Table of Contents

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, 2017
For the fiscal year ended: December 31, 2018
or
Or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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 ~~ofincorporation~~of incorporation or organization) 46‑-1454523 (I.R.S. ~~EmployerIdentification~~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~~ ☐ 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 ~~and posted on its corporate Website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S‑-T (§~~203~~232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes ☒ 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 ~~30,~~ ~~2017~~29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, there were 1318,~~142~~103,~~637~~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 ~~30,~~ ~~2017~~29, 2018, was $2226,~~999~~430,~~615~~396.

On ~~March 28,~~April ~~2018~~2, 2019, there were 2728,~~788~~077,~~802~~337 shares of the Company’s common stock outstanding.

Documents incorporated by reference: None

Table of Contents

PETROSHARE CORP.

ANNUAL REPORT ON FORM 10‑-K

TABLE OF CONTENTS

PART I
Items 1. and 2.	Business and Properties	1
Items 1 and 2.	Business and Properties	2
Item 1A.	Risk Factors	1512
Item 1B.	Unresolved Staff Comments	2922
Item 3.	Legal Proceedings	2922
Item 4.	Mine Safety Disclosures	2922
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3022
Item 6.	Selected Financial Data	3223
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3323
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4531
Item 8.	Consolidated Financial Statements and Supplementary Data	4632
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	8464
Item 9A.	Controls and Procedures	8464
Item 9B.	Other Information	8565
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	8665
Item 11.	Executive Compensation	9068
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	9170
Item 13.	Certain Relationships and Related Transactions, and Director Independence	9471
Item 14.	Principal Accounting Fees and Services	9572
PART IV
Item 15.	Exhibits, ~~and Consolidated~~ Financial Statements Schedules	9672

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 ~~the~~Item ~~Exhibit~~15. ~~Index~~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 28 21 of this report for important information contained herein.

Glossary

Please see page 42 30 for a glossary of certain terms used in this report.

~~Table of Contents~~ 1

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.

~~PetroShare~~All ~~Corp.~~of ~~(“we,” “~~our,” ~~“us”~~properties orare ~~the~~located ~~“Company”)~~in isColorado. anAs of ~~independent~~April ~~oil~~3, ~~and~~2019, ~~gas~~we ~~company~~had ~~incorporated~~an interest ~~under~~in ~~the~~58 ~~laws~~gross of(24.4 ~~the~~net) ~~State~~productive ofwells ~~Colorado~~and ~~on September 4~~31,656 ~~2012 to investigate~~gross (9,687 ~~acquire~~net) ~~and~~acres ~~develop~~of ~~crude~~ oil and ~~natural~~ gas properties. inAs ~~the Rocky Mountain or mid-continent portion~~ of ~~the~~December ~~United States. Since 2016~~31, 2018, ~~our~~we ~~operational~~were ~~focus~~producing ~~has~~hydrocarbons ~~been~~at in the ~~Wattenberg~~rate ~~Field~~of inapproximately 2,232 ~~the~~BOE/D. ~~Denver-Julesburg~~At ~~Basin~~December 31, or2018, DJwe ~~Basin,~~had inan ~~northeast~~estimated ~~Colorado~~2,910.7 WeMBOE of ~~believe~~proved ~~the~~developed ~~Wattenberg~~reserves ~~Field~~and is4,414.1 ~~one~~MBOE of ~~the~~proved ~~premier~~undeveloped reserves, ~~liquids-rich~~including ~~oil~~reserves ~~and~~associated ~~natural~~with ~~gas~~properties ~~resource~~that ~~plays~~we sold in ~~the~~February, ~~United States~~2019. It ~~contains~~Our ~~hydrocarbon-bearing~~net ~~deposits~~proved inreserves ~~several~~at ~~formations~~December 31, 2018 ~~including~~were ~~the~~comprised ~~Niobrara~~of ~~and~~approximately ~~Codell. The~~60% ~~area has produced~~ oil and ~~natural~~NGLs (collectively, ~~gas since the 1970s and benefits from an established infrastructure and seasoned service providers~~liquids).

~~All~~Our strategy ofto ~~our~~date ~~properties~~has ~~are~~been ~~located~~to infocus ~~Colorado.~~on Asacquiring ofand ~~March 28,~~developing crude ~~2018,~~oil weand ~~had~~natural angas ~~interest~~properties in 94those ~~gross~~areas ~~(31.8~~we ~~net)~~consider ~~productive~~as geo-mechanical ~~wells~~sweet ~~plus~~spots, 11including ~~gross (1.3 net) wells in~~ the ~~final~~southern-Wattenberg ~~stages~~ area of ~~completion~~the ~~and~~DJ 33Basin,~~681~~ ~~gross~~which ~~(9,770~~we ~~net)~~refer ~~acres~~to ofas ~~oil~~the ~~and~~Southern ~~gas~~Core ~~properties~~area. AsWe elected ofto ~~December 31,~~concentrate ~~2017,~~on wethe ~~were~~Southern ~~producing~~Core ~~hydrocarbons~~due atto the ~~rate~~high quality of ~~approximately~~hydrocarbon-bearing ~~785~~rock ~~BOE/D.~~and Atthe ~~December 31,~~production ~~2017~~from other, wenearby wells. ~~had~~The anSouthern ~~estimated~~Core 1area contains the Niobrara and Codell geologic formations,~~534.1~~ ~~MBOE~~which oftend ~~proved~~to ~~developed~~yield ~~reserves~~oil-weighted ~~and~~production that ~~6,310.8~~remains ~~MBOE~~economic ofin ~~proved~~lower ~~undeveloped~~commodity ~~reserves.~~price environments.

~~Our~~During 2018, ~~strategy~~we tocompleted ~~date~~and ~~has~~brought ~~been~~into toproduction ~~focus~~our onfirst ~~acquiring~~operated horizontal ~~and~~wells, ~~developing~~located ~~crude~~on ~~oil~~our ~~and~~Shook ~~natural~~Pad ~~gas properties~~ in ~~those~~northwest ~~areas~~Adams County. weSee ~~consider~~“Recent asDevelopments-Shook ~~geo‑mechanical sweet spots~~Pad,” ~~including~~below. ~~the~~In any ~~southern‑Wattenberg area of the DJ Basin~~drilling, ~~which~~ we ~~refer~~expect tothat asour ~~the~~retained ~~Southern~~working ~~Core~~interest ~~area.~~will Webe determined ~~elected~~based toupon ~~concentrate~~factors onsuch ~~the~~as ~~Southern~~level ~~Core due to the high quality~~ of ~~hydrocarbon‑bearing~~interest ~~rock and the production from other~~ownership, well ~~nearby~~costs ~~wells.~~and ~~The~~geologic ~~Southern Core area contains the Niobrara~~ and ~~Codell~~engineering ~~geologic~~risk. ~~formations,~~See ~~which~~Item ~~tend~~7. MANAGEMENT’S toDISCUSSION ~~yield~~AND ~~oil‑weighted~~ANALYSIS ~~production~~OF ~~that~~FINANCIAL ~~remains~~CONDITION AND ~~economic~~RESULTS inOF ~~lower~~OPERATIONS ~~commodity~~for ~~price~~more ~~environments~~information.

~~During~~In May ~~2017~~2015, wein ~~drilled~~connection ~~our~~with ~~first~~a ~~operated~~credit ~~wells~~agreement, ~~located~~we onentered ~~our~~into ~~Shook~~a participation ~~Pad~~agreement inwith ~~northwest~~Providence ~~Adams~~Energy ~~County~~Operators, ~~for~~LLC (“PEO”). ~~which~~PEO weis ~~expect~~an toaffiliate ~~initiate~~of ~~completion~~Providence ~~activities~~Energy Corp., ~~beginning~~a inprivately-held ~~April~~multi-million-dollar ~~2018. In~~acquirer ~~addition~~of tooil ~~the~~and gas 14properties ~~wells~~throughout on the ~~Shook~~United ~~Pad~~States. ~~operated~~As bydiscussed ~~the~~elsewhere in ~~Company~~this report, ~~all~~an affiliate of ~~the~~PEO ~~other~~is ~~horizontal~~a ~~wells~~major participant in ~~which~~our principal welender ~~have~~group anthrough ~~interest~~which aswe ofcurrently ~~March~~maintain ~~28,~~a ~~2018~~$25.0 million Secured ~~are~~Credit ~~operated~~Facility. byPEO ~~independent~~is ~~third-parties.~~also Wethe ~~maintain~~beneficial owner ~~less~~of ~~than~~11.6% aof ~~50%~~our ~~interest~~outstanding incommon ~~all~~stock. ofThe ~~these~~participation agreement ~~wells~~grants asPEO wethe ~~seek~~option to ~~diversify~~acquire ~~risk~~up ~~and~~to ~~minimize~~a ~~capital~~50% ~~exposure~~interest toand participate ~~development,~~in ~~drilling~~any oil and ~~completion~~gas ~~costs.~~development Inon ~~any~~acreage ~~drilling,~~ we ~~expect~~obtain within ~~that~~an ~~our~~area ~~retained~~of ~~working~~mutual interest ~~will~~(AMI) benear ~~determined~~our ~~based~~Southern ~~upon~~Core area. ~~factors~~To ~~such as~~date, ~~level~~PEO ofhas ~~interest~~exercised ~~ownership,~~its ~~well~~option ~~costs~~under ~~and~~the ~~geologic~~participation agreement ~~and~~or ~~engineering~~otherwise ~~risk.~~participated ~~See~~or ~~Item~~agreed 7.to ~~Management’s~~participate ~~Discussion~~in ~~and Analysis~~ all of ~~Financial~~our ~~Condition~~acreage acquisitions and ~~Results~~drilling ~~of Operations for more information~~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.

Our Competitive Strengths

We believe we are well‑positioned to capitalize on current conditions in the oil and natural gas industry as a result of the following competitive strengths, in addition to the location of our properties.

Table of Contents

Our Management

Our Chief Executive Officer, Stephen Foley, has over 16 years of experience as a real estate developer in Colorado, with an extensive background in surface development, including in the areas in which we have acquired acreage. Our President, Frederick Witsell, and Chief Operating Officer, William Lloyd, bring a long history and knowledge of basins in Colorado and depth of experience in the industry to our company. Mr. Witsell has over 37 years of experience in several facets of the oil and gas industry, including prospect development, conventional and horizontal drilling and completion operations, project management, gathering and compression systems and marketing and risk management. Mr. Lloyd also has over 37 years of experience in the industry, serving in engineering, management and senior leadership capacities. In addition to their experience, these individuals bring valuable relationships with other recognized industry participants which have, and we believe will continue to, provide opportunities to our company.

Our Strategic Partnerships

Through relationships cultivated by our executive officers, we have formalized agreements with business partners that have, and we believe will continue to, contribute significantly to our growth. Our relationships with real estate developers and other stakeholders in and around our focus areas, continue to yield leasing and surface access opportunities.

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, and which currently owns and/or manages over two million net acres in 37 states with royalty or working interests in over 10,000 wells. As discussed elsewhere in this report, an affiliate of PEO is a major participant in our principal lender group through which we currently maintain a $25.0 million term credit facility, and PEO is the beneficial owner of 11.7% of our common stock currently outstanding. PEO and related entities could beneficially own up to 37% of our common stock after exercising certain conversion rights. The participation agreement grants PEO the option to acquire up to a 45% 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.

We believe our relationship with PEO is instrumental to our success. In addition to providing funding for our acquisition and development strategy, the relationship provides us access to PEO’s oil and gas expertise. We believe our relationship with PEO is strong, as evidenced by its participation in our acreage acquisitions, our borrowing arrangement, and its holdings in our common stock.

Liquids-Weighted Reserves

Our net proved reserves at December 31, 2017 were comprised of approximately 67% oil and NGLs (collectively, liquids). Given the current commodity price environment and resulting disparity between oil and natural gas prices on a BOE basis, we believe our high percentage of liquid reserves and drilling program focused on oil-weighted projects, compared to our overall reserve base, is a key strength.

Multi-Year Drilling Inventory Targeting the Niobrara and Codell Formations

We believe nearby operator horizontal drilling activity and well results in and around our acreage have significantly mitigated the geologic risk in our drilling program. Our Todd Creek Farms and South Brighton prospects are located in an area where drilling results and the liquids-weighted nature of the assets allow for generating accretive returns even in a low commodity price environment. To date, we have identified up to 237 gross horizontal drilling

Table of Contents

locations (up to 15.5 net wells) in our Todd Creek Farms and South Brighton Focus Areas which we are in the process of increasing our interests through acreage swaps and lease purchases. As of December 31, 2017, 94 of these locations have been designated proved undeveloped reserves by our third-party reserve engineer. We believe our multi-year drilling portfolio provides the potential for near-term growth in our production and reserves and highlights the long-term resource potential across our asset base.

Recent Developments

AsFollowing is ~~discussed~~a insummary ~~more~~of ~~detail~~certain ~~below,~~significant weevents ~~drilled and cased 14 wells on our operated Shook pad during 2017. In March 2018, following successful negotiations~~ to ~~obtain~~which ~~access to gathering and pipeline facilities,~~ we ~~entered~~have ~~into~~been party ansince ~~agreement to fracture treat all~~ the ~~wells~~beginning ~~on the Shook pad. The wells on the Shook pad targeted all three benches~~ of ~~the Niobrara plus the Codell sandstone formations. Pressure pumping equipment is scheduled to be on location on April 1,~~ 2018 with all completion activities and production facilities expected to be finalized by mid-May. Subject to completion of the gathering pipeline by an independent third party, we expect these wells to be on full production by June 2018. :

~~Non‑Operated Drilling Participation~~ Shook Pad

~~Beginning in 2016 and continuing into 2017~~During 2018, we ~~participated~~completed ~~in the drilling~~ and ~~completion~~placed ofinto 17production ~~gross~~our ~~(2.9 net) horizontal wells in the Southern Core as a non~~14-~~operator.~~well ~~All~~Shook ~~of these wells are being operated by operators with an established track record~~ pad in ~~the~~Northwest ~~Wattenberg~~Adams ~~Field~~County. Of ~~the~~The ~~17 gross wells~~pad, ~~three~~started ~~were put~~ in ~~production~~2017, incontains ~~late 2016 and the~~ 14 ~~Jacobucci~~ mid-~~range~~length lateral wells ~~were~~and ~~put~~is onconnected ~~production~~to inthe ~~February~~White ~~and~~Cliffs pipeline ~~March~~through ~~2017. Our~~which ~~participation~~we intransport ~~these~~hydrocarbons ~~wells~~for ~~provided~~sale. usWe ~~with~~own an ~~the~~approximate ~~first~~working ~~significant~~interest ~~revenue~~of 49% in ~~our~~the ~~history~~wells, ~~providing~~and ~~the vast majority of~~ our partner ~~fiscal~~PEO ~~2017~~owns ~~revenue~~approximately ~~of $11~~49%.~~1 million.~~

We Secured ~~are~~Credit also currently participating as a non-operator in 22 Codell and Niobrara horizontal wells in which we have a working interest ranging from 3.4% to 18.6%. These non-op horizontal wells are in various stage of flowback and clean-up after fracture stimulation or have been drilled and cased and are waiting on fracture treatment and final completion activities. 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”

In December 2017, we completed the first closing of $5.0 million of what ultimately became a $25.0 million Credit Facility, all of which was used to reduce our accounts payable or accrued liabilities. On February 1, 2018, we finalized a credit agreement with Providence Wattenberg Ltd., a Texas limited partnership and affiliate of PEO, and 5NR Wattenberg, LLC, a Texas limited liability company (collectively, the “Lenders”) pursuant to which the Lenders loaned us $25.0 million under a term credit facility. This facility allowed us to partially or fully repay certain lines of credit and extend a line of credit that was to mature in December 2017. The remaining capital is earmarked for pipeline construction, drilling and completion activities and additional working capital. 2

~~Capital~~Our biggest ~~Raises~~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.

During 2017, we completed two financings which provided approximately a net $11.8 million of working capital. In the two private financings, completed in January and October 2017, we sold convertible promissory notes with warrants, the proceeds of which allowed us to continue our drilling and other development activities during the year. Non-Operated Sale

On 3February 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 ~~Table~~sale does not include any of ~~Contents~~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~~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~~Area covers areas in northwest Adams County and southwest Weld County. The Southern Core ~~area~~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~~ 3

The 4following map depicts our properties in the Southern Core:

We ~~Table~~currently possess an inventory of ~~Contents~~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.

We currently possess an inventory of approximately 237 gross potential horizontal drilling locations within our Southern Core area including over 200 locations that are fully permitted or in the permitting stages. The remaining locations are potential infill wells located in and around current drilling spacing units established under applicable industry rules. We have not included certain of these potential 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 ~~drilled and cased~~ 14 producing horizontal wells, is located in the Todd Creek focus area. We have also permitted eights wells on the Corcilius ~~Corcillius~~ pad located ~~with~~within this focus area, ~~but~~however, weour ~~have~~plans noto drill ~~immediate~~and ~~plans~~complete the Corcilius wells in ~~2018~~2019 toare ~~commence~~dependent ~~drilling~~on receiving ~~those~~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.

~~Our~~On February ~~working~~27, ~~interest~~2019, inwe completed the ~~Shook~~sale ~~pad~~of ~~wells~~essentially ~~averages~~all ~~approximately~~of ~~42%. Since~~our non-operated ~~the~~production ~~final~~and ~~well~~proven ~~was~~undeveloped ~~cased~~locations in ~~August~~the Todd ~~2017,~~Creek weFarms ~~have~~area. The ~~been~~non-operated ~~negotiating~~wells ~~pipeline~~ and ~~gathering~~associated production ~~access,~~provided ~~and have identified and reached agreement with~~ a ~~suitable~~significant ~~third~~portion ~~party. Assuming completion~~ of ~~the~~our ~~pipeline~~cash ~~and~~flow ~~gathering~~during 2018 ~~line,~~prior ~~and~~to ~~completion~~our ofbringing ~~fracture~~online ~~activities~~our ~~scheduled~~operated toShook ~~commence~~production in the ~~April~~fourth ~~2018,~~quarter weof ~~expect these 14 wells to be fully producing by June~~ 2018~~, adding significantly to our revenue~~.

~~Our~~ Wheels ~~most~~Up ~~significant~~(aka ~~non‑operated~~South interest in the Todd Creek Farms focus areas is the Jacobucci pad. In connection with an acquisition in April 2016, we acquired the seller’s right to participate in this 14 mid‑range well program. Our working interest in these wells ranges from 8% to 27%, resulting in a net of 2.9 wells to our interest. These wells were completed in February and March 2017 and have been producing since that time. These wells provided the majority of our cash flow during 2017. 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.

~~Our~~During ~~South~~2018, ~~Brighton~~we received ~~Focus~~state ~~Area~~approved isdrilling ~~east~~permits ofas ~~our~~the ~~Todd~~operator ~~Creek~~for ~~Farms~~up ~~prospect~~to 56 ~~and~~(2 ~~sits~~mile) inhorizontal ~~northern~~wells ~~Adams~~with ~~County~~another ~~and~~16 ~~southern~~horizontal ~~Weld~~wells targeting ~~County.~~the WeNiobrara ~~acquired~~and the ~~majority~~Codell offormations ~~this~~pending ~~acreage~~final state ~~in 2016~~approval. In Weaddition, we have ~~leaseholds~~eight ~~encompassing 5,807~~ (2~~,235~~ ~~net~~mile) horizontal ~~acres~~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 ~~South~~City of Brighton ~~Focus~~and ~~Area.~~the availability of capital.

During 2017 and early 2018, we have assembled drill spacing units and made application for 100 gross extended length (2 mile) horizontal wells as the operator targeting the Niobrara and the Codell formations. Of that amount, eight pending permits are for our Brighton Lakes Pad. 4

Runway

Our Runway prospect area is east of our Todd Creek Farms and ~~South~~our ~~Brighton~~Wheels Up areas and lies principally within Adams County, Colorado, east of the Denver International Airport. We have leaseholds encompassing 20,~~117~~118 gross (5,~~240~~239 net) acres in the Runway prospect.

Buck Peak

We divested of our interest in the Buck Peak prospect, located in Western Colorado in Moffat County, during 2017 and no longer hold any leaseholds in this area.

Table of Contents

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned a working interest as of ~~March 28,~~April ~~2018:~~2, 2019:

		Productive Wells(1)(2)
	Productive Wells (1)
	Crude Oil	~~Crude Oil~~	Natural Gas		Total	~~Natural Gas~~		~~Total~~
Location	Gross	~~Gross~~Net	Gross	Net	Gross	~~Gross~~Net	~~Net~~	~~Gross~~	~~Net~~
Southern Core	54	5723.24	4.0	161.12	58	3724.36	16	94	32
Total productive wells	54	5723.24	4.0	161.12	58	3724.36	16	94	32

(1) ~~Includes~~The a total ofwells 21in ~~gross~~which ~~wells~~we have an interest include 14 gross (26.995 net) inhorizontal ~~which~~wells weon the Shook pad. The remaining wells are ~~participating~~vertical aswells, asome ~~non~~of which are currently or periodically shut-~~operator~~in.

(2) Includes up to 33 gross wells that are currently or periodically shut-in.

Developed and Undeveloped Acreage

The following table shows our developed and undeveloped acreage as of April ~~March 28~~2, ~~2018~~2019:

			Acreage			~~Acreage~~
	Developed	~~Developed~~	Undeveloped (1)		Total	~~Undeveloped(1)~~		~~Total~~
Location	Gross	~~Gross~~Net	Gross	Net	Gross	~~Gross~~Net	~~Net~~	~~Gross~~	~~Net~~
Todd Creek Farms	2,016	~~2,570~~615	—	~~990~~—	2,016	~~1,351~~615	~~425~~	~~3,921~~	~~1,415~~
South Brighton		4,529		1,783		1,278	452	5,807	2,235
Wheels up	4,312	1,840	947	327	5,259	2,167
Northern Wattenberg	80	8032	2,036	32803	2,116	~~3,756~~835	~~848~~	~~3,836~~	~~880~~
Runway		12,284		4,402		7,833	838	20,117	5,240
South Brighton	—	—	549	268	549	268
Total acreage		19,463		7,207		14,218	2,563	33,681	9,770
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 ~~sale~~purchase, farm‑-in, or ~~purchase.~~ 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 ~~2018~~ 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.

6 5

Table of Contents

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	~~Expiration of~~
Gross	Net	~~Net~~Lease	~~Lease~~
80		20	2018
3,428	1,005	2019
4,378		1,153	2019
7,020	759	2020
8,317		1,074	2020
579	299	2021
1,123		156	2021
339	174	2022
320		160	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, ~~2017~~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,	~~For the Year Ended December 31,~~
		2017(1)				2016(2)		2015
	2018(2)		2017(1)		2016
	Gross	~~Gross~~Net	Gross	Net	Gross	~~Gross~~Net	~~Net~~	~~Gross~~	~~Net~~
Development Wells
Productive	28	368.4	21	72.695	—	~~17.0~~—	~~2.9~~	—	—
Dry	—	—	—	—	—	—	—	—	—
Exploratory Wells
Productive	—	—	—	—	—	—	—	—	—
Dry	—	—	—	—	—	—	—	—	—
Total Wells
Productive	28	368.4	21	72.695	—	~~17.0~~—	~~2.9~~	—	—
Dry	—	—	—	—	—	—	—	—	—

(1) Includes 22 non-operated wells.

(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.

(2) All non-operated wells.

Table of Contents

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,	~~Year Ended December 31,~~
		2017		2016		2015
	2018	2017	2016
Sales volumes
Oil (Bbls)	287,984	188,529	4,903	~~4,903~~		37
Gas (Mcf)	773,396	549,846	26,059	~~26,059~~		—
NGLs (Bbls)	55,811	50,111	1,511	~~1,511~~		—
BOE	472,694	330,281	10,756	~~10,756~~		37
Average sales price
Oil (per Bbl)	$58.37	$46.25	$48.91	~~48.91~~	$	~~36.29~~
Gas (per Mcf)	$3.18	$2.78	$2.62	~~2.62~~	$	—
NGLs (per Bbl)	$20.39	$17.20	$16.55	~~16.55~~	$	—
BOE	$43.17	$33.63	$30.97	~~30.97~~	$	~~36.29~~
Average production cost per BOE	$	5.19	$	19.21	$	871.82
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, ~~2017~~2018 and ~~2016~~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~~ 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 8estimate 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.

