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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Commission File Number 001-37943

PETROSHARE CORP.
(Exact name of registrant as specified in its charter)

9635 Maroon Circle, Suite 400
Englewood, Colorado 80112
(Address of principal executive offices) (Zip Code)

Registrant's telephone number including area code: (303) 500-1160

         Securities registered pursuant to Section 12(b) of the Act: None

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§203.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference into Part III of this Form 10-K or any amendment to this Form 10-K. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

         As of June 30, 2016, the last business day of the registrant's most recently completed second fiscal quarter, there were 21,828,191 shares outstanding and held by non-affiliates of the registrant. The aggregate market value of those shares, based on the closing price of the Company's common stock on the OTCQB on June 30, 2016, was $32,742,287.

         On March 30, 2017, there were 21,964,282 shares of the Company's common stock outstanding.

         Documents incorporated by reference: None

   

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PETROSHARE CORP.
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

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PART I

        Please see Cautionary Language Regarding Forward-Looking Statements on page 32 of this report for important information contained herein.

        Please see page 47 for a glossary of certain terms used in this report.

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 Denver—Julesburg 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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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

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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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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 Niobrara—Fort 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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Developed and Undeveloped Acreage

        The following table shows our developed and undeveloped acreage as of March 30, 2017:

        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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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.

Sales Data

        The following table shows the net sales volumes, average sales prices, and average production costs for the periods presented:

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 producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior 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.

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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

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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

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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:

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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:

        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:

•

fires;



•

explosions;



•

blow-outs and surface cratering;



•

uncontrollable flows of underground natural gas, oil or formation water;



•

natural disasters;



•

pipe and cement failures;



•

casing collapses;



•

embedded oilfield drilling and service tools;



•

abnormal pressure formations; and



•

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:

•

injury or loss of life;



•

severe damage to and destruction of property, natural resources or equipment;



•

pollution and other environmental damage;



•

clean-up responsibilities;



•

regulatory investigation and penalties;



•

suspension of our operations; or



•

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:

•

the limited trading market in our common stock;



•

commodity prices in general, and the price of oil in particular;



•

the success of our development efforts;



•

failure to successfully implement our business plan;



•

failure to meet our revenue or profit goals or operating budget;



•

decline in demand for our common stock;



•

sales of additional amounts of common stock;



•

downward revisions in securities analysts' estimates or changes in general market conditions;



•

investor perception of our industry or our prospects; and



•

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:

•

changes in the general economy affecting the disposable income of the public;



•

changes in environmental law, including federal, state and local legislation;



•

changes in drilling requirements imposed by state or local laws or regulations;



•

terrorist activities within and outside the United States;



•

technological changes in the crude oil and natural gas industry;



•

acts and omissions of third parties over which we have no control;



•

inflation and the costs of goods or services used in our operation;



•

access and availability of materials, equipment, supplies, labor and supervision, power, and water;



•

interpretation of drill hole results and the uncertainty of reserve estimates;



•

the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;



•

the level of demand for the production of crude oil and natural gas;



•

changes in our business strategy;



•

potential failure to achieve production from development drilling projects; and

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•

capital expenditures.

        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.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 3.    LEGAL PROCEEDINGS

        From time to time, we may become involved in litigation relating to claims arising out of our operations in the normal course of business. No legal proceedings, government actions, administrative actions, investigations, or claims are currently pending against us or our officers and directors in which we are adverse.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

        Beginning November 23, 2015, our common stock has been quoted on the OTCQB of OTCLink under the symbol "PRHR." Prior to that date, there was no trading market for our common stock.

        The table below sets forth the high and low sales prices for our common stock on the OTCQB from November 23, 2015 to December 31, 2016. The prices in the table represent prices between dealers and do not include adjustments for retail mark-up, mark-down, or commission, and may not represent actual transactions.

        On March 30, 2017, the high and low sales price of our common stock on the OTCQB were $1.857 and $1.80, respectively.

        Because our common stock is thinly traded and is not listed on a national securities exchange, the price for our common stock may be highly volatile and may bear no relationship to our actual financial condition or results of operations. Factors that we discuss in this report, including the many risks associated with our stock, may have a significant impact on the market price of our common stock. The market for our common stock will be affected by the offer and sale of our common stock by existing securities holders.

Holders of our Common Stock

        As of March 30, 2017, we have outstanding 21,964,282 shares of common stock and approximately 95 holders of record of our common stock.

Transfer Agent

        We have appointed Corporate Stock Transfer, Inc. of Denver, Colorado to be our transfer agent. Its address is 3200 Cherry Creek Drive South, #430, Denver, Colorado 80209 and its telephone number is 303-282-4800.

Penny Stock Rules

        Due to the price of our common stock, as well as the fact that our stock is not listed on a national securities exchange, our stock is characterized as a "penny stock" under applicable securities regulations. As a result, we are subject to rules adopted by the SEC and FINRA regulating broker-dealer practices in connection with transactions in penny stocks. The broker or dealer proposing to effect a transaction in a penny stock must furnish the customer with a document containing information prescribed by rule and obtain from the customer an executed acknowledgment of receipt of that document. Also, because of the relatively low trading price of our common stock, many brokerage firms may be unwilling to effect transaction in our common stock.

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        The broker or dealer must also provide the customer with pricing information regarding the security prior to the transaction and with the written confirmation of the transaction. The broker or dealer must also disclose the aggregate amount of any compensation received or receivable by him in connection with such transaction prior to consummating the transaction and with the written confirmation of the trade. The broker or dealer must also send an account statement to each customer for which he has executed a transaction in a penny stock each month in which such security is held for the customer's account. The existence of these rules may have an adverse effect on the price of our stock, and the willingness of certain brokers to effect transactions in our stock.

Dividend Policy

        We have never declared or paid dividends on our common stock and we do not expect to pay any in the near future. Payment of future dividends, if any, will be at the discretion of our Board of Directors after taking into account various factors, including the terms of any credit arrangements, our financial condition, operating results, current and anticipated cash needs and plans for expansion. Any earnings in the foreseeable future likely will be reinvested into our company. At the present time, we are not party to any agreement that would limit our ability to pay dividends.

Public Offering and Use of Proceeds

        We filed a registration statement on Form S-1 (File No. 333-198881) in connection with our initial public offering, which was declared effective by the SEC on February 4, 2015. We subsequently filed a post-effective amendment to the Form S-1, which was declared effective by the SEC on November 12, 2015. The following table illustrates the use of proceeds as of December 31, 2016:

Recent Sales of Unregistered Securities

        In addition to those sales of unregistered securities we previously disclosed on reports we have filed with the SEC, we have issued the following securities in transactions that were not registered under the Securities Act during the fourth quarter of 2016:

•

On November 11, 2016, we issued 14,425 shares of common stock to an oil and gas lease broker in connection with certain services to be provided to the Company. The shares were valued at $26,686.



•

On December 5, 2016, we issued 30,000 shares of common stock to a working interest partner in exchange for certain oil and gas interests. The shares were valued at $56,700.

        Each of the foregoing transactions was completed pursuant to the exemption from registration provided by Section 4(a)(2) of the Securities Act. In each transaction, we did not engage in any general solicitation or advertising and we offered the securities to a limited number of persons with whom we had pre-existing relationships. We exercised reasonable care to ensure that the purchasers of securities were not underwriters within the meaning of the Securities Act, including making reasonable inquiry prior to accepting any subscription, making written disclosure regarding the restricted nature of the securities and placing a legend on the certificates representing the shares. Stop transfer restrictions were placed with our transfer agent and a restrictive legend was placed on the certificate in connection

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with these offerings. In addition, the shares were issued exclusively to what the Company reasonably believed were accredited investors as defined in Rule 501 of the Securities Act.

        For additional information regarding the sale of unregistered securities in the fourth quarter of 2016, please see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 6.    SELECTED FINANCIAL DATA

        Not required for smaller reporting companies.

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

        The following discussion summarizes our plan of operation as of March 30, 2017 for the next 12 months and the related anticipated capital expenditures. It also analyzes (i) our financial condition at December 31, 2016 and 2015, and (ii) our results of operations for the years ended December 31, 2016 and 2015. The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes and with the understanding that the actual future results may be materially different from what we currently expect.

        We were organized on September 4, 2012 under the laws of the State of Colorado to investigate, acquire and develop crude oil and natural gas properties in the Rocky Mountain and mid-continent region of the United States. Following the acquisition of the PDC and Crimson assets and our participation in several drilling programs as a non-operator, we have an interest in 93 gross (32.91 net) oil and gas wells located in the Southern Core of the Wattenberg Field. We are also the operator of two gross (0.75 net) oil and gas wells on our Buck Peak prospect. We currently possess a lease inventory covering a total of approximately 26,258 gross (7,967 net) acres, the majority of which is in the Southern Core. After assignment to our working interest partners, we have approximately 352 net acres in our Buck Peak prospect and 7,615 net acres in the Southern Core, which we are in the process of developing.

        As an oil and natural gas exploration and production Company, our revenue, results of operation, cash flow from operations, reserve values, access to capital and future rate of growth are influenced by the prevailing prices of oil and natural gas. Changes in prices can affect, both positively and negatively, our financial condition, liquidity, ability to obtain financing, operating results, and the amount of oil and natural gas that we choose to produce. Prevailing prices for such commodities fluctuate in response to changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Inherently, the price received for oil and natural gas production is unpredictable, and such volatility is expected. All of our production is sold at market prices and, therefore, the amount of revenue that we realize, as well as our estimates of future revenues, is to a large extent determined by factors beyond our control.

        Under the terms of the participation agreements covering our prospects and operating agreements with other third party operators, we are required to pay our proportionate share of the costs of any wells in which we participate. In exchange, we are entitled to a proportionate share of the revenue, net of related expenses. Accordingly, the ultimate success of our business plan depends on our ability to generate sufficient cash flow from the sale of produced crude oil and natural gas from our interest in the leases to pay our overhead and costs of future acquisitions and development.

        We cannot fully determine what impact the volatility in crude oil and natural gas prices may have on our ongoing operations and future operations if such volatility continues into the future. Our decision on whether to drill and complete wells is based on both the prevailing commodity prices and

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the cost to drill such wells. Our ability to acquire financing and/or properties, drill wells, identify working interest and/or industry partners may all be negatively impacted by downward fluctuations in the price of oil and gas.

Plan of Operation and Expected Capital Expenditures

        Our plan of operation for the next 12 months includes: (i) pursuing the development of our Shook pad drilling program on the Todd Creek Farms prospect and, subject to receipt of required capital, commence drilling on the Shook pad, (ii) operating and increasing production from the wells we purchased from PDC and Crimson, (iii) participating as a non-operator in drilling projects operated, or to be operated, by third-parties, (iv) identifying other lease and asset acquisitions in the Southern Core, and (v) maintaining our operated wells on our Buck Peak prospect. Our plan of operation is contingent upon our obtaining adequate working capital from operations and proceeds from the offering of our securities, the success of which cannot be assured. Our goal is to become a leading independent producer of crude oil and natural gas and liquids in the Wattenberg Field.

Operated Properties

        We have permitted a 14-well drilling program consisting of standard-range lateral wells on our Shook pad, located in Section 3 of Township 1 South, Range 67 West, Adams County, and part of our Todd Creek Farms prospect. The Shook pad is our first anticipated operated program in the Wattenberg field. Subject to the availability of working capital, we expect to drill 14 and complete up to 7 wells in mid-2017. Based on current estimates, we have budgeted $16.7 million for our 50% share of those wells. We expect to receive revenue from these wells in the third quarter of 2017.

        We intend to monitor the production from the wells we acquired during 2016 in order to determine whether production rates could be improved through work-overs or by other means. Regardless of the success of our work-over efforts on the PDC or Crimson assets, we do not expect any net cash flow to be significant to our future operations. Nor do we expect that we will incur any material capital expenditures relating to those wells. The perceived value of the PDC and Crimson assets is that they hold by production certain of our leases on which we expect to drill a significant proportion of our planned horizontal wells.

