UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2018
Or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________to _____________

Commission File Number 001-37943

PETROSHARE CORP.

(Exact name of registrant as specified in its charter)

Colorado

(State or other jurisdiction of incorporation or organization)

46-1454523

(I.R.S. Employer Identification No.)

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 ☐ No ☒

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 ☒ No ☐

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 ☐ No ☒

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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. ☒

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

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ⌧
	Emerging growth company ⌧

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 ☐ No ☒

As of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, there were 18,103,011 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 29, 2018, was $26,430,396.

On April 2, 2019, there were 28,077,337 shares of the Company’s common stock outstanding.

Documents incorporated by reference: None

PETROSHARE CORP.

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

PART I
Items 1 and 2.	Business and Properties	2
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	22
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 8.	Consolidated Financial Statements and Supplementary Data	32
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	64
Item 9A.	Controls and Procedures	64
Item 9B.	Other Information	65
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	68
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	70
Item 13.	Certain Relationships and Related Transactions, and Director Independence	71
Item 14.	Principal Accounting Fees and Services	72
PART IV
Item 15.	Exhibits, Financial Statements Schedules	72

ADDITIONAL INFORMATION

Descriptions of agreements or other documents in this report are intended as summaries and are not necessarily complete. Please refer to the agreements or other documents filed or incorporated herein by reference as exhibits. Please see Item 15. Exhibits and Financial Statement Schedules at the end of this report for a complete list of those exhibits.

Cautionary Language Regarding Forward-Looking Statements

Please see Cautionary Language Regarding Forward-Looking Statements on page 21 of this report for important information contained herein.

Glossary

Please see page 30 for a glossary of certain terms used in this report.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Our History and Organization

PetroShare Corp. (“we,” “our,” “us” or the “Company”) is an independent oil and gas company incorporated 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 2016, our operational focus has been in the Wattenberg Field in the Denver-Julesburg Basin, or DJ Basin, in northeast Colorado. We believe the Wattenberg Field is one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara and Codell. The area has produced oil and natural gas since the 1970s and benefits from an established infrastructure and seasoned service providers.

All of our properties are located in Colorado. As of April 3, 2019, we had an interest in 58 gross (24.4 net) productive wells and 31,656 gross (9,687 net) acres of oil and gas properties. As of December 31, 2018, we were producing hydrocarbons at the rate of approximately 2,232 BOE/D. At December 31, 2018, we had an estimated 2,910.7 MBOE of proved developed reserves and 4,414.1 MBOE of proved undeveloped reserves, including reserves associated with properties that we sold in February, 2019. Our net proved reserves at December 31, 2018 were comprised of approximately 60% oil and NGLs (collectively, liquids).

Our strategy to date has been to focus on acquiring and developing crude oil and natural gas properties in 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 lower commodity price environments.

During 2018, we completed and brought into production our first operated horizontal wells, located on our Shook Pad in northwest Adams County. See “Recent Developments-Shook Pad,” below. In any drilling, we expect that our retained working interest will be determined based upon factors such as level of interest ownership, well costs and geologic and engineering risk. See Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for more information.

In May 2015, in connection with a credit agreement, we entered into a participation agreement with Providence Energy Operators, LLC (“PEO”). PEO is an affiliate of Providence Energy Corp., a privately-held multi-million-dollar acquirer of oil and gas properties throughout the United States. As discussed elsewhere in this report, an affiliate of PEO is a major participant in our principal lender group through which we currently maintain a $25.0 million Secured Credit Facility. PEO is also the beneficial owner of 11.6% of our outstanding common stock. The participation agreement grants PEO the option to acquire up to a 50% interest and participate in any oil and gas development on acreage we obtain within an area of mutual interest (AMI) near our Southern Core area. To date, PEO has exercised its option under the participation agreement or otherwise participated or agreed to participate in all of our acreage acquisitions and drilling operations.

Our executive and administrative offices are currently located at 9635 Maroon Circle, Suite 400, Englewood, Colorado 80112 and we maintain a website at www.petrosharecorp.com. We commenced filing reports under the Securities Exchange Act of 1934, as amended, or the Exchange Act, in February 2015, when we completed our initial public offering. 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 at www.petrosharecorp.com.

Recent Developments

Following is a summary of certain significant events to which we have been party since the beginning of 2018:

Shook Pad

During 2018, we completed and placed into production our 14-well Shook pad in Northwest Adams County. The pad, started in 2017, contains 14 mid-length lateral wells and is connected to the White Cliffs pipeline through which we transport hydrocarbons for sale. We own an approximate working interest of 49% in the wells, and our partner PEO owns approximately 49%.

Secured Credit Facility

In December 2017, we completed the first closing of $5.0 million of what ultimately became a $25.0 million Secured Credit Facility, all of which was used to reduce our accounts payable, accrued liabilities and a line of credit. On February 1, 2018, we finalized the Secured Credit Facility with Providence Wattenberg Ltd., a Texas limited partnership and affiliate of PEO, as lender and the administrative agent, and 5NR Wattenberg, LLC, a Texas limited liability company, as lender (collectively, the “Secured Lenders”) pursuant to which the Lenders loaned us and additional $20 million under the Secured Credit Facility. This facility allowed us to partially or fully repay a previously-outstanding line of credit and extend a line of credit that matured in December 2017. The remaining capital was utilized for pipeline construction, drilling and completion activities and additional working capital. As of December 31, 2018, we were in default under the Secured Credit Facility based a violations of certain covenants contained in the Secured Credit Facility. On April 2, 2019, the Secured Lenders delivered their formal Notice of Default under the terms of the Secured Credit Facility. The Notice declared that all amounts outstanding were immediately due and payable. See “MANAGEMENT’S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATION”

Our biggest challenge during 2018, and to which we devoted a significant amount of our time and resources during the year and beyond, was our lack of liquidity and capital. To address those challenges, we initiated a series of efforts to improve our working capital position. In addition to the Secured Credit Facility discussed above, we also undertook efforts to sell some of our assets to raise cash. This effort resulted in the sale of our non-operated oil and gas wells, discussed in more detail below.

Non-Operated Sale

On February 27, 2019, we completed the sale of nearly all of our non-operated assets. The assets we sold (collectively, the “Assets”) include all non-operated horizontal wells in which we had an interest, as well as the leases on which those wells are located, oil, gas and other hydrocarbons produced from the leases on or after the effective date of sale, related equipment, machinery, fixtures and other personal property, surface rights and contracts. The effective date of the asset sale was January 1, 2019.

The sale does not include any of our interest in the operated wells comprising our Shook Pad. The net purchase price received for the Assets was approximately $15.3 million in cash, net of closing costs, adjustments and broker’s fees. The proceeds of the sale were applied by the Secured Lenders to reduce balances owed to them under the terms of the Secured Credit Facility.

Resignation of Directors

On March 22, 2019, we received the resignations of three members of our Board of Directors: Michael Allen, Joseph Drysdale and Cullen Schaar. The notices stated that the resignations were effective immediately. These directors had been appointed by the Secured Lenders under the terms of the Secured Credit Facility. None of the directors expressed any disagreement with the Company or its Board of Directors that precipitated the resignations. The Board of Directors plans to continue with a reduced membership of six directors.

Proposed Legislation in Colorado

Recently proposed COLORADO SB-181 (“SB-181”), a state senate bill currently pending in the Colorado legislature, would introduce significant changes to the regulation of oil and gas development in the State. If passed and signed by the governor, it would change the mandate of the Colorado Oil and Gas Conservation Commission (“COGCC”) from that of promoting development of oil and gas to prioritizing the protection of public safety, health, welfare, and the environment. In addition to changing the mandate of the COGCC, it would change the composition of the Commission to include more health and safety advocates. The proposed legislation would also allow for more local control over the development of oil and gas properties and could alter the State statute allowing for “forced pooling” of oil and gas properties. This proposed legislation could significantly impact our ability to obtain permits to drill. See “Regulatory Environment” for additional information regarding this proposed legislation.

On March 20, 2019, the Adams County commissioners voted to place a six-month moratorium on the issuance of drilling permits in unincorporated portions of the County due to the pendency of proposed SB-181. A significant portion of our properties are located in Adams County, although some of the properties are located within the limits of the City of Brighton. It is not yet clear whether municipalities like Brighton will follow Adams County and consider a moratorium while the SB 191 is pending.

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.

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 even lower price environments.

The following map depicts our properties in the Southern Core:

We currently possess an inventory of approximately 88 gross wells that are permitted or pending final permit approval for horizontal drilling locations within our Southern Core Area. Of that amount, there are 56 locations that are fully permitted and available for drilling, subject to available capital. There are a number of remaining locations which are potential infill horizontal wells located in and around current drilling spacing units established under applicable industry rules. We have not included certain of these potential infill horizontal drilling locations in our proved undeveloped or probable 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. Our Shook pad, on which we have 14 producing horizontal wells, is located in the Todd Creek focus area. We have also permitted eights wells on the Corcilius pad located within this focus area, however, our plans to drill and complete the Corcilius wells in 2019 are dependent on receiving final approval from Adams County and our availability of capital. Our working interest in the Shook pad wells averages approximately 49%. The Shook Pad and its associated production represent a significant portion of our cash flow in 2018 and 2019 to date.

On February 27, 2019, we completed the sale of essentially all of our non-operated production and proven undeveloped locations in the Todd Creek Farms area. The non-operated wells and associated production provided a significant portion of our cash flow during 2018 prior to our bringing online our operated Shook production in the fourth quarter of 2018.

Wheels Up (aka South Brighton)

Our Wheels Up Area (formerly the South Brighton Focus Area) is east of our Todd Creek Farms prospect and sits in northern Adams County and southern Weld County. We acquired the majority of this acreage in 2016. In 2018, we completed acreage swaps and acquisitions with certain third parties to increase our leasehold interest to approximately 2,166 net acres with the right to acquire another 754 net acres under certain terms and conditions.