Table of Contents

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, ~~2017~~2018, all of which are located in Colorado, based on a reserve report prepared by Cawley Gillespie. dated March 4, 2019.

			Natural Gas		~~Natural Gas~~
	Crude Oil	~~Crude~~Natural ~~Oil~~Gas	Liquids	~~Natural Gas~~	~~Liquids~~
	(MBbls)	(~~MBbls~~MMcf)	(MBbls)	~~(MMcf)~~MBOE	~~(MBbls)~~	~~MBOE~~
Proved Developed Producing	1,188	~~254~~6,300.81	672.7	2,~~500~~910.07	~~187.4~~	~~858.9~~
Proved Developed Non‑Producing		266.5		1,252.4	200.0	675.2
Proved Developed Non-Producing	-	-	-	-
Proved Undeveloped Reserves	2,005.2	211,~~502~~232.86	536.8	114,~~666~~414.91	~~1,863.5~~	~~6,310.8~~
Total Proved Reserves	3,193.1	317,~~024~~532.17	1,209.6	157,~~419~~324.38	~~2,250.9~~	~~7,844.9~~

At December 31, ~~2017~~2018, we had estimated total proved reserves of 7,~~844~~324.98 MBOE, consisting of 3,~~024~~193.1 MBbls of crude oil, 1517,~~419~~532.3 7 MMcf of natural gas, and 21,~~250~~209.96 MBbls of natural gas liquids. ~~Our~~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 Undeveloped Reserves~~ 7

At Proved ~~December 31,~~Developed ~~2017,~~Reserves ~~we had 6,310.8 MBOE of proved undeveloped reserves. We have included in our proved undeveloped reserves only those locations for which we have established a development plan~~ and ~~believe~~Proved we can drill and complete within five years of the date of this report considering our existing and anticipated capital resources. We also have included certain non‑operated properties the operator of which has informed of us of planned development within the next five years and in which we have plans to participate.Undeveloped Reserves

At 9December 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 ~~Table~~December 31, 2018, we had 4,414.1 MBOE of ~~Contents~~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, ~~2017~~2018:

	Total (MBOE)	~~Total (MBOE)~~
Total proved undeveloped reserves:
Beginning of year	6,310.8		~~5,567.8~~
Revisions of previous estimates	570.9		~~35.8~~
Additions from discoveries, extensions and infill	69.7		~~2,168.2~~
Sales of reserves	(324.0)		—
Purchases of minerals in place	-		—
Removed for five-year rule	-		—
Conversions to proved developed	(2,213.3)		~~(1,461.0)~~
End of year	4,414.1		~~6,310.8~~

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, ~~2017~~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 7 4, ~~2018~~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.

10 Operations

~~Table of Contents~~ 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 Colorado Oil and Gas Conservation Commission, or 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. As of December 31, 2017, only one non-operated multi-well horizontal drilling units would be subject to these new large-scale facilities regulations. 9

WeOn January ~~currently~~25, ~~own~~2016, orthe ~~lease~~COGCC ~~numerous~~approved ~~properties~~new ~~that~~rules ~~have~~enhancing ~~been~~local government ~~used~~participation ~~for~~in ~~the~~locating ~~exploration~~ and ~~production~~planning offor ~~crude~~large scale oil and ~~natural~~ gas ~~for many years~~operations. IfThe ~~hydrocarbons~~COGCC ordefined ~~other~~large ~~wastes~~scale ~~have~~facilities ~~been~~as (i) ~~disposed~~any oflocation ~~or released on or under the properties~~ that weproposes ~~own~~eight ornew ~~lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties~~horizontal, ~~we could be subject to liability under the Comprehensive Environmental Response~~directional, ~~Compensation and Liability Act,~~ or ~~CERCLA,~~vertical ~~the Federal Resource Conservation and Recovery Act~~wells, or ~~RCRA~~(ii) ~~and~~cumulative ~~analogous~~hydrocarbon ~~state~~storage ~~laws, as well as state laws governing the management~~ capacity of ~~crude oil and natural gas wastes. CERCLA and similar state laws impose liability~~4,000 ~~without~~Bbls ~~regard to fault~~ or ~~the legality of the original conduct~~more, onwhich ~~certain classes of persons that~~ are ~~considered~~located towithin ~~have~~an ~~contributed~~urban tomitigation area ~~the~~as ~~release~~defined ofby aCOGCC ~~“hazardous~~rules. ~~substance”~~The ~~into~~new ~~the~~COGCC ~~environment.~~rules ~~These~~also ~~persons~~ include additional ~~the~~notice ~~owner or operator of the disposal site or sites where the release occurred~~ and ~~companies~~consultation ~~that~~requirements ~~disposed of, transported, or arranged~~ for ~~the~~operators ~~disposal~~when planning ofsuch ~~the~~large-scale ~~hazardous substances found at the site~~facilities. 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

We 11currently 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.

Table of Contents

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.

In March 2017, the Colorado Court of Appeals held that Colorado oil and gas regulations require the COGCC to grant permits for new oil wells on the condition that requisite levels of environmental and public safety are met based on a determination by an independent third party. The Court of Appeals’ holding invalidates the COGCC’s prior balancing inquiry, which weighed interests in oil and gas development against environmental and public safety factors. The case has been remanded to the lower court for further findings. It remains unclear what impact this holding will have on the oil and gas industry.

Hydraulic Fracturing

We operate primarily in the Wattenberg Field of the DJ Basin where the rock formations are typically tight, and it is a common practice to utilize hydraulic fracturing to allow for or increase hydrocarbon production. Hydraulic fracturing involves the process of injecting substances such as water, sand and additives (some proprietary) under pressure into a targeted subsurface formation to create pores and fractures, thus creating a passageway for the release of oil and gas. Hydraulic fracturing is a technique that we 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 ~~each~~ 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.

12 10

Table of Contents

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.

During 2014, opponents of hydraulic fracturing also sought statewide ballot initiatives that would have restricted oil and gas development in Colorado by, among other things, significantly increasing the setback between oil and natural gas wells and occupied buildings. These initiatives were withdrawn from the November 2014 ballot in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities.

During 2016, opponents of hydraulic fracturing again advanced various options for ballot initiatives restricting oil and gas development in Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a minimum distance of 2,500 feet between wells and any occupied structures or “areas of special concern.” If implemented, this proposal would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. The second proposal would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas exploration, development, and production activities within their boundaries notwithstanding state rules and approvals to the contrary. If implemented, this proposal could have resulted in us becoming subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in various jurisdictions. Neither of these proposals ultimately appeared

Table of Contents

on the ballot. However, similar proposals may be made in the future. Because all of our operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves.

Adams County USR Process

On March 22, 2016, the Adams County Board of County Commissioners approved amendments to the county’s oil and gas regulatory process~~, which ended a temporary drilling moratorium previously imposed~~. The new regulations include an enhanced administrative review process for operators that share a Memorandum of Understanding, or MOU, with Adams County, including a site‑-specific review of any oil and gas permit application. The regulations also require compliance with the USR approval process for oil and gas facilities governed by an MOU between the operator and Adams County. This approval process includes increased notice and 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 ~~2016,~~ we2019 ~~submitted a USR application for our Shook pad to Adams County, which was approved by~~ the ~~county in September 2016. The above newly‑enacted regulations in~~ Adams County ~~and~~Commissioners ~~any~~imposed ~~additional~~a ~~regulations~~moratorium ~~that~~on new ~~may result in the future may delay or prevent our~~ drilling ~~activities~~permits ~~and~~within ~~increase~~unincorporated ~~our~~areas ~~costs~~ of ~~development~~the ~~and~~County ~~production~~for a ~~and~~period ~~limit the quantity~~ of ~~oil~~six ~~and gas that we can economically produce~~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 ~~may~~ 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.

Table of Contents

The oil and gas industry is characterized by rapid and significant technological advancements and introduction of new products and services using new technologies. If one or more of the technologies we use now or in the future become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be materially adversely affected.

Market for Our Products

Currently, all of our produced oil and gas is sold under a variety of month-to-month contracts with local marketing companies. We have no long‑term marketing contract commitments at this time. The availability of a ready market for our oil and gas depends upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the relative status of the domestic and international economies, the proximity of our properties to gas pipeline systems, the capacity of those systems, the marketing of other competitive fuels, fluctuations in seasonal demand, and governmental regulation of production, refining, transportation, and pricing of oil, gas, and other fuels.

Employees

We currently have 1211 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 $1011,~~894~~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

~~Since~~ As wedescribed ~~are~~in athe ~~new~~notes ~~business~~to ~~with~~our aconsolidated ~~limited~~financial ~~operating history~~statements, there ~~investors~~is ~~have~~substantial nodoubt ~~basis~~about our ability to ~~evaluate~~continue as a going concern and we are dependent on receipt of additional capital to fund our ~~ability~~obligations and to ~~operate~~continue ~~profitability~~in operation.

WeThe uncertainty ~~were~~regarding ~~incorporated~~our inability ~~September~~to ~~2012~~continue ~~and~~as ~~our~~a ~~activities~~going toconcern ~~date~~is based ~~have~~on ~~been~~our ~~limited~~defaults tounder ~~organizational~~the ~~efforts~~Secured Credit Facility, substantial ~~raising~~near-term liabilities, continuing net losses and negative working capital, ~~developing~~among ~~our~~other ~~business~~things ~~plan~~which existed as of December 31, ~~assembling~~2018. anAt ~~initial~~December ~~lease~~31, ~~inventory~~2018, ~~participating~~we ashad a ~~non‑operator~~cash inbalance ~~several~~of approximately ~~drilling~~$2.6 ~~programs~~million and ~~limited~~other ~~drilling~~current ~~efforts~~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 ~~face~~had ~~all~~net losses, including non-cash charges, of $17.3 million and $10.8 million for the ~~risks~~years ~~commonly~~ended ~~encountered~~December by31, ~~other~~2018 ~~new~~and ~~businesses~~2017, ~~including~~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 ~~lack~~terms of anour ~~established~~Secured ~~operating~~Credit ~~history~~Facility and as a result, ~~need~~we have ~~for~~included ~~additional~~$29.9 ~~capital~~million including the outstanding principal and accrued ~~personnel,~~interest and ~~competition.~~penalties ~~Our~~in ~~business~~current ~~may~~liabilities. ~~not~~On beApril ~~successful~~2, 2019, orthe weSecured ~~may~~Lenders ~~never~~delivered ~~operate~~their ~~profitably~~formal Notice of Default under the terms of the Secured Credit Facility. The WeNotice declared ~~may~~that ~~not~~all beamounts ~~able~~outstanding were immediately due and payable. Some of our accounts payable obligations to ~~effectively~~vendors ~~manage~~are past the ~~demands~~due ~~required~~date and some of athose ~~new~~vendors ~~business~~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 ~~industry,~~Secured ~~such~~Lenders ~~that~~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 ~~unable~~compelled to reduce ~~successfully~~the ~~implement~~scope of our business ~~plan~~activities, sell a portion of our interests in our oil and gas properties or ~~achieve~~file ~~profitability~~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.

15We 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 ~~Table~~Chapter 11 protection may have a material adverse impact on our business and the trading price of ~~Contents~~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.

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 development of our business plan. 12

~~The~~ Our ~~uncertainty~~secured ~~regarding~~debt ~~our ability to continue as a going concern~~ is ~~based~~currently on our substantial near-term liabilities, limited revenue and cash flow and negative working capital, among other things which existed as of December 31, 2017. At December 31, 2017, we had a cash balance of approximately $0.7 million and other current assets of approximately $2.7 million. In June 2018, we are obligated to repay approximately $2.1 million in ~~principal~~default ~~plus accrued interest on our supplemental line of credit~~ and weif ~~are obligated to pay approximately $9.6 million in principal plus accrued interest on~~ our ~~outstanding~~effort ~~convertible promissory notes in December 2018. We also will incur additional expenses related~~ to negotiate ~~our~~a ~~operated~~continuing ~~drilling~~waiver ~~program on our Shook pad during the second and third quarters~~ of ~~this~~that ~~year.~~default Weis ~~had net losses~~unsuccessful, ~~including non-cash charges, of approximately $10.8 million and $4.5 million during~~ the lenders ~~years~~may ~~ended~~foreclose ~~December~~on ~~31,~~or ~~2017~~force ~~and~~a ~~2016,~~sale ~~respectively.~~of our assets.

~~Our~~We notified ~~ability~~our toSecured ~~continue~~Lenders asin a2018 ~~going~~and ~~concern~~2019 ~~depends~~of onseveral events of default under the ~~success~~terms of ~~our~~the ~~current~~Secured ~~drilling~~Credit ~~efforts~~Facility, ~~future~~including the ~~exploration~~filing ~~and~~of ~~development~~liens ~~efforts,~~on our ~~ability~~properties, toliabilities ~~generate~~that ~~revenue~~were ~~sufficient~~more than to90 ~~cover~~days ~~our~~past ~~costs~~due and ~~expenses~~our ~~and~~inability ~~receipt of additional capital. In addition~~ to ~~funds~~pay ~~required~~the ~~for~~unsecured ~~the~~notes when ~~satisfaction~~they ofmatured ~~existing~~at ~~obligations~~December ~~and~~31, ~~development~~2018. ofOn ~~our~~April ~~existing~~2, ~~acreage~~2019, wethe Secured ~~will~~Lenders ~~require~~delivered ~~capital~~their toformal ~~acquire~~Notice ~~and~~of ~~develop~~Default. ~~additional~~As ~~acreage~~a result asof ~~well~~these asevents, ~~pay~~we ~~our~~are ~~administrative~~in ~~expenses,~~default ~~including~~under ~~salary~~the ~~and~~terms ~~rent. In~~of the Secured ~~event~~Credit weFacility ~~are~~and ~~unable~~as toa ~~obtain~~result ~~adequate~~all ~~funding~~outstanding ~~from our ongoing drilling efforts~~principal, interest ~~both operated~~ and ~~non-operated,~~penalties ~~and~~are ~~through~~immediately ~~the~~due ~~sale~~and ofpayable. ~~debt~~If ~~or equity securities,~~ we ~~may~~are unable ~~have~~ to ~~delay,~~obtain ~~reduce~~a orwaiver ~~eliminate~~of ~~certain~~the ofdefaults ~~our~~the ~~planned~~lenders ~~operations,~~may ~~reduce~~undertake collection ~~overall~~efforts ~~overhead~~against ~~expense,~~us orand ~~divest~~our ~~assets~~property. ~~This~~In inthat ~~turn~~event, ~~may~~the holders ~~have~~of anthe ~~adverse~~debt ~~effect~~would onlikely ~~our~~be ~~ability~~entitled to ~~realize~~the first proceeds of the ~~value~~sale of our assets. Ifand wethe ~~are~~holders ~~unable~~of toour ~~continue~~equity ~~as a going concern, you~~ securities may lose ~~all~~some or ~~part~~all of ~~your~~their investment.

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

WeIn 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 ~~our existing~~ 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 ~~our~~the ~~existing~~Secured ~~debt instruments~~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 default which, if we were unable to obtain a waiver from our lenders, could accelerate our repayment obligations under the lines of credit and thereby have a material adverse impact on our liquidity, financial condition, and ability to remain in business. We would also likely be unable to borrow any further ~~amounts under our other debt instruments, which could adversely affect our ability to fund operations~~default.

We are highly leveraged and any default by us may cause us to forfeit all or a portion of our properties.

As of December 31, 2017, we had outstanding debt in excess of $23.1 million, approximately $18.1 million of which is due 2018. If we are unable to repay any of this debt on a timely basis, we may be forced to forfeit all or a portion of our properties.

Table of Contents

Of the total debt outstanding at December 31, 2017, approximately $13.6 million is secured by liens on our property. Of that amount, $2.1 million under the supplemental line of credit is due in June 2018. All of our convertible notes, approximately $9.6 million are due in December 2018. Our ability to repay our supplemental line of credit and convertible notes payable is dependent on our ability to generate sufficient revenue from operations or obtain cash from other sources. If we are unable to repay the short-term indebtedness or default under our other indebtedness, the lenders may foreclose on our assets. As a result, we may not be able to develop as much property as we presently expect.

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.

Our Southern Core area assets may be less valuable to us than expected.

We have made several oil and gas acquisitions in the Southern Core area since January 1, 2016. Much of the acreage is within our Southern Core focus areas, while the remainder of the acreage is located in outlying areas of Adams, Weld and Broomfield Counties and is prospective for formations other than the Niobrara and Codell. The value of our Southern Core area assets is based in large part on our ability to develop the properties and increase proven and probable reserves. This, in turn, requires us to make accurate estimates of our capital needs to implement and continue a development program for those properties, to obtain that capital and to successfully drill the wells. We may not be able to obtain the capital necessary to develop these properties or our development efforts may not be successful. If we are unable to obtain the necessary capital or successfully develop these properties, the price of our stock may decline, and investors may lose some of their investment.

Table of Contents

We have limited control over activities on properties we do not operate.

Our ability to exercise influence over the operations of the properties which we do not operate, or their associated costs, is limited. Our dependence on the operators and other working interest owners of these projects and any future projects, our limited ability to influence operations and associated costs or control the risks, and our access to required capital could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

· timing and amount of capital expenditures;

· the operator’s expertise and financial resources;

· the rate of production of reserves, if any;

· approval of other participants in drilling wells; and

· selection of technology.

As a result, our ability to exercise influence over the operations of some of our current or future properties is and may be limited.

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 ~~and its affiliate~~ 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 ~~and to~~ 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 45 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 1211 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:

18 ● the possibility that such third parties may not be available to us as and when needed; and

~~Table~~● the risk that we may not be able to properly control the timing and quality of ~~Contents~~ work conducted with respect to its projects.

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 ~~expect~~currently to deliver ~~much~~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.

19We 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 ~~Table~~so long as we remain an emerging growth company as defined in the JOBS Act, we intend to take advantage of ~~Contents~~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.

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.

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 ~~March~~April 272, ~~2018~~2019, the price of WTI was $6562.2561 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:

~~Our~~● ~~revenue,~~the ~~results~~level of ~~operation,~~consumer ~~cash~~product ~~flows, liquidity and reserve estimates depend to a large part on the price~~ demand;

of● ~~oil~~the domestic and ~~gas. Factors~~foreign ~~that~~supply ~~can~~of ~~cause~~oil ~~price~~and ~~fluctuations~~natural ~~include:~~ gas;

·● consumer perception and the ~~level~~availability of ~~consumer~~alternative ~~product~~energy ~~demand~~sources;

20 ● refinery capacity;

~~Table~~● ofdomestic ~~Contents~~ and foreign governmental regulations;

·● ~~the~~actions ~~domestic~~by ~~and~~other ~~foreign~~producers, ~~supply~~including the Organization of ~~oil~~the ~~and~~Petroleum ~~natural~~Exporting ~~gas~~Countries (OPEC);

·● ~~consumer~~political ~~perception~~ and ~~the~~ethnic ~~availability~~conflicts ofin ~~alternative~~oil ~~energy~~and ~~sources~~natural gas producing regions;

·● ~~refinery~~the ~~capacity~~price of foreign imports; and

·● ~~domestic~~overall ~~and~~economic ~~foreign governmental regulations;~~conditions.

· 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.

21 16

Table of Contents

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.

Table of Contents

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.

Table of Contents

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;~~18

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

~~Table~~● ofnatural ~~Contents~~ disasters;

·● ~~natural~~pipe ~~disasters~~and cement failures;

·● ~~pipe~~casing ~~and cement failures~~collapses;

·● ~~casing~~embedded ~~collapses~~oilfield drilling and service tools;

·● ~~embedded~~abnormal ~~oilfield~~pressure ~~drilling~~formations; and ~~service tools;~~

·● ~~abnormal~~environmental ~~pressure~~hazards ~~formations;~~such ~~and~~as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.

· 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;

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

~~Table~~● ofregulatory ~~Contents~~ developments, including new permitting regulations in Colorado;

·● ~~commodity prices in general, and~~ the ~~price~~success of ~~oil~~our indevelopment ~~particular~~efforts;

·● ~~the~~our ~~success~~ability ofto successfully implement our ~~development~~business ~~efforts~~plan;

·● failure to meet our ~~ability~~revenue toor ~~successfully~~profit ~~implement~~goals ~~our~~or ~~business~~operating ~~plan~~budget;

·● ~~failure~~decline toin ~~meet~~demand for our ~~revenue~~common ~~or profit goals or operating budget~~stock;

·● ~~decline~~sales inof ~~demand~~additional ~~for~~amounts ~~our~~of common stock;

~~· sales of additional amounts of common stock;~~19

·● 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 ~~after~~if ~~exercising~~the debtholders exercised certain conversion ~~elections~~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, ~~will~~if ~~strongly~~some convertible ~~influence~~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 26addition, 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.

Table of Contents

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.

Any reverse split of our common stock may adversely affect our shareholders.

In October 2017, our shareholders granted the Board of Directors the discretion to implement a reverse split of our common stock if the Board deems it advisable to do so. We do not intend to amend our Articles of Incorporation in connection with a reverse split to reduce the number of authorized shares of common stock. Accordingly, any reverse split would have the practical effect of an increased number of authorized shares of common stock being available for issuance. The resulting increase could have a number of effects on our shareholders depending on the exact nature and circumstances of any actual issuances of authorized but unissued shares. The practical increase in available authorized shares for issuance could have an anti-takeover effect, in that additional shares could be issued (within the limits imposed by applicable law) in one or more transactions that could make a change in control or takeover of our company more difficult. There is no assurance that the implementation of a reverse split would have the desired effect of raising the price of our stock.

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 ~~110~~210,000,000 shares of stock, including ~~100~~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.

Table of Contents

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 weit ~~may~~is unlikely ~~not~~that bewe inwill ~~a position to~~ 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~~, and will be at the discretion of our Board of Directors~~.

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

In this report, references to “PetroShare,” the “Company,” “we,” “us,” and “our” refer to PetroShare Corp., the Registrant.

The words “anticipates,” “believes,” “estimates,” “expects,” “intends,” “may,” “plans,” “will,” “would,” and similar words or expressions are intended to identify forward‑-looking statements, although not all forward‑-looking statements contain these identifying words. Forward‑-looking statements and information are necessarily based upon a number of estimates and assumptions that, while considered reasonable by management, are inherently subject to significant business, economic and competitive uncertainties, risks and contingencies, and there can be no assurance that such statements and information will prove to be accurate. Therefore, actual results and future events could differ materially from those anticipated in such statements and information. We caution you not to put undue reliance on these statements, which speak only as of the date of this report. Further, the information contained in this document or ~~incorporated herein by reference~~ is a statement of our present intention and is based on present facts and assumptions, and may change at any time and without notice, based on changes in such facts or assumptions. Readers should not place undue reliance on forward‑-looking statements.

The important factors that could affect the accuracy of forward‑-looking statements and prevent us from achieving our stated goals and objectives include, but are not limited to: 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;

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

~~Table~~● access and availability of ~~Contents~~ materials, equipment, supplies, labor and supervision, power, and water;

·● ~~inflation~~interpretation ~~and~~of ~~the~~drill ~~costs~~hole ofresults ~~goods~~and orthe ~~services~~uncertainty ~~used~~of inreserve ~~our operation~~estimates;

·● ~~access~~the ~~and~~ availability of ~~materials,~~sufficient ~~equipment,~~pipeline ~~supplies,~~and ~~labor~~other ~~and~~transportation ~~supervision,~~facilities ~~power,~~to carry our production and ~~water~~the impact of these facilities on price;

·● ~~interpretation~~the level of ~~drill~~demand ~~hole~~for ~~results and~~ the ~~uncertainty~~production of ~~reserve~~crude ~~estimates~~oil and natural gas;

·● ~~the~~changes ~~availability~~in ~~of sufficient pipeline and other transportation facilities to carry~~ our ~~production~~business ~~and the impact of these facilities on price~~strategy;

~~· the level of demand for the production of crude oil and natural gas;~~21

·● ~~changes~~potential infailure ~~our~~to ~~business~~achieve ~~strategy~~production from development drilling projects; and

·● ~~potential~~capital ~~failure to achieve production from development drilling projects; and~~expenditures.

· Those factors ~~capital~~discussed ~~expenditures~~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.

Those factors discussed above and elsewhere in this report are difficult to predict and expressly qualify all subsequent oral and written forward‑looking statements attributable to us or persons acting on our behalf. In light of these risks, uncertainties and assumptions, the forward‑looking events discussed may not occur. We do not have any intention or obligation to update forward‑looking statements included in this report after the date of this report, except as required by law. The preceding outlines some of the risks and uncertainties that may affect our forward‑looking statements.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

Table of Contents

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.