        In maintaining our wells on the Buck Peak prospect, we may incur additional capital expenditures; however we expect any expenditures related to the Buck Peak wells will be nominal.

Non-Operated Properties

        We are currently participating as a non-operator in a 14-well drilling program on the Jacobucci pad, which is operated by PDC and located in our Todd Creek Farms prospect. This program commenced in April 2016 and consists of 14 mid-range lateral wells, all of which were drilled and completed during 2016 and early 2017. We are participating in all 14 wells, with working interests varying from 8.6 to 26.5% and an average over all the wells of approximately 17.6%. The anticipated cost to our interest to drill and complete all of the Jacobucci pad wells is approximately $8.5 million, of which approximately $4.6 million has been paid as of March 30, 2017.

        We also are participating as a non-operator in a multi-well drilling program on the Marcus pad operated by Great Western Oil & Gas Company and located in our Todd Creek Farms prospect, of which two wells have been drilled and completed to date in which we have an approximate 15% working interest. We expect to participate in all future Marcus pad wells, with working interests varying from 11 to 12% and an average over all of the wells of approximately 11.5%. The anticipated cost to our interest to drill and complete all of the Marcus pad wells is approximately $9.0 million, of which approximately $1,382,031 has been paid as of March 30, 2017. In addition to the Marcus pad wells referred to above, Great Western has additional approved horizontal well permits in which we have the right to participate, if and when a drilling program is proposed to us.

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        We also are currently participating as a non-operator in an 11-well drilling program operated by Ward Petroleum Corporation and located in our Todd Creek Farms prospect, of which one well has been drilled and completed to date due to pipeline limitations. We expect to participate in all 11 wells, with our working interest in each well averaging approximately 11%. The anticipated cost to our interest to drill and complete all of the Riverdale pad wells is approximately $3.3 million, of which approximately $311,958 has been paid as of March 30, 2017, which is approximately our share of the first completed well

        We expect to pay the future costs associated with our operated and non-operated properties through existing cash, cash flow from new wells in which we have participated and proceeds from the sale of equity or debt, the success of which cannot be assumed. While we do not control the drilling and completion schedules of any wells in which we are a non-operator, we currently expect to begin receiving revenue from our non-operated properties in the second quarter of 2017.

        As discussed in more detail under "Liquidity and Capital Resources" below, our initial line of credit provides us the ability to borrow up to $5.0 million. As of the date of this report, the initial line of credit was fully drawn. Accordingly, our ability to continue acquiring acreage and to develop the acreage in which we currently have any interest is dependent on our ability to raise more capital. To achieve that objective, we expect to pursue additional equity offerings in 2017.

Results of Operations for the Year Ended December 31, 2016 Compared to December 31, 2015

        The following provides selected operating results and averages for the years ended December 31, 2016 and 2015:

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        Overview:    For the year ended December 31, 2016, we realized a net loss of $4,479,052, or $0.21 per share, compared to a net loss of $1,523,375, or $0.09 per share, for the year ended December 31, 2015. The increase in net loss of $2,955,677 for the year ended December 31, 2016 resulted primarily from an increase in our general and administrative expenses, including a substantial increase in share-based compensation, an increase in lease operating expenses, and an increase in depreciation, depletion, amortization and accretion expenses, partially offset by a decrease in our impairment loss. We expect to continue operating at a loss until such time as the anticipated cash flow from the wells in which we have an interest is sufficient to cover operating, general and administrative and other expenses.

        Revenues:    Crude oil and natural gas sales revenue increased $331,788, for the year ended December 31, 2016 to $333,116 from $1,328 for the year ended December 31, 2015, as described in "Volumes and Prices" below. All of the revenue that we reported in 2016 came from the sale of oil, natural gas and NGLs produced from the vertical wells that we acquired during the year, as none of the horizontal wells in which we participated were completed and put on line in time for us to realize any revenue.

        Volumes and Prices:    Crude oil and natural gas sales volumes increased 10,720 BOE for the year ended December 31, 2016 compared to the year ended December 31, 2015. The oil and natural gas sales volumes for the year ended December 31, 2016 were the result of production from wells acquired during the year and the completion of three non-operated wells that were put on production in the fourth quarter of 2016. In 2015, we only produced nominal volumes of oil due to our election not to sell any volumes produced in the last three quarters of the year. For the year ended December 31, 2016, our average oil sales price was $48.91 per Bbl compared to $36.29 per Bbl for the year ended December 31, 2015, reflecting higher average oil prices in 2016 compared to 2015; our average natural gas sales price was $2.62 per Mcf compared to $nil for the year ended December 31, 2015; and our average NGLs sales price was $16.55 per Bbl compared to $nil for the year ended December 31, 2015. The decrease of $5.32, or 15%, per BOE results primarily from a change in our product sales mix to include natural gas and NGL at blended lower sales prices, offset by higher average crude oil prices during the year ended December 31, 2016.

        Operating Expense:    Operating expense is comprised of the following items:

        Total operating expense increased $174,713, for the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily due to increased lease operating costs ("LOE"), production taxes, and transportation expense related to the wells acquired and completed during the year ended December 31, 2016. As mentioned above, our production during 2015 was nominal.

        LOE per BOE was $15.59 for the year ended December 31, 2016, compared to $870.60 for the year ended December 31, 2015. As a percent of crude oil and natural gas sales revenue, routine LOE was 50% for the year ended December 31, 2016, compared to 23,994% for the year ended December 31, 2015.

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        Production taxes for the year ended December 31, 2016 amounted to $38,634 as compared to $(11) for the year ended December 31, 2015, primarily due to production from the wells acquired during the year ended December 31, 2016 and wells placed online in the fourth quarter of 2016.

        Overall operating costs (crude oil and natural gas operating costs, including production taxes) per BOE was $19.21 for the year ended December 31, 2016, compared to $871.82 for the year ended December 31, 2015, primarily due to the increased volume from wells acquired during the year ended December 31, 2016.

        Depreciation, depletion, amortization, and accretion expense:    Depletion, depreciation, amortization and accretion increased $81,595, to $95,516 for the year ended December 31, 2016, from $13,921 for the year ended December 31, 2015. The increase in expense was the result of increased production volumes related to wells acquired and non-operated wells coming online during the 2016 period, partially offset by an increase in our reserves.

        Interest income (expense):    During the year ended December 31, 2016, we recognized interest income of $573 compared to $46 in the year ended December 31, 2015. During the year ended December 31, 2016, we recognized interest expense of $320,950 compared to $48,602 in the year ended December 31, 2015, an increase of 560%. The interest expense recognized in the current period primarily relates to advances on our two lines of credit, recorded during 2016.

        General and administrative expenses:    We incurred general and administrative expenses of $4,022,969 during the year ended December 31, 2016 compared to $1,265,134 in the year ended December 31, 2015, representing an increase of $2,757,835, or 218%. This increase is attributable to an increase in share-based compensation expense, to $1,365,388 from $191,205 in the prior period; increases in salary and wage expenses related to the payment of bonuses and the addition of new employees, to $697,583 from $498,000, and legal and accounting fees, board of director fees, filing fees and investor relations expense associated with being a public company required to file reports with the SEC, compared to limited activity in the prior period as we were commencing operations. Also included in general and administrative expense during the 2016 period are costs of approximately $1.0 million incurred in connection with an abandoned public offering in the fourth quarter of the year.

LIQUIDITY AND CAPITAL RESOURCES

Overview

        To date, we have generated essentially all of our capital resources through the sale of debt and equity, prospect fees received from working interest partners, drilling advances from working interest partners, and advances under our lines of credit. During the year ended December 31, 2016, we received $1,832,340 in proceeds from the sale of our common stock and units through our private placements and borrowed approximately $11,042,815 under our lines of credit. To date, we have generated nominal cash from operations and negative cash flows from operating activities.

        We have fully drawn our initial line of credit with Providence, and as of March 30, 2017, we have $5.0 million of principal plus accrued interest of approximately $401,000 outstanding. On October 13, 2016, we entered into the supplemental line of credit with PEP III, which 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. Interest on the supplemental line accrues at the rate of 8% per year and monthly interest-only payments are due beginning upon the advancement of funds. 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 against the supplemental line of credit in exchange for PEP III extending the maturity date until June 13, 2017. As of March 30, 2017, we have $7.1 million plus accrued interest of approximately $191,000 outstanding against our supplemental line of credit.

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        On June 30, 2016, we began generating revenue and cash flow from the 35 currently producing wells which we acquired as part of the PDC assets. These wells produce approximately 62.5 BOE/D, net to our interest. On December 1, 2016, we began generating revenue and cash flow from the 32 currently producing wells we acquired as part of the Crimson assets. These wells produce approximately 31.5 BOE/D, net to our interest. We also expect to begin recognizing revenue from our non-operated Jacobucci pad properties in the second quarter of 2017. The oil produced from our Wattenberg properties, including the PDC and Crimson assets, is sold at spot prices to third-parties, minus a discount from the current WTI price.

        The amount we invest in development, drilling, and leasing activities depends on, among other factors, opportunities presented to us, the results of drilling to date and the success of any fundraising efforts. The most significant of our future capital requirements include (i) costs to drill or participate in additional wells; (ii) costs to acquire additional acreage that we may identify in the Southern Core area or other areas; (iii) approximately $262,000 per month for salaries and other corporate overhead; and (iv) legal and accounting fees associated with our status as a public company required to file reports with the SEC. We anticipate funding these projected capital requirements with cash on hand, revenue from operations, and proceeds from the sale of debt or equity, the success of which cannot be assured.

Private Placement

        During December 2016 and January 2017, we completed a private placement of units consisting of convertible promissory notes and warrants to purchase our common stock for gross proceeds of $10.0 million. We received net proceeds of approximately $9.0 million from the private placement, after placement agent fees and other associated expenses.

        Each unit sold in the private placement is comprised of a 10% unsecured convertible promissory note in the face amount of $50,000 and 33,333 common stock purchase warrants. Each note sold in the private placement is one of a series of similar notes designated the "10% Unsecured Convertible Promissory Notes" with the series totaling $10.0 million. The notes bear interest at the rate of 10% per year and are due and payable on December 31, 2018. Interest is payable semi-annually beginning June 30, 2017 and until the notes are paid in full. At any time after issuance, the principal amount of the notes and any accrued but unpaid interest are convertible into shares of our common stock at the option of the holder at the rate of $1.50 per share. The conversion price will be proportionately adjusted in the event of any stock splits, stock dividends or a capital reorganization.

        We may force a conversion of the notes at any time after June 30, 2017 if and when all of the following conditions are satisfied:

•

Shares of common stock into which the notes are convertible have been registered for sale with the SEC or are eligible for resale under Rule 144 of the Securities Act of 1933, as amended;



•

The last sales price of our common stock on the OTCQB or other trading market equals or exceeds $3.00 for 20 out of 30 trading days and maintains an average daily trading volume of at least 100,000 shares per day during that time; and



•

We have paid or pay at the time of conversion an amount that would result in the holder having received a minimum of 12 months' interest.

        Each warrant issued in the private placement allows the holder to purchase one share of our common stock at a price of $3.00 per share at any time on or before December 31, 2019. The exercise price of the warrants, as well as the shares issuable upon the exercise of the warrants, is subject to adjustment in the event of any stock splits, stock dividends or a capital reorganization.

