may not be profitable.
Our investment in the Southern Core and the capital required to pay our share of drilling and production costs on the property increases the
risk that the operation of our business may not be profitable, as we will not be able to spread the risk of investment and operation over a number of different assets until we become profitable or
receive additional investment. If our prospects are not economic our business may suffer and you may lose all or part of your investment.
We are concentrated in one geographic area, which increases our exposure to many of the risks enumerated
herein.
Currently, our operations are concentrated in Colorado, an area that experiences severe weather events, including tornadoes, flooding and
storms. Our information systems and administrative and management processes could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged
our facilities. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business. In addition, operating in a concentrated area increases the
potential impact that many of the risks stated herein may have upon our ability to perform. For example, we have greater exposure to regulatory actions impacting Colorado, natural disasters in the
geographic area, competition for equipment, services and materials available in the area and access to infrastructure and markets. Although Moffatt, Adams and Weld Counties in Colorado have
well-established oilfield infrastructures, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells therein caused by transportation capacity
constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures
for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more
pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due
to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our
results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial
condition and results of operations.
If our Southern Core properties are not commercially productive of oil or natural gas, any funds spent on
exploration and production may be lost.
A significant portion of our current capital investment is tied up in our Southern Core properties. If our properties are not economic, all of
the funds that we have invested or will invest in the future will be lost. Any drilling program in the Southern Core likely will involve multiple horizontal wells, which are expensive to drill. Our
business plan is dependent on, among other things, developing sufficient reserves to generate cash flow and provide a return on investment. If we are not successful in producing economically viable
amounts of oil and/or gas from our properties, our business may suffer and you may lose all or part of your investment. In addition, the failure to produce commercially may make it more difficult for
us to raise additional funds in the form of additional sale of our equity securities or working interests in other property in which we may acquire an interest.
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We may have difficulty managing our growth and our results of operation may suffer as a result.
We have amassed a large number of leases, are participating in several non-operated drilling programs, and have added a number of producing and
non-producing wells to our inventory since the beginning of 2016 compared to our interest in 2015 and we may have difficulty managing those assets as we continue to grow our company. The integration
of operations from the PDC assets and the Crimson assets and management of our non-operated properties will require the dedication of significant management resources, which may temporarily distract
their attention from the day-to-day business of our company. The process of integrating those assets with our existing assets may cause an interruption of, or a loss of momentum in, our business and
could have an adverse effect on our operating results for an indeterminate period of time. We may also need to hire and train additional personnel to help manage our assets, which will require
additional financial resources and management attention. The failure to successfully integrate any such acquisitions or participation, to identify and retain key personnel, and to successfully manage
the challenges presented by the integration process may adversely affect our business.
Our ability to sell any production and/or receive market prices for our production may be adversely affected
by a lack of transportation, capacity constraints and interruptions.
The marketability of any production from any of our properties depends in part upon the availability, proximity and capacity of third-party
refineries, natural gas gathering systems and processing facilities. We expect to deliver much of the oil and natural gas produced from our properties through trucking services and pipelines that we
do not own. The availability of delivery capacity in these pipelines is in part dependent on the market price for oil and natural gas, as higher prices will attract additional production, which in
turn will take up capacity in these systems. The lack of availability or capacity of these systems and facilities could reduce the price offered for any production or result in the shut-in of
producing wells or the delay or discontinuance of development plans for properties.
Our business is substantially dependent on our senior executive officers and the loss of service of any of
these individuals would adversely affect our business.
Stephen Foley is our Chief Executive Officer and is responsible for overseeing our business, developing our business plan and the strategic
vision of our company. Frederick Witsell is our President and is responsible for identifying and valuing acquisition opportunities as well as managing our integrated business operations. Paul
Maniscalco is our Chief Financial Officer and is responsible for the oversight of our day-to-day accounting operations as well as our periodic financial reporting. William Lloyd is our Chief Operating
Officer and is responsible for the management of engineering and operating activities including coordination of permitting, drilling and completion activities. Each of these individuals is critical to
the perceived success of our business. The loss of service of any of these individuals would adversely affect our business, as we have very limited personnel and expect to rely on contractors for a
majority of services that we require. We may not be able to replace any of such individuals, or if so, on terms that were acceptable to our company. We have no key man life insurance on any of these
individuals.