During 2018, we received state approved drilling permits as the operator for up to 56 (2 mile) horizontal wells with another 16 horizontal wells targeting the Niobrara and the Codell formations pending final state approval. In addition, we have eight (2 mile) horizontal well permits approved by the state for our Brighton Lakes Pad which we plan to drill in 2019, subject to receiving final approval from the City of Brighton and the availability of capital.

Runway

Our Runway prospect area is east of our Todd Creek Farms and our Wheels Up areas and lies principally within Adams County, Colorado, east of the Denver International Airport. We have leaseholds encompassing 20,118 gross (5,239 net) acres in the Runway prospect.

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 April 2, 2019:

	Productive Wells (1)
	Crude Oil		Natural Gas		Total
Location	Gross	Net	Gross	Net	Gross	Net
Southern Core	54	23.24	4.0	1.12	58	24.36
Total productive wells	54	23.24	4.0	1.12	58	24.36

(1)

The total wells in which we have an interest include 14 gross (6.95 net) horizontal wells on the Shook pad. The remaining wells are vertical wells, some of which are currently or periodically shut-in.

Developed and Undeveloped Acreage

The following table shows our developed and undeveloped acreage as of April 2, 2019:

			Acreage
	Developed		Undeveloped (1)		Total
Location	Gross	Net	Gross	Net	Gross	Net
Todd Creek Farms	2,016	615	—	—	2,016	615
Wheels up	4,312	1,840	947	327	5,259	2,167
Northern Wattenberg	80	32	2,036	803	2,116	835
South Brighton	—	—	549	268	549	268
Runway	12,284	4,400	7,834	839	20,118	5,239
Total acreage	18,692	6,887	11,366	2,237	30,058	9,124

(1)

Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of oil and natural gas regardless of whether the leasehold interest is classified as containing proved reserves.

Following industry standard, we generally acquire oil and gas leases without warranty of title, except as to claims made by, through, or under the transferor. Accordingly, we conduct due diligence as to title prior to acquiring properties, but we cannot guarantee that there will not be losses resulting from title defects. We obtain drilling title opinions and perform any necessary curative work prior to commencing drilling operations. We believe the leasehold 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 any additional leases by lease purchase, farm-in, or exchange.

Leases that are held by production generally remain in force so long as the well on the particular lease is producing or capable of producing. 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 the well begins producing or is capable of producing, 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 which are not held by production are scheduled to expire, including potential extensions, from 2019 until 2022. 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:

Leased Acres		Expiration of
Gross	Net	Lease
3,428	1,005	2019
7,020	759	2020
579	299	2021
339	174	2022

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 three years ended December 31, 2018. 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.

	For the Year Ended December 31,
	2018(2)		2017(1)		2016
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	28	8.4	21	2.95	—	—
Dry	—	—	—	—	—	—
Exploratory Wells
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Wells
Productive	28	8.4	21	2.95	—	—
Dry	—	—	—	—	—	—

(1)	Includes 21 non-operated wells, all of which were sold subsequent to December 31, 2018.
(2)	The 2018 results do not include 3 gross (0.2 net) wells which were in the process of drilling or completion as of December 31, 2018.

Sales Data

The following table shows the net sales volumes, average sales prices, and average production costs for wells in which we had an interest during the periods presented:

	Year Ended December 31,
	2018	2017	2016
Sales volumes
Oil (Bbls)	287,984	188,529	4,903
Gas (Mcf)	773,396	549,846	26,059
NGLs (Bbls)	55,811	50,111	1,511
BOE	472,694	330,281	10,756
Average sales price
Oil (per Bbl)	$58.37	$46.25	$48.91
Gas (per Mcf)	$3.18	$2.78	$2.62
NGLs (per Bbl)	$20.39	$17.20	$16.55
BOE	$43.17	$33.63	$30.97
Average production cost per BOE(1)	$5.65	$2.95	$19.18

(1)

Excludes production taxes - Total operating cost per BOE for 2018, 2017 and 2016 including production taxes amounted to $8.77, $5.19, and $19.21.

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 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, 2018 and 2017 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, natural gas and natural gas liquids reserves at December 31, 2018, all of which are located in Colorado, based on a reserve report prepared by Cawley Gillespie dated March 4, 2019.

			Natural Gas
	Crude Oil	Natural Gas	Liquids
	(MBbls)	(MMcf)	(MBbls)	MBOE
Proved Developed Producing	1,188	6,300.1	672.7	2,910.7
Proved Developed Non-Producing	-	-	-	-
Proved Undeveloped Reserves	2,005.2	11,232.6	536.8	4,414.1
Total Proved Reserves	3,193.1	17,532.7	1,209.6	7,324.8

At December 31, 2018, we had estimated total proved reserves of 7,324.8 MBOE, consisting of 3,193.1 MBbls of crude oil, 17,532.7 MMcf of natural gas, and 1,209.6 MBbls of natural gas liquids. We sold approximately 47% of our proved reserves in our non-operated properties that closed on February 27, 2019. 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 basis of the areas in which the gas reserves are located.

Proved Developed Reserves and Proved Undeveloped Reserves

At December 31, 2018, we had 2,910.7 MBOE of estimated proved developed reserves. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods.

At December 31, 2018, we had 4,414.1 MBOE of estimated 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 the proved undeveloped reserves were first included in our proved reserves considering our existing and anticipated capital resources. We also have included certain non-operated properties the operator of which has informed us of planned development within the next five years and in which we have plans to participate.

The table below presents summary information with respect to the changes in our proved undeveloped reserves for the year ended December 31, 2018:

	Total (MBOE)
Total proved undeveloped reserves:
Beginning of year	6,310.8
Revisions of previous estimates	570.9
Additions from discoveries, extensions and infill	69.7
Sales of reserves	(324.0)
Purchases of minerals in place	-
Removed for five-year rule	-
Conversions to proved developed	(2,213.3)
End of year	4,414.1

During 2018 we successfully converted 35% of our proved undeveloped reserves into proved developed producing reserves. The majority of the conversions were associated with the 14 operated wells known as the Shook wells, which were completed during the year. In addition, 21 non-operated PUD locations were developed by third parties, including 18 Ocho locations and 3 B-Farm locations. In total, we reported 94 unique PUD locations as of December 31, 2017, and converted 35 of them into developed properties during 2018. We incurred capital expenditures of approximately $29.3 million to develop these reserves.

The positive revision in previous estimates was primarily the impact of revised drilling plans from other working interest owners on wells operated by them, including the Marcus, Kortum, and Seltzer locations. Substantially all the non-operated PUD locations were sold subsequent to year-end. As of December 31, 2018, we included 70 unique locations in our PUD development plan. As a result of the working capital and liquidity issues encountered during 2018, we reduced our drilling plans during the five-year development window based upon expected capital resources.

Independent Reserve Engineers

Our proved reserves estimate as of December 31, 2018, 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 31 years of practical experience in petroleum engineering, with approximately 29 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 4, 2019, 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 reserve estimation process and are the technical persons within our company primarily responsible for overseeing the preparation of our reserve estimates. Each of Mr. Witsell and Mr. Lloyd has over 37 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.

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 reserve estimates. We do not have a formal committee specifically designated to review our reserve reporting and our reserve 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.

Operations

General

We had an interest in both operated and non-operated properties during the year ended December 31, 2018. However, we sold all of our non-operated properties in February 2019, with an effective date of January 1, 2019.

As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

We sell the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices. Our largest purchaser is an oil marketer who has the ability to sell production into multiple markets.

During the year ended December 31, 2018, approximately 95% of our production was sold to three customers. During the year, approximately 41% of our revenue was derived from sales to Great West Oil and Gas Company, 33% were derived from sales to Rose Rock Midstream Crude LP and 21% were from sales to PDC Energy, Inc.

In connection with sales of oil and other products from our Shook pad, we are substantially dependent on Rocky Mountain Midstream LLC, which owns and operates the pipeline into which we produce oil to be sold to customers. We experienced significant interruptions in production during 2018 and in early 2019 due to operating difficulties with the pipeline, and we expect that such interruptions may occur in the future.

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, the location and reclamation of piping, taxation and environmental protection. Many laws and regulations govern the location of wells, the method of drilling, casing and completing 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 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 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 currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Federal Resource Conservation and Recovery Act, or RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported, or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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 have and intend to 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 such 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 United States Environmental Protection Area, or 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.

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 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.

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. 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 filing 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 2019 the Adams County Commissioners imposed a moratorium on new drilling permits within unincorporated areas of the County for a period of six months.

City of Brighton Permitting Process

During a two-year period between 2017 and 2019 we negotiated to obtain a Memorandum of Understanding (MOU) with the City of Brighton. In February 2019 we submitted an oil and gas Pre-Application and participated in a Pre-Application meeting with the City of Brighton. In March 2019 we submitted an oil and gas application for a permit to develop our Brighton Lakes pad. Once submitted, the City of Brighton has 10 days to request edits and additions to the permit. Once deemed complete, the City is required to provide a 14 day notice to neighbors within a 1,000 feet of the parcel and to host a neighborhood informational meeting to discuss questions and concerns. At such time, if all requirements have been met, the City can issue a permit to drill.

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.

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 will enable them to identify and acquire desirable producing properties and drilling prospects more economically and to attract more capital. 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, raise capital, 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.

Employees

We currently have 11 employees, including our Chief Executive Officer, President, Chief Operating Officer, and Chief Financial Officer. We also engage a number of 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 5,282 square feet at a rate of $11,224 per month. We consider this space to be adequate for our needs for the foreseeable future.

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

As described in the notes to our consolidated financial statements, there is substantial doubt about our ability to continue as a going concern and we are dependent on receipt of additional capital to fund our obligations and to continue in operation.