        We have the right to redeem any or all of the outstanding and unexercised warrants at a redemption price of $0.01 per warrant in the event (i) a registration statement covering the shares of

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the common stock issuable upon exercise of the warrant has been filed with the SEC and is in effect on the date of notice and the redemption date contained therein, (ii) there exists a public quotation for our common stock in any electronic quotation medium, and (iii) the public trading price of our common stock has equaled or exceeded $5.00 per share for 20 out of 30 trading days preceding the date of such notice with a volume of at least 100,000 shares per day. The holders of the warrants called for redemption shall have the right to exercise the warrants evidenced thereby until the close of business on the date next preceding the date fixed for redemption. On or after the date fixed for redemption, the holder of the warrants shall have no rights with respect to the warrant except the right to receive $0.01 per warrant upon surrender of the holder's warrant certificate.

        In connection with the private placement, we paid the placement agent and participating broker-dealers a total commission of $1.0 million. As additional compensation to the agent, we issued a placement agent warrant to purchase a total of 666,600 shares of our common stock exercisable at a price of $1.50 per share. The placement agent warrant expires on December 31, 2021.

        We granted to the holders of the notes, warrants and placement agent warrant "piggyback" registration rights, pursuant to which under certain conditions, we have agreed to register the shares that might be issued upon conversion or exercise of these securities on any registration statement that we might file in the future with the SEC.

Working Capital

        As of December 31, 2016, we had negative working capital of $6,115,501, comprised of current assets of $4,361,281 and current liabilities of $10,476,782. Working capital decreased by $9,226,990 from December 31, 2015, primarily due to advances on our lines of credit to pay for property acquisitions and increases in accounts payable and accrued liabilities related to accrued capital costs for the development of our oil and gas properties. Following year end, our working capital deficit decreased following the sale of an additional $8 million of units in the private placement.

        During the year ended December 31, 2016, we received gross proceeds of $2,037,600, less offering costs of $205,260, from the sale of common stock and units in two private placements. This compares to gross proceeds of $4,199,000, less offering costs of $364,999, from the sale of common stock during the year ended December 31, 2015.

Cash Flows

Year Ended December 31, 2016 Compared to December 31, 2015

Operating Activities

        Net cash used in operating activities during the year ended December 31, 2016 was $2,679,993 compared to $1,417,532 during the year ended December 31, 2015, representing an increase of $1,262,461. The increase in the 2016 period is attributable to an increase in net loss as discussed in Results of Operations above, increases in prepaid drilling expense, accounts receivable and accounts receivable due from our working interest partners, partially offset by increased share based compensation and accounts payable and accrued liabilities.

Investing Activities

        Net cash used in investing activities during the year ended December 31, 2016 was $10,757,041 compared to $892,721 during the year ended December 31, 2015, representing an increase of $9,864,320 and reflecting a significant increase in our acquisition and development activities. During the 2016 period, we paid $7,675,217 for the acquisition of properties and other fixed assets, including the PDC and Crimson acquisitions. During the 2016 period, we also paid $3,038,339 for our share of the

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development of our properties. During the 2015 period, we made investments totaling $892,721 related to the acquisition and development of our properties.

Financing Activities

        Financing activities in 2016 consisted primarily of borrowings under our two lines of credit and the sale of debt in a private placement. A planned underwritten public offering of our common stock was abandoned in the fourth quarter of the year due to market conditions.

        During the year ended December 31, 2016, we borrowed $3,937,815 on the initial line of credit from Providence and repaid $nil of that amount as compared to borrowing of $1,890,000 and repayment of $827,815 during the year ended December 31, 2015.

        During the year ended December 31, 2016, we borrowed $7,105,000 on the supplemental line of credit and repaid $nil of that amount. The supplemental line of credit did not exist in 2015.

        During the year ended December 31, 2016, we received gross offering proceeds of $1,942,600, less offering costs of $205,260, from the sale of units in a private placement. We received an additional $95,000 in a private placement of common stock in January 2016. This compares to gross proceeds of $4,199,000, less offering costs of $364,999, from the sale of our common stock during the year ended December 31, 2015.

Off-Balance Sheet Arrangements

        We have no material off-balance sheet transactions, arrangements, or obligations.

Critical Accounting Policies

Use of Estimates in the Preparation of Financial Statements

        The discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP"). The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 of the Notes to Financial Statements included as part of this Form 10-K. We have identified below the policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserve estimates, on a periodic basis and base our estimates on historical experience, independent third party reservoir engineers and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements:

Successful Efforts Method of Accounting

        Our application of the successful efforts method of accounting for our oil and gas exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later

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date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Oil and Gas Reserves

        Our estimates of proved reserves are based on the quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Our independent petroleum engineers, Cawley Gillespie, prepare a reserve and economic evaluation of all of our properties on a well-by-well basis. The accuracy of reserve estimates is a function of the:

•

quality and quantity of available data;



•

interpretation of that data;



•

accuracy of various mandated economic assumptions; and



•

judgment of the independent reserve engineer.

        One of the most significant estimates we make is the estimate of oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given area may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. For example, if estimates of proved reserves decline, our depreciation, depletion, and amortization (DD&A) rate will increase, resulting in an increase in net loss. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which would increase our loss. We cannot predict what reserve revisions may be required in future periods.

        The recent significant decline in oil, natural gas and NGL prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes to our development plans or costs.

Depreciation, Depletion, Amortization and Accretion.

        Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn increases our net loss. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.

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Impairment of Proved Oil and Gas Properties

        Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization.

        Our impairment analyses requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.

Impairment of Unproved Oil and Gas Properties

        Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration expenses in the statements of operations.

Accounting for Business Combinations

        We account for all of our business combinations using the purchase method, which is the only method permitted under FASB ASC 805, Business Combinations, and involves the use of significant judgment. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

        In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of gas, oil and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.

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        Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in increased net loss. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in an increase in net loss for the period in which the impairment is recorded.

Asset Retirement Obligations

        Our asset retirement obligations ("ARO") consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires management to make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.

Stock Based Compensation

        We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. The determination of the fair value of stock-based awards at the grant date requires judgment in developing assumptions, which involve a number of variables. These variables include, but are not limited to, the expected stock price volatility over the term of the awards, the expected dividend yield and the expected stock option exercise behavior.

        Our computation of expected volatility is based on a combination of historical and market-based implied volatility. The volatility rate was derived by examining historical stock price behavior and assessing management's expectations of stock price behavior during the term of the option. The term of the options was derived based on the "simplified method" calculation. The simplified method allows companies that do not have sufficient historical experience to provide a reasonable basis for an estimate to instead estimate the expected term of a "plain vanilla" option by averaging the time to vesting and the full term of the option. ("Plain vanilla" options are options with the following characteristics: (1) the options are granted at-the-money; (2) exercisability is conditional only upon performing service through the vesting date; (3) if an employee terminates service prior to vesting, the employee would forfeit the options; (4) if an employee terminates service after vesting, the employee would have a limited time to exercise the options (typically 30 to 90 days); and (5) the options are nontransferable and non-hedgeable.) The Company periodically evaluates the applicability of using the simplified method with respect to the characteristics noted above to estimate the expected term of our options and will continue to do so as our business continues to evolve. If any of the assumptions used in the Black-Scholes model change significantly, stock based compensation expense may differ materially in the future from that recorded in the current period.

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Going Concern Assessment

        Pursuant to ASU 2014-15, the Company has assessed its ability to continue as a going concern for a period of one year from the date of the issuance of these financial statements. Substantial doubt about an entity's ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year from the financial statement issuance date. As shown in the accompanying financial statements, the Company incurred a net loss of $4,479,052 during the year ended December 31, 2016, and as of that date, the Company's current liabilities exceeded its current assets by $6,115,501.

        Management has evaluated these conditions and determined that a reduction in the working capital deficit subsequent to December 31, 2016 related to a private placement and an extension and amendment to the Company's supplemental line of credit, coupled with anticipated increased revenues from the Company's non-operated and operated properties, will allow the Company to meet its maturing debt and interest obligations and continue as a going concern through March 31, 2018.

        As part of the analysis, the Company considered selective participation in certain non-operated drilling programs based on availability of working capital and the timing of production related cash flows.

Recent Accounting Pronouncements

        Please refer to Recent Accounting Pronouncements in Note 2—Basis of Presentation and Significant Accounting Policies in Part II, Item 8 of this report.

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GLOSSARY OF TERMS

        Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

        The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and within this prospectus:

        "Bbl"—Barrel or 42 US gallons liquid volume.

        "MBbls"—One thousand Bbls.

        "BOE"—One barrel of crude oil equivalent, which combines Bbls of oil, Bbls of natural gas liquids, and Mcf of natural gas by converting each six Mcf of natural gas to one Bbl of oil.

        "MBOE"—One thousand BOE.

        "BOE/D"—Barrels of oil equivalent per day.

        "Condensate"—A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

        "Developed acreage"—The number of acres that are allocated or assignable to producing wells or wells capable of production.

        "Development well"—A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.

        "Exploratory well"—A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

        "Field"—An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

        "Gross acres"—The number of acres in which the Company owns a gross working interest.

        "Gross well"—A well in which the Company owns a working interest.

        "Leases"—Full or partial rights in mineral interests authorizing the leaseholder to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

        "Mcf"—One thousand cubic feet of natural gas.

        "MMcf"—One thousand Mcf.

        "MMBtu"—One million British thermal units—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

        "Net acres" or "Net wells"—The sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

        "NGL"—Means natural gas liquids.

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        "Operator"—The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

        "Producing well"—A well that is currently producing crude oil, natural gas, or liquids.

        "Productive well"—A producing well or a well mechanically capable of production.

        "Prospect"—A location where hydrocarbons such as crude oil and natural gas are believed to be present in quantities which are economically feasible to produce.

        "Proved developed reserves"—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

        "Proved reserves"—Proved crude oil and natural gas reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

        "Proved undeveloped reserves"—Proved crude oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.

        "Reservoir"—A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

        "Resources"—Quantities of crude oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

        "Revenue interest"—The amount or percentage of revenue/proceeds derived from a producing well that the owner is entitled to receive.

        "Section"—640 acres.

        "Shut-in"—A well which is capable of producing but is not presently producing.

        "Spacing" or "Spacing Unit"—The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

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        "Standardized measure"—The present value of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

        "Undeveloped acreage"—Leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.

        "Unproved property"—A property or part of a property with no proved reserves.

        "Working interest"—The amount or percentage of costs that an owner is required to pay of drilling and production expenses. It also gives the owners, in the aggregate, the right to drill, produce and conduct operating activities on the property and to share in any revenue from the production.

        "Workover"—Operations on a producing well to restore or increase production.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Not required for smaller reporting companies.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
PetroShare Corp.

        We have audited the accompanying balance sheets of PetroShare Corp. as of December 31, 2016 and 2015 and the related statements of operations, shareholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PetroShare Corp. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

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PetroShare Corp.

Balance Sheets

December 31,

   

The accompanying notes are an integral part of these financial statements.

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PetroShare Corp.

Statements of Operations

For the years ended December 31,

   

The accompanying notes are an integral part of these financial statements.

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PetroShare Corp.

Statements of Changes in Shareholders' Equity

For the years ended December 31, 2016 and 2015

   

The accompanying notes are an integral part of these financial statements.

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PetroShare Corp.

Statements of Cash Flows

For the years ended December 31,

   

The accompanying notes are an integral part of these financial statements.

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS

December 31, 2016 and 2015

NOTE 1—ORGANIZATION AND NATURE OF BUSINESS

        PetroShare Corp. ("PetroShare" or the "Company") is a corporation organized under the laws of the State of Colorado on September 4, 2012 to investigate, acquire and develop crude oil and natural gas properties in the Rocky Mountain or mid-continent portion of the United States. Since inception, the Company has focused on financing activities and the acquisition, exploration and development of crude oil and natural gas prospects. The Company's current development focus is on the Denver-Julesburg basin in the State of Colorado. The Company realized its first significant revenue in 2016, following the acquisition of certain oil and gas producing properties.

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

        The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP").