Colorado law and our Articles of Incorporation may protect our directors from certain types of lawsuits at
the expense of the shareholders.
The laws of the State of Colorado provide that directors of a corporation shall not be liable to the corporation or its shareholders for
monetary damages for all but limited types of conduct. Our Articles of Incorporation permit us to indemnify our directors and officers against all damages incurred in connection with our business to
the fullest extent provided or allowed by law. The exculpation
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provisions
may have the effect of preventing shareholders from recovering damages against our directors caused by their negligence, poor judgment or other circumstances.
Risks Relating to the Energy Production and/or Distribution Industry
Oil and natural gas exploration and development are affected by fluctuations in oil and natural gas prices,
and low prices could have a material adverse effect on the future of our business.
If development efforts are successful in identifying economic amounts of oil and natural gas, our future success will depend largely on the
prices received for any oil or natural gas production. Prices received also will affect the amount of future cash flow available for capital expenditures and may affect the ability to raise additional
capital. Lower prices affect the amount of oil and natural gas that can be commercially produced from reserves either discovered or acquired. Lower prices may also make it uneconomical to drill in
certain areas.
The
prices for oil and natural gas have seen a steep decline since 2014 and may fluctuate widely in the future. The price of West Texas Intermediate (WTI) Crude Oil, as quoted on
NYMEX, has ranged from a high of $54.45 per barrel to a low of $35.70 per barrel in the twelve months ended March 30, 2017, and the price of Henry Hub Natural Gas, as quoted on NYMEX, has
ranged from a high of $3.93 per MMBtu to a low of $1.90 per MMBtu for the same period. On March 30, 2017, the price of WTI was $50.40 per barrel and Henry Hub Natural gas was $3.19 per MMBtu.
The
following table shows the high and low quarterly price per barrel of West Texas Intermediate (WTI) Crude Oil for the years 2014, 2015, and 2016, as quoted on NYMEX:
|
|
|
|
|
|
|
|
Period
|
|
High
|
|
Low
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
105.22
|
|
$
|
91.24
|
|
Second Quarter
|
|
|
107.73
|
|
|
98.74
|
|
Third Quarter
|
|
|
106.09
|
|
|
90.43
|
|
Fourth Quarter
|
|
|
92.96
|
|
|
52.44
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
54.56
|
|
$
|
43.46
|
|
Second Quarter
|
|
|
61.43
|
|
|
49.14
|
|
Third Quarter
|
|
|
56.96
|
|
|
38.24
|
|
Fourth Quarter
|
|
|
49.63
|
|
|
34.73
|
|
Year Ending December 31, 2016
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
41.90
|
|
$
|
26.05
|
|
Second Quarter
|
|
|
51.23
|
|
|
35.70
|
|
Third Quarter
|
|
|
49.01
|
|
|
39.51
|
|
Fourth Quarter
|
|
|
54.06
|
|
|
43.32
|
|
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The
following table shows the high and low quarterly price per MMBtu of NYMEX Henry Hub natural gas for the years 2014, 2015, and 2016, as quoted on NYMEX:
|
|
|
|
|
|
|
|
Period
|
|
High
|
|
Low
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
6.15
|
|
$
|
4.01
|
|
Second Quarter
|
|
|
4.83
|
|
|
4.28
|
|
Third Quarter
|
|
|
4.46
|
|
|
3.75
|
|
Fourth Quarter
|
|
|
4.49
|
|
|
2.89
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
3.23
|
|
$
|
2.58
|
|
Second Quarter
|
|
|
3.02
|
|
|
2.49
|
|
Third Quarter
|
|
|
2.93
|
|
|
2.52
|
|
Fourth Quarter
|
|
|
2.54
|
|
|
1.76
|
|
Year Ending December 31, 2016
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
2.47
|
|
$
|
1.64
|
|
Second Quarter
|
|
|
2.92
|
|
|
1.90
|
|
Third Quarter
|
|
|
3.06
|
|
|
2.55
|
|
Fourth Quarter
|
|
|
3.93
|
|
|
2.62
|
|
Factors
that can cause price fluctuations include:
-
-
the level of consumer product demand;
-
-
the domestic and foreign supply of oil and natural gas;
-
-
consumer perception and the availability of alternative energy sources;
-
-
refinery capacity;
-
-
domestic and foreign governmental regulations;
-
-
actions by other producers, including the Organization of the Petroleum Exporting Countries (OPEC);
-
-
political and ethnic conflicts in oil and natural gas producing regions;
-
-
the price of foreign imports; and
-
-
overall economic conditions.