~~The~~On April ~~table~~2, ~~below~~2019, ~~sets forth~~ the high and low sales ~~prices~~price ~~for~~of our common stock on the OTCQB ~~from~~were ~~November 23, 2015 to December 31, 2017~~$0.38 ~~The prices in the table represent prices between dealers~~ and ~~do not include adjustments for retail mark‑up~~$0.36, ~~mark‑down, or commission, and may not represent actual transactions~~respectively.

Period	High		Low
Fiscal Year Ended December 31, 2015
Fourth Quarter (from November 23, 2015)	$	3.50	$	1.10
Fiscal Year Ended December 31, 2016
First Quarter	$	1.77	$	0.60
Second Quarter		1.98		0.66
Third Quarter		1.65		1.20
Fourth Quarter		2.00		1.30
Fiscal Year Ended December 31, 2017
First Quarter	$	1.90	$	1.67
Second Quarter		2.00		1.75
Third Quarter		1.85		1.51
Fourth Quarter		1.51		1.20

On March 27, 2018, the high and low sales price of our common stock on the OTCQB were $1.14 and $1.01, respectively.

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

Holders of our Common Stock

As of ~~March 27~~April 2, ~~2018~~2019, we have outstanding 2728,~~788~~077,~~802~~337 shares of common stock and approximately ~~169~~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.

Table of Contents

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, wethe ~~are~~Secured Credit ~~not~~Facility ~~party~~limits ~~to any agreement that would limit~~ our ability to pay dividends.

Recent Sales of Unregistered Securities

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

· On September 23, 2017, we issued 250,000 shares of our common stock to one of our lenders in connection with an agreement to extend the term of that loan. The shares were valued at $0.4 million for purposes of that transaction.

· On November 16, 2017, we issued 4,814,265 shares of our common stock to a group of accredited investors who previously held convertible promissory notes. The shares were valued at $1.50 per share for purposes of the transaction.

The first of the foregoing transactions was completed pursuant to the exemption from registration provided by Section 4(a)(2) of the Securities Act. In that transaction, we did not engage in any general solicitation or advertising and we offered the securities to a limited number of persons with whom we had pre‑existing relationships. We exercised reasonable care to ensure that the purchasers of securities were not underwriters within the meaning of the Securities Act, including making reasonable inquiry prior to accepting any subscription, making written disclosure regarding the restricted nature of the securities and placing a legend on the certificates representing the shares. Stop transfer restrictions were placed with our transfer agent and a restrictive legend was placed on the certificate in connection with these offerings. In addition, the shares were issued exclusively to what the Company reasonably believed were accredited investors as defined in Rule 501 of the Securities Act.

Table of Contents

· In the second transaction, we relied on the exemption provided by Rule 506(b) of Regulation D adopted under the Securities Act. We exchanged the common stock exclusively with holders of our convertible notes, each of which we reasonably believed to be an accredited investor. All of the certificates representing the shares were embossed with a legend restricting transfer, and stop transfer restrictions were placed with the Company’s transfer agent.

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

ITEM 6. SELECTED FINANCIAL DATA

Not required for smaller reporting companies.

Table of Contents

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

Overview

The following discussion summarizes our plan of operation as of ~~March 28~~April 2, ~~2018~~2019 for the next twelve months and the related anticipated capital expenditures. It also analyzes (i) our financial condition at December 31, ~~2017~~2018 and compares it to December 31, ~~2016~~2017, and (ii) our results of operations for the years ended December 31, ~~2017~~2018 and ~~2016~~ 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.

WeAs an ~~were~~oil ~~organized~~and onnatural ~~September 4,~~gas ~~2012~~exploration ~~under~~and ~~the~~production ~~laws~~company, our revenue, results of ~~the~~operation, ~~State~~cash offlow ~~Colorado~~from tooperations, ~~investigate~~reserve values, ~~acquire~~access to capital and ~~develop~~future ~~crude~~rate of growth are influenced by the prevailing prices of oil and natural gas. ~~properties~~Changes in ~~the~~prices can ~~Rocky~~affect, ~~Mountain~~both positively and ~~mid‑continent~~negatively, ~~region~~our offinancial condition, ~~the~~liquidity, ~~United~~ability ~~States.~~to ~~Following~~obtain ~~the~~financing, ~~acquisition~~operating results, ~~of oil~~ and ~~gas~~the ~~properties~~amount inof ~~2016~~oil and ~~our~~natural ~~participation~~gas inthat ~~several~~we ~~drilling~~choose ~~programs~~to produce. asPrevailing aprices ~~non‑operator,~~for wesuch ~~have~~commodities anfluctuate ~~interest~~ in response 94to ~~gross~~changes ~~(31.8~~in ~~net)~~supply ~~producing~~and ~~oil~~demand and ~~gas~~a ~~wells~~variety ~~located~~of additional infactors ~~the~~beyond ~~Southern~~our ~~Core~~control, ofsuch ~~the~~as ~~Wattenberg~~global, ~~Field.~~political and Weeconomic ~~possess~~conditions. aThe ~~lease~~price ~~inventory~~received ~~covering~~for aoil ~~total~~and ofnatural ~~approximately~~gas production ~~33,681~~is ~~gross (9~~unpredictable,~~770~~ ~~net)~~and ~~acres,~~such ~~the~~volatility ~~majority~~is expected. All of ~~which~~our production is insold ~~the~~at ~~Southern~~market ~~Core.~~prices ~~After~~and, ~~assignment~~therefore, tothe amount ~~our~~of ~~working~~revenue ~~interest~~that ~~partners,~~ we ~~have approximately 3~~realize,~~650~~ ~~net~~as ~~acres~~well inas ~~the~~our ~~Southern~~estimates ~~Core~~of future revenues, ~~which~~is weto ~~are~~a inlarge ~~the~~extent ~~process~~determined ofby ~~developing.~~factors beyond our control.

AsUnder the anterms ~~oil~~of ~~and~~the ~~natural~~participation ~~gas~~agreements ~~exploration~~covering ~~and production Company,~~ our ~~revenue,~~prospects and ~~results~~operating ofagreements ~~operation,~~with ~~cash~~other ~~flow~~third-party ~~from operations~~operators, ~~reserve~~we ~~values,~~are required ~~access~~ to ~~capital~~pay ~~and~~our ~~future~~proportionate ~~rate~~share of ~~growth are influenced by~~ the ~~prevailing~~costs ~~prices~~ of ~~oil~~any ~~and natural gas. Changes~~ wells in ~~prices~~which ~~can~~we ~~affect,~~participate. ~~both~~In ~~positively and negatively~~exchange, ~~our~~we ~~financial~~are ~~condition,~~entitled ~~liquidity, ability~~ to ~~obtain~~a proportionate ~~financing,~~share ~~operating~~of ~~results, and~~ the ~~amount~~revenue, net of ~~oil~~related ~~and natural gas that we choose to produce~~expenses. Accordingly, ~~Prevailing~~the ~~prices~~ultimate ~~for~~success ~~such commodities fluctuate in response to changes in supply and demand and a variety~~ of ~~additional~~our ~~factors~~business ~~beyond~~plan depends on our ~~control,~~ability ~~such~~to asgenerate ~~global,~~sufficient ~~political~~cash ~~and~~flow ~~economic~~from ~~conditions. Inherently,~~ the ~~price~~sale ~~received~~of produced ~~for~~crude oil and natural gas ~~production~~from ~~is unpredictable, and such volatility is expected. All of~~ our ~~production~~interest isin ~~sold at market prices and, therefore,~~ the ~~amount~~leases to ofpay ~~revenue~~our ~~that we realize~~overhead, asoutstanding ~~well~~liabilities asand ~~our~~costs ~~estimates~~ of future acquisitions ~~revenues,~~and ~~is to a large extent determined by factors beyond our control~~development.

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

We cannot fully determine what impact the volatility in crude oil and natural gas prices may have on our ongoing operations and future operations if such volatility continues into the future. Our decision on whether to drill and complete wells is based on both the prevailing commodity prices and 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 ~~accountant’s~~registered ~~report~~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, ~~2017~~2018. We are dependent on improving cash flow and obtaining funding from the sale of debt or equity to continue as a going concern.

33 23

At ~~Table~~December 31, 2018 we had a cash balance of ~~Contents~~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.

As discussed in more detail under Liquidity and Capital Resources below, we had negative working capital of $17.8 million at December 31, 2017, including $2.1 million of a revolving credit facility that matures in June 2018 and $9.6 million of convertible notes that mature at December 31, 2018. If we are unable to generate sufficient cash flow from our operations to repay this debt, as well as pay our other ongoing obligations, we may be forced to curtail our operations or sell properties. We are not permitted to use the proceeds from the credit facility that we finalized in February 2018 to repay this debt. Please see Note 2 to our consolidated financial statements, “- Going Concern Assessment,” for additional information regarding this qualification.

Plan of Operation and Expected Capital Expenditures

Our plan of operation for the next twelve months is to drill and complete ~~the~~8 14wells ~~Shook~~on ~~pad~~our ~~wells~~Brighton ~~and~~lakes ~~participate~~pad. inHowever, ~~additional~~our ~~non-operated~~ability ~~wells~~ to achieve ~~the~~this ~~extent~~objective ~~that~~is ~~our~~subject ~~working~~to ~~capital~~receipt ~~permits.~~of additional capital. If we are successful in raising additional capital by means of an equity ~~offering~~financing in ~~2018~~2019, we may pursue another operated drilling program. Our goal is to increase the ~~price~~value of our ~~common~~company ~~stock~~ by selective deployment of capital in what we believe to be an attractive area in a premier oil and gas field.

~~Operated~~Subject to ~~Properties~~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.

In Results ~~2017,~~of weOperations ~~drilled~~for ~~and~~the ~~cased~~Year 14Ended ~~standard‑range~~December ~~lateral wells on our Shook pad~~31, ~~located~~2018 inCompared to ~~Section~~December ~~3 of Township 1 South~~31, Range 67 West, Adams County and part of our Todd Creek Farms prospect. The Shook pad is our first operated program in the Wattenberg Field. Our working interest in the Shook pad wells averages approximately 42%. 2017

~~Since~~The following ~~the~~provides ~~final~~selected ~~well~~operating ~~was~~results ~~cased in August 2017, we have been negotiating pipeline~~ and ~~gathering~~averages ~~access,~~for ~~and have identified and reached agreement with a third-party. We have budgeted $13.8 million to fracture stimulate and otherwise complete these wells. Assuming timely completion of~~ the years ~~pipeline~~ended ~~and~~December ~~gathering line~~31, ~~and completion of fracture activities scheduled to commence in April~~ 2018, weand expect these 14 wells to be fully producing by June 2018, adding significantly to our revenue. We also intend to monitor the production from the vertical wells we acquired during 2016 in order to determine whether production rates could be improved through work‑overs or by other means. 2017:

Non‑Operated Properties

	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

In addition to the 17 gross (2.9 net) non-operated wells in which we participated and which were producing at December 31, 2017, we are participating in 22 gross (1.70 net) new wells in 2018. These include 11 wells on the Marcus pad and eight on the Ocho pad, and three on the B-Farms pad all operated by Great Western Oil & Gas Company and located in our Todd Creek Farms prospect. At the end of 2017, the Company has participated in an additional four non-operated extended length horizontal wells on the Ocho pad in which we have an approximate 3.35% working interest. Those four wells had been drilled and completed but experienced limited production while waiting on new pipeline facilities. As of March 28, 2018, these wells are on full production into the new pipeline.

(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.

We expect to pay the future costs associated with our operated and non‑operated properties through existing cash, cash flow from new wells in which we have participated, and proceeds from the term credit facility that we complete in February 2018. While we do not control the drilling and completion schedules of any wells in which we are a non‑operator, we currently expect to begin receiving revenue from our Marcus pad and Ocho pad non‑operated properties in the second or third quarter of 2018. 24

AsOverview: Fiscal ~~discussed~~2018 inwas ~~more~~our ~~detail~~second ~~under~~year ~~“Liquidity~~of meaningful revenue, as we realized revenue from the non-operated horizontal wells in which we participated and ~~Capital~~revenue ~~Resources”~~from ~~below~~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, ~~remaining~~for ~~proceeds~~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 ~~term~~oil, ~~credit~~adversely affecting ~~facility~~our ~~provides~~revenue usfor the year. In addition to the interruption in production, the increase in net loss of $116.25 million. ~~Accordingly~~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 ~~ability~~Secured Credit Facility. We expect to continue ~~acquiring~~operating ~~acreage~~at ~~and~~a loss until cash flow from the wells in which we have an interest is sufficient to ~~further~~cover ~~develop~~operating costs, interest expenses, general and administrative and other expenses.

Revenue: 34Crude 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 ~~Table~~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 ~~Contents~~$9.53, or 28.3%, results primarily from increased sales volumes coupled with blended higher sales prices during the year ended December 31, 2018.

the acreage in which we currently have any interest is dependent on our ability to raise more capital. To achieve that objective, we expect to pursue additional equity offerings in 2018.

Results of Operations for the Year Ended December 31, 2017 Compared to December 31, 2016

The following provides selected operating results and averages for the years ended December 31, 2017 and 2016:

	For the year ended
	December 31,
	2017		2016
Revenue
Crude Oil	$	8,719,793	$	239,810
Natural Gas		1,525,833		68,304
NGLs		861,948		25,002
Total revenue	$	11,107,574	$	333,116
Total operating expense(1)	$	1,715,616	$	206,622
Depletion, depreciation and amortization expense	$	2,836,891	$	65,033
Interest income (expense)	$	(9,293,782)	$	(323,170)
General and administrative expense	$	6,205,412	$	4,022,969
Net (loss)	$	(10,847,379)	$	(4,481,272)
Sales volume(2)(3)
Crude Oil (Bbls)		188,529		4,903
Natural Gas (Mcfs)		549,846		26,059
NGLs (Bbls)		50,111		1,511
BOE		330,281		10,756
Average sales price(4)
Crude Oil (per Bbl)	$	46.25	$	48.91
Natural Gas (per Mcf)	$	2.78	$	2.62
NGLs (per Bbl)	$	17.20	$	16.55
BOE	$	33.63	$	30.97
Average per BOE
Operating expense	$	5.19	$	19.21
Depletion, depreciation and amortization expense	$	8.59	$	6.05

(1) Overall lifting cost (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 2017 was our first year of meaningful revenue, as we realized revenue from the non-operated horizontal wells in which we participated. However, for the year, we realized a net loss of $10.8 million, including non-cash charges, or $0.46 per share, compared to a net loss of $4.5 million, or $0.21 per share, for the year ended December 31, 2016.

Table of Contents

The significant increase in net loss of $6.3 million for the year ended December 31, 2017 resulted primarily from a significant increase in interest expense, depletion, depreciation and amortization and other non-cash expenses and including increases in our general and administrative expenses due to increased staffing requirements. We expect to continue operating at a net 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.

Revenues: Crude oil, natural gas and NGL sales revenue increased $10.8 million, for the year ended December 31, 2017, to $11.1 million from $0.3 million for the year ended December 31, 2016, attributable to increased production volume from 2016. Crude oil, natural gas and NGL sales volumes increased 319,525 BOE for the year ended December 31, 2017 compared to the year ended December 31, 2016. The increase, in turn, was primarily the result of production from the completion of 14 non-operated wells during 2017 in which we have an average net revenue interest of 12.9%. Our production in 2016 was solely from crude oil, natural gas and NGLs produced from vertical wells that we acquired during 2016 and the completion of three non-operated wells that were put on production in the fourth quarter of 2016. For the year ended December 31, 2017, our average oil sales price was $46.25 per Bbl compared to $48.91 per Bbl for the year ended December 31, 2016, due to lower average oil spot prices through most of 2017 compared to 2016; our average natural gas sales price was $2.78 per Mcf compared to $2.62 for the year ended December 31, 2016; and our average NGLs sales price was $17.20 per Bbl compared to $16.55 for the year ended December 31, 2016. The increase in the average price per BOE of $2.66, or 8.6%, results primarily from a change in our product sales mix to include natural gas and NGL at blended higher sales prices, offset by lower average crude oil prices during the year ended December 31, 2017.

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

	Year ended	~~Year ended~~
	December 31,	~~December 31,~~
		2017		2016
	2018	2017
Lease operating costs	$1,415,453	$722,799	~~722,799~~	$	~~167,638~~
Production taxes	1,475,866	742,787	~~742,787~~		~~38,634~~
Transportation and other costs	1,256,443	250,030	~~250,030~~		~~350~~
Total	$4,147,762	$1,715,616	~~1,715,616~~	$	~~206,622~~

Total operating expense increased in ~~2017~~2018 commensurate with increased production. This reflects our ~~participation~~operated inand ~~the~~additional ~~horizontal~~non-operated properties ~~wells~~coming online in ~~2017~~2018, while ~~2016~~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 $2.1999 for the year ended December 31, ~~2017~~2018, compared to $152.5919 for the year ended December 31, ~~2016~~2017. As a percent of crude oil, natural gas and NGL sales revenue, routine LOE was 6.594% for the year ended December 31, ~~2017~~ 2018, compared to 506.351% for the year ended December 31, ~~2016~~2017. Production taxes for the year ended December 31, ~~2017~~2018 amounted to $01.75 million as compared to $~~38,634~~0.7 million for the year ended December 31, ~~2016~~2017.

Overall operating costs (crude oil, natural gas and NGL operating costs, excluding ~~including~~ production taxes) per BOE was $5.1965 for the year ended December 31, ~~2017~~2018, compared to $192.2195 for the year ended December 31, ~~2016~~2017.

Depletion, depreciation and amortization expense: Depletion, depreciation and amortization increased $2.7 million to $2.8 million for the year ended December 31, 2017, from $0.1 million for the year ended December 31, 2016. The increase was the result of increased production volumes related to wells acquired and non‑operated wells coming online during the 2017 period, partially offset by an increase in our reserves. 25

Depletion, 36depreciation 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 ~~Table~~expense: During 2018, we recognized an impairment expense of ~~Contents~~$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 ~~income (~~ expense): During ~~2017~~2018, we recognized interest expense of $913.31 million compared to $09.3 million infor the year ended December 31, ~~2016~~2017. The interest expense recognized in2018 ~~the current period~~ relates to ~~advances~~the interest on our ~~two~~Secured ~~lines of credit~~Credit Facility, our unsecured convertible notes, ~~our~~the ~~new~~amortization ~~credit~~of ~~facility~~debt discounts ~~entered~~and inaccrued ~~December~~default ~~2017,~~interest and ~~the~~penalties ~~amortization~~related ofto ~~debt~~our technical ~~discounts.~~defaults ~~During~~under the Secured Credit Facility. During the year ended December 31, ~~2016~~2017, interest expense primarily ~~relates~~related to advances on our two lines of credit. and our convertibles notes payable.

~~General~~The ~~and~~following ~~administrative~~table presents ~~expenses: We~~the ~~incurred~~components ~~general and administrative expenses~~ of ~~$6.2~~interest ~~million~~expense ~~during~~for the ~~year~~years ended December 31, 2017, an increase of $2.2 million over 2016, or 54%. This increase is primarily attributable to an increase of $1.3 million in salary and wage expense, employee benefits and stock-based compensation, and increases of $0.9 million in professional fees, board of director fees, filing fees and investor relations expense associated with being a public company required to file reports with the SEC. In 2016, we incurred general and administrative expenses of $4.0 million. The 2016 activity is primarily attributable to stock-based compensation expense of $1.4 million, salary and wage expenses related to the payment of bonuses and the addition of new employees of $0.7 million and costs of $1.0 million incurred in connection with an abandoned public offering in the fourth quarter of 2016. :

	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 ~~2017~~ 2018, weour ~~continued to suffer from a~~ 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 ~~2017~~2018, our need for additional capital became more acute, as we ~~hoped~~accelerated ~~to accelerate~~ the pace of development of our properties, including ~~commencing~~completing our first operated drilling program. However, the state of the equity markets for junior exploration and production companies in ~~2017~~2018 forced us to rely on other avenues for funding during the year.

~~2017 Financings~~ 2018 Financing

WeIn February ~~explored~~2018, ~~numerous~~we ~~options~~completed ~~for~~the ~~both~~Secured ~~debt~~Credit ~~and~~Facility. ~~equity~~Under ~~financing during~~ the Secured ~~year~~Credit ~~and~~Facility, ~~ultimately~~we ~~completed~~refinanced ~~three~~$5 ~~financings. In~~million ~~January~~in December 2017, and wereceived ~~completed~~gross aproceeds ~~private placement~~ of ~~convertible~~an ~~notes~~additional ~~that~~$20 wemillion ~~commenced~~ in February ~~December~~2018. ~~2016~~The ~~that~~Secured ~~netted~~Credit usFacility ~~$9.0~~proceeds ~~million~~were inutilized to ~~total~~repay ~~after~~amounts ~~fees~~due ~~and~~to ~~expenses. We~~affiliates ~~sold~~of ~~those~~the ~~notes~~Secured asLenders ~~part~~under pre-existing lines of ~~units~~credit, ~~that~~for ~~included~~fees ~~warrants~~associated towith ~~purchase~~the ~~our~~Secured Credit ~~common~~Facility ~~stock~~and atfor adevelopment ~~price~~costs incurred in connection with the completion of ~~$3.00~~our ~~per~~operated ~~share~~Shook pad.

In October 2017, we completed another placement of convertible notes, which we refer to as the Series B Convertible Notes, also sold as units with additional warrants to purchase our common stock. We netted $4.7 million from this offering. As part of this offering, holders of the original convertible notes that were issued in late 2016 and early 2017 were offered the right to convert their original notes in an amount equal to two times the amount of their investment in Series B Notes into common stock at a reduced conversion price of $1.10 per share. As a result of that offer, $5.2 million of original notes were converted into common stock, improving our working capital.

In December 2017, we completed the first closing of what ultimately became a $25.0 million term credit loan from an affiliate of our working interest partner and the beneficial owner of our common stock. Prior to year-end, we received $5.0 million of this financing, all of which was used to reduce our accounts payable or accrued liabilities. The remainder was received in February 2018. The facility matures in its entirety in February 2020. As part of the second closing in 2018, we repaid the entire amount of the original line of credit from PEO of $5.0 million plus accrued interest and $1.5 million of principal plus accrued interest on our supplemental line of credit with an affiliate of PEO, further improving our working capital.

The amount we invest in development, drilling, and leasing activities depends on, among other factors, opportunities presented to us, the results of drilling to date and the success of any fundraising efforts. The most

Table of Contents

significant of our future capital requirements include (i) costs to drill or participate in additional wells; (ii) costs to acquire additional acreage that we may identify in the Southern Core area or other areas; (iii) approximately $0.6 million per month for salaries and other corporate overhead; and (iv) legal and accounting fees associated with our status as a public company required to file reports with the SEC. We anticipate funding these projected capital requirements with cash on hand, revenue from operations, and proceeds from the sale of debt or equity, the success of which cannot be assured.

Working Capital

As of December 31, ~~2017~~2018, we had negative working capital of $1732.8 9 million, comprised of current assets of $332.42 million and current liabilities of $2165.21 million. ~~Working~~A ~~capital~~significant ~~decreased~~portion byof ~~$11.7~~the ~~million~~current assets ~~from~~consisted ~~December~~of ~~31,~~property ~~2016,~~held ~~primarily~~for ~~due~~sale, towhich ~~additional~~property ~~short-term~~was disposed ~~borrowings. Our~~of ~~working capital improved~~ subsequent to ~~the~~year end ofand the ~~fiscal~~proceeds ~~year~~of ~~when~~which wewere applied ~~closed~~by the ~~second~~Secured ~~tranche~~Lenders ofagainst the ~~term~~amounts ~~credit~~owed ~~agreement~~to them. At Working ~~that~~capital ~~time,~~decreased weby ~~repaid~~ $715.51 million infrom ~~current~~December ~~debt~~31, ~~and~~2017, primarily ~~accrued~~due ~~interest~~to the default and ~~netted~~subsequent ~~$11.2~~reclassification ~~million~~of amounts ~~after~~due ~~expenses~~under our Secured Credit facility from a long-term liability to bea ~~used~~current ~~for~~liability.Current ~~development~~liabilities ofincreased ~~our~~by approximately ~~properties~~$38 ~~and~~million ~~other~~at ~~working~~December ~~capital.~~ 31, 2018 compared to 2017.