Business Combinations

        The Company accounts for the acquisition of oil and gas properties, that are not commonly controlled, based on the requirements of the Financial Accounting Standards Board ("FASB") ASC Topic 805, Business Combinations, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for certain property acquisitions of proved developed oil and gas property as business combinations.

Use of Estimates

        The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period

        Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of the Company's estimates. All reserve data included in these financial statements are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered.

        Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, asset retirement obligations, valuation allowances for deferred income tax assets and valuation assumptions related to the Company's share-based compensation. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Unaudited Crude Oil and Natural Gas Reserve Information. (Note 15)

Loss Per Common Share

        Basic and diluted loss per share attributable to PetroShare shareholders is computed by dividing net (loss) by the weighted average number of common shares outstanding during the period. The Company excluded potentially dilutive securities as shown below, as the effect of their inclusion would be anti-dilutive.

        Potentially dilutive securities at December 31, 2016 and 2015 are as follows:

Cash

        The Company's bank accounts periodically exceed federally insured limits. The Company maintains its deposits with high quality financial institutions and, accordingly, believes its credit risk exposure associated with cash is minimal.

Revenue Recognition

        The Company recognizes revenue from the sale of crude oil, natural gas and NGLs when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. In general, settlements for hydrocarbon sales may occur after the month in which the oil, natural gas or other hydrocarbon products were produced. The Company may estimate and accrue for the value of these sales using information available to it at the time its financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser.

Accounts Receivable—Crude oil, natural gas and NGLs

        Accounts receivable—Crude oil, natural gas and NGLs consists of amounts receivable from sales from the Company's well interests. Management continually monitors accounts receivable for collectability.

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable—Joint interest billing

        Accounts receivable—Joint interest billing consists primarily of joint interest billings, which are recorded at the invoiced and to-be-invoiced amounts. Collateral is not required for such receivables, nor is interest charged on past due balances. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself.

Deferred Offering Costs

        The Company defers as other current assets the direct incremental costs of raising capital through equity offerings until such time as the offering is completed. At the time of the completion of the offering, the costs are charged against the capital raised. Should the offering be terminated, deferred offering costs are charged to operations during the period in which the offering is terminated. During the year ended December 31, 2016, the Company charged $544,070 in deferred offering costs to operations, as the offering was terminated. As of December 31, 2016, the Company's deferred offering costs totaled $nil, with $nil recorded as of December 31, 2015.

Debt Issuance Costs

        Debt issuance costs include origination and other fees incurred in connection with the Company's private placement and with the origination of the Company's supplemental line of credit. Debt issuance costs related to the private placement are amortized to interest expense using the effective interest method over the respective borrowing term.

Crude Oil and Natural Gas Properties

Proved

        The Company follows the successful efforts method of accounting for its crude oil and natural gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.

        The Company assesses its proved crude oil and natural gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares estimated undiscounted future net cash flows to the assets' net book value. If the net capitalized costs exceed estimated future net cash flows, then the cost of the property is written down to fair value. Fair value for crude oil and natural gas properties is generally determined based on estimated discounted future net cash flows. Impairment expense for proved properties is reported in exploration and impairment expense.

        The net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

amortization rate, in which case a gain or loss is recognized in the statement of operations. Gains or losses from the disposal of complete units of depreciable property are recognized in earnings (loss).

Unproved

        Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified as proved properties and depleted on a unit-of- production basis. Impairment expense for unproved properties is reported in exploration and impairment expense.

Exploratory

        Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

        Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well contains proved reserves. If an exploratory well does not contain proved reserves, the costs of drilling the well and other associated costs are charged to expense. Costs incurred for exploratory wells that contain reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.

Property, Plant and Equipment

        Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using straight-line methods over the estimated useful lives of the related assets. Expenditures for renewals and betterments which increase the estimated useful life or capacity of the asset are capitalized; expenditures for repairs and maintenance are expensed when incurred.

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Asset Impairment

        Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future undiscounted cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method utilizes the most recent third party reserve estimation report and estimates future cash flows based on management's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate. The Company recognized impairment expense of $116,303 during the year ended December 31, 2016, while expense of $154,776 was recorded in 2015.

Depreciation, Depletion and Amortization

        Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed crude oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates. Depletion expense for the year ended December 31, 2016 was $59,262, and expense of $9,898 was recorded in 2015.

Prepaid Drilling Costs

        Prepaid drilling costs consist of cash payments made by the Company to the operators of oil and gas properties and other third party service providers.

Drilling Advances—related party

        The Company's drilling advances consist of cash provided to the Company from its joint interest partners for planned drilling activities. Advances are applied against the joint interest partner's share of expenses incurred. As of December 31, 2016 and 2015, drilling advances totaled $234,452 and $nil, respectively.

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Income Taxes

        The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax bases of assets and liabilities using the enacted tax rates that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

Asset Retirement Obligation

        Asset retirement obligations associated with tangible long-lived assets are accounted for in accordance with ASC 410, "Accounting for Asset Retirement Obligations." The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of crude oil and natural gas properties is recorded generally upon the completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the crude oil and natural gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method. The liability is periodically adjusted to reflect: (1) new liabilities incurred; (2) liabilities settled during the period; (3) accretion expense; and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion, accretion and amortization expense in the accompanying statements of operations.

Share Based Compensation

        The Company uses the Black-Scholes option-pricing model to determine the fair-value of stock-based awards in accordance with ASC 718, "Compensation." The option-pricing model requires the input of highly subjective assumptions, including the option's expected life, the price volatility of the underlying stock, and the estimated dividend yield of the underlying stock. The Company's expected term represents the period that stock-based awards are expected to be outstanding and is determined based on the contractual terms of the stock-based awards, vesting schedules and expectations of future employee behavior as influenced by changes to the terms of its stock-based awards. As there was insufficient historical data available to ascertain a forfeiture rate, the plain vanilla method was applied in calculating the expected term of the options. The Company's common stock has limited historical trading data, and as a result the expected stock price volatility is based on the historical volatility of a group of publicly traded companies that share similar operating metrics and histories. The Company has never paid dividends on its common stock and does not intend to do so in the foreseeable future, and as such, the expected dividend yield is zero.

Loans and Borrowings

        Borrowings are recognized initially at fair value, net of financing costs incurred, and subsequently measured at amortized cost. Any difference between the amounts originally received and the redemption value of the debt is recognized in the consolidated statement of operations over the period to maturity using the effective interest method.

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Fair Value of Financial Instruments

        Fair value accounting, as prescribed in ASC Section 825, utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described below:

Going Concern Assessment

        Pursuant to ASU 2014-15, the Company has assessed its ability to continue as a going concern for a period of one year from the date of the issuance of these financial statements. Substantial doubt about an entity's ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year from the financial statement issuance date. As shown in the accompanying financial statements, the Company incurred a net loss of $4,479,052 during the year ended December 31, 2016, and as of that date, the Company's current liabilities exceeded its current assets by $6,115,501.

        Management has evaluated these conditions and determined that a reduction in the working capital deficit subsequent to December 31, 2016 related to a private placement (Note 6) and an extension and amendment to the Company's supplemental line of credit (Note 6), coupled with anticipated increased revenues from the Company's non-operated and operated properties, will allow the Company to meet its maturing debt and interest obligations and continue as a going concern through March 31, 2018.

        As part of the analysis, the Company considered selective participation in certain non-operated drilling programs based on availability of working capital and the timing of production related cash flows.

Recent Accounting Pronouncements

Standards Adopted in 2016

        Debt Issuance Costs—In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. In August 2015, the

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December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update was effective for interim and annual periods beginning after December 15, 2015. The Company adopted this standards update, as required, effective January 1, 2016. The adoption of this standards update did not affect the Company's method of amortizing debt issuance costs and did not have a material impact on its financial statements.

        Measurement-Period Adjustments—In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update was effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this standard update, as required, effective January 1, 2016, which did not have a material impact on its financial statements.

        Stock Compensation—In March 2016, the FASB issued updated guidance on share-based payment accounting. The standards update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The standards update is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. The Company elected to early-adopt this standards update as of April 1, 2016 in connection with its initial grant of awards under the Company's 2015 Equity Incentive Plan. The Company has elected to record the impact of forfeitures on compensation cost as they occur. The Company is also permitted to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rates. There was no retrospective adjustment as the Company did not have any forfeitures nor settlements outstanding equity awards prior to adoption.

        Going Concern Analysis—In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements—Going Concern (Subtopic 205-40)." The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for annual periods ending after December 15, 2016 and for annual and interim periods thereafter. The Company adopted this standard as required, which did not have a material impact on its financial statements.

Recent Accounting Pronouncements Not Yet Adopted

        Various accounting standards and interpretations were issued in 2016 with effective dates subsequent to December 31, 2016. The Company has evaluated the recently issued accounting pronouncements that are effective in 2016 and believe that none of them will have a material effect on the Company's financial position, results of operations or cash flows when adopted.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers." The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in US GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers—Deferral of the Effective Date," which approved a one year deferral of ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of the original effective date for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

        In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The standard requires lessees to recognize the assets and liabilities that arise from leases on the balance sheet. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact of the new guidance on its financial statements.

        Further, the Company is monitoring the joint standard-setting efforts of the FASB and the International Accounting Standards Board. There are a large number of pending accounting standards that are being targeted for completion in 2017 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation. Because these pending standards have not yet been finalized, at this time the Company is not able to determine the potential future impact that these standards will have, if any, on its financial position, results of operations or cash flows.

NOTE 3—ACQUISITIONS

PDC Acquisition

        On June 30, 2016, the Company completed the acquisition of certain oil and gas assets from PDC Energy, Inc. ("PDC"), including leases covering approximately 3,652 gross (1,410 net) acres of lands located in Adams County, Colorado and PDC's interest in 35 producing wells ("PDC assets"). Simultaneous with the closing, the Company's working interest partner and primary lender exercised its option under a participation agreement (the "Participation Agreement") (Note 12) and acquired 50% of the Company's interest in the PDC assets. The acquisition was effective April 1, 2016.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 3—ACQUISITIONS (Continued)

        Following a final proration of costs and revenues from the operation of the PDC assets and the Company's working interest partner's exercise of its option under the Participation Agreement, the Company's net purchase price for the PDC assets was $2,260,890. A final allocation of the purchase price was prepared using, among other things, an internally prepared reserve analysis. The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:

        The following table presents the unaudited pro forma combined results of operations for the years ended December 31, 2016, and 2015, as if the PDC assets acquisition had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to depletion expense, accretion expense and costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

Crimson Acquisition

        On December 22, 2016, the Company completed the acquisition of certain oil and gas assets from Crimson Exploration Operating, Inc. ("Crimson"), including leases covering approximately 15,514 gross (5,609 net) acres of lands located mostly in Adams and Weld Counties, Colorado and Crimson's

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 3—ACQUISITIONS (Continued)

interest in 32 producing wells ("Crimson assets"). Simultaneous with the closing, the Company's working interest partner and primary lender acquired 50% of the Company's interest in the Crimson assets. The acquisition was effective December 1, 2016.

        Following a reconciliation of certain suspense and inventory accounts, the Company's net purchase price for the Crimson assets was $2,538,945. The purchase price is subject to post-closing adjustments scheduled to occur not more than 90 days following the closing date.

        An interim allocation of the purchase price was prepared using, among other things, an internally prepared reserve analysis. The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:

        The following table presents the unaudited pro forma combined results of operations for the years ended December 31, 2016, and 2015 (unaudited), as if the Crimson assets acquisition had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to depletion expense, accretion expense and costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 3—ACQUISITIONS (Continued)

2016 Activity

        On March 10, 2016, the Company acquired certain surface rights and easements on lands located in Township 1 South, Range 67 West located on its Todd Creek Farms prospect in exchange for $184,360 in cash. The surface rights and easements permit the Company to access its Shook well pad.