The cost of oil and natural gas exploration is extremely volatile and may adversely affect our operations.
The costs of oil and natural gas exploration, such as the costs of drilling rigs, casing, cement, and pumps, and the fuel and parts necessary to
keep the rigs and pumps operating and the costs of the oil field service crews have been volatile over the past few years in direct proportion to the amount of ongoing oil and natural gas exploration.
As with most other companies involved in resource exploration and development, we may be adversely affected by future increases in the costs of conducting exploration, development and resource
extraction that may not be fully offset by increases in the price received on sales of oil or natural gas.
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If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant
reductions in price. Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant
fluctuations in our profitability.
We may use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to
reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases. Hedging
transactions also involve the risk that the counterparty may be unable to satisfy its obligations. Alternatively, in the event that we choose not to hedge, our exposure to reductions in oil and
natural gas prices by purchasing futures and by using other hedging strategies, we may be subject to significant reduction in prices which could have a material negative impact on our profitability.
We identified locations scheduled to be drilled over several years, making them susceptible to uncertainties
that could materially alter the occurrence or timing of their drilling.
Our management team has identified drilling locations in our operating areas scheduled over a multi-year period. Our ability to drill and
develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of
risks, costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this report as well as, to some degree,
the results of our drilling activities with respect to our established drilling locations. Due to these uncertainties, we do not know if the drilling locations we have identified will be drilled
within our expected timeframe or at all. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition and
results of operations.
We have limited control over activities on properties we do not operate.
We are not, or will not be, the operator on some of our properties and, as a result, our ability to exercise influence over the operations of
these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and any future projects, our limited ability to influence
operations and associated costs or control the risks, and our access to required capital could materially and adversely affect the realization of our targeted returns on capital in drilling or
acquisition activities. The success and timing of our drilling and
development activities on properties operated by others therefore depends upon a number of factors, including:
-
-
timing and amount of capital expenditures;
-
-
the operator's expertise and financial resources;
-
-
the rate of production of reserves, if any;
-
-
approval of other participants in drilling wells; and
-
-
selection of technology.
As
a result, our ability to exercise influence over the operations of some of our current or future properties is and may be limited.
Financial difficulties encountered by our oil and natural gas purchasers, third party operators or other
third parties could decrease cash flow from operations and adversely affect exploration and development activities.
We expect to derive essentially all our revenue from the sale of our oil and natural gas to unaffiliated third party purchasers, including
independent marketing companies and mid-stream
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companies.
Any delays in payments from such purchasers caused by financial problems encountered by them would have an immediate negative effect on our results of operations and cash flows. Liquidity
and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a
project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a working interest owner, we could be required to pay
the working interest owner's share of the project costs. We may not be able to obtain the capital necessary to fund these contingencies.
We may face difficulties in securing and operating under authorizations and permits to drill, complete or
operate our wells.
The recent growth in oil and gas exploration in the United States has drawn intense scrutiny from environmental and community interest groups,
regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations that may make it difficult or impossible to obtain
permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwise make oil and gas exploration more costly or difficult than in other countries.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could
adversely affect our ability to execute exploration and development plans within the established budget and on a timely basis.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect development and
exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or
results of operations.