Cash Flows

Year Ended December 31, ~~2017~~2018 Compared to December 31, ~~2016~~ 2017

Operating Activities

Net cash provided by operating activities during the year ended December 31, ~~2017~~2018 was $~~10.~~4.6 million, compared to ~~cash used of~~ $210.74 million during the year ended December 31, ~~2016~~2017, representing ana ~~improvement~~decrease of $135.17 million. The increased net loss in ~~2017~~2018 ~~was~~accounted ~~more~~for ~~than~~most ~~offset by increases in depletion, depreciation and amortization, accretion~~ of the ~~debt discount associated with the issuance of the convertible notes and a loss on the conversion of notes, each of which was a non-cash expense; and an increase in accounts payable, among other items~~difference.

Investing Activities

Cash used in investing activities in ~~2017~~2018 ~~nearly~~decreased ~~doubled~~to ~~from~~$13.9 ~~the prior year,~~ million from $1020.83 million in ~~2016~~the to2017 ~~$20~~period.4 ~~million~~During ~~during~~ the ~~year~~2018 ~~ended~~period, ~~December~~our drilling 31and other development activity, ~~2017~~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. ~~This~~of oil ~~compares to $7.7 million spent on acquisitions~~ and ~~$3.0~~gas ~~million for our share of the development of our~~ properties ~~during 2016~~.

Financing Activities

During ~~2017~~ 2018, we ~~received~~closed aon ~~total~~the Secured Credit Facility which provided net cash proceeds of $11.82 million, ~~net,~~and ~~from~~provided ~~the~~resources ~~sale~~after repaying of$6.5 ~~units~~million ~~consisting~~in ofprincipal ~~convertible~~and ~~notes~~$1.1 ~~and~~million ~~warrants~~in accrued interest from other financings. ~~Offsetting~~ ~~that~~The ~~cash~~total ~~received,~~face wevalue ~~repaid~~of the Secured Credit Facility is $325.60 million, ~~under~~including the ~~supplemental~~$5.0 ~~line~~million ofthat originated ~~credit~~in 2017.

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

~~During~~We have ~~the~~no ~~year~~material ~~ended~~off-balance ~~December~~sheet 31transactions, ~~2016~~arrangements, we borrowed $3.9 million on the initial line of credit from PEO and $7.1 million on the supplemental line of credit. We also received gross offering proceeds of $1.7 million from the sale of units in a private placement. We received an additional $0.1 million in a private placement of common stock in January 2016.or obligations.

Table of Contents

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 ~~that~~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;

39 ● accuracy of various mandated economic assumptions; and

~~Table~~● judgment of ~~Contents~~ the independent reserve engineer.

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

Depletion, Depreciation, Amortization ~~and Accretion.~~

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 ~~estimates~~, ~~estimated~~ future capital expenditures, ~~estimated~~ future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of ~~long~~proved ~~lived~~crude oil ~~assets~~and natural gas properties in the consolidated statements of operations~~, which increases accumulated depletion, depreciation and amortization~~.

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.

40 28

Table of Contents

Impairment of Unproved Oil and Gas Properties

Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit‑-of‑-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration ~~expenses~~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, ~~and~~ land restoration in accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of ~~the~~proved crude oil and natural gas ~~asset~~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 ~~net~~operating ~~income~~ 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.

Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 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.

Table of Contents

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. As shown in the accompanying consolidated financial statements, the Company incurred a net loss of $10.8 million during the year ended December 31, 2017, and as of that date, the Company's current liabilities exceeded its current assets by $10.8 million, the Company had a cash balance of $0.7 million and other current assets of $2.7 million.

Going Concern Assessment

AsPursuant ofto ~~December~~Financial ~~31,~~Accounting ~~2017,~~Standards ~~the~~Board (“FASB”) ~~Company~~Accounting ~~had~~Standards ~~insufficient~~Update (“ASU”) ~~working~~No. ~~capital~~2014-15, ~~and~~Presentation ~~revenues~~of ~~from~~Financial Statements ~~operations~~– toGoing ~~meet~~Concern, ~~its~~we ~~maturing~~have ~~debt~~assessed ~~obligations~~our ~~and~~ability ~~other liabilities incurred and~~ to becontinue ~~incurred~~as ina going ~~connection~~concern ~~with~~for ~~the~~a ~~Company’s~~period ~~development~~of ~~activities.~~one ~~The~~year ~~Company will also need to generate sufficient cash flow~~ from ~~operations~~the ~~and~~date ~~sell~~of ~~equity~~the issuance orof ~~debt~~these toconsolidated ~~fund~~financial ~~further drilling and acquisition activity~~statements. IfSubstantial doubt ~~sufficient~~about ~~cash~~an ~~flow~~entity’s ~~and~~ability ~~additional financing is not available, the Company may be compelled~~ to ~~reduce~~continue ~~the~~as ~~scope of its business activities and/or sell~~ a ~~portion~~going concern ofexists ~~the~~when ~~Company’s~~relevant ~~interests~~conditions ~~in its oil~~ and ~~gas properties. This~~events, considered in the ~~turn~~aggregate, ~~may~~indicate ~~have~~that anit ~~adverse~~is ~~effect~~probable onthat the ~~Company’s~~entity ~~ability~~will be unable to ~~realize~~meet ~~the value of~~ its ~~assets.~~obligations ~~These~~as ~~factors~~they ~~raise~~become ~~substantial~~due ~~doubt~~within ~~about~~one year from the ~~Company’s~~consolidated ~~ability~~financial tostatement ~~continue as a going concern.~~issuance date.

Management has evaluated these conditions and determined that ~~a reduction in the working capital deficit subsequent to December 31, 2017 as a result of a new term Credit Facility coupled with anticipated~~ increased revenues from the Company’s ~~non-~~operated ~~and operated~~ properties, may allow the Company to meet its ~~maturing~~ongoing ~~debt~~operational ~~and interest~~ obligations. ~~However,~~There tois uncertainty ~~continue~~whether tomanagement’s ~~execute~~plans, ~~its~~if ~~business plan~~executed, ~~additional capital~~ will allow beus ~~required.~~to Asmeet ~~part~~all of ~~the~~our ~~analysis, the Company considered selective participation in certain non-operated drilling programs based on availability of working capital and the timing of production-related cash flows~~obligations.

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 in existence.

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.

Table of Contents

“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.

Table of Contents

“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.

Table of Contents

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.

45 31

Table of Contents

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firms	47
Report of Independent Registered Public Accounting Firm	33
Consolidated Balance Sheet as of December 31, 2017 and Balance Sheet as of December 31, 2016	49
Consolidated Balance Sheets as of December 31, 2018 and 2017	35
Consolidated Statement of Operations for the year ended December 31, 2017 and Statement of Operations for the year ended December 31, 2016	50
Consolidated Statements of Operations for the years ended December 31, 2018 and 2017	36
Consolidated Statement of Changes in Shareholders’ Equity for the year ended December 31, 2017 and Statement of Changes in Shareholders’ Equity for the year ended December 31, 2016	51
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) for the years ended December 31, 2018 and 2017	37
Consolidated Statement of Cash Flows for the year ended December 31, 2017 and Statement of Cash Flows for the year ended December 31, 2016	52
Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2017	38
Notes to Consolidated Financial Statements	5339

46 32

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

PetroShare Corp.

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

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

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

/s/ SingerLewak LLP SingerLewak LLP Denver, Colorado March 31, 2017

Table of Contents

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 ~~sheet~~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 ~~year~~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 ~~year~~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 ~~raises~~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 ~~audit~~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 ~~audit~~ in accordance with the standards of the PCAOB. Those standards require that we plan and perform the ~~audit~~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 ~~audit~~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 ~~audit~~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 ~~audit~~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 ~~audit~~provide ~~provides~~ a reasonable basis for our opinion.

/s/ Eide Bailly LLP Eide Bailly LLP

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

Denver, Colorado

~~March~~April 283, ~~2018~~ 2019

What inspires you, inspires us. | 48 eidebailly.com

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

PetroShare Corp.

Consolidated Balance Sheets

December 31,

		2017		2016
	2018	2017
				(see Note 14)
ASSETS
ASSETS
Current assets:
Current assets:
Cash	$2,636,943	$713,924
Cash		$	713,924	$	2,449,412
Accounts receivable - joint interest billing, net of allowance	495,911	828,583
Accounts receivable - joint interest billing			828,583		240,450
Accounts receivable - joint interest billing - related party	1,158,213	204,730
Accounts receivable - joint interest billing - related party			204,730		286,226
Accounts receivable - crude oil, natural gas and NGL sales	11,659,479	1,412,612
Accounts receivable - crude oil, natural gas and NGL sales			1,412,612		179,236
Prepaid expenses and other assets	178,259	26,795
Accounts receivable - other			—		27,876
Deferred financing fee, net	—	251,389
Prepaid expenses and other assets			26,795		1,178,081
Assets held for sale, net of costs to sell	16,090,898	—
Deferred financing fee, net			251,389		—
Total current assets	32,219,703	3,438,033
Total current assets			3,438,033		4,361,281
Crude oil and natural gas properties - using successful efforts method:
Crude oil and natural gas properties - using successful efforts method:
Proved crude oil and natural gas properties	41,017,944	22,144,366
Proved crude oil and natural gas properties			22,144,366		8,132,881
Unproved crude oil and natural gas properties	2,055,752	1,919,335
Unproved crude oil and natural gas properties			1,919,335		4,092,550
Wells in progress	1,194,114	9,858,262
Wells in progress			9,858,262		2,168,092
Less: accumulated depletion, depreciation and amortization	(14,395,458)	(2,849,374)
Less: accumulated depletion, depreciation and amortization			(2,849,374)		(783,320)
Crude oil and natural gas properties, net	29,872,352	31,072,589
Crude oil and natural gas properties, net			31,072,589		13,610,203
Property, plant and equipment, net	115,350	168,411
Property, plant and equipment, net			168,411		39,542
Other assets	357,070	233,871
Other assets			233,871		15,758
TOTAL ASSETS	$62,564,475	$34,912,904
TOTAL ASSETS		$	34,912,904	$	18,026,784
LIABILITIES & SHAREHOLDERS’ EQUITY (DEFICIT)
LIABILITIES & SHAREHOLDERS’ EQUITY
Current liabilities:
Current liabilities:
Accounts payable and accrued liabilities	$24,385,417	$4,140,352
Accounts payable and accrued liabilities		$	4,140,352	$	3,009,106
Accounts payable and accrued liabilities - related party	7,624,877	589,496
Accounts payable and accrued liabilities - related party			589,496		—
Oil and gas revenue distributions payable	2,501,095	148,103
Oil and gas revenue distributions payable			148,103		144,526
Drilling advances - related party	—	680,248
Drilling advances - related party			680,248		234,452
Asset retirement obligation	843,796	288,784
Asset retirement obligation			288,784		—
Line of credit - related party	—	5,000,000
Line of credit - related party			5,000,000		—
Supplemental line of credit	—	3,552,500
Supplemental line of credit			3,552,500		7,088,698
Derivative liabilities – Secured Credit Facility	241,800	—
Convertible notes payable, net	9,358,100	6,831,897	~~6,831,897~~		—
Total current liabilities			21,231,380		10,476,782
Secured Credit Facility, net	20,182,264	—
Long-term liabilities
Total current liabilities	65,137,349	21,231,380
Line of credit - related party			—		5,000,000
Long-term liabilities
Credit facility, net	—	4,896,565	~~4,896,565~~		—
Convertible notes payable, net			—		5,308
Other long-term liabilities	448,465	67,265
Other long-term liabilities			67,265		23,128
Asset retirement obligation	1,246,151	834,660
Asset retirement obligation			834,660		945,419
Total liabilities	66,831,965	27,029,870
Total liabilities			27,029,870		16,450,637
Shareholders’ equity (deficit):
Shareholders’ equity:
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued or outstanding	—	—
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
Common stock, $0.001 par value, 100,000,000 shares authorized, 27,718,802 and 21,964,282 shares issued and outstanding, respectively			27,719		21,964
Additional paid-in capital	33,710,588	28,553,736
Additional paid-in capital			28,553,736		11,405,225
Accumulated deficit	(38,006,168)	(20,698,421)
Accumulated deficit			(20,698,421)		(9,851,042)
Total Shareholders’ Equity (Deficit)	(4,267,490)	7,833,034
Total Shareholders’ Equity			7,883,034		1,576,147
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY (DEFICIT)	$62,564,475	$34,912,904
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY		$	34,912,904	$	18,026,784

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

49 34

Table of Contents

PetroShare Corp.

Consolidated Statements of Operations

For the years ended December 31,

			2017		2016
	2018	2017
						(see Note 14)
REVENUE:
REVENUE:
Crude oil sales	$16,809,145	$8,719,793
Crude oil sales			$	8,719,793	$	239,810
Natural gas sales	2,456,927	1,525,833
Natural gas sales				1,525,833		68,304
NGL sales	1,137,895	861,948
NGL sales				861,948		25,002
Total revenue	20,403,967	11,107,574
Total revenue				11,107,574		333,116
COSTS AND EXPENSES:
COSTS AND EXPENSES:
Lease operating expense	1,415,453	722,799
Lease operating expense				722,799		167,988
Production taxes, gathering and marketing	2,732,309	992,817
Production taxes, gathering and marketing				992,817		38,634
Exploration and abandonment costs	580,881	61,693
Exploration costs				61,693		19,259
Depletion, depreciation and amortization	7,067,729	2,836,891
Depletion, depreciation and amortization				2,836,891		65,033
Accretion expense	117,636	99,682
Accretion expense				99,682		30,483
Asset retirement and plugging expense	(2,989)	9,608
Plugging expense				9,608		31,122
Impairment of proved crude oil and natural gas properties	9,896,807	—
Loss on impairment of proved crude oil and natural gas properties				—		116,303
General and administrative expense	4,155,651	6,205,412
General and administrative expense				6,205,412		4,022,969
Total costs and expenses	25,963,477	10,928,902
Total costs and expenses				10,928,902		4,491,791
Operating (loss) income	(5,559,510)	178,672
Operating income (loss)				178,672		(4,158,675)
OTHER INCOME (EXPENSE):
OTHER INCOME (EXPENSE):
Other income (expense)	(102,165)	39,381
Other income				39,381		573
Change in fair value of derivative liabilities	1,428,217	—
Interest expense	(13,074,289)	(9,293,782)		~~(9,293,782)~~		~~(323,170)~~
Loss on conversion of notes payable	—	(1,771,650)		~~(1,771,650)~~		—
Total other (expense)	(11,748,237)	(11,026,051)		~~(11,026,051)~~		~~(322,597)~~
Net (loss)	$(17,307,747)	$(10,847,379)	$	~~(10,847,379)~~	$	~~(4,481,272)~~
Net (loss) per share:
Basic and diluted	$(0.62)	$(0.46)	$	~~(0.46)~~	$	~~(0.21)~~
Weighted average number of shares outstanding:
Basic and diluted	27,991,742	23,530,583		~~23,530,583~~		~~21,828,853~~

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

50 35

Table of Contents

PetroShare Corp.

Consolidated Statements of Changes in Shareholders’ Equity (Deficit)

For the years ended December 31, ~~2017~~2018 and ~~2016~~ 2017

			Additional			~~Additional~~		~~Accumulated~~
	Common Stock	~~Common Stock~~	Paid-In	Accumulated		~~Paid-In~~		~~Earnings/~~
	Shares	~~Shares~~Amount	Capital	~~Amount~~(Deficit)	Total	~~Capital~~		~~(Deficit)~~		~~Total~~
Balance at December 31, 2015		21,633,191		$	21,633	$	8,124,443	$	(5,369,770)	$	2,776,306
Balance at December 31, 2016	21,964,282	$21,964	$11,405,225	$(9,851,042)	$1,576,147
Issuance of common stock for cash at $1.00 per share		95,000			95		94,905		—		95,000
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 in connection with consulting agreements		141,666			142		173,774		—		173,916
Issuance of common stock for lease acquisition	470,555	471	846,529	—	847,000
Issuance of common stock for services		50,000			50		50,455		—		50,505
Issuance of common stock for loan extension	250,000	250	387,250	—	387,500
Issuance of common stock for lease acquisition		14,425			14		26,672		—		26,686
Issuance of restricted shares	219,700	220	155,111	—	155,331
Issuance of common stock for property acquisition		30,000			30		56,670		—		56,700
Beneficial conversion feature on convertible notes payable	—	—	4,329,365	—	4,329,365
Stock-based compensation		—			—		1,140,967		—		1,140,967
Warrants issued in connection with convertible notes payable	—	—	2,978,796	—	2,978,796
Common stock warrants issued in connection with private placement (revised - Note 14)		—			—		1,033,586		—		1,033,586
Stock-based compensation	—	—	1,388,932	—	1,388,932
Beneficial conversion feature on convertible notes		—			—		703,753		—		703,753
Net (loss)	—	—	—	(10,847,379)	(10,847,379)
Net (loss) (revised - Note 14)		—			—		—		(4,481,272)		(4,481,272)
Balance at December 31, 2017	27,718,802	$27,719	$28,553,736	$(20,698,421)	$7,883,034
Balance at December 31, 2016 (revised - Note 14)		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	135,963	136	203,811	—	203,947
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 shares as compensation	145,000	145	162,105	—	162,250
Issuance of common stock for lease acquisition		470,555			471		846,529		—		847,000
Issuance of restricted shares	90,000	90	101,018	—	101,108
Issuance of common stock for loan extension		250,000			250		387,250		—		387,500
Beneficial conversion feature on Secured Credit Facility	—	—	2,272,775	—	2,272,775
Issuance of restricted shares		219,700			220		155,111		—		155,331
Warrants issued in connection with Secured Credit Facility	—	—	1,521,451	—	1,521,451
Beneficial conversion feature on convertible notes payable		—			—		4,329,365		—		4,329,365
Stock-based compensation	—	—	895,692	—	895,692
Warrants issued in connection with convertible notes payable		—			—		2,978,796		—		2,978,796
Net (loss)	—	—	—	(17,307,747)	(17,307,747)
Stock-based compensation		—			—		1,388,932		—		1,388,932
Balance at December 31, 2018	28,089,765	$28,090	$33,710,588	$(38,006,168)	$(4,267,490)
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

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

51 36

Table of Contents

PetroShare Corp.

Consolidated Statements of Cash Flows

For the years ended December 31,

		2017		2016
	2018	2017
					(see Note 14)
Cash flows from operating activities:
Cash flows from operating activities:
Net (loss)	$(17,307,747)	$(10,847,379)
Net (loss)		$	(10,847,379)	$	(4,481,272)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Adjustments to reconcile net (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	7,067,729	2,836,891
Depletion, depreciation and amortization			2,836,891		65,033
Deferred rental liability	(23,625)	6,526
Deferred rental liability			6,526		—
Accretion of asset retirement obligation	117,636	99,682
Accretion of asset retirement obligation			99,682		30,483
Accretion of debt discounts and deferred financing fee	6,380,057	7,666,313
Accretion of debt discounts and deferred financing fee			7,666,313		17,253
Loss on conversion of notes payable	—	1,771,650
Loss on conversion of notes payable			1,771,650		—
Stock-based compensation	1,159,051	1,544,261
Stock-based compensation			1,544,261		1,365,388
Change in fair value – derivative liabilities	(1,428,217)	—
Impairment of proved crude oil and natural gas properties			—		116,303
Default penalties incurred in connection with Secured Credit Facility	3,670,375	—
Changes in operating assets and liabilities:
Impairment of proved crude oil and natural gas properties	9,896,807	—
Accounts receivable - joint interest billing			(588,132)		144,168
Break-up fees in connection with abandonment of lease acquisition	580,881	—
Accounts receivable - joint interest billing - related party			81,495		(286,226)
Bad debt expense	131,395	—
Accounts receivable - crude oil, natural gas and NGL sales			(1,233,376)		(179,236)
Changes in operating assets and liabilities:
Accounts receivable - other			—		(27,876)
Accounts receivable - joint interest billing	(66,470)	(588,132)
Prepaid expenses and other assets			961,048		(1,160,314)
Accounts receivable - joint interest billing - related party	204,731	81,495
Accounts payable and accrued liabilities			7,053,693		1,338,274
Accounts receivable - crude oil, natural gas and NGL sales	(10,246,868)	(1,233,376)
Accounts payable and accrued liabilities- related party			589,496		—
Prepaid expenses, other assets and liabilities	130,164	961,048
Accounts payable - oil and gas revenue distributions payable			3,578		143,577
Settlement of asset retirement obligations	(174,532)	—
Drilling advances - related party			445,796		234,452
Accounts payable and accrued liabilities	758,525	7,053,693
Net cash provided by (used in) operating activities			10,391,542		(2,679,993)
Accounts payable and accrued liabilities- related party	2,123,621	589,496
Cash flows from investing activities:
Oil and gas revenue distributions payable	2,352,992	3,578
Additions of property, plant and equipment			(91,186)		(43,485)
Drilling advances - related party	(680,248)	445,796
Development of crude oil and natural gas properties			(17,052,313)		(3,038,339)
Net cash provided by operating activities	4,646,257	10,391,542
Acquisitions of crude oil and natural gas properties - business combinations			—		(4,820,742)
Cash flows from investing activities:
Acquisitions of unproved crude oil and natural gas properties			(3,202,380)		(2,854,475)
Additions of property, plant and equipment	—	(91,186)
Net cash (used in) investing activities			(20,345,879)		(10,757,041)
Development of crude oil and natural gas properties	(13,379,249)	(17,052,313)
Cash flows from financing activities:
Acquisitions of proved and unproved crude oil and natural gas properties	(507,181)	(3,202,380)
Long-term debt - advances on initial line of credit			—		3,937,815
Net cash (used in) investing activities	(13,886,430)	(20,345,879)
Repayment of supplemental line of credit			(3,552,500)		—
Cash flows from financing activities:
Borrowings under supplemental line of credit			—		7,105,000
Repayment of supplemental line of credit	—	(3,552,500)
Convertible notes issued for cash			11,771,349		1,737,340
Borrowings on Secured Credit Facility	11,163,192	—
Common stock issued for cash (net of offering costs)			—		95,000
Convertible notes issued for cash	—	11,771,349
Net cash provided by financing activities	11,163,192	8,218,849	~~8,218,849~~		~~12,875,155~~
Cash:
Net (decrease) in cash			(1,735,488)		(561,879)
Net increase (decrease) in cash	1,923,019	(1,735,488)
Cash, beginning of period	713,924	2,499,412	~~2,449,412~~		~~3,011,291~~
Cash, end of period	$2,636,943	$713,924	~~713,924~~	$	~~2,449,412~~
Supplemental cash flow disclosure:
Cash paid for interest		$	640,410	$	—
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:
Acquisition of crude oil and natural gas properties - business combinations		$	—	$	973,604
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	~~1,719,481~~	$	—
Addition of property, plant and equipment through tenant improvement allowance		$	84,460	$	—
Revisions and other non-cash charges in asset retirement obligation	$1,023,400	$127,826
Beneficial conversion feature in connection with convertible notes payable		$	4,329,365	$	—
Conveyance of oil and gas properties – to satisfy supplemental line of credit	$2,052,500	$4,683
Issuance of common stock warrants in connection with convertible notes payable		$	2,978,796	$	191,692
Addition of property, plant and equipment through tenant improvement allowance	$—	$84,460
Issuance of common stock in connection with conversion of notes payable and accrued interest		$	7,067,342	$	—
Embedded derivative liabilities – Secured Credit Facility	$1,670,017	$—
Conversion of notes payable and accrued interest to common stock		$	5,295,692	$	—
Previous borrowings refinanced through Secured Credit Facility	$6,500,000	$—
Issuance of common stock in connection with lease acquisitions		$	847,000	$	26,686
Issuance of common stock warrants in connection with Secured Credit Facility	$1,521,451	$—
Issuance of common stock for property acquisition		$	—	$	56,700
Issuance of common stock warrants in connection with convertible notes payable	$—	$2,978,796
Issuance of common stock in connection with deferred financing fee		$	387,500	$	—
Beneficial conversion feature in connection with Secured Credit Facility and convertible notes payable	$2,272,775	$4,329,365
Accounts payable paid with credit facility borrowing		$	4,895,128	$	—
Issuance of common stock in connection with conversion of notes payable and accrued interest	$203,947	$5,295,692
Financing fee paid through credit facility borrowing		$	104,871	$	—
Conversion of notes payable and accrued interest – Additional paid in capital	$—	$7,067,342
Revisions and other non-cash changes to asset retirement obligation		$	127,826	$	—
Issuance of common stock in connection with lease acquisitions	$—	$847,000
Forgiveness of accounts payable in connection with the sale of proven oil and gas properties		$	4,683	$	—
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.