        On March 31, 2016, the Company acquired oil and gas assets on land adjacent to the Company's Todd Creek Farms prospect, including approximately 160 net acres and a 50% working interest in one well following an assignment to the Company's working interest partner pursuant to the Participation Agreement. The Company's net cost for the foregoing assets was $590,274.

        On April 14, 2016, the Company acquired oil and gas leases in the Todd Creek Farms prospect covering approximately 189 net acres. The Company's net cost for the leases was $288,056.

        In connection with obtaining its supplemental line of credit (Note 6), the Company assigned Providence Energy Partners III, LP ("PEP III") 10% of the Company's working interest in 278 gross (170 net) net acres in the Wattenberg Field including the Company's interest in the Jacobucci wells.

        On October 14, 2016, the Company completed the acquisition of additional royalty interests in 10 Jacobucci pad horizontal wells located on its Todd Creek Farms prospect. The Company's net cost for the royalty interests was $1.55 million, which the Company paid using a draw under its supplemental line of credit.

2015 Activity

        On May 15, 2015, the Company acquired approximately 1,280 gross acres (171 net acres) located in the Todd Creek Farms Prospect. The Company paid $785,630 and Kingdom conveyed to the Company an 80% net revenue interest in the acreage after accounting for landowner and other royalties. Pursuant to the provisions of the Participation Agreement, executed in connection with the Company's initial line of credit (See Note 6), the Company assigned the right to acquire up to 50% of its interest in the Todd Creek Farms prospect to Providence in part consideration for extending the Company the initial line of credit, which Providence exercised with an effective date of June 1, 2015. The Company recorded the exercise of the option by reducing its acquisition costs in the Kingdom Lease by 50%. A reduction of acquisition costs in the amount of $287,815 was recorded, comprised of $392,815 net of $105,000 related to a one-time credit issued to the lender pursuant to the provisions of the Participation Agreement. The Company has recorded the net assignment of interest to Providence as a $287,815 non-cash payment against the initial line of credit.

        Between May 15, 2015 and December 31, 2015, the Company acquired approximately 77 additional net acres in the Todd Creek Prospect area and, as of December 31, 2015, the Todd Creek Farms prospect area covers approximately 1,460 gross and 244 net acres.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

        Property and equipment balances were comprised of furniture, fixtures, and equipment and are shown below:

        Depreciation expense recorded for the years ended December 31, 2016 and 2015, amounted to $5,772 and $963, respectively.

NOTE 5—CRUDE OIL AND NATURAL GAS PROPERTIES

        The Company's oil and gas properties are entirely within the United States. The net capitalized costs related to the Company's oil and gas producing activities were as follows:

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 5—CRUDE OIL AND NATURAL GAS PROPERTIES (Continued)

        Costs Incurred in Crude Oil and Natural Gas Activities.    Costs incurred in connection with the Company's crude oil and natural gas acquisition, exploration and development activities for each of the periods are shown below:

        During the year ended December 31, 2016, depletion expense was $59,262, and expense of $9,898 was recorded in 2015.

NOTE 6—DEBT

Line of credit

        On May 13, 2015, the Company entered into a Revolving Line of Credit Facility Agreement ("initial line of credit") with Providence, which provides to the Company a revolving line of credit of up to $5,000,000. As of December 31, 2016, the outstanding balance on the initial line of credit was $5,000,000 plus accrued interest of $302,477. During the year ended December 31, 2016, the Company borrowed $3,937,815 on the initial line of credit, primarily to fund the acquisition and development of crude oil and natural gas properties (Note 3 and Note 12). During the year ended December 31, 2016, the Company recorded interest expense of $253,875 related to the initial line of credit.

        Interest on the outstanding principal balance of the initial line of credit begins accruing on the dates of advancements of principal at an annual rate equal to 8.0% simple interest. The Company is obligated to pay interest monthly after the Company receives its first production payment from a well associated with the Participation Agreement and/or in which the Company has or has had a working interest and in accordance with the terms of the promissory note.

Supplemental line of credit

        On October 13, 2016, the Company entered into a revolving line of credit facility agreement (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 the Company to borrow up to $10.0 million to pay costs associated with its acquisition and development of oil and gas properties in the Wattenberg Field. The original maturity date for the supplemental line of credit was April 13, 2017.

        As amended on March 30, 2017, the Company 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. (Note 14)

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 6—DEBT (Continued)

        As of December 31, 2016, the outstanding balance on the supplemental line of credit was $7,088,698 net of deferred financing fees of $16,302, plus accrued interest of $50,422. During the year ended December 31, 2016, the Company borrowed $7,105,000 under the supplemental line of credit, primarily to fund the acquisition and development of crude oil and natural gas properties (Note 3 and Note 12). During the year ended December 31, 2016, the Company recorded interest expense of $50,422 related to the supplemental line of credit.

Convertible notes

        On December 30, 2016, the Company completed the first closing of a private placement of 200 units, each unit consisting of a convertible promissory note in the principal amount of $50,000 ("Notes") and 33,333 common stock purchase warrants ("Warrants"). Each Note sold in the private placement is one of a series of similar Notes designated the "10% Unsecured Convertible Promissory Notes" with the series totaling $10,000,000. The Notes bear interest at the rate of 10% per year and are due and payable on December 31, 2018. Interest is payable semi-annually beginning June 30, 2017 and until the Notes are paid in full. At any time after issuance, the principal amount of the Notes and any accrued but unpaid interest are convertible into shares of the Company's common stock at the option of the holder at the rate of $1.50 per share. Each Warrant allows the holder to purchase one share of the Company's common stock at a price of $3.00 per share at any time on or before December 31, 2019. (Note 9)

        Related to the December 31, 2016 closing, the Company sold 38.85 units consisting of $1,942,600 principal amount of Notes and Warrants to purchase 1,294,987 shares of common stock. The Company received gross proceeds of $1,942,600 and net proceeds of $1,747,340 after placement agent fees and expenses. The Company also issued warrants to purchase 129,526 shares of common stock to the placement agent. (Note 9). The value of the warrants of $174,475 has been recorded as a discount and will be amortized to interest expense using the effective interest method through the maturity date of the Notes.

        The Company recorded a debt discount of $750,963 related to the intrinsic value of the beneficial conversion feature embedded in the Notes. The discount will be amortized to interest expense using the effective interest method through the maturity date of the Notes.

        In January and February 2017, the Company completed the private placement for a total of 200 units or $10,000,000 in total. (Note 14)

        The following table reflects the net amounts recorded as Convertible Notes at December 31, 2016 and 2015:

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 7—ASSET RETIREMENT OBLIGATION

        For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended December 31, 2016, the Company assumed an inflation rate of 2.0%, an estimated average asset life of 13.0 years, and a credit adjusted risk free interest rate of 9.48%.

        The following reconciles the value of the asset retirement obligation for the periods presented:

        Accretion expense recorded for the year ended December 31, 2016 was $30,483, accretion expense recorded for the year ended December 31, 2015 was $3,061.

NOTE 8—ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

        Accounts payable and accrued liability balances were comprised of trade accounts payable and accrued liabilities, drilling advances, crude oil and natural gas distributions payable and are shown below:

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 9—SHAREHOLDERS' EQUITY

Common Stock

        As of December 31, 2016 and December 31, 2015, the Company had 100,000,000 shares of common stock authorized with a par value of $0.001 per share. As of December 31, 2016 and December 31, 2015, 21,964,282 and 21,633,191 shares were issued and outstanding, respectively.

        Activity for the year ended December 31, 2016 included the following:

•

In January 2016, the Company sold 95,000 shares of common stock at $1.00 per share to one accredited investor pursuant to a private placement of its common stock.



•

On April 8, 2016, the Company issued 50,000 shares of common stock valued at $0.73 per share to an investor relations company in connection with the certain services to be provided pursuant to an investor relations agreement.



•

On May 4, 2016, the Company issued an aggregate of 50,000 shares of common stock valued at $1.01 per share to two of the Company's directors in connection with their appointment to the Board (Note 9).



•

On July 5, 2016, the Company issued 25,000 shares of common stock valued at $1.60 per share to a director in connection with his appointment to the Board (Note 9).



•

On July 22, 2016, the Company issued 8,333 shares of common stock valued at $1.65 per share and on August 22, 2016 the Company issued 8,333 shares of common stock valued at $1.40 per share, each to an investor relations company in connection with certain services to be provided to the Company.



•

On August 30, 2016, the Company issued 50,000 shares of common stock valued at $1.44 per share to an investor relations company in connection with a termination agreement.



•

On November 11, 2016, the Company issued 14,425 shares of common stock valued at $1.85 per share to an individual in connection with the consideration and acquisition of the certain oil and gas leases.



•

On December 5, 2016, the Company issued 30,000 shares of common stock valued at $1.89 per share in connection with the exchange of interests in certain oil and gas assets in Buck Peak prospect.

        Activity for the year ended December 31, 2015 included the following:

•

4,600,000 shares of common stock were issued under the terms of the public offering; 340,000 shares at $1.00 per share sold by the Company prior to engaging an underwriter and 4,260,000 shares at $0.90 per share to an underwriter. The Company received gross proceeds of $4,174,000, and incurred offering costs, commissions and expenses related to the offering of $364,999.



•

In December 2015, 25,000 shares of common stock were issued at $1.00 per share to one accredited investor pursuant to a private placement of the Company's common stock.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 9—SHAREHOLDERS' EQUITY (Continued)

Preferred Stock

        As of December 31, 2016, the Company had 10,000,000 shares of preferred stock authorized with a par value of $0.01 per share. As of December 31, 2016 and 2015, there were no shares of preferred stock issued or outstanding.

Warrants

        The table below summarizes warrants outstanding as of December 31, 2016:

        Activity for the year ended December 31, 2016:

•

On December 30, 2016, the Company issued 129,516 warrants. The warrants are exercisable at $1.50 per share and expire on December 31, 2021. The warrants were issued in connection with the closing of the first round of the Company's private placement. (Note 6)



•

On December 30, 2016, the Company issued 1,294,987 warrants. The warrants are exercisable at $3.00 per share and expire on December 31, 2019. The warrants were issued in connection with the closing of the first round of the Company's private placement. (Note 6)

        Activity for the year ended December 31, 2015:

•

On November 20, 2015, the Company issued 255,600 warrants. The warrants are exercisable at $1.25 per share and expire on November 12, 2020.

NOTE 10—STOCK BASED COMPENSATION

        On August 18, 2016, the Company's Board of Directors adopted the Amended and Restated PetroShare Corp. Equity Incentive Plan (the "Plan"), which replaced and restated the Company's original equity incentive plan. The Plan terminates by its terms on August 17, 2026. Among other things, the Plan increased the number of shares of common stock reserved for issuance thereunder from 5,000,000 to 10,000,000 shares. The Company's shareholders approved the Plan at the Company's annual meeting of shareholders on September 8, 2016.

        During the year ended December 31, 2016, the Board of Directors granted non-qualified options to employees, directors and consultants of the Company under the Plan to acquire 2,275,000 shares of common stock.

        During the year ended December 31, 2015, the Board of Directors granted non-qualified options to employees and consultants of the Company under the Plan to acquire 275,000 of common stock. The options are exercisable at $1.00 and expire three years from the date of grant.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 10—STOCK BASED COMPENSATION (Continued)

        A summary of activity under the Plan for the years ended December 31, 2016 and 2015 is as follows:

        The fair value of each share-based award was estimated on the date of the grant using the Black-Scholes pricing model that incorporates key assumptions including volatility, dividend yield and risk-free interest rates. As the Company's common stock has limited historical trading data, the expected stock price volatility is based primarily on the historical volatility of a group of publicly-traded companies that share similar operating metrics and histories. The expected term of the awards represents the period of time that management anticipates awards will be outstanding. As there was insufficient historical data available to ascertain a forfeiture rate, the plain vanilla method was applied in calculating the expected term of the options. The risk-free rates for the periods within the contractual life of the options are based on the US Treasury bond rate in effect at the time of the grant for bonds with maturity dates at the expected term of the options. The Company has never paid dividends on its common stock and currently does not intend to do so, and as such, the expected dividend yield is zero. Compensation expense related to stock options was recorded net of estimated forfeitures, which for options remaining at December 31, 2016, the Company expects no additional forfeitures.