Our operations are subject to health, safety and environmental laws and regulations which may expose us to
significant costs and liabilities and which may not be covered by insurance.
Our oil and natural gas exploration is subject to stringent and complex federal, state and local laws and regulations governing health and
safety aspects of our operations, the discharge of materials into the environment and the protection of the environment. These laws and regulations impose on our operations numerous requirements,
including the obligation to obtain a permit before conducting drilling activities; restrictions on the types, quantities and concentration of materials that may be released into the environment;
limitations or prohibitions of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; specific health and safety criteria to protect workers; and the
responsibility for cleaning up any pollution resulting from operations. Numerous governmental authorities such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies
have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing
some or all of our proposed operations; and delays in granting permits and cancellation of leases.
Under
certain environmental laws and regulations, we may be liable regardless of whether we were at fault for the full cost of removing or remediating contamination, even when multiple
parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant
liabilities that could have a material adverse effect on our financial condition or results of operations and which may not be covered by insurance. Aside from government agencies, the owners of
properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are expected
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to
be taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, collect penalties for violations or obtain
damages for any related personal injury or property damage. Some sites are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that
contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling,
emission, waste management or cleanup requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our own
results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
Federal, state, and local legislative and regulatory initiatives relating to oil and gas production,
including hydraulic fracturing, as well as government reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production
and/or ability to book future reserves.
Hydraulic fracturing involves the injection of water, sand or other proppants, and chemical additives under pressure into a targeted subsurface
formation. The water and pressure create fractures in the rock formations, which are held open by the proppant, enabling the oil or natural gas to flow to the wellbore. The process is typically
regulated by state oil and natural gas commissions; however, the U.S. Environmental Protection Agency, or EPA, asserted federal regulatory authority over certain hydraulic-fracturing activities
involving diesel fuel under the Safe Drinking Water Act. In addition, the Colorado Oil and Gas Conservation Commission, or the COGCC, has adopted (and other states have adopted or are considering
adopting) regulations that impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Further, on February 23, 2014, Colorado's Air
Quality Control Commission fully adopted EPA's Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution; adopted corresponding revisions to its emissions
reporting and permitting framework; and adopted complimentary oil and gas control measures. These regulations will affect our operations, increase our costs of exploration and production and limit the
quantity of oil and natural gas that we can economically produce to the extent that we use hydraulic fracturing.
Effective
March 22, 2016, Adams County adopted new amendments to the county's oil and gas regulatory process. The new regulations include an enhanced administrative review
process, which may increase our costs or delay our drilling program.
In
the event that additional regulations or legal restrictions at the federal, state or local level are adopted related to oil and gas production, hydraulic fracturing or other
development activities in the areas in which we currently or in the future plan to operate, we may incur additional costs to comply with such requirements that may be significant in nature, and also
could become subject to additional permitting and siting requirements and cause us to experience added delays or curtailment in the pursuit of exploration, development, or production activities.
Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and
larger operating staff.
Legislative and regulatory initiatives related to global warming and climate change could have an adverse
effect on our operations and the demand for oil and natural gas.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases," or GHG, present an endangerment to
public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the
EPA has begun adopting
and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act.
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The
EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the
other of which regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large
greenhouse gas emission sources in the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities.
On
March 10, 2016, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will
"begin with a formal process (
i.e.
, an Information Collection Request) to require companies operating existing oil and gas sources to provide
information to assist in the development of comprehensive regulations to reduce methane emissions." On May 12, 2016, the EPA issued regulations (effective August 2, 2016) that build on
the existing New Source Performance Standards, or the NSPS OOOO, promulgated by the EPA in 2012, as amended in 2013 and 2014. The regulations directly regulate methane and volatile organic compound,
or VOC, emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells,
pneumatic pumps, and certain equipment and components at gas well sites and compressor stations, will be covered for the first time.