The uncertainty regarding our ability to continue as a going concern is based on our defaults under the Secured Credit Facility, substantial near-term liabilities, continuing net losses and negative working capital, among other things which existed as of December 31, 2018. At December 31, 2018, we had a cash balance of approximately $2.6 million and other current assets of approximately $29.6 million, including assets held for sale of $16.1 million which were sold subsequent to year-end, resulting in negative working capital of $32.9 million. We had net losses, including non-cash charges, of $17.3 million and $10.8 million for the years ended December 31, 2018 and 2017, respectively. At December 31, 2018 we were obligated to repay $9.4 million in principal plus accrued interest on our outstanding convertible promissory notes, which payment we did not make. We are in default under the terms of our Secured Credit Facility and as a result, we have included $29.9 million including the outstanding principal and accrued interest and penalties in current liabilities. On April 2, 2019, the Secured Lenders delivered their formal Notice of Default under the terms of the Secured Credit Facility. The Notice declared that all amounts outstanding were immediately due and payable. Some of our accounts payable obligations to vendors are past the due date and some of those vendors have filed liens or indicated an intent to file liens against certain of our assets. The net proceeds from the sale of our non-operated assets in February 2019 have been applied by our Secured Lenders to reduce amounts allegedly owed under the Secured Credit Facility. We will need to generate sufficient cash flow from operations and sell equity or debt to fund further drilling and acquisition activity and to continue in operation. If sufficient cash flow and additional financing is not available, we may be compelled to reduce the scope of our business activities, sell a portion of our interests in our oil and gas properties or file for bankruptcy protection. This, in turn, may have an adverse effect on our ability to realize the value of our assets. These factors raise substantial doubt about our ability to continue as a going concern and you may lose some or all of your investment.

We have engaged legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness and we may elect to implement such a restructuring through Chapter 11 of the United States Bankruptcy Code in order to obtain court supervision and to facilitate the stakeholder approvals necessary to implement such a restructuring, or it may otherwise become necessary for us to seek protections under Chapter 11.

Seeking Chapter 11 protection may have a material adverse impact on our business and the trading price of our securities. As long as a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization, including managing potential negative impact to our reputation. Bankruptcy court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. Additionally, all of our indebtedness is senior to the existing common stock in our capital structure. As a result, we believe that seeking bankruptcy court protection under a Chapter 11 proceeding could cause the shares of our existing common stock to be canceled, or otherwise result in a limited recovery, if any, for holders of our common stock, and would place holders of our common stock at significant risk of losing some or all of their investment in our shares.

Our secured debt is currently in default and if our effort to negotiate a continuing waiver of that default is unsuccessful, the lenders may foreclose on or force a sale of our assets.

We notified our Secured Lenders in 2018 and 2019 of several events of default under the terms of the Secured Credit Facility, including the filing of liens on our properties, liabilities that were more than 90 days past due and our inability to pay the unsecured notes when they matured at December 31, 2018. On April 2, 2019, the Secured Lenders delivered their formal Notice of Default. As a result of these events, we are in default under the terms of the Secured Credit Facility and as a result all outstanding principal, interest and penalties are immediately due and payable. If we are unable to obtain a waiver of the defaults the lenders may undertake collection efforts against us and our property. In that event, the holders of the debt would likely be entitled to the first proceeds of the sale of our assets and the holders of our equity securities may lose some or all of their investment.

Our use of debt financing could have a material adverse effect on our financial condition.

In addition to the existing defaults under the Secured Credit Facility, 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 that 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, 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 the Secured Credit Facility. These covenants generally require us to satisfy certain financial ratios related to our oil and gas reserves and debt to earnings, and 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 or selling, leasing, or otherwise disposing of any material amount of assets. Failure to comply with these covenants could result in a further default.

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 unconventional resource 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 unconventional resources such as the shale and tight sand formations, of 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 unconventional oil and gas resource wells.

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 estimates and future cash flows have a greater chance of being material to us.

Legislation pending in the Colorado legislature and a recent permitting moratorium in Adams County may have an adverse effect on our ability to raise capital and develop our oil and gas properties.

The Colorado legislature, the State all of our properties are located in, has proposed legislation that would significantly affect oil and gas development in the state. Among other things, that legislation would revise the mandate of the COGCC from one of primarily fostering oil and gas development to one of ensuring the health, safety and environment of the State’s citizens. The proposed legislation, if adopted in its present form, would also revamp the composition of the COGCC to include more health and safety advocates and less industry advocates. In addition, the legislation could allow the COGCC to refuse to issue new permits until final rules are adopted consistent with the new legislation. This legislation is presently making its way through the legislature and there is no assurance that it will be adopted in its present form, or at all. However, if past in some form, the governor of the state has promised to sign the legislation. In response to the proposed legislation, in March, 2019 Adams County has imposed a six-month moratorium on new permits while the legislation is considered. If this legislation is approved in its present form, it could have a significant and adverse effect on oil and gas development in the State, especially on development in proximity to residential and other sensitive areas. This legislation and the Adams County moratorium may also have a chilling effect on our ability to raise capital, as bankers and other investors seek to evaluate the effect of the pending legislation on our properties and future prospects.

We may experience a change in control and our officers and/or directors may be replaced.

It is possible that in connection with a refinancing or other restructuring of our debt to improve our liquidity, we would have to issue additional common stock or new preferred stock and that the issuance of this stock may give the new shareholders control of our board of directors. We are unable to determine at this time who these investors might be or who might be appointed to our board. Investors in our common stock will be unable to evaluate the new directors until such time, if ever, they are formally appointed.

Oil and gas wells are depleting assets and our failure or inability to reinvest in additional wells will lead to reduced production.

Our ability to invest additional amounts in new wells and additional acreage is a function of the availability of capital. If we are unable to obtain that capital in amounts sufficient to allow for additional investment, our existing and contemplated production will eventually diminish. This may lead to a drop in the price of our stock, and investors may lose all or part of their investment.

The due diligence undertaken by us in connection with 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.

The due diligence undertaken by us in connection with the acquisition of our 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 the diligence process, we have also made subjective judgments regarding the results of operations and prospects of the assets. If the due diligence investigations have 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 processes and which may have a material adverse effect on our financial condition or results of operations.

We have granted PEO the option to participate in certain of our acreage acquisitions.

On May 13, 2015, we entered into a participation agreement with PEO which has been amended on two subsequent occasions. Under the terms of the original participation agreement, we assigned an undivided 50% interest to our right, title and interest in our then-existing leases in our Todd Creek Farms prospect and granted PEO the right to acquire up to 50% of other acquisitions within an area of mutual interest, or AMI. The Participation Agreement was subsequently amended to provide an option to another affiliate of PEO, potentially reducing our retained interest in any properties to 50%. The AMI covers all of our Southern Core area and part of our other properties. To date, PEO has exercised its option to participate in all of our acreage acquisitions.

We have limited management and staff and are dependent upon partnering arrangements and third-party service providers.

We currently have 11 employees, including our Chief Executive Officer, President, Chief Financial Officer and Chief Operating Officer. The loss of any of these individuals would have an adverse effect on our business, as we have very limited personnel. We 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 create 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.

The proceeds from the recent sale of all of our non-operated oil and gas assets have been paid to our Secured Lenders and applied to the outstanding balance on our Secured Credit Facility and will not be available to pay any of our vendors or the olders of any other accrued liabilities.

Under the terms of the Secured Credit Facility, we were obligated to obtain the consent of our Secured Lenders to sell the non-operated assets. As a condition of that consent, the Secured Lenders required that the proceeds of the sale be paid to an account controlled by them, and that we grant the Secured Lenders a security interest in the proceeds. Following the sale, the Secured Parties notified us that they had applied the proceeds of the sale against the amounts that they deemed outstanding under the Secured Credit Facility. As a result, we are unable to use those proceeds to pay our vendors or the holders of any other accrued liabilities. Some of those vendors have filed mechanic's liens against our property interests as a result of our failure to pay the amounts due to the vendors. If the amounts due giving rise to those liens are not paid prior to the expiration of the liens, the vendors may foreclose the liens and attempt to sell some of our properties. The vendors may also put us on cash terms for future transactions, severely restricting our ability to conduct business in the ordinary course.

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 purchase and transport hydrocarbons, carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to attract more capital and 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 raise capital and evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors are also 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.

We are concentrated in one geographic area, which increases our exposure to many of the risks enumerated herein.

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. 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.

Our ability to sell any production and/or receive market prices for our production has in the past and may in the future 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 currently deliver most of the oil and natural gas produced from our properties through pipelines that we do not own and expect to do so in the future. 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. In addition to capacity constraints, we have been significantly affected by interruptions in operation of these gathering systems and processing facilities and may be affected in the future. Since we do not own these systems, we cannot control their operation.

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 $1.0 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 $1.0 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.

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 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.

In addition to our efforts to raise capital, 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 been volatile since 2014, with a high over $100.00 per barrel in June 2014 and to lows below $30.00 per barrel in 2016 based on West Texas Intermediate (WTI) Crude Oil, as quoted on NYMEX. Prices for natural gas have also been volatile. On April 2, 2019, the price of WTI was $62.61 per barrel and Henry Hub Natural gas was $2.69 per MMBtu. Our revenue, results of operation, cash flows, liquidity and reserve estimates depend to a large part on the price of oil and gas. 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.

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 may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells.

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. Increased drilling or completion costs may not be fully offset by increases in the price received for oil and gas.

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 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 or 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 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 EPA asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel fuel under the Safe Drinking Water Act. In addition, 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. 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.

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 $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 very 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;

●	regulatory developments, including new permitting regulations in Colorado;

●	the success of our development efforts;

●	our ability 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.