        The table below summarizes assumptions utilized in the Black-Scholes pricing model for the years ended 2016 and 2015:

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 10—STOCK BASED COMPENSATION (Continued)

        During the years ended December 31, 2016 and 2015, the Company recorded share-based compensation of $1,140,967 and $191,205, respectively. Unvested share-based compensation at December 31, 2016 amounted to $1,434,961.

NOTE 11—PROVISION FOR INCOME TAXES

        Deferred taxes are provided on a liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carry-forwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax basis. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

        The Company has analyzed filing positions in all of the federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in these jurisdictions. No uncertain tax positions have been identified as of December 31, 2016.

        The Company is in a position of cumulative reporting losses for the current and preceding reporting periods. The volatility of energy prices is not readily determinable by management. At this date, this fact pattern does not allow the Company to project sufficient sources of future taxable income to offset tax loss carry-forwards and net deferred tax assets. Under these circumstances, it is management's opinion that the realization of these tax attributes does not reach the "more likely than not criteria" under ASC 740, "Income Taxes." As a result, the Company's deferred tax assets as of December 31, 2016 and 2015 are subject to a full valuation allowance.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 11—PROVISION FOR INCOME TAXES (Continued)

        Net deferred tax assets and liabilities consist of the following components as of December 31, 2016 and 2015:

        The income tax provision differs from the amount of income tax determined by applying the US federal tax rate to the pretax loss from continuing operations for the years ended December 31, 2016 and 2015 due to the following:

        At December 31, 2016, the Company had net operating loss carry-forwards of approximately $11,570,570 that may be offset against future taxable income from the years 2016 through 2036.

        Due to the change in ownership provisions of the Tax Reform Act of 1986, net operating loss carry forwards for federal income tax reporting purposes are subject to annual limitations. Should a change in ownership occur, net operating loss carry forwards may be limited as to use in future years.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 11—PROVISION FOR INCOME TAXES (Continued)

        The Company files income tax returns in the US federal jurisdiction and in the State of Colorado. The Company is currently subject to US federal, state and local income tax examinations by tax authorities since inception of the Company.

NOTE 12—RELATED PARTY TRANSACTIONS

        In May 2015, the Company entered into the Participation Agreement with Providence. As Providence is also the Company's primary lender through which the Company currently maintains the $5,000,000 initial line of credit (Note 6). The Participation Agreement grants Providence the option to acquire up to a 50% interest and participate in any oil and gas development on acreage the Company obtains through its Kingdom services agreement and any other leases acquired by the Company within an area of mutual interest ("AMI"). 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 township, plus any other mutually agreeable areas. Providence currently holds 13.7% of the Company's outstanding common stock.

        At December 31, 2016, the Company had drawn $5,000,000 on the initial line of credit, and recorded related accrued interest of $302,477.

        On December 30, 2016 six officers and directors of the Company participated in Company's private placement by investing $500,000. (Note 6) The officers and directors participated on the same terms and conditions as third-party investors.

NOTE 13—COMMITMENTS AND CONTINGENCIES

Operating leases and agreements

        The Company leases its office facilities under a four year non-cancelable operating lease agreement expiring in October 2020. The following is a schedule by year of future minimum rental payments required under the operating lease agreement:

        Lease expense totaled $34,651 and $31,562 for the years ended December 31, 2016 and December 31, 2015 respectively.

Employment agreements

        On February 25, 2016, the Board of Directors approved a form of amended and restated executive employment in order to provide uniform terms of employment for the Company's executive officers.

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NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 13—COMMITMENTS AND CONTINGENCIES (Continued)

Effective March 1, 2016, the Company entered into an amended and restated employment agreement with each Stephen J. Foley and Fredrick J. Witsell. Pursuant to the amended and restated employment agreements, Mr. Foley and Mr. Witsell are compensated by the Company at the rate of $13,000 per month, or $156,000 per year. The Company also executed an executive agreement with William B. Lloyd, Chief Operating Officer, pursuant to which, as amended, Mr. Lloyd is compensated at the rate of $13,000 per month, or $156,000 per year. For each of the foregoing executives, the employment agreements provide for an initial term expiring on December 31, 2018 with an automatic renewal for successive one-year periods unless terminated in accordance with its terms and provisions for termination and payment of severance under various circumstances.

        On April 15, 2016, the Company entered into an executive employment agreement with William R. Givan, Vice President, Land, pursuant to which Mr. Givan is compensated at the rate of $10,833.33 per month, or $130,000 per year. Mr. Givan's employment agreement provides for an initial term expiring on April 14, 2017 with an automatic renewal for successive one-year periods unless terminated in accordance with its terms and provisions for termination and payment of severance under various circumstances.

NOTE 14—SUBSEQUENT EVENTS

Completion of Private Placement

        On January 20, 2017, the Company completed a second closing of a private placement in which it sold an additional 66.509 units, including $2,216,978 in Notes and Warrants to purchase 2,216,978 shares of common stock. The Company received gross proceeds of $3,325,450 from this second closing prior to the deduction of placement agent fees and other associated expenses. (Notes 6 and 9)

        On January 30, 2017, the Company completed the final closing of the private placement in which it sold an additional 94.64 units, including $3,154,601 in Notes and Warrants to purchase 3,154,601 shares of common stock. The Company received gross proceeds of $4,731,950 from the final closing and gross proceeds of $10,000,000 from the entire private placement prior to the deduction of placement agent fees and other associated expenses. (Notes 6 and 9)

        In connection with the private placement, the Company paid the placement agent and participating broker-dealers a total commission of $1,000,000 pursuant to a Placement Agent Agreement between the Company and the agent dated December 16, 2016 and amended on January 24, 2017. As additional compensation, the Company issued a placement agent warrant to purchase a total of 666,797 shares of the Company's common stock exercisable at a price of $1.50 per share. The placement agent warrants expire on December 31, 2021.

Supplemental Line of Credit

        As amended on March 30, 2017, the Company agreed to repay $3,552,500 in outstanding principal not later than April 13, 2017 and not to borrow additional funds against the supplemental line of credit in exchange for PEP III extending the maturity date of the supplemental line of credit until June 13, 2017. (Note 6)

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 14—SUBSEQUENT EVENTS (Continued)

Pending Acquisitions

        On February 23, 2017 the Company entered into a Purchase and Sale Agreement with an independent third party seller to acquire oil and gas leases totaling approximately 5,879 gross (2,930 net) acres, with an average net revenue interest of 84%, located in Weld and Adams Counties, Colorado. The total purchase price for the leases and associated assets is $2,582,500. Providence has agreed to purchase a 50% interest in the assets, which would reduce the Company's interest to 1,465 net acres. Subject to satisfaction of closing conditions, the Company will pay approximately $460,000 in cash and issue 450,000 shares of its common stock to the seller for its 50% share of the acquisition.

        On March 16, 2017, the Company entered into a Letter Agreement with an independent third party seller to acquire an 18.75% royalty interest covering approximately 291 net acres, located in Adams County, Colorado. The total purchase price for the interests is $1,138,800. If completed, the transaction will be effective April 1, 2017. If completed, the Company may sell 50% of its acquired interest to Providence.

NOTE 15—UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION

        The reserves at December 31, 2016, presented below were prepared by the independent engineering firm Cawley, Gillespie & Associates Inc. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine the proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of the Company's fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

        As the result of volatile crude oil prices coupled with nominal estimated reserve volumes, the Company's management deemed that is was not economically prudent to obtain a reserve report for the year December 31, 2015. Based on management's analysis, as of December 31, 2015, the Company has ascribed no value related to proved reserves. At December 31, 2014, the Company had ascribed a nominal value to the standardized measure of estimated discounted future net cash flows related to its reserves.

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 15—UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION (Continued)

        Analysis of Changes in Proved Reserves.    Estimated quantities of proved developed reserves (all of which are located within the United States), as well as the changes in proved developed reserves during the periods indicated, are presented in the following tables:

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 15—UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION (Continued)

        The values for the 2016 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2016. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $42.75 per barrel (West Texas Intermediate price) for crude oil and NGLs and $2.48 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2016 was $34.09 per barrel for oil, $2.69 per Mcf for natural gas and $14.44 per barrel for NGLs.

        The Company did not ascribe a value to its proved reserves as of December 31, 2015 due to immaterial quantity estimates and a volatile price environment.

        The values for the 2014 oil and natural gas reserves are based on the 12- month arithmetic average of the first day of the month prices for the period January through December, 31, 2014. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $94.99 per barrel (West Texas Intermediate price) for crude oil and NGLs and $4.35 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials.

        For the year ended December 31, 2016, the Company reported extensions and discoveries of 6,030,624 BOE as a result of drilling and completion activities during 2016. Additionally, during 2016 the Company purchased reserves of 287,999 BOE.

        For the year ended December 31, 2015, the Company had downward revisions of previous estimates of 122 BOE. The Company ascribed no value related to proved reserves at December 31, 2015.

        For the year ended December 31, 2014, the Company reported extensions discoveries of 250 BOE related to the drilling and completion of two wells.

Standardized Measure of Estimated Discounted Future Net Cash Flows to Proved Oil and Natural Gas Reserves (in thousands):

        The Company follows the guidelines prescribed in ASC 932, Extractive Activities—Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

        The information is based on estimates of proved reserves attributable to the Company's interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Cawley Gillespie & Associates, Inc., independent petroleum engineers.

        The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) the estimated future cash flows are compiled by applying the twelve month average of the first of the

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 15—UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION (Continued)

month prices of crude oil and natural gas relating to the Company's proved reserves to the year-end quantities of those reserves for reserves; (3) the future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; and (4) future net cash flows are discounted to present value by applying a discount rate of 10%.

        The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

        The following are the principal sources of change in the standardized measure (in thousands):

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PetroShare Corp.

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2016 and 2015

NOTE 15—UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION (Continued)

        The following summary sets forth the Company's future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities—Oil and Gas (in thousands):

Changes in Standardized Measure of Estimated Discounted Future Net Cash Flows

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        The change in our independent registered accountants was disclosed in a Current Report on Form 8-K dated May 1, 2015, and filed with the SEC on May 6, 2015. No other information is required by this Item.

ITEM 9A.    CONTROLS AND PROCEDURES

        During the fiscal period covered by this report, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the required time periods specified in the Commission's rules and forms and are designed to ensure that information required to be disclosed in our reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

        There were no changes in our internal control over financial reporting during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations Over Internal Controls

        Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

ITEM 9B.    OTHER INFORMATION

        Not applicable.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Identification of Directors and Executive Officers

        Our executive officers and directors as of March 30, 2017 and their respective ages, positions, and biographical information are set forth below:

        Each of our directors is serving a term which expires at the next annual meeting of our shareholders and until his successor is elected and qualified or until he resigns or is removed.