In
addition, the U.S. Congress has from time to time considered adopting legislation to reduce GHG emissions and almost one-half of the states have already taken legal measures to reduce
GHG emissions, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these GHG cap and trade programs work by requiring major
sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances
available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
The
adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control
systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby
reduce demand for, the oil, natural gas liquids, and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business,
financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth's atmosphere may produce climate
changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other
climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
We may not be able to keep pace with technological developments in the industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and
services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at
substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the
future allow them to implement new technologies before we are in a position to do so. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or
at an acceptable cost. If one or more of the technologies used now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, the
business, financial condition, and results of operations could be materially adversely affected.
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We may incur losses as a result of title deficiencies.
We own working and revenue interests in oil and natural gas leasehold interests. The existence of a material title deficiency can render a lease
worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, in many instances, we forego the
expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is
customary in our industry, we rely upon the judgment of oil and natural gas lease brokers, in-house landmen or independent landmen who perform the field work in examining records in the appropriate
governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We do not always perform curative work to correct deficiencies in the
marketability of the title to us. In cases involving serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. We may be
subject to litigation from time to time as a result of title issues.
The oil and natural gas business involves many operating risks that can cause substantial losses.
The oil and natural gas business involves a variety of operating risks, including:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of underground natural gas, oil or formation water;
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natural disasters;
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pipe and cement failures;
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casing collapses;
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embedded oilfield drilling and service tools;
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abnormal pressure formations; and
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environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.
If
any of these events occur, we could incur substantial losses as a result of:
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injury or loss of life;
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severe damage to and destruction of property, natural resources or equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations; or
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repairs necessary to resume operations.
If
we were to experience any of these problems, it could affect well bores, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct
operations. We may be affected by any of these events more than larger companies, since we have limited working capital. We currently have general liability insurance with a combined single limit per
occurrence of not less than $1.0 million for bodily injury and property damage and a combined occurrence limit of
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$2.0 million,
an excess umbrella liability policy for up to $5.0 million, and control of well insurance with limits of $5.0 million for any one occurrence. For other risks,
however, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully
insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect operations and/or our financial condition. Moreover, we may not be able to
maintain adequate insurance in the future at rates considered reasonable.
Risks Related to Our Common Stock
The price of our common stock may be volatile or may decline and you may have difficulty reselling any shares
of our common stock.
Our common stock currently trades on the OTCQB Marketplace with limited daily trading volume. The market price of our common stock may fluctuate
significantly in response to numerous factors, many of which are beyond our control, including:
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the limited trading market in our common stock;
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commodity prices in general, and the price of oil in particular;
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the success of our development efforts;
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failure to successfully implement our business plan;
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failure to meet our revenue or profit goals or operating budget;
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decline in demand for our common stock;
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sales of additional amounts of common stock;
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downward revisions in securities analysts' estimates or changes in general market conditions;
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investor perception of our industry or our prospects; and
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general economic trends.
In
addition, stock markets have experienced extreme price and volume fluctuations and the market prices of securities have been highly volatile. These fluctuations are often unrelated to
operating performance and may adversely affect the market price of our common stock. As a result, investors may be unable to resell their shares at a fair price.
The sale of a substantial number of shares of our common stock may cause the price of our common stock to
decline.
We registered 14,026,003 shares of our common stock, including 9,426,003 shares of common stock for sale by our shareholders, and 460,000 shares
of common stock underlying broker warrants, in connection with our initial public offering in 2015. Our common stock is currently thinly-traded and it is likely that market sales of large amounts of
common stock (or the potential for those sales even if they do not actually occur) could cause the market price of our common stock to decline, which may make it difficult to sell our common stock in
the future at a time and price which we deem reasonable or appropriate and may also cause you to lose all or a part of your investment.
A small number of existing shareholders own a significant amount of our common stock, which could limit your
ability to influence the outcome of any shareholder vote.