52 37

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 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, ~~and is currently focused~~ 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,. ~~and~~The ~~have~~Company’s ~~been~~undivided interests ~~prepared~~ in ~~accordance~~joint ~~with~~operating ~~accounting~~ventures ~~principles~~are ~~generally accepted in the United States (“GAAP”).~~ proportionately consolidated.

Business Combinations

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

Use of Estimates

The preparation of ~~consolidated~~ 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 ~~and~~well as the disclosure of contingent assets and liabilities. Estimated atquantities of crude oil, natural gas and natural gas liquids are the ~~date~~most significant of the ~~consolidated~~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 ~~the~~natural ~~reported~~gas ~~amounts~~liquids. There are numerous uncertainties inherent in estimating quantities of ~~revenues~~proved, probable and ~~expenses~~possible ~~during~~reserves. The accuracy of any reserve estimate is a function of the ~~reporting~~quality ~~period~~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.

Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of the Company’s estimates. All reserve data included in these 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 crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered. 38

Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, asset retirement obligations, valuation allowances for deferred income tax assets and valuation assumptions related to the Company’s stock-based compensation. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Note 17, Unaudited Crude Oil and Natural Gas Reserves Information.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

~~Loss~~Other items ~~Per~~subject ~~Common~~to ~~Share~~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.

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

~~Potentially~~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 atthat ~~December~~have 31an anti-dilutive impact on the per share calculation are excluded. During periods in which the Company reports a net loss, ~~2017~~diluted ~~and~~weighted ~~2016~~average shares outstanding are asequal ~~follows:~~to basic weighted average shares outstanding because the impact of all potentially dilutive securities would be anti-dilutive.

	December 31,	December 31,
	2017	2016
Exercisable stock options	4,347,500	3,010,000
Warrants issued to underwriter	255,600	255,600
Warrants issued to convertible note holders	6,666,600	1,294,987
Warrants issued to placement agent - convertible note offering	666,600	129,526
Shares underlying convertible notes	6,372,066	1,295,067
Total	18,308,366	5,985,180

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

Cash

	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

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

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

Revenue Recognition

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

~~Accounts~~Under the ~~Receivable~~Company’s –oil ~~Crude~~sales ~~oil~~contracts, ~~natural~~the ~~gas~~Company sells oil production at the point of delivery and ~~NGLs~~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.

~~Accounts~~ Natural ~~receivable~~gas –and ~~Crude oil,~~ natural gas ~~and NGLs consists of amounts receivable from sales from the Company’s well interests. Management continually monitors accounts receivable for collectability.~~ liquids

~~Accounts~~Under the ~~Receivable –~~Company’s ~~Joint~~natural ~~interest~~gas ~~billing~~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.

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

~~Table of Contents~~ 39

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 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 ~~recognizes~~regularly anreviews ~~allowance~~outstanding ~~for losses on~~ accounts receivable infor indication anthat ~~amount~~amounts ~~equal~~may tonot ~~the~~be ~~estimated probable losses net of recoveries~~collectible. The Company’s allowance for doubtful accounts is based on an 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. ~~The~~An ~~expense associated with the~~ allowance of ~~for doubtful accounts is recognized as other expense~~$0.1 Wemillion ~~have~~and ~~not~~$nil was recorded ~~an allowance for doubtful accounts~~ as of December 31, ~~2017~~2018 and ~~2016~~ 2017, respectively.

Deferred Equity Issuance Costs

The Company defers as other current assets the direct incremental costs of raising capital through equity offerings until such time as the offering is completed. At the time of the offering completion, the costs are charged against the capital raised. Should the offering be terminated, deferred offering costs are charged to operations during the period in which the offering is terminated.

Capitalized Interest Costs

The Company ~~has~~capitalizes ~~capitalized certain~~ interest costs ~~related~~as topart 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 ~~Company~~period isthat ~~currently~~they ~~preparing~~are being prepared for their intended use. ~~The~~Capitalized interest ~~costs~~is ~~that~~calculated ~~have~~by ~~been~~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 tointo oil and gas properties ~~total~~totaled $02.32 million and $~~nil~~0.3 million for the years ended December 31, ~~2017~~2018 and ~~2016~~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 ~~regions~~ 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,	~~For the Years Ended December 31,~~
		2017		2016
	2018	2017
Great Western Operating Company		22	%	43	%
Great Western Oil and Gas Company	40.5%	22%
Kerr-McGee Oil and Gas Onshore		4	%	23	%
Rose Rock Midstream Crude LP	33.4%	-
Ward Petroleum		2	%	20	%
PDC Energy, Inc	20.6%	71%
DCP Midstream		1	%	11	%
PDC Energy, Inc.		71	%	0	%

The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment. 40

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 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

~~The~~Proved properties ~~Company~~include ~~follows~~all ~~the~~capitalized ~~successful~~costs ~~efforts~~associated ~~method~~with ofproved developed ~~accounting~~and ~~for~~proved ~~its~~undeveloped ~~crude~~reserves. ~~oil~~Depletion, depreciation and ~~natural~~amortization ~~gas~~(“DDA”) of proved properties. ~~Under~~is calculated ~~this~~as ~~method~~a group of ~~accounting,~~assets ~~all~~(properties ~~property~~aggregated ~~acquisition~~based ~~costs~~upon common ~~and~~attributes) using the units-of-production method. DDA of development costs, ~~are~~including capitalized ~~when~~tangible ~~incurred~~and intangible drilling costs, well equipment, and ~~depleted~~facilities costs, is based on the aestimate ~~units-~~of~~-production~~ ~~basis~~proved ~~over~~developed ~~the~~reserves. ~~remaining~~Similarly, ~~life~~DDA of proved leasehold ~~reserves~~costs, ~~and~~including proved ~~developed~~undeveloped ~~reserves~~leases, ~~respectively.~~is ~~Costs~~calculated using the same method based on the estimate of ~~drilling~~total ~~exploratory~~proved reserves ~~wells~~(both ~~are~~developed ~~initially~~and ~~capitalized~~undeveloped). ~~but~~Currently, the Company’s properties are ~~charged~~located tosolely ~~expense~~within ifthe Wattenberg Field of the ~~well~~DJ Basin, which is ~~determined~~considered toone befield ~~unsuccessful~~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. ~~whenever~~The ~~events~~impairment ortest ~~circumstances~~compares ~~indicate that~~ the ~~carrying~~net capitalized ~~value~~costs of the ~~assets~~properties ~~may~~to ~~not~~the ~~be recoverable. The impairment test compares~~ estimated undiscounted future net cash flows ~~to the assets’ net book value~~. If the net capitalized costs exceed estimated future net cash flows, ~~then~~an ~~the~~impairment ~~cost~~expense ~~of the property~~ is ~~written down~~ recorded to ~~fair~~reduce ~~value.~~the ~~Fair~~carrying value ~~for~~of ~~crude~~the ~~oil and natural gas properties is generally determined based on estimated discounted future net cash flows~~property. ~~Impairment expense for proved properties is reported in exploration and impairment expense.~~

The sale ~~net~~or ~~carrying~~other ~~values~~disposition of ~~retired,~~part ~~sold~~of ora ~~abandoned~~proved ~~properties~~property ~~that~~is ~~constitute~~reported as ~~less than~~ a ~~complete~~normal ~~unit~~retirement, ofunder ~~depreciable~~which ~~property~~no ~~are~~gain ~~charged~~ or ~~credited,~~loss ~~net~~is ~~of proceeds~~recognized, ~~to accumulated depletion, depreciation and amortization~~ unless doing so significantly affects the unit-of-production amortization rate,. inGains ~~which case a gain~~ or ~~loss~~losses isare ~~recognized~~recorded in the statement of operations. ~~Gains~~for orall ~~losses~~other ~~from~~divestiture ~~the disposal of complete units of depreciable property are recognized in operations~~activities.

Unproved

Unproved properties consist of costs to acquire ~~undeveloped~~unproved and unevaluated leases asand ~~well~~other asmineral ~~costs to acquire unproved reserves~~assets. ~~Undeveloped~~All ~~lease~~acquisition costs ~~and unproved reserve acquisitions~~ are initially capitalized,. ~~and~~When ~~individually~~successful ~~insignificant~~wells ~~unproved properties~~ are ~~amortized~~drilled on unproved ~~a composite basis~~properties, ~~based~~the onassociated ~~past~~costs ~~success,~~are ~~past~~reclassified ~~experience~~as proved properties and ~~average~~depleted ~~lease~~on a units-~~term~~of-production ~~lives~~basis. The Company periodically evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or ~~future~~ plans to develop acreage. ~~When~~Individually ~~successful~~insignificant ~~wells~~unproved properties are evaluated ~~drilled~~ on ~~undeveloped~~a ~~leaseholds~~composite basis, ~~unproved~~and, ~~property~~when ~~costs~~appropriate, are amortized ~~reclassified~~ as ~~proved~~a ~~properties~~group ~~and~~based ~~depleted~~ on apast ~~units-of-production~~success, ~~basis.~~experience ~~Impairment expense for unproved properties is reported in exploration~~ and ~~impairment~~average lease-term ~~expense~~lives.

~~Exploratory~~ 41

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

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

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

~~raises~~ Exploration ~~substantial doubt about the economic or operational viability of the project, the exploratory well~~ costs~~, net of any salvage value, are expensed.~~

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 ~~methods~~ 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.

~~Asset Impairment~~ Related Party Transactions

~~Proved~~The Company ~~crude~~engages ~~oil~~in ~~and~~a ~~natural~~number ~~gas~~of ~~properties~~transactions ~~are~~with ~~reviewed~~Providence ~~for~~Energy Operators, ~~impairment~~LLC on(“PEO”) aand ~~field-by-field~~its ~~basis~~affiliates. ~~each~~PEO ~~quarter,~~is ora subsidiary ~~when~~of ~~events~~Providence ~~and~~Energy ~~circumstances~~Corporation, ~~indicate~~ a ~~possible~~privately-held corporation ~~decline~~based in ~~the~~Dallas, ~~recoverability~~Texas. ofPEO is the ~~carrying~~beneficial ~~value~~owner of 11.6% ~~such~~of ~~field.~~our ~~The~~outstanding ~~estimated~~common ~~future~~stock. ~~undiscounted~~We ~~cash~~have ~~flows~~a ~~expected~~participation agreement inthat ~~connection~~grants ~~with~~PEO the ~~field~~option ~~are compared~~ to ~~the~~acquire ~~carrying~~up ~~amount~~to ofa ~~the~~50% interest ~~field~~and toparticipate ~~determine~~in ifany ~~the~~oil ~~carrying~~and ~~amount~~gas isdevelopment ~~recoverable.~~on Ifacreage we ~~the~~obtain ~~carrying~~within ~~amount~~an area of ~~the~~mutual ~~field~~interest ~~exceeds~~(AMI) ~~its~~near ~~estimated~~our ~~undiscounted~~Southern Core ~~future~~area. ~~cash~~To ~~flows~~date, ~~the~~PEO ~~carrying~~has ~~amount~~exercised ~~of the field is reduced to~~ its ~~estimated~~option ~~fair~~under ~~value. Due to~~ the participation ~~unavailability~~agreement ofor ~~relevant~~otherwise ~~comparable~~participated ~~market~~or ~~data,~~agreed ~~a discounted cash flow method is used~~ to participate ~~determine~~in ~~the~~all ~~fair~~acreage ~~value~~acquisitions ofand ~~proved~~drilling ~~properties~~operations. ~~The~~As discussed ~~discounted cash~~elsewhere ~~flow~~in ~~method~~this ~~utilizes the most recent third-party reserve estimation~~ report, ~~and~~an ~~estimates~~affiliate ~~future~~of ~~cash~~PEO ~~flows~~is ~~based~~a onmajor participant ~~management’s~~in ~~estimates~~our ofprincipal ~~future~~lender ~~crude~~group ~~oil~~through ~~and~~which ~~natural~~we currently ~~gas~~maintain ~~production,~~a ~~commodity~~$25.0 ~~prices~~million ~~based~~Secured onCredit ~~commodity~~Facility. ~~futures~~The Board ~~price~~of ~~strips,~~Directors ~~operating~~is ~~and~~required ~~development~~to ~~costs,~~approve ~~and~~all asignificant ~~risk-adjusted~~related party ~~discount rate~~transactions.

Depletion, Depreciation and Amortization

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

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 ~~expenses~~costs incurred.

Prepaid Drilling Costs

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

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 ~~differences~~the ~~between~~tax ~~the~~effects ~~financial~~of ~~reporting~~temporary ~~and~~differences between ~~tax~~the ~~bases~~cost basis of assets and liabilities reported for financial reporting purposes compared to income tax reporting purposes using ~~the~~currently enacted tax rates. ~~that~~These ~~are~~differences ~~expected~~will result toin betaxable income or deductions in ~~effect~~future years when the reported ~~differences~~amounts of the assets or liabilities are ~~expected~~recorded or settled. Deferred tax assets are also recognized for future tax consequences attributable to beoperating ~~recovered~~loss carryforwards. The Company provides a valuation allowance for deferred tax assets ~~for~~when it ~~which~~does itnot 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.

57 Asset Retirement Obligation

The ~~Table~~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 ~~Contents~~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, ~~2017~~2018 and ~~2016~~ 2017

~~consider~~ Upon initial ~~realization~~recognition of ~~such~~an ~~assets~~ARO, tothe becarrying ~~more~~amount ~~likely~~of ~~than~~the associated ~~not. The~~asset ~~Company~~is ~~complies~~increased ~~with~~by ~~authoritative~~the ~~accounting~~same ~~guidance regarding uncertain tax provisions~~amount. The ~~entire~~capitalized costs ~~amount~~are ofincluded ~~unrecognized~~in ~~tax benefit reported by~~ the ~~Company~~periodic ~~would~~calculation ~~affect~~of ~~its~~DD&A ~~effective~~and ~~tax~~are subject ~~rate~~to ifimpairment ~~recognized~~testing. ~~Interest~~If ~~expense in~~ the ~~accompanying~~estimated ~~statements~~timing ofor ~~operations~~estimated cash ~~includes~~flow aof ~~negligible~~the ~~amount~~ARO ~~associated~~changes, ~~with~~an ~~income~~adjustment ~~taxes.~~is ~~The~~recorded ~~Company~~to ~~does~~both ~~not~~the ARO ~~expect~~and ~~a significant change to~~ the ~~recorded~~asset ~~unrecognized~~retirement ~~tax benefits in 2018~~cost.

~~Asset~~ Assets ~~Retirement~~Held ~~Obligation~~ for Sale

~~Asset~~We occasionally ~~retirement~~identify ~~obligations~~specific ~~associated~~oil ~~with~~and ~~tangible~~gas ~~long-lived~~properties ~~assets~~that ~~are~~we ~~accounted~~wish to ~~for~~sell. inAt ~~accordance~~the ~~with~~end ~~Accounting~~of ~~Standards~~each ~~Codification~~reporting ~~(“ASC”) 410~~period, ~~“Accounting~~we ~~for~~evaluate properties ~~Asset~~that ~~Retirement~~might ~~Obligations.”~~be ~~The~~sold ~~estimated~~to ~~fair~~determine ~~value~~whether ofany ~~the~~should ~~future~~be reclassified ~~costs~~as ~~associated~~held ~~with~~for ~~dismantlement,~~sale. ~~abandonment~~The ~~and~~held-for-sale ~~restoration~~criteria ofinclude: a ~~crude~~commitment ~~oil~~to ~~and~~a ~~natural~~plan ~~gas~~to ~~properties~~sell; the asset is ~~recorded~~available ~~generally~~for immediate ~~upon~~sale; ~~the~~an ~~completion~~active ofprogram ato ~~well.~~locate ~~The~~a ~~net~~buyer ~~estimated~~exists; ~~costs~~the sale ~~are~~of ~~discounted~~the toasset ~~present~~is ~~values~~probable ~~using~~and aexpected ~~credit-adjusted~~to ~~risk-free~~be ~~interest~~completed ~~rate~~within one ~~over~~year; the ~~estimated~~asset ~~economic~~is ~~life~~being ofactively ~~the~~marketed ~~crude~~for ~~oil~~sale; and ~~natural~~it ~~gas~~is unlikely ~~properties.~~that ~~Such~~significant ~~costs~~changes ~~are~~to ~~capitalized~~the asplan ~~part~~will be made. If each of ~~the~~these ~~related~~criteria ~~asset.~~is ~~The~~met, ~~asset~~the property is ~~depleted~~reclassified as held for sale on our consolidated balance sheets. We also compare the ~~units-~~fair values of~~-production~~ ~~method. The~~the ~~liability~~properties isheld ~~periodically~~for ~~adjusted~~sale to ~~reflect:~~the ~~(1)~~net ~~new~~unamortized ~~liabilities~~cost. If ~~incurred;~~an ~~(2)~~impairment ~~liabilities~~is ~~settled~~indicated, ~~during~~ the ~~period;~~assets ~~(3)~~held ~~accretion~~for ~~expense;~~sale ~~and~~are recorded ~~(4)~~at ~~revisions~~fair tovalue ~~estimated~~less ~~future~~costs ~~cash~~to ~~flow~~sell ~~requirements.~~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 aan ~~forfeiture~~expected ~~rate~~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 ~~received~~recorded and the redemption value of the debt is recognized inas interest expense in the consolidated ~~statement~~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 ~~1Unadjusted~~Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

Level 2 ~~2Quoted~~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 583 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 ~~Table~~financial assets and liabilities are classified based on the lowest level of ~~Contents~~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, ~~2017~~2018 and ~~2016~~ 2017

~~Level~~ Estimated ~~3Prices~~Fair orValue ~~valuation~~of ~~techniques~~Other ~~that~~Financial ~~require~~Assets ~~inputs that are both significant to the fair value measurement~~ and ~~unobservable (supported by little or no market activity).~~ 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 ~~will~~may be unable to meet its obligations as they become due within one year from the consolidated financial statement issuance date. As shown in the accompanying consolidated financial statements, the Company incurred a net loss of $10.8 million during the year ended December 31, 2017, and as of that date, the Company's current liabilities exceeded its current assets by $17.8 million, the Company had a cash balance of $0.7 million and other current assets of $2.7 million.

AsThe ofuncertainty 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, ~~2017~~2018. At December 31, 2018 the Company had ~~insufficient~~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 ~~and~~of ~~revenues~~$32.9 ~~from~~million. The ~~operations~~Company tohad ~~meet~~net ~~its~~losses, ~~maturing~~including ~~debt~~non-cash ~~obligations~~charges, of $17.3 million and ~~other~~$10.8 ~~liabilities~~million ~~incurred~~for the years ended December 31, 2018 and 2017, respectively. At December 31, 2018 the Company was obligated to berepay ~~incurred~~$9.4 million in ~~connection~~principal ~~with~~plus ~~the~~accrued ~~Company’s~~interest ~~development~~on outstanding ~~activities~~convertible promissory notes, which payment was not made. The ~~Company~~convertible ~~will~~notes ~~also~~are ~~need~~currently toin ~~generate~~default. ~~sufficient~~The ~~cash~~Company is ~~flow~~also ~~from~~in ~~operations~~default ~~and~~under ~~sell~~the ~~equity~~terms orof ~~debt~~the toSecured ~~fund~~Credit ~~further~~Facility (Note ~~drilling~~5) and ~~acquisition~~as ~~activity~~a result $29.9 Ifmillion, ~~sufficient~~including ~~cash~~the ~~flow~~outstanding principal, accrued interest and ~~additional~~penalties ~~financing~~are isdue. On ~~not~~April ~~available~~2, 2019, the ~~Company~~Secured ~~may~~Lenders delivered betheir ~~compelled~~formal toNotice ~~reduce~~of Default under the ~~scope~~terms of ~~its~~the Secured ~~business~~Credit ~~activities~~Facility. ~~and/or~~Some ~~sell~~accounts apayable ~~portion~~obligations ofto vendors ~~the~~are ~~Company’s~~past ~~interests~~the indue ~~its~~date ~~oil~~ and ~~gas~~some ~~properties.~~of ~~This,~~those invendors ~~turn,~~have ~~may~~filed liens ~~have~~or indicated an ~~adverse~~intent ~~effect~~to file liens on ~~the~~certain of the Company’s ~~ability~~assets. toThe ~~realize~~net proceeds from the ~~value~~sale of ~~its~~the non-operated assets. ~~These~~in ~~factors~~February ~~raise~~2019 ~~substantial~~were ~~doubt~~applied ~~about~~by the Secured Lenders to amounts allegedly owed to them. The Company’s ~~ability~~has been unable to ~~continue~~access asthe adebt ~~going~~or ~~concern.~~equity markets to obtain any additional funding during 2018.

Management has evaluated these conditions and determined that ~~a reduction in the working capital deficit subsequent to December 31, 2017 as a result of a new term Credit Facility (Note 6) coupled with anticipated~~ increased revenues from the Company’s ~~non-~~operated ~~and operated~~ properties, may allow the Company to meet its ~~maturing~~ongoing ~~debt~~operational ~~and interest~~ 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 ~~non-~~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.

~~The~~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 inas ~~existence.~~a going concern.

~~Recently Issued Accounting Pronouncements~~ 44

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires lessees to recognize a right-of-use asset and a lease liability for virtually all leases currently classified as operating leases. The Company is currently analyzing the impact this standard will have on the Company’s leases, including non-cancelable leases, drilling rigs, pipeline gathering, transportation, gas processing, and other existing arrangements. Further, the Company is evaluating current accounting policies, applicable systems, controls, and processes to support the potential recognition and disclosure changes resulting from ASU 2016-02. Based upon the Company’s initial assessment, ASU 2016-02 is expected to result in an increase in assets and liabilities recorded. The Company will adopt ASU 2016-02 using a modified retrospective method on the effective date of January 1, 2019. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides an optional transitional practical expedient which allows entities to exclude from evaluation land easements that exist or expired before adoption of ASU 2016-02. The Company is currently evaluating this practical expedient and will adopt ASU 2018-01 at the same time as ASU 2016-02.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

In Recently ~~January~~Adopted ~~2017,~~Accounting the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company has determined that the adoption of ASU 2017-01 on the effective date of January 1, 2018, using a prospective method, does not impact the Company’s current consolidated financial statements or disclosures. However, the clarified definition of a business will be applied by the Company to future transactions. Standards

In ~~February~~May ~~2018~~2014, the Financial Accounting Standards Board (“FASB”) issued ~~ASU~~a ~~No.~~new ~~2018-02, Income~~standard ~~Statement–Reporting~~on ~~Comprehensive~~revenue recognition ~~Income~~that ~~(Topic~~provides ~~220):~~a ~~Reclassification~~single, ofcomprehensive ~~Certain~~model ~~Tax~~that entities ~~Effects~~will ~~from~~apply ~~Accumulated~~to ~~Other~~determine ~~Comprehensive~~the ~~Income (“ASU~~measurement ~~2018-02”)~~and timing of revenue to be recognized. ~~ASU~~The ~~2018-02~~underlying ~~permits~~principle ~~entities~~is tothat ~~reclassify~~an entity ~~tax~~will ~~effects~~recognize ~~stranded~~revenue infor ~~accumulated~~the ~~other~~transfer ~~comprehensive~~of ~~income~~goods ~~(loss)~~or services to ~~retained~~customers ~~earnings~~at asthe aamount ~~result~~expected ofto ~~the~~be ~~2017~~received ~~Tax~~in ~~Act.~~exchange ~~ASU~~for those ~~2018-02,~~goods isor toservices. beThe ~~applied~~standard ~~either~~outlines ina five-step approach to apply the ~~period~~underlying ofprinciple: ~~adoption~~(1) oridentify ~~retrospectively~~the tocontract ~~each~~with the ~~period~~customer, (~~or periods~~2) inidentify ~~which~~the separate performance obligations in the ~~effect~~contract, of(3) determine the ~~change~~transaction inprice, (4) allocate the transaction ~~United~~price ~~States~~to ~~federal~~separate ~~corporate~~performance ~~income~~obligations ~~tax~~and ~~rate~~(5) recognize inrevenue ~~the~~when ~~2017~~or ~~Tax~~as ~~Act~~each isperformance ~~recognized~~obligation is satisfied. The ~~guidance~~standard, isknown ~~effective~~as ~~for~~Accounting ~~annual~~Standards ~~periods~~Update (“ASU”) No. 2014-09, ~~and~~Revenue ~~interim~~from ~~periods~~Contracts ~~within~~with Customers ~~those~~(Topic ~~annual~~606), ~~periods~~and all related ASU’s, ~~beginning~~was ~~after~~adopted ~~December~~by 15the Company effective January 1, 2018. ~~Early~~The ~~adoption~~Company isadopted ~~permitted~~ASU 2014-09 using the modified retrospective transition method, which was applied to all active contracts as ~~outlined~~of inJanuary ~~ASU~~1, 2018~~-02~~. The ~~Company~~adoption isof ~~currently~~ASU ~~evaluating~~2014-09 ~~the~~did not ~~provisions~~result ofin ~~this~~a ~~guidance~~change ~~and~~to ~~assessing~~current ~~the~~or ~~potential~~prior ~~impact~~period onresults nor did it result in a material change to the Company’s ~~consolidated~~business processes, ~~financial~~systems, ~~statements~~or ~~and~~controls. However, upon adopting ASU 2014-09, the Company expanded its disclosures. to comply with the expanded disclosure requirements of ASU 2014-09.