        The following information summarizes the business experience of each of our officers and directors for at least the last five years:

        Bill M. Conrad, Chairman.    Mr. Conrad has served as Chairman of our Board of Directors since our inception. He is presently an independent consultant, providing financial management services. From January 1990 until December 2012, Mr. Conrad served as the Vice-President, Chief Financial Officer and Director of MCM Capital Management, Inc., or MCM, a privately-held financial and management consulting firm. MCM assisted other companies in developing and implementing their business plans and capital formation strategies. In that capacity, Mr. Conrad participated in the organization or development of a number of companies in industries as diverse as oil and gas, real estate, and technology. From 2006 to the present, Mr. Conrad has served as a director of Gold Resource Corporation (NYSE MKT: GORO), a publicly traded gold and silver mining and exploration company, and since 2014 has served as Chairman of the Board. From May 2005 to March 2016, Mr. Conrad served as a director of Synergy Resources Corporation (NYSE MKT: SYRG), a publicly traded oil and gas exploration and production company. Mr. Conrad's extensive experience as a director of other extraction companies gives him valuable insight into the growth and development of our company. For these reasons, we believe Mr. Conrad is qualified to serve as a director of our company.

        Stephen J. Foley, Chief Executive Officer and Director.    Mr. Foley has served as our Chief Executive Officer since our inception. Prior to entering private business, Mr. Foley had a successful professional football career as a safety with the Denver Broncos football organization of the National Football League where he played for 11 seasons, from 1976 to 1986. In 1991, Mr. Foley founded and continues to serve as the president of FSI Development Inc., a privately-held construction and development company engaged in residential development and construction. In 2000, he founded and continues to serve as a managing member of FS Land, LLC, a privately-held real estate development company. From August 2011 to the present, he has served as Vice President, Secretary and Director of KBW Enterprises, Inc., an oil and gas servicing company. He holds a B.S. in Business Administration from Tulane University and serves on the Board of Denver Street Schools. Mr. Foley has extensive

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knowledge of our operations and of developing companies. For these reasons, we believe Mr. Foley is qualified to serve as a director of our company.

        Frederick J. Witsell, President and Director.    Mr. Witsell became our President in November 2012 and assumed the role of Secretary in August 2013. Mr. Witsell has over 35 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. From July 2011 to September 2012, Mr. Witsell served as the owner and General Manager of Premier Energy Supply, LLC, a consulting service firm in the oil and gas industry. From 2010 to 2011, Mr. Witsell served as Vice-President and General Manager of Monroe Gas Storage, an affiliate of High Sierra Energy Partners, and led the organization's projects and eventual divestiture in 2011. From 1999 to 2003, he was with Markwest Hydrocarbons (NYSE: MPLX) in the capacity of Vice-President of the Rocky Mountain Business Unit and responsible for the growth through capital programs and financial performance of the company's oil and gas operations in the United States and Canada. Mr. Witsell led the acquisition and eventual divestiture process of Markwest oil and gas assets. Prior to 1999 and at various times between 2003 and 2010 and in 2012, Mr. Witsell also served as an executive and co-founder of a series of small, privately-funded oil and gas companies with properties in North Dakota, Wyoming, Utah and Colorado. He was responsible for the growth and execution of capital programs, utilizing modern horizontal / directional drilling and completion technologies. He led the divestiture of these oil and gas companies. Mr. Witsell has a B.A. in Geology from Colorado College, an M.B.A. in Energy Management from the University of Denver, and is a member of Society of Petroleum Engineers, the American Association of Petroleum Geologists and the Rocky Mountain Association of Geologists. Our Board of Directors believes that Mr. Witsell is well qualified to serve as a director and executive officer of the company as a result of his extensive oil and gas industry experience including in areas of executive management and operations developed by serving as an executive officer of other oil and gas companies throughout his career. Mr. Witsell brings years of hands-on experience with oil and natural gas companies in many capacities and across multiple basins. For these reasons, we believe Mr. Witsell is qualified to serve as a director of our company.

        Paul D. Maniscalco, Chief Financial Officer.    Mr. Maniscalco became our Chief Financial Officer in January 2016. Mr. Maniscalco has been a principal with SJM Holdings, Inc., d/b/a SJM Accounting, Inc., an accounting and business advisory services firm headquartered in Englewood, Colorado, since 2008. From 2012 until 2014, Mr. Maniscalco served as interim Chief Financial Officer of Earthstone Energy Inc. (NYSE MKT: ESTE), a company engaged in the oil and gas industry. From 2010 until 2011, Mr. Maniscalco served as the interim Chief Financial Officer of GeoPetro Resources Company, a company engaged in the oil and gas industry with securities formerly traded on AMEX and currently traded on OTC Pink of OTCMarkets. Prior to joining SJM Accounting, Inc., Mr. Maniscalco was a senior manager for several accounting firms. Mr. Maniscalco holds a B.B.A. in Accounting and a B.H.S. in Healthcare Administration, each from Florida Atlantic University.

        William B. Lloyd, Chief Operating Officer.    Mr. Lloyd became our Chief Operating Officer in January 2016. Mr. Lloyd has over 35 years of experience in the oil and gas industry, serving in engineering, management, and senior leadership capacities. Prior to joining the Company, from 2007 until 2015, Mr. Lloyd served as the Senior Vice President of Operations for Cirque Resources L.P. ("Cirque"), a company engaged in the oil and gas industry. From 2006 until 2007, Mr. Lloyd served as the Western Region Drilling Manager for El Paso Exploration Company, which has oil and gas exploration and drilling operations in the Uintah Basin, Powder River Basin, and the Raton Basin. From 2002 until 2006, Mr. Lloyd served as Operations Director for ConocoPhillips Norway, during which time Mr. Lloyd managed well operations on multiple fixed platforms and exploratory drilling operations. Mr. Lloyd holds a Bachelor of Science in Petroleum Engineering from Montana Tech of the University of Montana.

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        William R. Givan, Vice President, Land.    Mr. Givan became the Vice President of Land in April 2016. Mr. Givan has over 35 years of experience in the oil and gas industry having been involved with every phase of land work relating to oil and gas production. Prior to joining the Company, from 2008 until 2015, Mr. Givan served as Regional Land Manager for Cirque and oversaw all land functions in Colorado, North Dakota, Montana, Wyoming and Utah. From 2004 until 2008, Mr. Givan served as Senior Landman for Bill Barrett Corporation overseeing all land functions in the Piceance Basin. Mr. Givan has worked on several large acquisitions on both the buyer's and seller's side and was instrumental in forming land departments in several oil and gas companies. Mr. Givan attended University of Colorado—Denver, School of Business and holds a Certified Professional Landman designation with the American Association of Professional Landmen. Mr. Givan is a member of land organizations in Denver, Wyoming, North Dakota & Montana and is a past President of the Montana Association of Professional Landmen. Effective April 1, 2017, Mr. Givan will be promoted to the position of Executive Vice President of Land.

        Scott C. Chandler, Director.    Mr. Chandler joined our Board of Directors in May 2016. Mr. Chandler has over 25 years of senior executive level management experience. He is the founder and owner of Franklin Court Partners, Inc., or FCP, an entity that provides management and financial consulting services in connection with developing business plans, securing financing and restructuring, a position he has held since 2002. Prior to founding FCP, Mr. Chandler was a founder, Chief Financial Officer and Senior Vice President for Rhythms Netconnections, Inc. (former NASDAQ: RTHM), a formerly publicly-traded corporation, where he served from 1998 to 2001. Mr. Chandler was a member of the senior management team that led this national provider of DSL networking and services prior to the sale of a majority of its assets to MCI Worldcom. From 1996 to 1998, Mr. Chandler served as President and Chief Executive Officer of C-COR Incorporated, or C-COR, a publicly-traded corporation and pioneer in the cable television industry and leading supplier of broadband telecommunications equipment. The common stock of C-COR was traded on the NASDAQ Global Market until the company was merged in late 2007. Prior to C-COR, Mr. Chandler held a number of positions at US WEST. Mr. Chandler's business career began with Arthur Andersen & Co. as a Senior Consultant/Accountant. He earned an M.B.A. from the Wharton School of Business at the University of Pennsylvania and a B.A. from Whitworth University. Mr. Chandler currently serves as a member of the board of directors of several privately-held and non-profit entities and has in the past served as a member of several public company boards, such as Cimetrix Incorporated (OTCMKTS: CMXX), Tollgrade Communications Inc. (NASDAQ: TLGD), and Paradyne Networks Inc. (NASDAQ: PDYN). He has been determined to be an audit committee financial expert under applicable rules of the Securities and Exchange Commission, or the SEC. Mr. Chandler's extensive audit and SEC reporting experience will give him valuable insight into our financial reporting and internal control and risk control procedures. For these reasons, we believe Mr. Chandler is qualified to serve as a director of our company.

        James H. Sinclair, Director.    Mr. Sinclair joined our Board of Directors in May 2016. Mr. Sinclair has over 31 years of experience in exploration, development, acquisitions and divestitures in the oil and gas industry. Since joining our board, Mr. Sinclair has served as a consultant to PEC E&P, LLC, which is the managing member of Providence, immediately prior to which he served as PEC's Chief Operating Officer, a position he held since April 2014. PEC invests primarily in non-operated oil and gas properties in the United States. In his role as a consultant to PEC, Mr. Sinclair assists with the identification, analysis, and recommendation of oil and gas investment opportunities. In 2010, Mr. Sinclair co-founded Petro Harvester O&G, LLC, an oil and gas production company, where he served as President and Chief Operating Officer until 2012. From 1993 until 2008, Mr. Sinclair served as the Exploration Manager, District Manager of Mississippi, Director of Acquisitions, and Vice President of Exploration and Geosciences of Denbury Resources Inc. (NYSE: DNR), a publicly traded exploration and production company with operations primarily in the Gulf Coast area and offshore Gulf of Mexico. Mr. Sinclair received a B.S. in Geoscience from Northeast Louisiana University.

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Mr. Sinclair has significant experience in the management and financing of oil and gas companies. For these reasons, we believe Mr. Sinclair is qualified to serve as a director of our company.

        Douglas R. Harris, Director.    Mr. Harris joined our Board of Directors in July 2016. Mr. Harris has over 38 years of experience in the oil and gas industry. In March 2015, he founded and currently serves as the Chief Operating Officer of Axia Energy II, LLC, a company that identifies and develops oil and gas prospects throughout the United States. From 2009 to 2015, Mr. Harris served as co-founder and Chief Operating Officer of Axia Energy I, LLC, also a company that identifies and develops oil and gas prospects throughout the United States. Prior to that, he served as the co-founder and Vice President of Operations for Orion Energy Partners, Inc., a position he held from 2004 to 2009, and the Vice President and General Manager of the Denver Division of Tom Brown Inc., a position he held from 2001 to 2004. From 1986 to 2001, Mr. Harris served in numerous positions for Burlington Resources Inc., culminating as the Vice President of Production Operations in its Calgary, Alberta offices. He serves on the board of directors of a number of privately-held companies. Mr. Harris holds a B.S. in Civil Engineering from New Mexico State University. For these reasons, we believe Mr. Harris is qualified to serve as a director of our company.

Code of Ethics

        On March 1, 2016, the Company's Board of Directors adopted a code of ethics, a copy of which is available on our website at www.petrosharecorp.com. We believe that the code of ethics is reasonably designed to deter wrongdoing and promote honest and ethical conduct; provide full, fair, accurate, timely and understandable disclosure in public reports; comply with applicable laws; ensure prompt internal reporting of code violations; and provide accountability for adherence to the code.

Director Independence

        Our Board of Directors has determined that Bill M. Conrad, Scott C. Chandler, James H. Sinclair, and Douglas R. Harris each qualify as "independent" in accordance with Section 803(A) of the NYSE MKT Company Guide. During the review, our Board of Directors considered relationships and transactions during 2016 and during the past three fiscal years between each director or any member of his immediate family, on the one hand, and our company and our affiliates, on the other hand. The purpose of this review was to determine whether any such relationships or transactions were inconsistent with a determination that the director is independent. The only compensation or remuneration that we provide to Messrs. Conrad, Chandler, Sinclair, or Harris during their tenures as a director is compensation as a non-employee director. Neither Messrs. Conrad, Chandler, Sinclair, or Harris, nor any members of their families, have participated in any transaction with us that would disqualify him as an "independent" director under the standard described above. Stephen J. Foley and Frederick J. Witsell do not qualify as "independent" because they are executive officers.