Our executive officers, directors, and certain beneficial owners beneficially own approximately 40.9% of our common stock as of the date of this
report. Under our Articles of Incorporation and
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Colorado
law, the vote of a majority of the shares outstanding is generally required to approve most shareholder action. As a result, these individuals will strongly influence the outcome of
shareholder votes for the foreseeable future, including votes concerning the election of directors, amendments to our Articles of Incorporation or proposed mergers or other significant corporate
transactions. We have no existing agreements or plans for mergers or other corporate transactions that would require a shareholder vote at this time. However, shareholders should be aware that they
may have limited ability to influence the outcome of any vote in the future.
Our financial statements may not be comparable to other public companies.
We have elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b) of the
JOBS Act. This election allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to
private companies. As a result of this election, if the Public Company Accounting Oversight Board adopts new or revised accounting standards and we decide to delay adoption of such changes, our
financial statements may not be comparable to companies that comply with public company effective dates and the price of our common stock may be adversely affected.
We are not required to obtain an opinion from our independent registered public accounting firm on the
effectiveness of our internal controls over financial reporting under Section 404(b) of the Sarbanes-Oxley Act of 2002 until we are no longer an emerging growth company.
For so long as we remain an emerging growth company as defined in the JOBS Act, we intend to take advantage of certain exemptions from various
reporting requirements that are applicable to public companies that are not emerging growth companies, including, but not limited to, not being required to obtain the auditor attestation of our
assessment of our internal controls. Once we are no longer an emerging growth company or, if prior to such date, we opt to no longer take advantage of the applicable exemption, we will be required to
include an opinion from our independent registered public accounting firm on the effectiveness of our internal controls over financial reporting. We will remain an "emerging growth company" until the
earliest to occur of (1) the last day of the fiscal year during which our total annual revenues equal or exceed $1 billion (subject to adjustment for inflation), (2) the last day
of the fiscal year during which occurs the fifth anniversary of our initial public offering, (3) the date on which we have, during the previous three-year period, issued more than
$1 billion in non-convertible debt, or (4) the date on which we are deemed a "large accelerated filer" under the Securities Exchange Act of 1934, as amended, or the Exchange Act. Once we
are no longer an emerging growth company, compliance with Section 404(b) will be costly.
Since our common stock is not presently nor expected to be listed on a national securities exchange, trading
in our shares will likely be subject to rules governing "penny stocks," which will impair trading activity in our shares.
Our common stock is currently subject to rules adopted by the SEC regulating broker-dealer practices in connection with transactions in penny
stocks. Those disclosure rules applicable to penny stocks require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized disclosure
document required by the SEC. These rules also require a cooling off period before the transaction can be finalized. These requirements may have the effect of reducing the level of trading activity in
the secondary market for our common stock. Many brokers may be unwilling to engage in transactions in our common stock because of the added disclosure requirements, thereby making it more difficult
for stockholders to dispose of their shares.
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FINRA sales practice requirements may also limit a shareholder's ability to buy and sell our stock.
In addition to the penny stock rules promulgated by the SEC, which are discussed in the immediately preceding risk factor, FINRA rules require
that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low
priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and
other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA
requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit the ability to buy and sell our stock and have an adverse effect on the
market value for our shares.
If we are unable to implement and maintain effective internal control over financial reporting in the future,
investors may lose confidence in the accuracy and completeness of our financial reports and the market price of our common stock may decline.
As a public company, we are required to maintain internal control over financial reporting and to report any material weaknesses in such
internal control. Further, we are required to report any changes in internal controls on a quarterly basis. In addition, we are required to furnish a report by management on the effectiveness of
internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Our independent registered public accounting firm will be required to attest to the
effectiveness of our internal control over financial reporting beginning with our annual report on Form 10-K following the date on which we are no longer an "emerging growth company." If we
identify material weaknesses in our internal control over financial reporting, if we are unable to comply with the requirements of Section 404 in a timely manner or assert that our internal
control over financial reporting are effective, or if our independent registered public accounting firm is unable to express an opinion as to the effectiveness of our internal control over financial
reporting when required, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of the common stock could be negatively affected, and we could
become subject to investigations by the stock exchange on which the securities are listed, the U.S. Securities and Exchange Commission, or other regulatory authorities, which could require additional
financial and management resources.