InEffective ~~May~~January 1, ~~2014~~2018, the ~~FASB~~Company ~~issued~~adopted ASU ~~2014~~No. 2017-0901, ~~“Revenue~~Business ~~from~~Combinations ~~Contracts with Customers~~ (Topic ~~606~~805)” ~~(“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict~~ Clarifying the ~~transfer~~Definition of ~~goods or services to~~ a ~~customer~~Business in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016‑08 (~~collectively with~~ “ASU ~~2014~~2017-~~09, the "Revenue ASUs"~~01”) ~~to clarify principal versus agent considerations~~. The ~~Revenue~~ASU ~~ASUs~~clarifies ~~allow for~~ the ~~use~~definition of ~~either~~a ~~the~~business ~~full~~with ~~or modified retrospective transition method, and~~ the ~~standard~~objective of ~~will~~adding beguidance ~~effective~~ for ~~annual~~the ~~reporting~~evaluation ~~periods~~of ~~beginning~~whether ~~after~~certain transactions ~~December~~represent ~~15,~~the ~~2017~~acquisition ~~including~~(or ~~interim~~disposal) ~~periods~~of ~~within~~assets ~~that~~or business ~~period,~~combinations. ~~with~~The ~~early~~Company ~~adoption~~adopted ~~permitted~~ASU ~~for~~2017-01 ~~annual~~on ~~reporting~~a prospective ~~periods beginning after December 15, 2016~~basis. ~~Currently, the~~

~~Company~~ Recent Accounting ~~has~~Pronouncements ~~not~~– ~~identified~~In ~~any~~February ~~contracts~~2016, ~~that~~FASB ~~would~~issued ~~require~~ASU aNo. 2016-02, ~~change~~Leases ~~from~~(Topic ~~the~~842). ~~entitlements~~For ~~method~~lessees, ~~historically~~the ~~used~~guidance ~~for~~in ~~certain~~this update ~~domestic~~and ~~crude~~subsequent ~~oil~~amendments require that a company recognize most leases by recording both a lease liability and ~~natural~~right-of-use asset ~~gas~~on ~~sales~~its balance sheet, representing the obligation to make payments and the ~~sales~~right ~~method~~to use or control the use of ~~accounting~~a specified asset for the lease term. The ~~Company~~standards ~~plans~~include toan ~~adopt~~exception ~~the~~for short ~~guidance~~term ~~using~~leases. Furthermore, the ~~modified~~new ~~retrospective~~lease ~~method~~standard ondoes ~~the~~not apply ~~effective~~to ~~date~~leases of ~~January~~mineral 1rights 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 ~~determined~~the practical expedient provided in the standard that allows the ~~adoption~~new ~~of,~~guidance ~~ASU~~to ~~2014~~be applied prospectively to all new or modified land easements and rights-~~09,~~of-way. ~~does~~Based ~~not~~upon ~~impact~~its preliminary analysis, the Company’s ~~current~~implementation ~~consolidated~~of ~~financial~~this standard ~~statements~~on orJanuary ~~disclosures.~~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).

~~There~~In ~~are~~August no2017, ~~other~~the ~~ASUs~~FASB ~~applicable~~issued ASU 2017-12, Derivatives and Hedging (Topic 815), which makes significant changes to the ~~Company~~current hedge ~~that~~accounting ~~would~~guidance. ~~have~~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 ~~material~~instrument ~~effect~~to onbe presented in the ~~Company’s~~same line as the hedged item in the consolidated ~~financial~~statement ~~statements~~of operations. The new standard also eases certain documentation and ~~related~~assessment ~~disclosures~~requirements ~~that~~and modifies ~~have~~the ~~been~~accounting ~~issued~~for ~~but~~components ~~not~~excluded ~~yet~~from the assessment of hedge effectiveness. The new standard will be adopted by the Company aseffective of for the annual period beginning after December 31 15, ~~2017~~2018, ~~and~~including ~~through~~interim ~~the~~periods ~~filing~~within that annual period. The adoption of this ~~report.~~guidance is not expected to have a material impact on the Company’s consolidated financial statements.

~~NOTE~~There are 3no -other ~~ACQUISITIONS~~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.

~~PDC Acquisition~~ 45

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

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

~~Following~~ NOTE a final proration of costs and revenues from the operation of the PDC assets and the Company's working interest partner's exercise of its option under the Participation Agreement, the Company's net purchase price for the PDC assets was $2.3 ~~million.~~– ~~A final allocation of the purchase price was prepared using~~PROPERTY, ~~among~~PLANT ~~other~~AND ~~things, an internally prepared reserve analysis. The following table summarizes the consideration transferred, fair value of assets acquired, and liabilities assumed:~~ EQUIPMENT

	December 31,
	2016
Consideration:
Cash		2,260,890
Total consideration	$	2,260,890
Fair Value of Liabilities Assumed:
Current liabilities		93,225
Asset retirement obligations		542,611
Total consideration plus liabilities assumed	$	2,896,726
Fair Value of Assets Acquired:
Proved crude oil and gas properties		2,473,082
Unproved crude oil and gas properties		423,644
Amount attributable to assets acquired	$	2,896,726

In accordance with FASB Topic ASC 805, the following table presents the unaudited pro forma combined results of operations for the years ended December 31, 2016, and 2015 (unaudited), as if the PDC assets acquisition had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to depletion, depreciation and amortization expense, accretion expense and costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Year Ended December 31,
	2016		2015
Crude oil and natural gas revenues	$	466,138	$	423,653
Net income (loss)	$	(4,498,325)	$	(1,439,823)
Net income (loss) per common share basic and diluted	$	(0.21)	$	(0.08)

Crimson Acquisition

On December 22, 2016, the Company completed the acquisition of certain oil and gas assets from Crimson Exploration Operating, Inc. (“Crimson”), including leases covering approximately 15,514 gross (5,609 net) acres of lands located mostly in Adams and Weld Counties, Colorado and Crimson’s interest in 32 producing wells (“Crimson assets”). Simultaneous with the closing, the Company’s working interest partner acquired 50% of the Company’s interest in the Crimson assets. The acquisition was effective December 1, 2016.

Following a reconciliation of certain suspense and inventory accounts, the Company’s net purchase price for the Crimson assets was $2.5 million.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

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

	December 31,
	2016
Consideration:
Cash		2,559,852
Total consideration	$	2,559,852
Fair Value of Liabilities Assumed:
Current liabilities		13,938
Asset retirement obligations		337,468
Total consideration plus liabilities assumed	$	2,911,258
Fair Value of Assets Acquired:
Current assets		20,907
Proved crude oil and gas properties		899,591
Unproved crude oil and gas properties		1,990,760
Amount attributable to assets acquired	$	2,911,258

In accordance with FASB Topic ASC 805, the following table presents the unaudited pro forma combined results of operations for the years ended December 31, 2016, and 2015 (unaudited), as if the Crimson assets acquisition had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to depletion expense, accretion expense and costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Year Ended December 31,
	2016		2015
Crude oil and natural gas revenues	$	595,074	$	237,035
Net income (loss)	$	(4,437,877)	$	(1,551,850)
Net income (loss) per common share basic and diluted	$	(0.20)	$	(0.09)

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

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

	December 31,	~~December 31,~~
		2017		2016
	2018	2017
Property, plant and equipment	$223,517	$223,517	~~223,517~~	$	~~47,870~~
Accumulated depreciation	(108,167)	(55,106)	~~(55,106)~~		~~(8,328)~~
Total	$115,350	$168,411	~~168,411~~	$	~~39,542~~

Depreciation 62expense recorded for the years ended December 31, 2018 and 2017 amounted to $53,061 and $46,778, respectively.

~~Table~~NOTE of4 ~~Contents~~ – CRUDE OIL AND NATURAL GAS PROPERTIES

The ~~PetroShare~~Company’s ~~Corp.~~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:

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	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

December 31, 2017 and 2016

Depreciation expense recorded for the years ended December 31, 2017 and 2016 amounted to $46,778 and $5,772, respectively.

NOTE 5 – CRUDE OIL AND NATURAL GAS PROPERTIES

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

	As of December 31,
	2017		2016
Proved oil and gas properties	$	22,144,366	$	8,132,881
Unproved oil and gas properties (1)		1,919,335		4,092,550
Wells in progress (2)		9,858,262		2,168,092
Total capitalized costs		33,921,963		14,393,523
Accumulated depletion, depreciation and amortization		(2,849,374)		(783,320)
Net capitalized costs	$	31,072,589	$	13,610,203

(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.

~~Costs~~During the ~~Incurred~~years inended ~~Crude~~December ~~Oil~~31, 2018 and ~~Natural~~2017, ~~Gas~~DDA ~~Activities~~expense was $7. ~~Costs~~0 million ~~incurred~~and in$2.8 ~~connection~~million, ~~with~~respectively. ~~the~~As ~~Company’s~~discussed ~~crude~~below, ~~oil~~the Company ~~and~~recorded ~~natural~~impairment ~~gas~~charges ~~acquisition,~~of ~~exploration~~$9.9 million and ~~development~~lease abandonment ~~activities~~charges ~~for~~of ~~each~~$0.6 ofmillion during the ~~periods~~fourth ~~are~~quarter ~~shown below:~~of 2018.

	December 31,
	2017		2016
Exploration costs	$	61,693	$	2,700
Development costs		18,771,794		3,038,339
Acquisition of properties
Proved		—		3,630,195
Unproved		4,049,380		4,045,022
Total	$	22,882,867	$	10,716,256

Acquisitions and Divestitures, including Assets Held for Sale

~~During the years ended December 31, 2017 and 2016, depletion, depreciation and amortization expense was $2.8 million and $0.1 million, respectively.~~ 2018 Activity

~~2017~~During 2018, ~~Activity~~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.

~~Significant~~In ~~acquisitions~~June ~~during~~2018, ~~2017~~the ~~included~~Company executed two participation agreements with PEO whereby the ~~following:~~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.

OnEffective ~~April~~June 31, ~~2017~~ 2018, the Company completed ana ~~acquisition~~conveyance of ~~oil~~property ~~and~~in ~~gas~~lieu ~~leases~~of payment ~~covering~~transaction ~~approximately~~with ~~5,874~~Providence ~~gross~~Energy Partners III (1“PEP III”),~~462~~ ~~net)~~one ~~acres~~of inits ~~Adams and Weld Counties, Colorado~~lenders. The ~~seller~~exchange ~~reserved~~conveyed tothe Company’s ~~itself~~working ~~all~~interests ~~rights~~ in ~~the~~four ~~leases~~producing ~~that~~wells, ~~exist~~eight wells ~~below~~in 50various ~~feet~~stages ~~above the top~~ of ~~the~~drilling ~~uppermost~~and Jcompletion, ~~Sand~~16 ~~formation~~proposed wells ~~for~~and ~~those~~the ~~lands~~underlying ~~located~~mineral inleases ~~Township~~(the 7"Ocho ~~North,~~Assets"). ~~Range~~The conveyance 63of ~~West~~properties inrepresented ~~Weld~~full ~~County,~~and ~~Colorado.~~final ~~The~~settlement ~~acquisition was effective January~~ of $2.1, ~~2017.~~million ~~The~~outstanding ~~net~~principal ~~purchase~~balance ~~price~~under to the ~~Company’s~~supplemental line ~~retained~~of ~~interest~~credit inwith ~~the~~PEP ~~assets,~~III ~~following~~(Note ~~the~~5). ~~Company’s~~PEP ~~working~~III ~~interest~~is ~~partner’s~~considered ~~50%~~an affiliate ~~participation~~of inPEO. As the transaction ~~and~~represented athe ~~reduction~~conveyance inof part ~~purchase~~of ~~price~~an ~~due~~interest toin ~~title~~a ~~defects,~~proved ~~was~~property ~~$1.3~~and ~~million.~~did ~~The~~not ~~Company~~have ~~paid~~a significant ~~$0.5~~impact ~~million~~on of the ~~Company’s~~DDA ~~net purchase price in cash~~calculation, ~~and~~it ~~$0.8~~has ~~million~~been ~~was~~recorded ~~paid~~as a ~~through~~normal ~~the~~retirement. ~~issuance~~The ofcarrying ~~450,000~~cost ~~shares~~ of the ~~Company’s~~oil ~~common~~and ~~stock~~gas properties ~~valued~~was at $10.808 ~~per share~~million.

During 63the 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.

~~Table of Contents~~ 46

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 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.

~~2016~~Costs ~~Activity~~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:

Significant acquisitions during 2016 included the following:

	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

On March 10, 2016, the Company acquired certain surface rights and easements on lands located in Township 1 South, Range 67 West in its Todd Creek Farms prospect in exchange for $0.2 million in cash. The surface rights and easements allow the Company to access its Shook pad wells. 47

On March 31, 2016, the Company acquired oil and gas assets on land adjacent to the Company’s Todd Creek Farms prospect, including approximately 160 net acres and a 50% working interest in one well following an assignment to the Company’s working interest partner pursuant to the Participation Agreement. The Company’s net cost for the foregoing assets was $0.6 million.

On April 14, 2016, the Company acquired oil and gas leases in the Todd Creek Farms prospect covering approximately 189 net acres. The Company’s net cost for the leases was $0.3 million.

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

On October 14, 2016, the Company completed the acquisition of additional royalty interests in 10 Jacobucci pad wells located on its Todd Creek Farms prospect. The Company’s net cost for the royalty interests was $1.6 million.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

NOTE 65 – DEBT

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

	Initial	~~Initial~~Supplemental	Convertible	Convertible	~~Supplemental~~Secured		~~Convertible~~		~~Convertible~~
	Line of	Line of	Notes	Notes	~~Line of~~Credit		~~Notes~~		~~Notes~~		~~Credit~~
	Credit	Credit	10%	Series B	~~Credit~~Facility		~~Series A~~		~~Series B~~		~~Facility~~
December 31, 2015 Principal Balance		$	(1,062,185)		$	-	$	-	$	-	$	-
December 31, 2016 Principal Balance	$(5,000,000)	$(7,105,000)	$(1,942,600)	$-	$-
Principal
December 31, 2016, Total, net	$(5,000,000)	$(7,105,000)	$(5,308)	$-	$-
Borrowings			(3,937,815)			(7,105,000)		(1,942,600)		-		-
Principal
Repayments			-			-		-		-		-
Borrowings	-	-	(8,057,400)	(4,724,900)	(5,000,000)
Conversions			-			-		-		-		-
Repayments	-	3,552,500	-	-	-
Beginning Balance - Unamortized Debt Issuance Costs - Original Issuer Discount			-			-		-		-		-
Conversions	-	-	5,166,800	-	-
Additions			-			-		205,260		-		-
Beginning Balance - Unamortized Debt Issuance Costs - Original Issuer Discount	-	-	204,703	-	-
Accretion			-			-		(557)		-		-
Additions	-	-	804,750	205,211	104,871
Ending - Unamortized Debt Issuance Costs - Original Issuer Discount			-			-		204,703		-		-
Accretion	-	-	(742,944)	(36,887)	(1,436)
Beginning Balance - Unamortized Debt Issuance Costs - Beneficial Conversion Feature			-			-		-		-		-
Ending - Unamortized Debt Issuance Costs - Original Issuer Discount	-	-	266,509	168,324	103,435
Additions			-			-		1,033,585		-		-
Beginning Balance - Unamortized Debt Issuance Costs - Beneficial Conversion Feature	-	-	1,030,762	-	-
Accretion			-			-		(2,823)		-		-
Additions	-	-	4,272,867	56,500	-
Ending - Unamortized Debt Issuance Costs - Beneficial Conversion Feature			-			-		1,030,762		-		-
Accretion	-	-	(3,978,881)	(11,959)	-
Beginning Balance - Unamortized Debt Issuance Costs - Warrant Discount			-			-		-		-		-
Ending - Unamortized Debt Issuance Costs - Beneficial Conversion Feature	-	-	1,324,748	44,541	-
Additions			-			-		703,753		-		-
Beginning Balance - Unamortized Debt Issuance Costs - Warrant Discount	-	-	701,827	-	-
Accretion			-			-		(1,926)		-		-
Additions	-	-	2,978,791	-	-
Ending - Unamortized Debt Issuance Costs - Warrant Discount			-			-		701,827		-		-
Accretion	-	-	(2,758,537)	-	-
December 31, 2016 Principal Balance		$	(5,000,000)		$	(7,105,000)	$	(1,942,600)	$	-	$	-
Ending - Unamortized Debt Issuance Costs - Warrant Discount	-	-	922,081	-	-
December 31, 2016, Total, net		$	(5,000,000)		$	(7,105,000)	$	(5,308)	$	-	$	-
December 31, 2017, Principal Balance	$(5,000,000)	$(3,552,500)	$(4,833,200)	$(4,724,900)	$(5,000,000)
Principal
December 31, 2017, Total, net	$(5,000,000)	$(3,552,500)	$(2,319,862)	$(4,512,035)	$(4,896,565)
Borrowings			-			-		(8,057,400)		(4,724,900)		(5,000,000)
Principal
Repayments			-			(3,552,500)		-		-		-
Borrowings	-	-	-	-	(20,000,000)
Conversions			-			-		5,166,800		-		-
Repayments	5,000,000	3,552,500	-	-	-
Beginning Balance - Unamortized Debt Issuance Costs - Original Issuer Discount			-			-		204,703		-		-
Conversions	-	-	200,000	-	-
Additions			-			-		804,750		205,211		104,871
Beginning Balance - Unamortized Debt Issuance Costs - Original Issuer Discount	-	-	266,509	168,324	103,435
Accretion			-			-		(742,944)		(36,887)		(1,436)
Additions	-	-	-	-	4,284,416
Ending - Unamortized Debt Issuance Costs - Original Issuer Discount			-			-		266,509		168,324		103,435
Accretion	-	-	(266,509)	(168,324)	(1,789,664)
Beginning Balance - Unamortized Debt Issuance Costs - Beneficial Conversion Feature			-			-		1,030,762		-		-
Ending - Unamortized Debt Issuance Costs - Original Issuer Discount	-	-	-	-	2,598,187
Additions			-			-		4,272,867		56,500		-
Beginning Balance - Unamortized Debt Issuance Costs - Beneficial Conversion Feature	-	-	1,324,748	44,541	-
Accretion			-			-		(3,978,881)		(11,959)		-
Additions	-	-	-	-	2,272,775
Ending - Unamortized Debt Issuance Costs - Beneficial Conversion Feature			-			-		1,324,748		44,541		-
Accretion	-	-	(1,324,748)	(44,541)	(949,372)
Beginning Balance - Unamortized Debt Issuance Costs - Warrant Discount			-			-		701,827		-		-
Ending - Unamortized Debt Issuance Costs - Beneficial Conversion Feature	-	-	-	-	1,323,403
Additions			-			-		2,978,791		-		-
Beginning Balance - Unamortized Debt Issuance Costs - Warrant Discount	-	-	922,081	-	-
Accretion			-			-		(2,758,537)		-		-
Additions	-	-	-	-	1,538,943
Ending - Unamortized Debt Issuance Costs - Warrant Discount			-			-		922,081		-		-
Accretion	-	-	(922,081)	-	(642,797)
December 31, 2017, Principal Balance		$	(5,000,000)		$	(3,552,500)	$	(4,833,200)	$	(4,724,900)	$	(5,000,000)
Ending - Unamortized Debt Issuance Costs - Warrant Discount	-	-	-	-	896,146
December 31, 2017, Total, net		$	(5,000,000)		$	(3,552,500)	$	(2,319,862)	$	(4,512,035)	$	(4,896,565)
December 31, 2018, Principal Balance	$-	$-	$(4,633,200)	$(4,724,900)	$(25,000,000)
December 31, 2018, Total, net	$-	$-	$(4,633,200)	$(4,724,900)	$(20,182,264)

65 48

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

~~Initial~~ Line of ~~Credit~~ credit

On May 13, 2015, the Company entered into a ~~revolving~~Revolving ~~line~~Line of ~~credit~~Credit ~~facility~~Facility ~~agreement~~ Agreement (“~~Initial~~initial ~~Line~~line of ~~Credit~~credit”, “Line of credit”) with PEO, a related party, which provided the Company with a revolving line of credit of up to $5.0 million,. ~~maturing~~Interest ~~June~~on 30the supplemental line initially accrued at the rate of 10% per year. On February 1, 2018 concurrent with the closing of the Secured Credit Facility (as described more fully below), the outstanding balance of $5.0 million plus accrued interest was repaid in full. In connection with the repayment, the Company recognized $0.3 million in interest expense related to the recognition of an unaccreted debt discount associated with the Line of Credit.

~~PEO~~ As isof ~~the~~December ~~beneficial~~31, ~~owner~~2018, ofand ~~approximately~~2017, ~~11.7% of~~ the ~~Company’s~~ outstanding ~~common~~balance ~~stock. The initial interest rate of 8% per year~~ on the Line ~~initial line~~ of credit was ~~increased~~$0.0 ~~twice~~and in$5.0 ~~connection~~million ~~with~~respectively. ~~other~~The ~~transactions~~Company had ~~involving~~accrued ~~the~~interest ~~parties,~~was ~~the~~$0.0 ~~first~~and ~~time~~$0.5 inmillion ~~September~~respectively. ~~2017 to 10% per year and~~ During the ~~second~~years ~~time~~ended in December ~~2017~~31, to2018 ~~15%~~and ~~per~~2017, ~~year.~~the ~~The~~Company ~~initial~~recorded interest ~~line~~expense of ~~credit~~$0.3 ~~was~~million ~~repaid~~and ~~in full in February 2018, together with accrued interest of~~ $0.64 million respectively, related asto ~~part~~the ofinitial ~~another~~line ~~financing~~of credit.

Supplemental ~~Line~~line of ~~Credit~~ credit

On October 13, 2016, the Company entered into a revolving line of credit facility agreement (the “~~Supplemental~~supplemental ~~Line~~line of ~~Credit~~ credit”) with ~~Providence~~PEP ~~Energy~~III. ~~Partners,~~PEP III, LPis ~~(“PEP~~an ~~III”)~~affiliate ~~under~~of ~~which~~PEO. ~~the~~The supplemental ~~Company~~line ~~was~~of ~~originally~~credit ~~entitled~~permitted the Company to borrow up to $10.0 million. ~~PEP~~to ~~III~~pay iscosts anassociated ~~affiliate~~with ofits ~~PEO~~acquisition byand development ~~virtue~~ of ~~having~~oil ~~some~~and ~~common~~gas ~~management~~properties ~~personnel.~~in the Wattenberg Field. Interest on the ~~Supplemental~~supplemental ~~Line~~line ~~of Credit~~ initially accrued at the rate of 8% per year ~~and the line matured on April 13, 2017~~.