Substantially all of our outstanding common stock is currently available for resale under applicable securities laws. In addition, we have a significant amount of common stock that can be issued under outstanding warrant, options or convertible debt, and we are obligated to register that common stock for resale. 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 investors to lose all or a part of their 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 would own approximately 70% of our common stock if the debtholders exercised certain conversion rights outstanding as of the date of this report. Under our Articles of Incorporation and Colorado law, the vote of a majority of the shares outstanding is required to approve certain shareholder action, such as the approval of a merger or share exchange. As a result, these individuals, if some convertible debt is converted, would control the outcome of shareholder votes on these matters 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.

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.

In addition, 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. Many brokers may be unwilling to engage in transactions in our common stock because of the added disclosure requirements and applicable FINRA requirements, thereby making it more difficult for stockholders to dispose of their 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. If we identify material weaknesses in our internal control over financial reporting or are unable to assert that our internal control over financial reporting is effective, 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. A weakness in internal control could also result in a restatement of our consolidated financial statements, which could have a material adverse effect on the trading price of our stock.

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 210,000,000 shares of stock, including 200,000,000 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.

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 it is unlikely that we will pay dividends for the foreseeable future. The provisions of the Secured Credit Facility prohibit the payment of dividends without the approval of the Secured Lenders, and it is unlikely that the Lenders would approve any dividends so long as the debt is outstanding. Our ability to pay dividends will also depend on our ability to successfully develop our business plan and generate additional 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.

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 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 information set forth under "Risk Factors" and the following:

●	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

●	capital expenditures.

Those factors discussed above and elsewhere in this report are difficult to predict and expressly qualify all 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.

PART II

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

Market Information

Since 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.

On April 2, 2019, the high and low sales price of our common stock on the OTCQB were $0.38 and $0.36, 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 April 2, 2019, we have outstanding 28,077,337 shares of common stock and approximately 162 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.

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, the Secured Credit Facility limits our ability to pay dividends.

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 April 2, 2019 for the next twelve months and the related anticipated capital expenditures. It also analyzes (i) our financial condition at December 31, 2018 and compares it to December 31, 2017, and (ii) our results of operations for the years ended December 31, 2018 and 2017. The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements and related notes and with the understanding that the actual future results may be materially different from what we currently expect.

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. 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, outstanding liabilities 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 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.

Going Concern

As described in the notes to our consolidated financial statements and the report of the independent registered public accounting firm accompanying those consolidated financial statements, there is substantial doubt about our ability to continue as a going concern. The uncertainty is based on our substantial current liabilities, negative working capital, accumulated deficit and limited cash flow, among other things, which existed as of December 31, 2018. We are dependent on improving cash flow and obtaining funding from the sale of debt or equity to continue as a going concern.

At December 31, 2018 we had a cash balance of approximately $2.6 million and other current assets of approximately $29.6 million including assets held for sale of $16.1 million, resulting in negative working capital of $32.9 million. We had net losses, including non-cash charges, of $17.3 million and $10.8 million for the years ended December 31, 2018 and 2017, respectively. At December 31, 2018 we were obligated to repay $9.4 million in principal plus accrued interest on our outstanding convertible promissory notes, which payment we did not make. The convertible notes are currently in default. We are in default under the terms of our Senior Secured Credit Facility and as a result $29.9 million including the outstanding principal and accrued interest and penalties are due. On April 2, 2019, the Secured Lenders delivered their formal Notice of Default under the terms of the Secured Credit Facility. Some of our accounts payable obligations to vendors are past the due date and some of those vendors have filed liens or indicated an intent to liens against certain of our assets. The net proceeds from the sale of our non-operated assets in February 2019 have been applied by our Secured Lenders to amounts allegedly outstanding under the Secured Credit Facility. We will need to generate additional cash flow from operations and sell equity or debt to fund further drilling and acquisition activity and pay our existing obligations. If sufficient cash flow and additional financing is not available, we may be compelled to reduce the scope of our business activities and/or sell a portion of our interests in our oil and gas properties. This, in turn, may have an adverse effect on our ability to realize the value of our assets. These factors raise substantial doubt about our ability to continue as a going concern.

Plan of Operation and Expected Capital Expenditures

Our plan of operation for the next twelve months is to drill and complete 8 wells on our Brighton lakes pad. However, our ability to achieve this objective is subject to receipt of additional capital. If we are successful in raising additional capital by means of an equity financing in 2019, we may pursue another operated drilling program. Our goal is to increase the value of our company by selective deployment of capital in what we believe to be an attractive area in a premier oil and gas field.

Subject to the availability of additional capital and final permitting, we expect to spend $13.5 million to drill and complete 8 wells on our Brighton Lakes pad. We expect to begin drilling in the Spring of 2019 and expect that these wells are fully producing by December 2019, adding significantly to our revenue. We also intend to monitor the production from our operated Shook pad and vertical wells in order to determine whether production rates could be improved through work overs or by other means.

Results of Operations for the Year Ended December 31, 2018 Compared to December 31, 2017

The following provides selected operating results and averages for the years ended December 31, 2018 and 2017:

	For the year ended
	December 31,
	2018	2017
Revenue
Crude Oil	$16,809,145	$8,719,793
Natural Gas	2,456,927	1,525,833
NGLs	1,137,896	861,948
Total revenue	$20,403,968	$11,107,574
Total operating expense (1)	$4,147,762	$1,715,616
Depletion, depreciation and amortization expense	$7,067,729	$2,836,891
Interest expense	$13,074,289	$9,293,782
General and administrative expense	$4,155,651	$6,205,412
Net (loss)	$(17,307,747)	$(10,847,379)
Sales volume (2)(3)
Crude Oil (Bbls)	287,984	188,529
Natural Gas (Mcfs)	773,396	549,846
NGLs (Bbls)	55,811	50,111
BOE	472,694	330,281
Average sales price
Crude Oil (per Bbl)	$58.37	$46.25
Natural Gas (per Mcf)	$3.18	$2.78
NGLs (per Bbl)	$20.39	$17.20
BOE	$43.17	$33.63
Average per BOE
Production cost	$5.65	$2.95
Total operating expense (1)	$8.77	$5.19
Depletion, depreciation and amortization expense	$14.95	$8.59

(1)	____________________________________ Total operating expense (oil and gas production costs, including production taxes).
(2)	Estimates are inherent in reported volumes to coincide with revenue accruals as a result of the timing of sales information reporting by third-party operators.
(3)	Sales volumes are based upon crude oil, natural gas and NGL’s sold or accrued during the period and differ from crude oil, natural gas and NGL’s produced during the period.
(4)	Averages calculated based upon non-rounded figures.

Overview: Fiscal 2018 was our second year of meaningful revenue, as we realized revenue from the non-operated horizontal wells in which we participated and revenue from our first operated horizontal wells. The 14 mid-length lateral wells on the Shook Pad commenced commercial production during the third quarter of 2018. However, for the year, we realized a net loss of $17.3 million, including non-cash charges, or $0.62 per share, compared to a net loss of $10.8 million, or $0.46 per share, for the year ended December 31, 2017. Production from the Shook Pad wells was periodically interrupted due to problems with the gathering pipeline into which we deliver our oil, adversely affecting our revenue for the year. In addition to the interruption in production, the increase in net loss of $6.5 million for the year ended December 31, 2018 resulted primarily from a significant increase in impairment charges, interest expense, depletion, depreciation and amortization and other non-cash expenses including amortization of debt discount associated with our Secured Credit Facility. We expect to continue operating at a loss until cash flow from the wells in which we have an interest is sufficient to cover operating costs, interest expenses, general and administrative and other expenses.

Revenue: Crude oil, natural gas and NGL sales revenue increased $9.3 million for the year ended December 31, 2018, to $20.4 million, from $11.1 million for the year ended December 31, 2017, attributable to increased production volume and higher oil and natural gas commodity prices. Crude oil, natural gas and NGL sales volumes increased by 142,413 BOE for the year ended December 31, 2018 compared to the year ended December 31, 2017. The increase, in turn, was primarily the result of production from the completion of 14 operated wells during 2018 in which we have an average net revenue interest of 39%, coupled with the completion of 14 non-operated wells. Our production in 2017 was solely from crude oil, natural gas and NGLs produced from vertical wells that we acquired during 2016 and the completion of 7 non-operated wells that were put on production in the in late 2016 and in 2017.

For the year ended December 31, 2018, our average sales price for oil was $58.37 per Bbl compared to $46.25 per Bbl for the year ended December 31, 2017, due to higher average oil spot prices during 2018. Overall, the increase in the average price per BOE of $9.53, or 28.3%, results primarily from increased sales volumes coupled with blended higher sales prices during the year ended December 31, 2018.

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

	Year ended
	December 31,
	2018	2017
Lease operating costs	$1,415,453	$722,799
Production taxes	1,475,866	742,787
Transportation and other costs	1,256,443	250,030
Total	$4,147,762	$1,715,616

Total operating expense increased in 2018 commensurate with increased production. This reflects our operated and additional non-operated properties coming online in 2018, while 2017 primarily reflects the operations of legacy vertical wells and a smaller number of non-operated wells.

Lease operating costs, or LOE, per BOE was $2.99 for the year ended December 31, 2018, compared to $2.19 for the year ended December 31, 2017. As a percent of crude oil, natural gas and NGL sales revenue, routine LOE was 6.94% for the year ended December 31, 2018, compared to 6.51% for the year ended December 31, 2017. Production taxes for the year ended December 31, 2018 amounted to $1.5 million as compared to $0.7 million for the year ended December 31, 2017.

Overall operating costs (crude oil, natural gas and NGL operating costs excluding production taxes) per BOE was $5.65 for the year ended December 31, 2018, compared to $2.95 for the year ended December 31, 2017.