Board Committees

        Audit Committee.    Messrs. Conrad, Chandler, and Harris serve as members of our audit committee and Mr. Chandler serves as the Chairman of the audit committee. The Board has determined that Messrs. Conrad, Chandler, and Harris are each "independent" in accordance with the NYSE MKT definition of independence, that Mr. Chandler is a "financial expert," as defined by SEC regulations, and each has the related financial management expertise within the meaning of the NYSE MKT rules.

        The primary purpose of the audit committee is to act on behalf of our Board of Directors in its oversight of all material aspects of our accounting and financial reporting processes, internal controls, and audit function, including our compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Pursuant to its charter, our audit committee reviews on an on-going basis for potential conflicts of

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interest, and approves if appropriate, all of our related party transactions. For purposes of the audit committee charter, related party transactions means those transaction required to be disclosed pursuant to SEC regulations. In addition, the audit committee reviews, acts on, and reports to our Board of Directors with respect to various auditing and accounting matters, including the selection of our independent registered public accounting firm, the scope of annual audits, fees to be paid to our independent registered public accounting firm, the performance of our independent registered public accounting firm, our accounting practices, and our internal controls and legal compliance functions. The audit committee also reviews, prior to publication, our reports to the SEC on Forms 10-K and 10-Q. The audit committee operates pursuant to a written charter, which is available on our website, www.petrosharecorp.com. The charter describes the nature and scope of responsibilities of the audit committee.

        The Audit Committee's policy is to pre-approve all audit and non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. The independent auditors are required to periodically report to the Audit Committee regarding the extent of services provided by the independent registered public accounting firm in accordance with such pre-approval.

        During the year ended December 31, 2016, the Audit Committee approved in advance all audit and non-audit services to be provided by SingerLewak LLP. The Audit Committee has determined that the non-audit services rendered by SingerLewak LLP during fiscal years 2016 and 2015 were compatible with maintaining the independence of the respective independent registered public accounting firms.

        Compensation Committee.    We do not currently have a compensation committee. Under a policy adopted by our Board, the compensation of our chief executive officer and all other executive officers will be determined by a majority of our independent directors. Executive officers who also serve on our Board of Directors do not vote on matters pertaining to their own personal compensation. Although we may form a compensation committee in the future, there is no assurance as to when or whether we will do so.

        Nominating and Corporate Governance Committee.    We do not currently have a nominating and corporate governance committee. Board of Directors nominations will be selected by a majority of our independent directors.

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ITEM 11.    EXECUTIVE COMPENSATION

Compensation to Officers of the Company

        The following table contains compensation data for our executive officers for the fiscal years ended December 31, 2016 and 2015:

Summary Compensation Table

        On February 25, 2016, the Board of Directors approved a form of amended and restated executive employment in order to provide uniform terms of employment for our executive officers. Effective March 1, 2016, we entered into an amended and restated employment agreement with each Stephen J. Foley and Fredrick J. Witsell. Pursuant to the amended and restated employment agreements, Messrs. Foley and Witsell are each compensated by us at the rate of $13,000 per month, or $156,000 per year. We entered into an executive employment agreement with William B. Lloyd, Chief Operating Officer, effective January 1, 2016 and amended on March 1, 2016 pursuant to which Mr. Lloyd is compensated at the rate of $13,000 per month, or $156,000 per year. For each of the foregoing executives, the employment agreements provide for an initial term expiring on December 31, 2018 with an automatic renewal for successive one-year periods unless terminated in accordance with its terms and provisions for termination and payment of severance under various circumstances.

        On April 15, 2016, we entered into an executive employment agreement with William R. Givan, Vice President, Land, pursuant to which Mr. Givan is compensated by us at the rate of $10,833.33 per month. Mr. Givan's employment agreement provides for an initial term expiring on April 14, 2017 with an automatic renewal for successive one-year periods unless terminated in accordance with its terms and provisions for termination and payment of severance under various circumstances. In December 2016, the Board of Directors awarded a $25,000 bonus to Mr. Givan in recognition of his efforts in the achievements of our company during 2016.

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Outstanding Equity Awards at Year End

        The following table sets forth outstanding stock option awards held by our executive officers as of December 31, 2016:

Director Compensation

        Bill M. Conrad, the Chairman of our Board of Directors, was paid a director's fee in the amount of $6,500 per month beginning November 2013 and continuing through February 2016. Effective March 1, 2016, Mr. Conrad's compensation was increased to $10,000 per month. Scott C. Chandler, James H. Sinclair, and Douglas R. Harris are each are paid a director's fee in the amount of $3,000 per quarter beginning the first month of their appointment to the Board. In connection with their appointment to the Board, Mr. Chandler and Mr. Sinclair were each granted 25,000 shares of our common stock and options to purchase an additional 25,000 shares of our common stock, which options are exercisable at a price of $1.10 per share until December 31, 2022. In connection with his appointment to our Board of Directors, Mr. Harris was granted 25,000 shares of our common stock and options to purchase an additional 25,000 shares of our common stock, which options are exercisable at a price of $1.60 per share until December 31, 2022.

        Messrs. Foley and Witsell are not compensated in their capacities as directors. We do, however, reimburse all of our directors for reasonable and necessary expenses incurred by them in that capacity.

        We will review our compensation arrangements periodically in the future and may change our compensation policies as our business needs dictate and our resources permit.

        The following table sets forth with respect to the directors, compensation information inclusive of equity awards and payments made during the year ended December 31, 2016 in the director's capacity as such:

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ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial Ownership

        As of March 30, 2017, there were a total of 21,964,282 shares of our common stock outstanding, our only class of voting securities currently outstanding. The following table describes the ownership of our voting securities before the offering and after the offering, by: (i) each of our named executive officers and directors; (ii) all of our officers and directors as a group; and (iii) each shareholder known us to own beneficially more than 5% of our common stock. Unless otherwise stated, the address of each of the individuals is our address, 9635 Maroon Circle, Suite 400, Englewood, Colorado 80112.

        In calculating the percentage ownership for each shareholder, we assumed that any options, warrants, or convertible promissory notes owned by an individual and exercisable or convertible within 60 days are exercised or converted, but not the options, warrants, or convertible promissory notes owned by any other individual.

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Securities Authorized for Issuance Under Equity Compensation Plans

        On August 18, 2016, our Board of Directors adopted the Amended and Restated PetroShare Corp. Equity Incentive Plan, or the Amended Plan, which replaced and restated our original equity incentive plan. The Amended Plan terminates by its terms on August 17, 2026. Among other things, the Amended Plan increased the number of shares of common stock reserved for issuance thereunder from 5,000,000 to 10,000,000 shares. Our shareholders approved the Amended Plan at our annual meeting of shareholders on September 8, 2016. Set forth below is information as of December 31, 2016, with respect to compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance:

Equity Incentive Plan Information

        Under the Amended Plan, incentive or non-qualified stock options and/or grants of restricted or non-restricted common stock may be issued to key persons. Key persons include officers, directors, employees, consultants and others providing service to us. The Amended Plan was established to advance the interests of our company and our shareholders by affording key persons, upon whose judgment, initiative, and efforts we may rely for the successful conduct of our businesses, an opportunity for investment in our company and the incentive advantages inherent in stock ownership in our company. The Amended Plan gives our Board of Directors broad authority to grant options and make stock grants to key persons selected by the board while considering criteria such as employment position or other relationship with us, duties and responsibilities, ability, productivity, length of service or association, morale, interest in us, recommendations by supervisors, and other matters, and to set

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the option price, term of option, and other broad authorities. Options may be granted at a price determined by our Board of Directors in its sole discretion, but in no event at a price less than fair market value (as defined in the Amended Plan), and may have a term up to 10 years.

        Options granted under the Amended Plan may generally be exercised by paying the exercise price to us in cash at the time of exercise. In the event the exercise price is expected to exceed $2,000 in the aggregate, the Board of Directors may allow the option holder to surrender shares already owned by him or her in satisfaction of the exercise price, or by "attestation," where a portion of the shares underlying the option are surrendered in payment.

        When a non-qualified option is exercised, the holder is subject to tax on the difference between the exercise price of the option and the fair market value of the stock on the date of exercise at ordinary rates. We receive a corresponding deduction for income tax purposes in that case as well. Recipients of stock grants are subject to tax on the fair market value of the stock on the date of grant and we receive a corresponding deduction.

        Shares issued upon exercise of options or upon stock grants under the Amended Plan are "restricted securities" as defined under the Securities Act unless a registration statement covering such shares is effective. Restricted shares cannot be freely sold and must be sold pursuant to an exemption from registration (such as Rule 144) which exemptions typically impose conditions on the sale of the shares.

Changes in Control

        We know of no arrangements that may result in a change in control of our company.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The following includes a summary of transactions, during our last two fiscal years, to which we have been a party, in which the amount involved in the transaction exceeded $120,000 or one percent of the average of our total assets at fiscal year-end for the last two fiscal years, and in which any of our directors, executive officers or, to our knowledge, beneficial owners of more than 5% of our capital stock or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than equity and other compensation, termination, change in control and other arrangements which are described under "Director Compensation" and "Executive Compensation."

Providence Energy Operators, LLC

Revolving Line of Credit Facility Agreement

        On May 13, 2015, we entered into the initial line of credit with Providence. The initial line of credit was amended on February 24, 2016 to extend the maturity date to June 1, 2018. Under the terms of the initial line of credit, we are permitted to borrow up to $5.0 million. Interest on the outstanding principal balance of the initial line of credit accrues at an annual rate of 8% simple interest per year. As of March 30, 2017, the outstanding balance on the initial line of credit was $5.0 million, plus approximately $401,000 of accrued but unpaid interest.

Participation Agreement

        On May 13, 2015, we entered into the participation agreement with Providence. Under the terms of the participation agreement, we assigned an undivided 50% to our right, title and interest in and to our then existing leases. 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

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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. The payments made to us by Providence were based on the pro rata share of our acquisition costs, which in turn were determined by negotiations with independent third parties.

        As of March 30, 2017, Providence owns 13.7% of our common stock.

Private Placement

        During December 2016 and January 2017, we completed a private placement of 200 units at an offering price of $50,000 per unit. Certain of the units were purchased by our directors and officers in the following amounts and on the following dates on the same terms and conditions as independent third parties:

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit Fees and Services

        For the fiscal years ended December 31, 2016 and 2015, professional services were performed by SingerLewak LLP. The aggregate fees for the fiscal years ended December 31, 2016 and 2015 were as follows:

        The Audit Committee's policy is to pre-approve all audit and non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. The independent auditors are required to periodically report to the Audit Committee regarding the extent of services provided by the independent registered public accounting firm in accordance with such pre-approval.

        During the year ended December 31, 2016, the Audit Committee approved in advance all audit and non-audit services to be provided by SingerLewak LLP. The Audit Committee has determined that the non-audit services rendered by SingerLewak LLP during fiscal years 2016 and 2015 were compatible with maintaining the independence of the respective independent registered public accounting firms.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES

(a)

(1)  Financial Statements:

        See Item 8 of this report for a list of financial statements.

(a)

(3)  Exhibits required by Item 601 of Regulation S-K

        The information required by this Section (a)(3) of Item 15 is set forth on the exhibit index that follows the Signatures page of this Form 10-K.

ITEM 16.    FORM 10-K SUMMARY

        None.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

        In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

        No annual report, proxy statement, form of proxy, or other proxy soliciting material has been sent to the registrant's security holders. The registrant undertakes to furnish to the Commission any annual report or proxy material which it delivers to security holders in connection with an annual meeting.

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EXHIBIT INDEX

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