The supplemental ~~Supplemental~~line ~~Line~~ of ~~Credit~~credit was amended on March 30, 2017, pursuant to which the Company agreed not to borrow additional amounts against the supplemental line of credit and to repay $3.6 million ~~in outstanding principal not later than April 13, 2017, in exchange for PEP III extending the maturity date of the Supplemental Line of Credit until June 13, 2017~~. ~~On April 12, 2017, the Company paid $3.6 million in accordance with the amendment.~~

On June 8, 2017, the Company entered into a letter agreement (“PEP III Agreement”) with PEP III and PEO, pursuant to which PEP III ~~again~~ agreed to modify the ~~Supplemental~~Company’s ~~Line~~supplemental line of ~~Credit~~credit. The PEP III Agreement ~~further~~ extended the maturity date of the ~~Supplemental~~supplemental ~~Line~~line of ~~Credit~~credit, including approximately $3.8 million in outstanding principal and accrued interest, from June 13, 2017 until December 27, 2017, and increased the interest rate on the supplemental line from 8% to 10%, effective June 8, 2017. The Company and PEO also agreed to amend the participation agreement between the Company and PEO, dated May 13, 2015 (“Participation Agreement”), in order to expand the area of mutual interest (“AMI”) established and ~~to grant~~ granted PEP III an option to participate under the Participation Agreement. PEP’s Asoption ~~amended,~~under the Participation Agreement ~~provides~~expired ~~PEO~~ when the ~~option~~line ~~to acquire up to a 45% interest and, so long as the Supplemental Line~~ of ~~Credit~~credit ~~remained~~was ~~outstanding,~~extinguished ~~PEP III the option to acquire up to a 10% interest~~ in, ~~and~~June ~~participate in, any oil and gas development on acreage acquired by the Company within the expanded AMI~~2018.

~~As described more fully below, on~~ On December 21, 2017, ~~the~~in ~~interest~~connection ~~rate~~with on the ~~Supplemental~~execution ~~Line~~ of ~~Credit~~a ~~was~~Letter Agreement ~~increased~~(as ~~from~~described ~~10%~~more tofully ~~15%,~~below) ~~and~~the oninterest ~~February~~rate 1,on ~~2018, concurrent with~~ the supplemental ~~closing~~line of ~~another~~ credit ~~facility,~~was aincreased ~~principal~~to ~~payment~~15% inand the ~~amount~~maturity date ~~of $1.5 million plus accrued interest of $0.5 million~~ was ~~made~~extended onuntil ~~the~~June ~~Supplemental~~30, ~~Line of Credit~~2018.

~~Convertible~~On February ~~Notes~~1, 2018, concurrent with the closing of the Secured Credit Facility (as described more fully below), $1.5 million of principal plus accrued interest was repaid on the supplemental line of credit.

OnEffective June ~~December 30~~1, ~~2016~~2018, ~~January~~the ~~20,~~Company ~~2017~~ and ~~January~~PEP ~~30,~~III ~~2017,~~closed ~~the~~on ~~Company~~a ~~completed~~transaction to exchange the ~~private~~Company’s ~~placement~~interest ofin ~~units~~the ~~consisting~~Ocho ofAssets ~~convertible promissory notes~~ (~~“Convertible~~Note ~~Notes”~~5) in ~~with~~full ansatisfaction ~~aggregate~~of ~~face~~the ~~value~~remaining of $102.01 million ~~and~~of ~~common~~outstanding principal ~~stock~~balance ~~purchase~~on ~~warrants.~~the ~~The~~supplemental ~~Convertible~~line ~~Notes~~of ~~are~~credit. ~~unsecured,~~The ~~bear~~Company accounted ~~interest~~for atthis ~~10%~~transaction ~~per~~as ~~year~~a ~~and~~retirement ~~are~~in ~~due~~accordance ~~and~~with ASC ~~payable on December 31, 2018~~932-360-40-3. AtAs the ~~option~~retirement ofdid ~~the~~not ~~holders~~impact of the ~~Convertible Notes, the principal amount~~ unit-of-production ~~the~~amortization ~~Convertible~~rate ~~Notes,~~no ~~and~~gain ~~any~~or ~~accrued~~loss ~~but~~was ~~unpaid~~recognized on ~~interest, are convertible into shares of~~ the ~~Company's common stock at a conversion price of $1~~transaction.~~50 per share.~~

66 49

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

As of December 31, 2018, and 2017, the outstanding balance on the supplemental line of credit was $0.0 and $2.1 million respectively. The Company had accrued interest of $nil and $0.5 million respectively. During the years ended December 31, 2018 and 2017, the Company recorded interest expense of $0.1 million and $0.4 million respectively, related to the supplemental line of credit.

10% Convertible Notes

On January 30, 2017, the Company completed the private placement of units consisting of convertible promissory notes (“Convertible Notes”) with an aggregate face value of $10.0 million and common stock purchase warrants. The Convertible Notes are unsecured, bear interest at 10% per year and were due and payable on December 31, 2018. At the option of the holders of the Convertible Notes, the principal amount and any accrued but unpaid interest are convertible into shares of the Company’s common stock at a conversion price of $1.50 per share.

The Company received net proceeds of approximately $9.0 million from the private placement, after placement agent fees and other associated expenses.

OnIn accordance ~~October~~with 16ASC 470, ~~2017~~“Debt”, inthe ~~connection~~proceeds ~~with~~from the sale ~~sales~~ of ~~Series~~the BConvertible ~~Unsecured~~Notes ~~Convertible~~was ~~Promissory~~allocated ~~Notes~~between ~~(“Series~~the Bconversion feature embedded in the Convertible Notes”) asand ~~described~~the ~~more~~warrants ~~fully~~attached to ~~below~~the notes based on the fair values of the debt instrument without the warrants, $5and of the warrants themselves, at the time of issuance.2 ~~million~~The infair ~~principal~~value of the ~~Convertible~~beneficial ~~Notes~~conversion ~~and~~feature (BCF) was $05.13 million inand ~~accrued~~the ~~interest~~fair ~~was~~value ~~converted~~of ~~into~~the ~~4,814,265~~warrants ~~shares~~was $3.7 million. Each of ~~common~~the ~~stock~~fair atvalue amounts were recorded as a reduction ~~conversion~~of ~~rate~~the carrying value of ~~$1.10~~the ~~per~~Convertible ~~share.~~Notes ~~The~~and ~~Company~~were amortized ~~has~~to ~~recorded~~interest aexpense ~~loss~~using onthe ~~conversion~~effective interest method over the term of the Convertible Notes. In addition, warrants with an estimated fair value of $1.80 million were issued to the placement agent in connection with the ~~reduction~~offering. ofThe ~~the~~placement agent ~~initial~~warrants ~~contractual~~were ~~conversion~~recorded ~~rate.~~as a charge to additional paid-in capital.

InOn October ~~accordance with ASC 470~~16, ~~Debt~~2017, ~~the~~in ~~proceeds~~connection ~~from~~with the ~~sale~~sales of ~~the~~Series B Unsecured Convertible Promissory Notes ~~was~~(“Series ~~allocated~~B ~~between the conversion feature embedded in the~~ Convertible Notes”) ~~and~~as ~~the~~described ~~warrants~~more ~~attached~~fully ~~to the notes based on the fair values of the debt instrument without the warrants~~below, ~~and of the warrants themselves, at the time of issuance~~$5.2 ~~The~~million ~~fair~~in principal ~~value~~ of the ~~beneficial conversion feature has been recorded as a reduction of the carrying value of the~~ Convertible Notes and is$0.1 ~~being~~million ~~amortized~~in to accrued interest ~~expense~~was ~~using~~converted ~~the~~into ~~effective~~4,814,265 ~~interest~~shares ~~method~~of ~~over~~common ~~the~~stock ~~term~~at a conversion rate of ~~the~~$1.10 ~~Convertible~~per ~~Notes~~share. The ~~fair~~Company ~~value of the warrants~~ has ~~been~~ recorded as a ~~reduction~~loss on toconversion ~~the carrying value~~ of ~~the Convertible Notes and is being amortized to interest expense using the effective interest method over the term of the Convertible Notes~~$1.8 ~~The~~million ~~fair value of the warrants issued to the placement agent~~ in connection with the ~~offering~~reduction of the ~~$1.0~~initial ~~million~~contractual ~~has~~conversion ~~been recorded as a charge to additional paid-in capital~~rate.

As of December 31, 2018, and 2017, the Convertible Notes had an outstanding principal balance of $4.6 million and $4.8 million and accrued interest of $nil and $0.3 million respectively. Interest expense related to the notes for the years ended December 31, 2018 and 2017 was $0.5 million and $0.8 million.

The 10% Convertible Notes were not paid as of December 31, 2018, and they remain outstanding and in default.

Series B Convertible Notes

In September and October 2017, the Company sold Series B Convertible Notes in the principal amount of $4.7 million. The Series B Convertible Notes are unsecured, bear interest at 15% per year, and were ~~are~~ due and payable on December 31, 2018. At the option of the holders, the principal amount of the Series B Convertible Notes and any accrued but unpaid interest are convertible into shares of the Company'’s common stock at a conversion price of $1.50 per share. The Company netted $4.5 million from the sale of the Series B Convertible Notes after expenses.

In accordance with ASC 470, the fair value of the beneficial conversion feature of $56,500 has been recorded as a reduction of the carrying value of the Series B Notes and iswas ~~being~~ amortized to interest expense using the effective interest method over the term of the Series B Notes.

As of December 31, 2018, and 2017, the Series B Convertible notes had and outstanding balance of $4.7 million and $4.7 million and accrued interest of $nil and $0.2 million respectively. Interest expense related to the notes for the years ended December 31, 2018 and 2017 was $0.7 million and $0.2 million.

The Series B Convertible Notes were not paid as of December 31, 2018, and they remain outstanding and in default.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Secured Credit Facility

On February ~~December 21~~1, ~~2017~~2018, the Company ~~entered~~closed ~~into~~on a ~~letter~~$25.0 ~~agreement~~million ~~(“Letter~~Secured Credit ~~Agreement”)~~Facility with Providence ~~Energy Ltd. (“PEC”)~~Wattenberg, LP and ~~Fifth~~5NR ~~Partners~~Wattenberg, LLC (“~~Fifth,~~Secured Lenders”). ~~and~~Each ~~together~~of ~~with~~Providence ~~PEC,~~and ~~the~~5NR ~~“Lenders”)~~are affiliates ~~pursuant~~of ~~to which~~ the ~~Company~~Lenders ~~borrowed~~under ~~$5.0~~a ~~million~~Letter ~~from~~Agreement ~~PEC~~entered ~~(“Initial~~into ~~Funding”).~~by the ~~PEC~~Company ison anDecember ~~affiliate~~21, of2017, ~~PEO~~under bywhich ~~virtue~~the ofCompany ~~common~~borrowed $5.0 ~~management~~million. InThe ~~connection~~obligation ~~with~~under the ~~Initial~~Secured ~~Funding,~~Credit Facility includes the ~~Company~~$5 ~~and~~million ~~the~~borrowed ~~Lenders~~under ~~agreed~~the toLetter ~~negotiate~~Agreement aand includes ~~second~~additional ~~credit~~borrowings ~~facility~~ of $20.0 million ~~(“Second Funding”), which was completed on February 1, 2018~~.

~~Interest~~The following onare the ~~outstanding~~material ~~principal~~terms ~~balance~~ of the ~~Initial~~Secured Funding accrued at the three-month LIBOR plus 14%, or 15.7%. As of December 31, 2017, accrued interest payable related to the Initial Funding amounted $21,801. In connection with the Initial Funding, the Company recorded debt issuance costs in the amount of $0.1 million and incurred interest expense in the amount of $1,437 related to the accretion of these costs.Credit Facility:

67 ● Interest on the outstanding principal balance accrues at the base rate of 14% per year plus the greater of either 1% or US Dollar LIBOR (three-month tenor), but in no event greater than 17%, plus, in the event of default, penalty interest of 5%. Interest payments are due and payable each month commencing March 1, 2018.

Table of Contents

●	The Company paid a $1.25 million origination fee at the time of the closing and agreed to pay a $1.25 million underwriting fee on February 1, 2019.
●	The borrowing is secured by a lien on all of the Company’s assets.

●	All principal is due February 1, 2020 (“Maturity Date”).

●	At any time, each Secured Lender may convert 20% of the outstanding principal balance into common stock of the Company at a conversion rate of $1.15 per share and 80% of the outstanding principal balance at a conversion rate of $1.55 per share.

●	The Secured Lenders received warrants to purchase 1,500,000 shares of common stock of the Company at a price of $0.01 per share (Note 8).

●	The Secured Lenders were granted the right to participate in any public or private securities offering by the Company, limited to 50% of securities offered until December 31, 2018, and 25% of any securities offered thereafter.

●	Beginning on the maturity date and continuing until February 2021, the Secured Lenders were granted an option to purchase up to $25 million of the Company’s common stock at a 10% discount from the 30-day volume-weighted average trading price (“VWAP”) of the common stock at the time the option is exercised, but in no event shall the exercise price be less than $1.85 per share; and registration rights in connection with the common stock that may be issued upon exercise of the foregoing rights.

●	The Borrower has the right to make an optional prepayment prior to the maturity date. Upon prepayment of the loan or upon certain events of default, the Company is subject to a “Make-Whole Premium” in the amount of 40% multiplied by the then-outstanding balance, less amounts paid for interest and certain fees paid by the Borrower under the Secured Credit Facility

The Secured Credit Facility is subject to certain financial and restrictive covenants under which the Company’s failure to comply results in an event of default. The covenants include:

●

The Company has agreed not to issue any equity securities or securities convertible into or exercisable for equity securities without the consent of Lenders, except for common stock issuable under the Company’s equity incentive plan, certain registered public offerings, common stock issuable in connection with certain convertible promissory notes and certain outstanding warrants; and

●	Maintenance of a Total Leverage Ratio and a Present Value of Proved Developed Producing Reserves Coverage Ratio, as defined in the borrowing documents.

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

~~NOTE~~The following 7table –summarizes ~~ASSET~~the ~~RETIREMENT~~use ~~OBLIGATION~~of the $20.0 million in additional borrowings under the terms of the Secured Credit Facility:

For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended December 31, 2017, the Company assumed an inflation rate of 2.0%, an estimated average asset life of 29.9 years, and a credit-adjusted risk-free interest rate of 11.26% to 14.0%. For the year ended December 31, 2016, the Company assumed an inflation rate of 2.0%, an estimated average life of 13.2 years, and a credit-adjusted risk-free rate of 9.48% to 10.73%.

Gross Proceeds	$20,000,000
Payment of origination fee	(1,250,000)
Principal repayment on Initial Line of Credit	(5,000,000)
Principal repayment on Supplemental Line of Credit	(1,500,000)
Payment of accrued interest costs	(1,086,808)
Net Cash Proceeds	$11,163,192

The Secured ~~following~~Credit ~~reconciles~~Facility is considered a hybrid debt instrument with several elements that required identification and valuation. As the fair value of the ~~asset~~embedded ~~retirement~~derivatives ~~obligation~~is ~~for~~not readily determinable through an active marketplace of identical instruments, the ~~periods~~Company employed ~~presented:~~the Monte Carlo simulation valuation model to determine the fair value of the embedded derivative liabilities.

	December 31,
	2017		2016
Asset retirement obligation, beginning of period	$	945,419	$	34,776
Liabilities settled (1)		(50,163)		1,990
Liabilities incurred		91,999		878,170
Revisions in estimated liabilities		36,507		—
Accretion		99,682		30,483
Asset retirement obligation, end of period	$	1,123,444	$	945,419

It was determined that the rights to convert the debt into common shares contained a beneficial conversion feature that could be detached from the debt and valued as a component of equity. It was likewise determined that the warrants could be detached from the debt and valued as a component of equity. It was determined that the option to purchase shares at a 10% discount from VWAP represented a derivative liability that should be remeasured at fair value for each reporting period. The Company further determined that certain provisions of the agreement which provide for additional interest payments under certain conditions represent an additional compound derivative liability that should also be remeasured at fair value for each reporting period. The compound derivative liability included the Make-Whole Premium, Default Interest Penalty, and Registration Rights Penalty. For both the share purchase option and the additional interest provisions, a Monte Carlo simulation model was used to calculate estimates of fair value. The model was used as of February 1, 2018 to determine the initial valuation. In each interim reporting period subsequent to February 1, 2018, the model was updated to determine changes in the estimated values.

~~_________________________~~The values allocated to each component of the debt instrument are set forth below;

Secured Credit Facility, net of all discounts	$16,786,981
Make whole premium derivative liability	14,698
Default interest penalty derivative liability	243,794
Registration rights penalty derivative liability	63,672
Share purchase option derivative liability	1,347,853
Stock purchase warrants	1,538,943
Beneficial conversion feature	2,272,775
Legal fees and other	231,284
Subtotal	22,500,000
Origination fee and Underwriting fee	2,500,000
Secured Credit Facility, face value	$25,000,000

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2018 and 2017

Defaults

As of December 31, 2018, the Company was in default under certain provisions of the Secured Credit Facility including the inability of the Company to pay its debts or other obligations as they become due, a mechanic’s lien filed against the Company in Adams, County Colorado and for accounts payable outstanding for greater than 90 days. On February 1, 2019, the Company incurred another event of default by failing to pay the Secured Lenders a $1.3 million underwriting fee incurred in connection with the origination of the Secured Credit Facility.

As a result of the defaults, the Company has accrued additional default penalty interest of $0.3 million at the penalty interest rate of an additional 5%, from the date of the first reported default on October 1, 2018 through December 31, 2018. The Company has accrued $3.4 million related to the embedded make-whole premium.

As of December 31, 2018, $29.9 million in principal, penalty interest and amounts accrued for the make-whole premium are due and payable. 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.

The Company is currently in negotiation with the Secured Lenders as to the impact and resolution of the defaults.

NOTE 6 – ASSET RETIREMENT OBLIGATION

For the purpose of determining changes in the amount of the asset retirement obligation during the year ended December 31, 2018, the Company assumed an inflation rate of 2% and a credit-adjusted risk-free interest rate ranging from approximately 14% to 21%. For the year ended December 31, 2017, the Company assumed an inflation rate of 2% and a credit-adjusted risk-free rate ranging from approximately 11% to 14%. For both years, assumed well lives are based upon engineering and economic data and approximate 30 years for new horizontal wells and shorter lives for the acquisition of older wells.

The following table presents changes in the asset retirement obligation for the years ended:

	December 31,
	2018	2017
Asset retirement obligation, beginning of year	$1,123,444	$945,419
Liabilities settled (1)	(192,996)	(50,163)
Liabilities incurred	58,511	91,999
Revisions in estimated cash flows	983,352	36,507
Accretion	117,636	99,682
Asset retirement obligation, end of year	$2,089,947	$1,123,444

Current liability	$843,796	$288,784
Long-term liability	$1,246,151	$834,660

(1)	Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

~~Accretion~~The revisions ~~expense~~in ~~recorded~~estimated cash flows during 2018 were primarily due to changes in estimates of costs for labor and materials related to the ~~year~~plugging ~~ended~~and ~~December~~abandonment ~~31,~~of ~~2017~~wells and ~~2016~~the ~~was~~shortening ~~$0.1~~of ~~million~~the estimated ~~and~~lives ~~$30,483,~~of ~~respectively~~wells.

NOTE 87 - ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities were comprised of the following amounts:

	December 31,	~~December 31,~~
		2017		2016
	2018	2017
Trade payables and accrued liabilities	$2,093,428	$1,544,112	~~1,544,112~~	$	~~2,416,551~~
Accrued interest payable	-	876,455	~~876,455~~		~~302,477~~
Liabilities incurred in connection with acquisition of crude oil and natural gas properties	22,291,989	1,719,785	~~1,719,785~~		~~290,078~~
Total	$24,385,417	$4,140,352	~~4,140,352~~	$	~~3,009,106~~

~~NOTE~~See Note 911 -for ~~SHAREHOLDERS’~~related ~~EQUITY~~ party liabilities.

~~Common Stock~~ 53

As of December 31, 2017 and 2016, the Company had 100,000,000 shares of common stock authorized with a par value of $0.001 per share. As of December 31, 2017 and 2016, the Company had 27,718,802 and 21,964,282 shares issued and outstanding, respectively.

Activity for the year ended December 31, 2017 included the following:

· On October 16, 2017, the Company issued 4,814,265 shares of common stock valued at $1.38 in conversion of $5.2 million of Convertible Notes and $0.1 million in accrued interest (Note 6);

· On September 23, 2017, the Company issued 250,000 shares of common stock valued at $1.55 to PEO in connection with the execution of a Letter Agreement;

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

· NOTE On8 ~~various~~- ~~dates,~~SHAREHOLDERS’ in connection with the execution of four employment agreements (Note 13) and the employment of additional employees, the Company issued 219,700 shares of restricted stock. The shares are subject to certain vesting restrictions, but all 219,700 shares have full voting rights and are eligible to receive dividends during the vesting period; andEQUITY

· Increase Onin ~~April 3, 2017, the Company issued 470,555 shares valued at $1.80 per~~ share ~~in connection with the acquisitions of oil and gas assets.~~capital

~~Activity~~On March ~~for~~15, 2019, at a special meeting, the ~~year~~shareholders ~~ended~~approved ~~December~~an amendment 31to the Company’s Articles of Incorporation (“Amendment”) to increase the authorized common stock from 100,000,000 ~~2016~~shares ~~included~~to 200,000,000 shares. The Amendment was effective on March 20, 2019 upon filing with the ~~following:~~Colorado Secretary of State.

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

· As of OnDecember ~~April~~31, 82018, ~~2016~~and 2017, the Company ~~issued~~had 50100,000,000 shares of common stock ~~valued~~authorized atwith a par value of $0.73001 per share. toAs of anDecember ~~investor~~31, ~~relations~~2018, ~~company~~and in2017, ~~connection with~~ the ~~certain~~Company ~~services~~had to28,089,765 beand 27,718,802 ~~provided~~shares ~~pursuant~~issued toand ~~an investor relations agreement;~~outstanding, respectively.

· Activity Onfor ~~May 4, 2016,~~ the ~~Company~~year ~~issued~~ended anDecember ~~aggregate of 50~~31,~~000~~ ~~shares~~2018 ofincluded ~~common stock valued at $1.01 per share to two of~~ the ~~Company's directors in connection with their appointment to the Board (Note 10);~~ following:

· On February ~~July 5~~23, ~~2016,~~2018 the Company issued 2570,000 shares of common stock , valued at $1.6000 per share, ~~to a director~~ in ~~connection~~lieu ~~with~~of ~~his appointment to the Board (Note 10);~~cash compensation.

· On March ~~July 22~~12, ~~2016,~~2018 the Company issued 8135,~~333~~963 shares of common stock ~~valued~~in connection atwith ~~$1.65 per share and on August 22, 2016~~ the ~~Company~~conversion ~~issued 8,333 shares~~ of ~~common stock valued at~~ $~~1.40 per share~~200,000 ~~each~~of to10% anconvertible ~~investor~~notes payable ~~relations~~plus ~~company~~accrued ininterest. ~~connection~~The ~~with~~shares ~~certain~~were ~~services~~issued toat bethe contractual ~~provided~~rate toof ~~the Company;~~$1.50.

· On April ~~August 30~~18, ~~2016,~~2018 the Company issued 5075,000 shares of common stock , valued at $1.4423 per share, toin anconnection ~~investor~~with ~~relations~~the ~~company~~appointment inof three ~~connection~~new ~~with~~members ato ~~termination~~its ~~agreement;~~Board of Directors.

· On June ~~November 11~~1, ~~2016,~~2018 the Company issued 1465,~~425~~000 shares of common stock valued at $1.8540 per share to anemployees ~~individual~~of inthe ~~connection~~Company ~~with~~as ~~the~~compensation. The ~~consideration~~shares ~~and~~are ~~acquisition~~subject ofto ~~the~~ certain ~~oil~~vesting ~~and~~restrictions, ~~gas~~but ~~leases;~~all 65,000 shares have full voting rights and are eligible to receive dividends during the vesting period.

· On ~~December 5~~July 24, ~~2016,~~2018 the Company issued 3045,000 shares of common stock valued at $1.8929 per share into ~~connection~~an ~~with~~officer of the ~~exchange~~Company ofas ~~interests~~compensation. inThe shares are subject to certain ~~oil~~vesting restrictions, but all 45,000 shares have full voting rights and ~~gas~~are ~~assets~~eligible into ~~Buck~~receive dividends ~~Peak~~during ~~prospect~~the vesting period.

Activity for the year ended December 31, 2017 included the following:

●	On October 16, 2017, the Company issued 4,814,265 shares of common stock valued at $1.38 in conversion of $5.2 million of Convertible Notes and $0.1 million in accrued interest (Note 5).

●	On September 23, 2017, the Company issued 250,000 shares of common stock valued at $1.55 to PEO in connection with the execution of a Letter Agreement.