Depletion, depreciation and amortization expense: Depletion, depreciation and amortization increased by $4.3 million in 2018, from $2.8 million for the year ended December 31, 2017 to $7.1 million for the year ended December 31, 2018. The increase was the result of increased production volumes related to wells coming online during the 2018 period, partially offset by an increase in our reserves.

Impairment expense: During 2018, we recognized an impairment expense of $9.9 million related to the sale of our non-operated assets on February 27, 2019. This impairment resulted from the sale of our non-operated assets in February 2019 and our determination that the net unamortized costs of the assets exceeded the proceeds from the sale. We incurred no comparable expense during 2017.

Interest expense: During 2018, we recognized interest expense of $13.1 million compared to $9.3 million for the year ended December 31, 2017. The interest expense recognized 2018 relates to the interest on our Secured Credit Facility, our unsecured convertible notes, the amortization of debt discounts and accrued default interest and penalties related to our technical defaults under the Secured Credit Facility. During the year ended December 31, 2017, interest expense primarily related to advances on our two lines of credit and our convertibles notes payable.

The following table presents the components of interest expense for the years ended December 31:

	2018	2017
Interest incurred at the contract rate	$5,434,231	$2,004,041
Default interest	312,500	—
Make whole premium	3,357,875	—
Accretion of debt discount	6,126,680	7,546,497
Interest capitalized	(2,156,997)	(259,756)
Total	$13,074,289	$9,293,782

Change in fair value – derivative liability: During 2018 we recognized other income of $1.4 million related to a change in the fair value of the compound derivative liabilities embedded in the Secured Credit Facility. Accounting standards require us to re-measure the value of the derivative liabilities each reporting period, and any changes in fair value are included in Other income or Other expense. During 2017, we did not have any derivative liabilities.

General and administrative expenses: We incurred general and administrative expenses of $4.2 million during the year ended December 31, 2018, a decrease of $2.0 million from 2017, or 33%. This decrease is primarily attributable to decreased non-cash compensation of $0.6 million, decreases in professional fees of $0.6 million, increases in drilling overhead charges recorded as a reduction to general and administrative expense of $1.1 million and increases in producing overhead charges of $0.6 million recorded as a reduction to general and administrative expense, offset by increased salaries and insurance expense of $0.9 million. In 2017, we incurred general and administrative expenses of $6.2 million.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In 2018, our shortage of capital and liquidity was exacerbated. Historically, we have relied on sales of our equity securities, borrowing and advances from our working interest partners to fund operations. In 2018, our need for additional capital became more acute, as we accelerated the pace of development of our properties, including completing our first operated drilling program. However, the state of the equity markets for junior exploration and production companies in 2018 forced us to rely on other avenues for funding during the year.

2018 Financing

In February 2018, we completed the Secured Credit Facility. Under the Secured Credit Facility, we refinanced $5 million in December 2017 and received gross proceeds of an additional $20 million in February 2018. The Secured Credit Facility proceeds were utilized to repay amounts due to affiliates of the Secured Lenders under pre-existing lines of credit, for fees associated with the Secured Credit Facility and for development costs incurred in connection with the completion of our operated Shook pad.

Working Capital

As of December 31, 2018, we had negative working capital of $32.9 million, comprised of current assets of $32.2 million and current liabilities of $65.1 million. A significant portion of the current assets consisted of property held for sale, which property was disposed of subsequent to year end and the proceeds of which were applied by the Secured Lenders against the amounts owed to them. Working capital decreased by $15.1 million from December 31, 2017, primarily due to the default and subsequent reclassification of amounts due under our Secured Credit facility from a long-term liability to a current liability.Current liabilities increased by approximately $38 million at December 31, 2018 compared to 2017.

Cash Flows

Year Ended December 31, 2018 Compared to December 31, 2017

Operating Activities

Net cash provided by operating activities during the year ended December 31, 2018 was $4.6 million, compared to $10.4 million during the year ended December 31, 2017, representing a decrease of $5.7 million. The increased net loss in 2018 accounted for most of the difference.

Investing Activities

Cash used in investing activities in 2018 decreased to $13.9 million from $20.3 million in the 2017 period. During the 2018 period, our drilling and other development activity, as well as acquisitions of property, decreased due to our lack of working capital. During 2017, we spent $17.1 million on drilling and other development activities on our properties and $3.2 million on acquisitions of oil and gas properties.

Financing Activities

During 2018, we closed on the Secured Credit Facility which provided net cash proceeds of $11.2 million and provided resources after repaying $6.5 million in principal and $1.1 million in accrued interest from other financings. The total face value of the Secured Credit Facility is $25.0 million, including the $5.0 million that originated in 2017.

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 Consolidated Financial Statements

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”). The preparation of these consolidated 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 Consolidated 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 consolidated financial statements:

Assets Held for Sale

We occasionally identify specific oil and gas properties that we wish to sell. At the end of each reporting period, we evaluate properties that might be sold to determine whether any should be reclassified as held for sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale on our consolidated balance sheets. We also determine whether the fair values of the properties held for sale are less than the net unamortized cost. If an impairment is indicated, the assets held for sale are recorded at fair value less costs to sell and an impairment expense is recorded.

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 whether 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 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 depletion, depreciation 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 volatility 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.

Depletion, Depreciation, Amortization

Our DD&A rate is dependent upon our estimates of total proved producing 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.

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 the estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production, future capital expenditures, 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 proved crude oil and natural gas properties in the consolidated statements of operations.

Our impairment analyses require 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 and abandonment costs in the consolidated statements of operations.

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, 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 proved crude oil and natural gas properties. 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 operating results 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.

Going Concern Assessment

Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2014-15, Presentation of Financial Statements – Going Concern, we have assessed our ability to continue as a going concern for a period of one year from the date of the issuance of these consolidated 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 consolidated financial statement issuance date.

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.

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.

“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.

“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 depletion, depreciation 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.

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	33
Consolidated Balance Sheets as of December 31, 2018 and 2017	35
Consolidated Statements of Operations for the years ended December 31, 2018 and 2017	36
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) for the years ended December 31, 2018 and 2017	37
Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2017	38
Notes to Consolidated Financial Statements	39

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors

PetroShare Corp.

Englewood, Colorado

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of PetroShare Corp. (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of operations, changes in shareholders' equity (deficit), and cash flows, for the years then ended, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the entity will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the entity is in default under the terms of its secured credit facility, is in default under the terms of its convertible promissory notes, has suffered recurring losses from operations and has a net capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. PetroShare Corp. is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

We have served as the Company's auditor since 2017.

Denver, Colorado

April 3, 2019

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7001 E. Belleview Ave., Ste. 700 | Denver, CO 80237-2733 | TF 866.740.4100 | T 303.770.5700 | F 303.770.7581 | EOE

PetroShare Corp.

Consolidated Balance Sheets

December 31,

	2018	2017

ASSETS
Current assets:
Cash	$2,636,943	$713,924
Accounts receivable - joint interest billing, net of allowance	495,911	828,583
Accounts receivable - joint interest billing - related party	1,158,213	204,730
Accounts receivable - crude oil, natural gas and NGL sales	11,659,479	1,412,612
Prepaid expenses and other assets	178,259	26,795
Deferred financing fee, net	—	251,389
Assets held for sale, net of costs to sell	16,090,898	—
Total current assets	32,219,703	3,438,033
Crude oil and natural gas properties - using successful efforts method:
Proved crude oil and natural gas properties	41,017,944	22,144,366
Unproved crude oil and natural gas properties	2,055,752	1,919,335
Wells in progress	1,194,114	9,858,262
Less: accumulated depletion, depreciation and amortization	(14,395,458)	(2,849,374)
Crude oil and natural gas properties, net	29,872,352	31,072,589
Property, plant and equipment, net	115,350	168,411
Other assets	357,070	233,871
TOTAL ASSETS	$62,564,475	$34,912,904
LIABILITIES & SHAREHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities	$24,385,417	$4,140,352
Accounts payable and accrued liabilities - related party	7,624,877	589,496
Oil and gas revenue distributions payable	2,501,095	148,103
Drilling advances - related party	—	680,248
Asset retirement obligation	843,796	288,784
Line of credit - related party	—	5,000,000
Supplemental line of credit	—	3,552,500
Derivative liabilities – Secured Credit Facility	241,800	—
Convertible notes payable, net	9,358,100	6,831,897
Secured Credit Facility, net	20,182,264	—
Total current liabilities	65,137,349	21,231,380
Long-term liabilities
Credit facility, net	—	4,896,565
Other long-term liabilities	448,465	67,265
Asset retirement obligation	1,246,151	834,660
Total liabilities	66,831,965	27,029,870

Shareholders’ equity (deficit):
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued or outstanding	—	—
Common stock, $0.001 par value, 100,000,000 shares authorized, 28,089,765 and 27,718,802 shares issued and outstanding, respectively with 184,350 and 155,350 shares subject to vesting restrictions respectively	28,090	27,719
Additional paid-in capital	33,710,588	28,553,736
Accumulated deficit	(38,006,168)	(20,698,421)
Total Shareholders’ Equity (Deficit)	(4,267,490)	7,833,034
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY (DEFICIT)	$62,564,475	$34,912,904

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

PetroShare Corp.