Issuance of our stock in the future could dilute existing shareholders and adversely affect the market price
of our common stock.
We have the authority to issue up to 110,000,000 shares of stock, including 100,000,000 shares of common stock and 10,000,000 shares of
preferred stock, and to issue options and warrants to purchase shares of our common stock. We are authorized to issue significant amounts of common stock in the future, subject only to the discretion
of our Board. These future issuances could be at values substantially below the price paid for our common stock by investors. In addition, we could issue large blocks of our stock to fend off unwanted
tender offers or hostile takeovers without further shareholder approval. Because the trading volume of our common stock is relatively low, the issuance of our stock may have a disproportionately large
impact on its price compared to larger companies.
The issuance of preferred stock in the future could adversely affect the rights of the holders of our common
stock.
An issuance of preferred stock could result in a class of outstanding securities that would have preferences with respect to voting rights and
dividends and in liquidation over the common stock and could, upon conversion or otherwise, have all of the rights of our common stock. Our Board of Directors' authority to issue preferred stock could
discourage potential takeover attempts or could delay or prevent a change in control through merger, tender offer, proxy contest or otherwise by making these attempts more difficult or costly to
achieve.
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We have never paid dividends on our common stock and we do not anticipate paying any in the foreseeable
future.
We have not paid dividends on our common stock to date, and we may not be in a position to pay dividends for the foreseeable future. Our ability
to pay dividends will depend on our ability to successfully develop our business plan and generate revenue from operations. Further, our initial earnings, if any, will likely be retained to finance
our operations. Any future dividends will depend upon our earnings, our then-existing financial requirements and other factors, and will be at the discretion of our Board of Directors.
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
In this report, references to "PetroShare," the "Company," "we," "us," and "our" refer to PetroShare Corp., the Registrant.
The
words "anticipates," "believes," "estimates," "expects," "intends," "may," "plans," "will," "would," and similar words or expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain these identifying words. Forward-looking statements and information are necessarily based upon a number of estimates and assumptions
that, while considered reasonable by management, are inherently subject to significant business, economic and competitive uncertainties, risks and contingencies, and there can be no assurance that
such statements and information will prove to be accurate. Therefore, actual results and future events could differ materially from those anticipated in such statements and information. We caution you
not to put undue reliance on these statements, which speak only as of the date of this report. Further, the information contained in this document or incorporated herein by reference is a statement of
our present intention and is based on present facts and assumptions, and may change at any time and without notice, based on changes in such facts or assumptions. Readers should not place undue
reliance on forward-looking statements.
The
important factors that could affect the accuracy of forward-looking statements and prevent us from achieving our stated goals and objectives include, but are not limited
to:
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changes in the general economy affecting the disposable income of the public;
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changes in environmental law, including federal, state and local legislation;
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changes in drilling requirements imposed by state or local laws or regulations;
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terrorist activities within and outside the United States;
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technological changes in the crude oil and natural gas industry;
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acts and omissions of third parties over which we have no control;
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inflation and the costs of goods or services used in our operation;
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access and availability of materials, equipment, supplies, labor and supervision, power, and water;
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interpretation of drill hole results and the uncertainty of reserve estimates;
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the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on
price;
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the level of demand for the production of crude oil and natural gas;
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changes in our business strategy;
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potential failure to achieve production from development drilling projects; and
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Those
factors discussed above and elsewhere in this report are difficult to predict and expressly qualify all subsequent oral and written forward-looking statements attributable to us or
persons acting on our behalf. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not have any intention or obligation to update
forward-looking statements included in this report after the date of this report, except as required by law. The preceding outlines some of the risks and uncertainties that may affect our
forward-looking statements.