Consolidated Statements of Operations

For the years ended December 31,

	2018	2017

REVENUE:
Crude oil sales	$16,809,145	$8,719,793
Natural gas sales	2,456,927	1,525,833
NGL sales	1,137,895	861,948
Total revenue	20,403,967	11,107,574
COSTS AND EXPENSES:
Lease operating expense	1,415,453	722,799
Production taxes, gathering and marketing	2,732,309	992,817
Exploration and abandonment costs	580,881	61,693
Depletion, depreciation and amortization	7,067,729	2,836,891
Accretion expense	117,636	99,682
Asset retirement and plugging expense	(2,989)	9,608
Impairment of proved crude oil and natural gas properties	9,896,807	—
General and administrative expense	4,155,651	6,205,412
Total costs and expenses	25,963,477	10,928,902
Operating (loss) income	(5,559,510)	178,672
OTHER INCOME (EXPENSE):
Other income (expense)	(102,165)	39,381
Change in fair value of derivative liabilities	1,428,217	—
Interest expense	(13,074,289)	(9,293,782)
Loss on conversion of notes payable	—	(1,771,650)
Total other (expense)	(11,748,237)	(11,026,051)
Net (loss)	$(17,307,747)	$(10,847,379)
Net (loss) per share:
Basic and diluted	$(0.62)	$(0.46)
Weighted average number of shares outstanding:
Basic and diluted	27,991,742	23,530,583

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

PetroShare Corp.

Consolidated Statements of Changes in Shareholders’ Equity (Deficit)

For the years ended December 31, 2018 and 2017

			Additional
	Common Stock		Paid-In	Accumulated
	Shares	Amount	Capital	(Deficit)	Total
Balance at December 31, 2016	21,964,282	$21,964	$11,405,225	$(9,851,042)	$1,576,147
Issuance of common stock in connection with conversion of convertible notes payable	4,814,265	4,814	7,062,528	—	7,067,342
Issuance of common stock for lease acquisition	470,555	471	846,529	—	847,000
Issuance of common stock for loan extension	250,000	250	387,250	—	387,500
Issuance of restricted shares	219,700	220	155,111	—	155,331
Beneficial conversion feature on convertible notes payable	—	—	4,329,365	—	4,329,365
Warrants issued in connection with convertible notes payable	—	—	2,978,796	—	2,978,796
Stock-based compensation	—	—	1,388,932	—	1,388,932
Net (loss)	—	—	—	(10,847,379)	(10,847,379)
Balance at December 31, 2017	27,718,802	$27,719	$28,553,736	$(20,698,421)	$7,883,034
Issuance of common stock in connection with conversion of convertible notes payable	135,963	136	203,811	—	203,947
Issuance of common shares as compensation	145,000	145	162,105	—	162,250
Issuance of restricted shares	90,000	90	101,018	—	101,108
Beneficial conversion feature on Secured Credit Facility	—	—	2,272,775	—	2,272,775
Warrants issued in connection with Secured Credit Facility	—	—	1,521,451	—	1,521,451
Stock-based compensation	—	—	895,692	—	895,692
Net (loss)	—	—	—	(17,307,747)	(17,307,747)
Balance at December 31, 2018	28,089,765	$28,090	$33,710,588	$(38,006,168)	$(4,267,490)

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

PetroShare Corp.

Consolidated Statements of Cash Flows

For the years ended December 31,

	2018	2017

Cash flows from operating activities:
Net (loss)	$(17,307,747)	$(10,847,379)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	7,067,729	2,836,891
Deferred rental liability	(23,625)	6,526
Accretion of asset retirement obligation	117,636	99,682
Accretion of debt discounts and deferred financing fee	6,380,057	7,666,313
Loss on conversion of notes payable	—	1,771,650
Stock-based compensation	1,159,051	1,544,261
Change in fair value – derivative liabilities	(1,428,217)	—
Default penalties incurred in connection with Secured Credit Facility	3,670,375	—
Impairment of proved crude oil and natural gas properties	9,896,807	—
Break-up fees in connection with abandonment of lease acquisition	580,881	—
Bad debt expense	131,395	—
Changes in operating assets and liabilities:
Accounts receivable - joint interest billing	(66,470)	(588,132)
Accounts receivable - joint interest billing - related party	204,731	81,495
Accounts receivable - crude oil, natural gas and NGL sales	(10,246,868)	(1,233,376)

Prepaid expenses, other assets and liabilities	130,164	961,048
Settlement of asset retirement obligations	(174,532)	—
Accounts payable and accrued liabilities	758,525	7,053,693
Accounts payable and accrued liabilities- related party	2,123,621	589,496
Oil and gas revenue distributions payable	2,352,992	3,578
Drilling advances - related party	(680,248)	445,796
Net cash provided by operating activities	4,646,257	10,391,542
Cash flows from investing activities:
Additions of property, plant and equipment	—	(91,186)
Development of crude oil and natural gas properties	(13,379,249)	(17,052,313)
Acquisitions of proved and unproved crude oil and natural gas properties	(507,181)	(3,202,380)
Net cash (used in) investing activities	(13,886,430)	(20,345,879)
Cash flows from financing activities:

Repayment of supplemental line of credit	—	(3,552,500)
Borrowings on Secured Credit Facility	11,163,192	—
Convertible notes issued for cash	—	11,771,349
Net cash provided by financing activities	11,163,192	8,218,849
Cash:
Net increase (decrease) in cash	1,923,019	(1,735,488)
Cash, beginning of period	713,924	2,499,412
Cash, end of period	$2,636,943	$713,924
Supplemental cash flow disclosure:
Cash paid for interest, net of amounts capitalized of $2.2 million and $0.3 million as of December 31, 2018 and 2017	$3,394,575	$640,410
Non-cash investing and financing activities:
Addition of oil and natural gas properties – Asset exchange agreement	$2,873,912	$—
Accrued development costs of crude oil and natural gas properties	$16,015,992	$1,719,481
Revisions and other non-cash charges in asset retirement obligation	$1,023,400	$127,826
Conveyance of oil and gas properties – to satisfy supplemental line of credit	$2,052,500	$4,683
Addition of property, plant and equipment through tenant improvement allowance	$—	$84,460
Embedded derivative liabilities – Secured Credit Facility	$1,670,017	$—
Previous borrowings refinanced through Secured Credit Facility	$6,500,000	$—
Issuance of common stock warrants in connection with Secured Credit Facility	$1,521,451	$—
Issuance of common stock warrants in connection with convertible notes payable	$—	$2,978,796
Beneficial conversion feature in connection with Secured Credit Facility and convertible notes payable	$2,272,775	$4,329,365
Issuance of common stock in connection with conversion of notes payable and accrued interest	$203,947	$5,295,692
Conversion of notes payable and accrued interest – Additional paid in capital	$—	$7,067,342
Issuance of common stock in connection with lease acquisitions	$—	$847,000
Issuance of common stock in connection with deferred financing fee	$—	$387,500
Accounts payable and accrued interest repaid through Secured Credit Facility	$1,086,808	$4,895,128
Financing fee paid through Secured Credit facility	$1,250,000	$104,871

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

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

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 in the Denver-Julesburg Basin, or DJ Basin, in northeast Colorado.

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

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”). The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical to its comprehensive income or loss.

Principles of Consolidation

The consolidated financial statements include the accounts and balances of the Company and its wholly-owned subsidiary, CFW Resources, LLC, a Colorado limited liability company. The Company’s undivided interests in joint operating ventures are proportionately consolidated.

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 revenues, expenses, assets and liabilities, as well as the disclosure of contingent assets and liabilities. Estimated quantities of crude oil, natural gas and natural gas liquids are the most significant of the Company’s estimates. All reserve data used in the preparation of these consolidated 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, probable and possible 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.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Other items subject to significant estimates and assumptions include, but are not limited to, the carrying amounts of crude oil and natural gas properties, accrued and unpaid revenues and unbilled costs, asset retirement obligations, deferred income tax liabilities and assets, including any associated valuation allowances, derivative liabilities, convertible notes payable and the Secured Credit Facility. Furthermore, valuation assumptions related to the Company’s stock-based compensation and fair value financial instruments require significant judgments and estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Actual results could be significantly different from the estimates.

Income (or Loss) Per Common Share

Basic earnings (or loss) per share is computed by dividing net income (or loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (or loss) per share is computed after considering the potential dilution from additional shares that would be issued pursuant to the conversion of debt, exercise of warrants, and fulfillment of outstanding equity awards. Any potentially dilutive securities that have an anti-dilutive impact on the per share calculation are excluded. During periods in which the Company reports a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the impact of all potentially dilutive securities would be anti-dilutive.

The following table presents the number of potentially dilutive securities that were excluded from the calculation at December 31, 2018 and 2017:

	December 31,	December 31,
	2018	2017
Exercisable stock options	4,621,000	4,347,500
Warrants to purchase common stock	9,088,800	7,588,800
Shares underlying secured credit facility
and convertible notes	23,489,786	6,372,066
Total	37,199,586	18,308,366

Cash, cash equivalents, and restricted cash

During the periods presented herein, the Company had no cash equivalents or restricted cash.

Revenue Recognition

Oil sales

Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. Payment is generally received from the customer in the month following delivery.

Natural gas and natural gas liquids

Under the Company’s natural gas sales processing contracts, the Company delivers commingled natural gas and natural gas liquids (NGLs) to a midstream processing entity. The midstream processing entity gathers and processes the various hydrocarbons and remits proceeds to the Company for the resulting sale. Under these processing agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery. Payment is generally received from the customer one to two months following delivery. Revenue is recognized net of gathering and processing fees.

Disaggregation of Revenue. The following table presents revenues disaggregated by product:

Operating revenues	2018	2017
Crude oil sales	$16,809,145	$8,719,793
Natural gas sales	2,456,927	1,525,833
NGL sales	1,137,895	861,947
Total Operating Revenues	$20,403,967	$11,107,574

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Accounts Receivable – Crude oil, natural gas and NGLs

Accounts receivable – Crude oil, natural gas and NGLs consists of amounts due from customers for the sale of hydrocarbons. In general, settlements for hydrocarbon sales occur 30 to 90 days after the month in which the oil, natural gas or other hydrocarbon products were produced.

Accounts Receivable – Joint interest billing

Accounts receivable – Joint interest billing represents costs to be reimbursed by the Company’s working interest partners under joint operating agreements. Collateral is not required for such receivables, nor is interest charged on past due balances. However, should a working interest partner default on its obligation, the Company would have a claim against their future pro rata revenue and to any reserves attributable to the joint interest.

Allowance for doubtful accounts

The Company regularly reviews outstanding accounts receivable for indication that amounts may not be collectible. The Company’s allowance for doubtful accounts is based on analysis of historical bad debt experience, current receivables aging, and expected future write-offs, as well as an assessment of specific identifiable customer accounts considered at risk or uncollectible. An allowance of $0.1 million and $nil was recorded as of December 31, 2018 and 2017, respectively.

Capitalized Interest Costs

The Company capitalizes interest costs as part of the historical cost of developing assets. Significant oil and gas investments in unproved properties and significant exploration and development projects including wells in progress that have not commenced production are assets that qualify for interest capitalization during the period that they are being prepared for their intended use. Capitalized interest is calculated by using the weighted average interest cost on the Company’s outstanding debt, including the accretion of interest expense associated with debt discounts. The interest costs capitalized into oil and gas properties totaled $2.2 million and $0.3 million for the years ended December 31, 2018 and 2017, respectively.

Concentration of Credit Risk and Major Customers

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to regular review.

The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating region. The Company had the following major customers, which accounted for 10 percent or more of its total crude oil, natural gas, and NGL production revenue for at least one of the periods presented:

	For the Years Ended December 31,
	2018	2017
Great Western Oil and Gas Company	40.5%	22%
Rose Rock Midstream Crude LP	33.4%	-
PDC Energy, Inc	20.6%	71%

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. Bank account balances periodically exceed federally insured limits. To mitigate risk of loss, the Company’s policy is to maintain its deposits with high quality financial institutions.

Crude Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its crude oil and natural gas properties. Under this method of accounting, the costs incurred to acquire, drill, and complete productive wells, development wells, and proved properties are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized as wells in progress until the viability of the well is determined. Successful exploratory wells are capitalized, and unsuccessful exploratory wells are charged to expense.

Proved

Proved properties include all capitalized costs associated with proved developed and proved undeveloped reserves. Depletion, depreciation and amortization (“DDA”) of proved properties is calculated as a group of assets (properties aggregated based upon common attributes) using the units-of-production method. DDA of development costs, including capitalized tangible and intangible drilling costs, well equipment, and facilities costs, is based on the estimate of proved developed reserves. Similarly, DDA of proved leasehold costs, including proved undeveloped leases, is calculated using the same method based on the estimate of total proved reserves (both developed and undeveloped). Currently, the Company’s properties are located solely within the Wattenberg Field of the DJ Basin, which is considered one field for unit-of-production calculations. The Company based its determination upon certain common attributes, including geological structure, geographic proximity, cost environment, and similar operating practices.

The Company periodically assesses its proved crude oil and natural gas properties for impairment. The impairment test compares the net capitalized costs of the properties to the estimated undiscounted future net cash flows. If the net capitalized costs exceed estimated future net cash flows, an impairment expense is recorded to reduce the carrying value of the property.

The sale or other disposition of part of a proved property is reported as a normal retirement, under which no gain or loss is recognized, unless doing so significantly affects the unit-of-production amortization rate. Gains or losses are recorded in the statement of operations for all other divestiture activities.

Unproved

Unproved properties consist of costs to acquire unproved and unevaluated leases and other mineral assets. All acquisition costs are initially capitalized. When successful wells are drilled on unproved properties, the associated costs are reclassified as proved properties and depleted on a units-of-production basis. The Company periodically evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or plans to develop acreage. Individually insignificant unproved properties are evaluated on a composite basis, and, when appropriate, are amortized as a group based on past success, experience and average lease-term lives.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Exploration costs

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 satisfactory 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 are expensed.

Property, Plant and Equipment

Property, plant and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using straight-line method 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 as incurred.

Related Party Transactions

The Company engages in a number of transactions with Providence Energy Operators, LLC (“PEO”) and its affiliates. PEO is a subsidiary of Providence Energy Corporation, a privately-held corporation based in Dallas, Texas. PEO is the beneficial owner of 11.6% of our outstanding common stock. We have a participation agreement that grants PEO the option to acquire up to a 50% interest and participate in any oil and gas development on acreage we obtain within an area of mutual interest (AMI) near our Southern Core area. To date, PEO has exercised its option under the participation agreement or otherwise participated or agreed to participate in all acreage acquisitions and drilling operations. As discussed elsewhere in this report, an affiliate of PEO is a major participant in our principal lender group through which we currently maintain a $25.0 million Secured Credit Facility. The Board of Directors is required to approve all significant related party transactions.

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 partners’ share of costs incurred.

Income Taxes

The Company accounts for deferred income taxes under the asset and liability method whereby it recognizes deferred tax assets and liabilities based on the tax effects of temporary differences between the cost basis of assets and liabilities reported for financial reporting purposes compared to income tax reporting purposes using currently enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled. Deferred tax assets are also recognized for future tax consequences attributable to operating loss carryforwards. The Company provides a valuation allowance for deferred tax assets when it does not consider realization of such assets to be more likely than not. The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2018.

Asset Retirement Obligation

The Company recognizes an estimated liability for future costs associated with the dismantlement, abandonment, or other restoration required when its oil and gas assets are retired or otherwise permanently removed from service. Calculation of an asset retirement obligation (“ARO”) requires estimates about several future events, including the estimated date of retirement, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free interest rate.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Upon initial recognition of an ARO, the carrying amount of the associated asset is increased by the same amount. The capitalized costs are included in the periodic calculation of DD&A and are subject to impairment testing. If the estimated timing or estimated cash flow of the ARO changes, an adjustment is recorded to both the ARO and the asset retirement cost.

Assets Held for Sale

We occasionally identify specific oil and gas properties that we wish to sell. At the end of each reporting period, we evaluate properties that might be sold to determine whether any should be reclassified as held for sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale on our consolidated balance sheets. We also compare the fair values of the properties held for sale to the net unamortized cost. If an impairment is indicated, the assets held for sale are recorded at fair value less costs to sell and impairment expense is recorded.

Stock-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, “Stock 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 expected term of outstanding stock-based awards 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 an expected term for these awards, 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. Forfeitures are recorded as they occur.

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 recorded and the redemption value of the debt is recognized as interest expense in the consolidated statements of operations over the period to maturity using the effective interest method.

Fair Value of Financial Instruments

Fair value accounting, as prescribed in ASC Section 825, “Financial Instruments,” 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:

Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability; and

Level 3 Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

As disclosed in Note 5, the Secured Credit Facility contained embedded elements that required identification and quantification of fair value. The estimated fair values as of February 1, 2018, the closing date of the facility, are presented in Note 5. As of December 31, 2018, the estimated fair values are presented in the following table:

	December 31, 2018
Registration rights penalty derivative liability	$(102,892)
Share purchase option derivative liability	(138,908)
	$(241,800)

The following table presents a roll-forward of the fair value of the derivative liabilities associated with the Company’s Secured Credit Facility, categorized as Level 3 for the year ended December 31, 2018. There were no comparable liabilities for the 2017 period:

	Year Ended December 31, 2018
Beginning balance	$-
Additions (Note 5)	(1,670,017)
Gain included in earnings	1,428,217
Gain (loss) included in other comprehensive income	-
Ending Balance	$(241,800)

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Estimated Fair Value of Other Financial Assets and Liabilities

The Company’s other financial instruments consist primarily of cash, accounts receivable, accounts payable, and various borrowings. Substantially all of the Company’s other financial instruments are classified as current assets or current liabilities. The carrying values of current assets and current liabilities are representative of their fair values due to their short-term maturities.

Going Concern Assessment

Pursuant to Accounting Standards Update (“ASU”) 2014-15, “Presentation of Financial Statements – Going Concern” 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 consolidated 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 may be unable to meet its obligations as they become due within one year from the consolidated financial statement issuance date.

The uncertainty regarding the Company’s ability to continue as a going concern is based on it’s substantial near-term liabilities, continuing net losses and negative working capital, among other things which existed as of December 31, 2018. At December 31, 2018 the Company had a cash balance of approximately $2.6 million and other current assets of approximately $29.6 million including assets held for sale of $16.1 million, resulting in negative working capital of $32.9 million. The Company had net losses, including non-cash charges, of $17.3 million and $10.8 million for the years ended December 31, 2018 and 2017, respectively. At December 31, 2018 the Company was obligated to repay $9.4 million in principal plus accrued interest on outstanding convertible promissory notes, which payment was not made. The convertible notes are currently in default. The Company is also in default under the terms of the Secured Credit Facility (Note 5) and as a result $29.9 million, including the outstanding principal, accrued interest and penalties are due. On April 2, 2019, the Secured Lenders delivered their formal Notice of Default under the terms of the Secured Credit Facility. Some accounts payable obligations to vendors are past the due date and some of those vendors have filed liens or indicated an intent to file liens on certain of the Company’s assets. The net proceeds from the sale of the non-operated assets in February 2019 were applied by the Secured Lenders to amounts allegedly owed to them. The Company has been unable to access the debt or equity markets to obtain any additional funding during 2018.

Management has evaluated these conditions and determined that increased revenues from the Company’s operated properties may allow the Company to meet its ongoing operational obligations. However, to continue to execute its business plan, and meet its debt obligations, additional working capital will be required. As part of the analysis, the Company considered selective participation in certain operated drilling programs based on availability of working capital and the timing of production-related cash flows. There is uncertainty that management’s plans, if executed will allow the Company to meet all of its obligations.

As a result, there is substantial doubt about the Company’s ability to continue as a going concern within one year after the date the consolidated financial statements are issued. The Company’s consolidated financial statements do not include any adjustments related to the realization of the carrying value of assets or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Recently Adopted Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued a new standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement and timing of revenue to be recognized. The underlying principle is that an entity will recognize revenue for the transfer of goods or services to customers at the amount expected to be received in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when or as each performance obligation is satisfied. The standard, known as Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), and all related ASU’s, was adopted by the Company effective January 1, 2018. The Company adopted ASU 2014-09 using the modified retrospective transition method, which was applied to all active contracts as of January 1, 2018. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adopting ASU 2014-09, the Company expanded its disclosures to comply with the expanded disclosure requirements of ASU 2014-09.

Effective January 1, 2018, the Company adopted ASU No. 2017-01, Business Combinations (Topic 805) Clarifying the Definition of a Business (“ASU 2017-01”). The ASU clarifies the definition of a business with the objective of adding guidance for the evaluation of whether certain transactions represent the acquisition (or disposal) of assets or business combinations. The Company adopted ASU 2017-01 on a prospective basis.

Recent Accounting Pronouncements – In February 2016, FASB issued ASU No. 2016-02, Leases (Topic 842). For lessees, the guidance in this update and subsequent amendments require that a company recognize most leases by recording both a lease liability and right-of-use asset on its balance sheet, representing the obligation to make payments and the right to use or control the use of a specified asset for the lease term. The standards include an exception for short term leases. Furthermore, the new lease standard does not apply to leases of mineral rights related to crude oil and natural gas. The new requirements are effective for annual periods beginning after December 15, 2018. Upon adoption, the Company will begin reflecting long-term future lease payments as both an asset and a liability on its consolidated balance sheet. The Company has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Based upon its preliminary analysis, the Company’s implementation of this standard on January 1, 2019 resulted in an increase to total assets and total liabilities of insignificant amounts, with no adjustment to the opening balance of retained earnings (accumulated deficit).

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815), which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same line as the hedged item in the consolidated statement of operations. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The new standard will be adopted by the Company effective for the annual period beginning after December 15, 2018, including interim periods within that annual period. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements.

There are no other recently issued ASUs (issued through April 2, 2019 and not yet adopted by the Company) that are expected to have a material effect on the Company’s consolidated financial statements and related disclosures when they are adopted.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2018	2017
Property, plant and equipment	$223,517	$223,517
Accumulated depreciation	(108,167)	(55,106)
Total	$115,350	$168,411

Depreciation expense recorded for the years ended December 31, 2018 and 2017 amounted to $53,061 and $46,778, respectively.

NOTE 4 – CRUDE OIL AND NATURAL GAS PROPERTIES

The Company’s crude oil and natural gas properties are located entirely within the State of Colorado in the United States of America. The net capitalized costs related to the Company’s crude oil and natural gas activities were as follows:

	As of December 31,
	2018	2017
Proved oil and gas properties	$41,017,944	$22,144,336
Unproved oil and gas properties (1)	2,055,752	1,919,335
Wells in progress (2)	1,194,114	9,858,262
Total capitalized costs	44,267,810	33,921,963
Accumulated DDA and impairment	(14,395,458)	(2,849,374)
Net capitalized costs	$29,723,352	$31,072,589

(1)	Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined.

(2)	Costs from wells in progress are excluded from the amortization base until production commences.

During the years ended December 31, 2018 and 2017, DDA expense was $7.0 million and $2.8 million, respectively. As discussed below, the Company recorded impairment charges of $9.9 million and lease abandonment charges of $0.6 million during the fourth quarter of 2018.

Acquisitions and Divestitures, including Assets Held for Sale

2018 Activity

During 2018, the Company completed an asset exchange that increased its working interest in its operated producing property in exchange for cash and cancellation of joint interest billing receivables. No gain or loss was recognized on the exchange.

In June 2018, the Company executed two participation agreements with PEO whereby the Company agreed to acquire working interests in approximately 2,200 gross mineral acres for a total purchase price of $4.6 million (Note 11). The terms of the agreements allowed the Company to defer payment until December 31, 2018. As of December 31, 2018, the Company decided not to fund the agreement and recorded an abandonment charge of $0.6 million payable to PEO.

Effective June 1, 2018, the Company completed a conveyance of property in lieu of payment transaction with Providence Energy Partners III (“PEP III”), one of its lenders. The exchange conveyed the Company’s working interests in four producing wells, eight wells in various stages of drilling and completion, 16 proposed wells and the underlying mineral leases (the "Ocho Assets"). The conveyance of properties represented full and final settlement of $2.1 million outstanding principal balance under the supplemental line of credit with PEP III (Note 5). PEP III is considered an affiliate of PEO. As the transaction represented the conveyance of part of an interest in a proved property and did not have a significant impact on the DDA calculation, it has been recorded as a normal retirement. The carrying cost of the oil and gas properties was $0.8 million.

During the fourth quarter of 2018, as part of the plan to divest certain properties and improve liquidity, the Company began an active program to sell certain undeveloped properties along with some producing properties operated by other companies. As the plan did not represent a strategic shift, it did not qualify for accounting treatment as a discontinued operation. The Company evaluated the six criteria for classification of assets held for sale in accordance with FASB ASC 360-10-45-9. After the evaluation of these criteria, the assets were reclassified as Assets Held for Sale as of December 31, 2018.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

The proceeds from the February 27, 2019 sale of the Assets held for sale was $16.1 million after adjusting for anticipated costs to sell. As the net unamortized costs of the properties was $26.0 million, the Company recorded an impairment provision of $9.9 million for the year ended December 31, 2018. On February 27, 2019, the Company closed on the sale for price of $16.5 million, after adjustments to the purchase price for amounts owed to the buyer of approximately $8.4 million and title defects of $0.1 million offset by revenue receivable of $7.5 million and net of brokers fees of $0.3 million, net, proceeds amounted to $15.3 million which were remitted to the Company’s Secured Lenders.

2017 Activity

On April 3, 2017, the Company completed an acquisition of oil and gas leases covering approximately 5,874 gross (1,462 net) acres in Adams and Weld Counties, Colorado. The seller reserved to itself all rights in the leases that exist below 50 feet above the top of the uppermost J Sand formation for those lands located in Township 7 North, Range 63 West in Weld County, Colorado. The acquisition was effective January 1, 2017. The net purchase price to the Company’s retained interest in the assets, following the Company’s working interest partner’s 50% participation in the transaction and a reduction in purchase price due to title defects, was $1.3 million. The Company paid $0.5 million of the Company’s net purchase price in cash, and $0.8 million was paid through the issuance of 450,000 shares of the Company’s common stock valued at $1.80 per share.

On April 21, 2017, the Company acquired a 9.37% royalty interest covering approximately 145 net acres located in Adams County, Colorado for a net purchase price of $0.6 million following the Company’s working interest partner’s 50% participation in the transaction. The acquisition was effective April 1, 2017. In connection with the acquisition, the Company paid a finders’ fee of 20,555 shares of common stock valued at $1.80 per share to a lease broker.

On May 9, 2017, the Company acquired 200 gross (70 net) acres in Adams County, Colorado for a net purchase price of $0.4 million following the Company’s working interest partner’s 50% participation in the transaction. The transaction was effective April 1, 2017.

On September 15, 2017, the Company completed a purchase of additional oil and gas leases covering approximately 400 gross (200 net) acres. The gross purchase price was $0.4 million, or $0.2 million to the Company’s retained interest following the Company’s working interest partner’s 50% participation in the transaction. The location of the acreage is contiguous with that of the acreage acquired in the April 3, 2017 transaction described above.

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 years ended December 31, 2018 and 2017 are shown below:

	December 31,
	2018	2017
Exploration and abandonment costs	$580,881	$61,693
Development costs	33,393,215	18,771,794
Acquisition of properties
Proved	164,199	—
Unproved	342,982	4,049,380
Total	$34,481,277	$22,882,867

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

NOTE 5 – DEBT

The following table presents account balances and activity for our various debt instruments as of December 31:

	Initial	Supplemental	Convertible	Convertible	Secured
	Line of	Line of	Notes	Notes	Credit
	Credit	Credit	10%	Series B	Facility

December 31, 2016 Principal Balance	$(5,000,000)	$(7,105,000)	$(1,942,600)	$-	$-
December 31, 2016, Total, net	$(5,000,000)	$(7,105,000)	$(5,308)	$-	$-
Principal
Borrowings	-	-	(8,057,400)	(4,724,900)	(5,000,000)
Repayments	-	3,552,500	-	-	-
Conversions	-	-	5,166,800	-	-

Beginning Balance - Unamortized Debt Issuance Costs - Original Issuer Discount	-	-	204,703	-	-
Additions	-	-	804,750	205,211	104,871
Accretion	-	-	(742,944)	(36,887)	(1,436)
Ending - Unamortized Debt Issuance Costs - Original Issuer Discount	-	-	266,509	168,324	103,435

Beginning Balance - Unamortized Debt Issuance Costs - Beneficial Conversion Feature	-	-	1,030,762	-	-
Additions	-	-	4,272,867	56,500	-
Accretion	-	-	(3,978,881)	(11,959)	-
Ending - Unamortized Debt Issuance Costs - Beneficial Conversion Feature	-	-	1,324,748	44,541	-

Beginning Balance - Unamortized Debt Issuance Costs - Warrant Discount	-	-	701,827	-	-
Additions	-	-	2,978,791	-	-
Accretion	-	-	(2,758,537)	-	-
Ending - Unamortized Debt Issuance Costs - Warrant Discount	-	-	922,081	-	-

December 31, 2017, Principal Balance	$(5,000,000)	$(3,552,500)	$(4,833,200)	$(4,724,900)	$(5,000,000)
December 31, 2017, Total, net	$(5,000,000)	$(3,552,500)	$(2,319,862)	$(4,512,035)	$(4,896,565)
Principal

PetroShare Corp. 10-K