●

On various dates, in connection with the execution of four employment agreements and the employment of additional employees, the Company issued 219,700 shares of restricted stock. The shares are subject to certain vesting restrictions, but all 219,700 shares have full voting rights and are eligible to receive dividends during the vesting period.

●	On April 3, 2017, the Company issued 470,555 shares valued at $1.80 per share in connection with the acquisitions of oil and gas assets.

Preferred Stock

As of December 31, ~~2017~~2018, and ~~2016~~2017, the Company had 10,000,000 shares of preferred stock authorized with a par value of $0.01 per share. As of December 31, ~~2017~~2018, and ~~2016~~2017, there were no shares of preferred stock issued or outstanding.

69 54

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

Warrants

The table below summarizes warrants outstanding as of December 31, ~~2017:~~ 2018:

	Shares Underlying	~~Shares~~Exercise ~~Underlying~~Price		~~Exercise Price~~
	Outstanding Warrants	~~Outstanding~~Per ~~Warrants~~Share	Expiration Date	~~Per Share~~		~~Expiration Date~~
Underwriter warrants	255,600	~~255,600~~$1.25	11/12/2020	$	~~1.25~~	~~11/12/2020~~
Investor warrants	6,666,600	~~6,666,600~~$3.00	12/31/2019	$	~~3.00~~	~~12/31/2019~~
Placement agent warrants	666,600	~~666,600~~$1.50	12/31/2021	$	~~1.50~~	~~12/31/2021~~
Total		7,588,800
Secured Credit Facility warrants	1,500,000	$0.01	02/01/2020
Total	9,088,800

Activity for the year ended December 31, ~~2017:~~2018 included the following:

· On February ~~January 20~~1, ~~2017~~2018 ~~and~~in ~~January~~connection ~~30,~~with ~~2017~~the closing of the Secured Credit Facility, the Company issued ~~537~~1,~~260~~500,000 stock purchase warrants. The warrants are exercisable at $10.5001 per share and expire ~~expiring~~ on ~~December~~February 311, ~~2021~~2020 ~~in connection with a private placement~~ (~~Note~~Notes 65)~~; and~~.

· Activity Onfor ~~January 20, 2017 and January 30, 2017,~~ the ~~Company~~year ~~issued~~ended ~~5,371,579 warrants exercisable at $3.00 per share and expiring on~~ December 31, ~~2019,~~2017 ~~also~~included ~~in connection with~~ the ~~private placement (Note 6).~~ following:

~~Activity~~● ~~for~~On January 20, 2017 and January 30, 2017, the ~~year~~Company ~~ended~~issued 537,260 warrants exercisable at $1.50 per share and expiring on December 31, ~~2016:~~ 2021 in connection with a private placement (Note 5).

·● On ~~December~~January 20, 2017 and January 30, ~~2016~~2017, the Company issued ~~129~~5,~~516~~371,579 warrants exercisable at $13.5000 per share and expiring on December 31, ~~2021~~2019, also in connection with the ~~closing of the first round of the Company’s~~ private placement (Note 65)~~; and~~.

· NOTE On9 ~~December~~– ~~30,~~STOCK-BASED 2016, the Company issued 1,294,987 warrants exercisable at $3.00 per share and expiring on December 31, 2019 in connection with the closing of the first round of the Company’s private placement (Note 6).COMPENSATION

~~NOTE~~On August 18, 2016, the Company’s Board of Directors adopted the Amended and Restated PetroShare Corp. Equity Incentive Plan (the “Plan”). The Plan terminates on August 17, 2026. Among other things, the Plan increased the number of shares of common stock reserved for issuance thereunder from 5,000,000 to 10,000,000 shares. –The ~~STOCK-BASED~~Company’s ~~COMPENSATION~~shareholders approved the Plan at the Company’s annual meeting of shareholders on September 8, 2016.

OnDuring the ~~August~~year 18ended December 31, ~~2016~~2018, the ~~Company's~~ Board of Directors ~~adopted~~granted non-qualified ~~the~~options ~~Amended~~to ~~and Restated PetroShare Corp. Equity Incentive Plan (the "Plan")~~employees, ~~which~~directors ~~replaced~~ and ~~restated~~consultants of the Company's ~~original~~under ~~equity incentive plan. The Plan terminates by its terms on August 17, 2026. Among other things,~~ the Plan ~~increased~~to ~~the~~acquire ~~number of shares of common stock reserved for issuance thereunder from 5~~790,000~~,000~~ ~~to 10,000,000~~ shares. ~~The Company's shareholders approved the Plan at the Company's annual meeting~~ of ~~shareholders on September 8, 2016.~~common stock.

During the year ended December 31, 2017, the Board of Directors granted non-qualified options to employees, directors and consultants of the Company under the Plan to acquire 422,000 shares of common stock. 55

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

A summary of activity under the Plan for the years ended December 31, 2018 ~~2017~~ and ~~2016~~2017 is as follows:

		Weighted	Remaining		~~Weighted~~	~~Remaining~~
		Average	Contractual		~~Average~~	~~Contractual~~
	Number of	~~Number of~~Exercise	Term		~~Exercise~~	~~Term~~
	Shares	~~Shares~~Price	(Years)	~~Price~~		~~(Years)~~
Outstanding, December 31, 2015		2,275,000		$	0.33	6.50
Outstanding, December 31, 2016	4,675,000	$0.76	5.39
Exercisable, December 31, 2015		2,200,000		$	0.30	6.72
Granted	422,000	$1.86	5.69
Granted		2,400,000		$	1.16	5.34
Exercised	—	—	—
Exercised		—			—	—
Forfeited	(100,000)	—	—
Forfeited		—			—	—
Outstanding, December 31, 2017	4,997,000	$0.85	4.44
Outstanding, December 31, 2016		4,675,000		$	0.76	5.39
Exercisable, December 31, 2017	4,347,500	$0.74	4.48
Exercisable, December 31, 2016		3,010,000		$	0.54	5.97
Granted	790,000	0.93	4.07
Granted		422,000		$	1.86	5.69
Exercised	—	—	—
Exercised		—			—	—
Expired	(425,000)	1.00	—
Forfeited	(325,000)	~~(100,000)~~1.35	3		—	—
Outstanding, December 31, 2017		4,997,000		$	0.85	4.44
Outstanding, December 31, 2018	5,037,000	$0.79	3.87
Exercisable, December 31, 2017		4,347,500		$	0.74	4.48
Exercisable, December 31, 2018	4,621,000	$0.75	3.86

The fair value of each stock-based award was estimated on the date of the grant using the Black-Scholes pricing model that incorporates key assumptions including volatility of the Company’s stock, dividend yield and risk-free interest rates. As the Company’s common stock has limited historical trading data, the expected stock price volatility is based primarily on the historical volatility of a group of publicly-traded companies that share similar operating metrics and histories. The expected term of the awards represents the period of time that management anticipates awards will be outstanding. As there was insufficient historical data available to ascertain aan ~~forfeiture~~expected ~~rate~~term, the plain vanilla method was applied in calculating the expected term of the options. The risk-free rates for the periods within the contractual life of the options are based on the US Treasury bond rate in effect at the time of the grant for bonds with maturity dates at the expected term of the options. The Company has never paid dividends on its common stock and currently does not intend to do so, and as such, the expected dividend yield is zero. Compensation expense related to stock options was recorded net of ~~estimated~~actual forfeitures~~, which for options remaining at December 31, 2017, the Company expects no additional forfeitures~~.

The table below summarizes assumptions utilized in the Black-Scholes pricing model for the years ended ~~2017~~2018 and ~~2016~~2017:

	December 31,	December 31,
	2017	2016
	2018	2017
Expected option term—years	2.5 0- 3.250	12.5 - 23.525
Risk-free interest rate	12.7558% - 12.9381%	01.9475% - 1.3193%
Expected dividend yield	—	—
Volatility	~~162~~85% - ~~169~~100%	~~142~~162% - ~~214~~169%
Forfeited	—	—

During the years ended December 31, ~~2017~~2018 and ~~2016~~2017, the Company recorded stock-based compensation related to options of $10.47 million, and $1.14 million, respectively. Unvested stock-based option compensation at December 31, ~~2017~~2018 amounted to $0.6 1 million.

71 56

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

NOTE 1110 – PROVISION FOR INCOME TAXES

~~Deferred~~The Company ~~taxes~~has ~~are~~analyzed ~~provided~~filing onpositions ain ~~liability~~all ~~method~~of whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carry-forwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the ~~differences~~federal ~~between the reported amounts of assets~~ and state ~~liabilities~~jurisdictions ~~and~~where ~~their tax basis. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management,~~ it is ~~more~~required ~~likely~~to ~~than~~file ~~not~~income ~~that~~tax returns, ~~some~~as ~~portion~~well oras all ofopen ~~the deferred~~ tax ~~assets~~years ~~will~~in ~~not~~these ~~be realized~~jurisdictions. ~~Deferred~~No uncertain tax ~~assets~~positions ~~and~~have ~~liabilities~~been ~~are~~identified ~~adjusted~~as ~~for the effects~~ of ~~changes~~December ~~in tax laws and rates on the date of enactment.~~31, 2018.

The Company ~~has~~is ~~analyzed~~in ~~filing~~a ~~positions~~position inof ~~all~~cumulative ofreporting ~~the~~losses ~~federal~~for the current and ~~state~~preceding ~~jurisdictions~~reporting ~~where~~periods. itThe volatility of energy prices is ~~required~~not readily determinable by management. At this date, this fact pattern does not allow the Company to ~~file~~project sufficient sources of future taxable income to offset tax ~~returns~~loss carry-forwards and net deferred tax assets. Under these circumstances, asit ~~well~~is management’s asopinion ~~all~~that ~~open~~the realization of these tax attributes ~~years~~does innot ~~these~~reach ~~jurisdictions~~the “more likely than not criteria” under ASC 740, “Income Taxes.” NoAs ~~uncertain~~a result, ~~tax~~the ~~positions~~Company’s ~~have~~deferred ~~been~~tax ~~identified~~assets as of December 31, 2018 and 2017. are subject to a full valuation allowance.

The Company is in a position of cumulative reporting losses for the current and preceding reporting periods. The volatility of energy prices is not readily determinable by management. At this date, this fact pattern does not allow the Company to project sufficient sources of future taxable income to offset tax loss carry-forwards and net Net deferred tax assets. ~~Under~~and ~~these~~liabilities ~~circumstances,~~consist ~~it is management's opinion that the realization~~ of ~~these tax attributes does not reach~~ the ~~"more~~following components ~~likely than not criteria" under ASC 740, "Income Taxes." As a result, the Company's deferred tax assets~~ as of December 31, ~~2017~~2018 and ~~2016 are subject to a full valuation allowance.~~ 2017:

Net deferred tax assets and liabilities consist of the following components as of December 31, 2017 and 2016:

	Year Ended December 31,
	2018	2017
Deferred tax assets - noncurrent:
NOL carryover$	5,385,347	$2,109,423
Stock based compensation	727,631	727,631
Asset retirement obligation	515,333	277,015
Charitable contribution	814	814
Allowance for doubtful accounts	29,321	—
Total deferred tax assets	$6,658,446	$3,114,883

Deferred tax liabilities - current:
Property and equipment	(9,405)	(15,251)
Impairment, intangible drilling costs and other exploration costs capitalized	(1,205,247)	(935,482)
Debt discount - Beneficial conversion feature	(326,321)	(337,518)
Derivative liabilities	(352,165)	—
Total deferred tax liabilities	(1,893,138)	(1,288,251)
Net deferred tax assets	4,765,308	1,826,632
Valuation allowance	(4,765,308)	(1,826,632)
Net deferred tax assets	$—	$—

	Year Ended December 31,
	2017		2016
Deferred tax assets - current:
Exploration costs	$	—	$	—
Deferred tax assets - noncurrent:
NOL carryover		2,109,423		4,287,567
Stock based compensation		727,631		576,808
Asset retirement obligation		277,015		350,333
Charitable contribution		814		—
Total deferred tax assets		3,114,883		5,214,708
Deferred tax liabilities - current:
Property and equipment		(15,251)		(1,990)
Impairment, intangible drilling costs and other exploration costs capitalized		(935,482)		(1,796,102)
Debt discount - Beneficial conversion feature		(337,518)		—
Total deferred tax liabilities		(1,288,251)		(1,798,092)
Net deferred tax assets		1,826,632		3,416,616
Valuation allowance		(1,826,632)		(3,416,616)
Net deferred tax assets	$	—	$	—

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

The income tax provision differs from the amount of income tax determined by applying the US federal tax rate to the pretax loss from continuing operations for the years ended December 31, ~~2017~~ 2018 and ~~2016~~2017 due to the following:

	Year Ended December 31,	~~Year Ended December 31,~~
		2017		2016
	2018	2017
Tax at statutory federal rate	$(3,634,627)	$(3,688,109)	~~(3,688,109)~~	$	~~(1,520,524)~~
Permanent difference	836,035	2,258,353	~~2,258,353~~		~~2,378~~
State taxes, net of federal	(519,052)	(331,474)	~~(331,474)~~		~~(136,847)~~
Depletion, depreciation, amortization and impairment			—		—
Change in valuation allowance	3,499,090	396,256
Change in valuation allowance			396,256		938,026
Effect of the Tax Cuts and Jobs Act	—	918,446
Effect of the Tax Cuts and Jobs Act			918,446
Other	(181,446)	446,528
Other			446,528		716,967
Provision (benefit) for income taxes	$—	$—
Provision (benefit) for income taxes		$	—	$	—

At December 31, ~~2017~~2018, the Company had net operating loss carry-forwards of approximately $821.68 million that may be offset against future taxable income from the years ~~2018~~2019 through ~~2037.~~ 2038.

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

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

ASC 740 requires the recognition of the tax effects of the of the Act for annual periods that include December 22, ~~2017~~2018. At December 31, ~~2017~~ 2018, the Company has made reasonable estimates of the effects on its existing deferred tax balances. The Company has remeasured certain federal deferred tax assets and liabilities based upon the rates at which they are expected to reverse in the future, which is generally 21 percent. The provisional amount recognized related to the remeasurement of its federal deferred tax balance was approximately $01.9 million, which was subject to a valuation allowance at December 31, ~~2017~~2018.

The Company will continue to analyze the Tax Act and future IRS regulations, refine its calculations and gain a more thorough understanding of how ~~individual~~Colorado ~~states~~is ~~are~~ implementing this new law. This further analysis could potentially affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts.

NOTE 1211 – RELATED ~~PARTIES~~PARTY TRANSACTIONS

~~Providence~~ PEO

The table below summarizes related party balances with PEO and its affiliates as of December 31:

	December 31,
	2018	2017
Liabilities
Revenue distribution payable and accrued liabilities	$(2,133,622)	$(589,496)
Initial line of credit	-	(5,000,000)
Secured Credit Facility	(25,000,000)	(5,000,000)
Loan commitment fee – Secured Credit Facility	(1,250,000)	-
Default penalty interest – Secured Credit Facility	(312,500)	-
Make-whole premium Secured Credit Facility	(3,347,874)	-
Break-up fee payable, participation agreement	(580,881)	-
Assets
Accounts receivable – joint interest billing	1,158,213	204,730

Initial Line of Credit

· As At of December 31, ~~2017~~2018, ~~and~~there ~~2016~~was no balance outstanding on the initial line of credit. As of December 31, 2017, the Company had ~~drawn~~an outstanding balance of $5.0 million and had accrued interest in the amount of $5.0.5 million. onThe ~~the~~outstanding ~~initial~~principal ~~line~~balance of ~~credit~~$5.0 million and ~~had~~ accrued interest ~~in the amount~~ of $0.5 million ~~and~~were repaid on February 1, 2018 with proceeds from the closing of the Secured Credit Facility. Interest expense of $0.3 million was recognized related to the note and accretion of unamortized debt discount during the year ended December 31, ~~respectively~~2017.

· On September 23, 2017, the Company issued 250,000 shares of common stock valued at $1.55 to PEO in connection with the execution of a letter agreement and extension of a loan (Notes 6 and 9). The Company recorded interest expense in the amount of $0.1 million as related to the accretion of this debt discount. As of December 31, 2017, the unaccreted portion of the discount amounted to $0.3 million.58

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

Secured Credit Facility

· On February ~~Related~~1, to2018, the ~~execution~~Company ofentered a ~~Letter~~Secured ~~Agreement pursuant to the Initial Funding of a~~ Credit Facility ~~on December 21, 2017~~ (Note 65), ~~the~~pursuant ~~Company drew $5.0 million on the facility resulting in a liability~~ to awhich ~~PEO-affiliated entity in~~ the ~~amount~~Company ofborrowed $~~5.0~~25 million ~~in principal and $21,801 in accrued interest as of December 31, 2017.~~ from PEO ~~beneficially~~affiliated ~~owns approximately 11~~entities.~~7% of the Company’s common stock.~~

~~Operations~~As of December 31, 2018, PEO beneficially owns approximately 11.6% of the Company’s outstanding common stock. As of December 31, 2018, included in accounts payable and accrued liabilities – related party are $1.3 million in underwriting fees payable which were due on February 1, 2019. Interest expense of $7.5 million was recognized related to the note and the accretion of debt discounts during the year ended December 31, 2018.

· In connection Atwith ~~December~~the ~~31,~~execution ~~2017,~~of the ~~Company~~Secured ~~has~~Credit ~~recorded~~Facility, athe Company ~~net~~issued $01.25 million inwarrants ~~Accounts receivable – joint interest billing – related party. This amount relates~~ to ~~amounts~~purchase ~~billed~~common tostock ~~PEO~~of ~~related to its participation in~~ the Company’s ~~operated~~to ~~Shook drilling program and~~ PEO’s ~~ownership~~affiliated ~~interest~~entities in(Note ~~the vertical wells that the Company operates~~8).

· As of At December 31, ~~2017~~2018, the Company was in default with certain provisions of the Secured Credit Facility including the inability of the Company to pay its debts or other obligations as they become due, mechanics liens filed against the Company in Adams County, Colorado and for in occurrence of prohibited new debt related to accounts payable outstanding for greater than 90 days. On February 1, 2019 the Company incurred another event of default by failing to pay the Senior Secured Lender a $1.3 million underwriting fee incurred in connection with the origination of the Secured Credit Facility in February 2018. As a result of the defaults, the Company has ~~recorded~~accrued additional penalty interest of $0.73 million inat ~~drilling~~the penalty ~~advances~~interest –rate ~~related~~of ~~party~~5%, from the date of the first reported default October 1, 2018 through December 31, 2018. ~~This~~The ~~amount~~Company ~~relates~~has accrued $3.4 million related to ~~unapplied~~the ~~cash~~embedded ~~advances~~make-whole ~~received~~premium, which, ~~from~~per ~~PEO~~the Agreement, is triggered upon the event of default. As of December 31, 2018, $29.9 million in ~~connection~~principal, penalty interest, underwriting fee payable and amounts accrued for the make-whole premium are due and payable. On April 2, 2019, the Secured Lenders delivered their formal Notice of Default under the terms of the Secured Credit Facility. From December 31, 2018, until April 2, 2019, the Company was in negotiations with Secured Lenders to resolve the events of default, the negotiations continue. Accordingly, the Company’s ~~operated~~did ~~Shook~~not retroactively ~~drilling~~accelerate ~~program~~the accretion of debt discounts recorded in connection with the Secured Credit Facility.

Operations/PEO

At December 31, 2018, the Company has recorded $1.1 million in Accounts receivable – joint interest billing – related party. This amount relates to amounts billed and unbilled to PEO related to its participation in the Company’s operated Shook drilling program and PEO’s ownership interest in the vertical wells that the Company operates.

At December 31, 2018, the Company has recorded $1.8 million in royalties and revenue distribution payable to a related party. This amount relates to undistributed revenue from Company’s operated Shook pad and vertical wells.

At December 31, 2018, the Company has recorded $0.6 million in abandonment costs payable, related to the Company’s election not to participate in a participation agreement related to the acquisition of leasehold acreage (Note 4).

Convertible Notes

In January 2017, the Company sold ~~Series~~10% AConvertible Notes to a total of four employees and directors who collectively purchased ~~Series~~10% Convertible A Notes in the aggregate principal amount of $0.2 million (Note 65), on the same terms and conditions as the other purchasers.

On October 16, 2017, ten of the Company’s officers and directors converted ~~Series~~10% AConvertible Notes in the aggregate principal amount of $0.7 million and accrued interest of $20,670 into 691,516 shares of common stock at $1.10 per share. (~~Notes~~Note ~~6 and 9~~5) .

~~Ten~~As of ~~employees~~December 31, ~~officers~~2018, and ~~directors~~2017, of the ~~Company~~principal ~~received~~balance ~~cash interest payments for interest~~ of ~~$0.1~~the ~~million~~10% Convertible ~~related~~Notes payable to ~~Series~~employees A and ~~Series~~officers Bamounted ~~notes~~to $80,000 ~~during~~and ~~the year ended December 31~~$80,000 ~~2017~~respectively.

Employees, officers and directors of the Company received cash interest payments $8,000 and $0.1 million related to 10% Convertible Notes during the years ended December 31, 2018 and 2017.

Series B Convertible Notes

In September and October 2017, the Company sold Series B Convertible Notes to ten of the Company’s officers and directors who collectively purchased $0.6 million in aggregate principal amount (Note 65), on the same terms and conditions as the other purchasers, with the exception that the Company did not pay commissions on these sales. Employees, officers and directors received cash interest payments of $0.1 million and $0.1 million during the years ended December 31, 2018 and 2017. As of December 31, 2018 and 2017, the outstanding principal balance of the Series B Convertible Notes payable to employees and directors amounted to $0.6 million and $0.6 million respectively.

74 59

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

NOTE 1312 – COMMITMENTS AND CONTINGENCIES

Operating ~~Leases and Agreements~~ Lease

The Company leases its office facilities under a four-year non-cancelable operating lease agreement expiring in March 2021. The following is a schedule by year of future minimum rental payments required under the operating lease agreement:

Year ending December 31,	Amount	~~Amount~~
2018		$	129,738
2019	$133,698
2019			133,698
2020	137,658
2020			137,658
2021	34,662
2021			34,662
Total	$306,018
2022			—
Total		$	435,756

Lease expense totaled $0.1 million and $~~34,651~~0.1 for the years ended December 31, ~~2017~~2018 and December 31, ~~2016~~2017, respectively.

~~Employment Agreements~~ NOTE 13 – SUBSEQUENT EVENTS

~~2017~~On February 27, 2019, the Company completed the sale of nearly all its non-operated oil and natural gas assets. The assets sold include all non-operated horizontal wells in which the Company had an interest, as well as the leases on which those wells are located, oil, natural gas and other hydrocarbons produced from the leases on or after the effective date of the sale, related equipment, machinery, fixtures and other personal property, surface rights and contracts. The effective date of the sale was January 1, 2019. 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 have been applied the Secured Lenders against amounts allegedly owed under the Secured Credit Facility. See Note 4 for description of the impact of this sale on the December 31, 2018 consolidated financial statements.

On March ~~April 1~~15, ~~2017~~2019, ~~the~~at ~~Company entered an employment agreement with its Manager of Production and Completion Operations. The agreement provides for~~ a ~~base~~special ~~salary of $130~~meeting,~~000~~ ~~per~~the ~~year,~~shareholders anapproved ~~initial term expiring on March 31, 2018 with~~ an amendment ~~automatic~~to ~~renewal~~the ~~for~~Company’s ~~successive~~Articles ~~one-year periods unless terminated in accordance with its terms, and provisions for termination and payment~~ of ~~severance~~Incorporation (“Amendment”) ~~under~~to ~~various~~increase ~~circumstances. In connection with~~ the ~~execution~~authorized ofcommon ~~the~~stock from ~~agreement~~100, ~~the employee was granted 50~~000,000 shares ~~of restricted stock and an option~~ to ~~purchase up to~~ 200,000,000 shares. ofThe ~~common~~Amendment ~~stock~~was effective aton anMarch ~~exercise~~20, ~~price~~2019 ofupon ~~$1.83~~filing ~~per~~with ~~share.~~the Colorado Secretary of State.

On March ~~April 1~~22, ~~2017~~2019, ~~the~~three ~~Company~~members ~~entered~~of ~~into~~the anBoard ~~employment~~of ~~agreement~~Directors ~~with~~provided notice ~~its~~of ~~Executive~~their ~~Vice~~resignation ~~President~~from ~~for~~the ~~Capital Markets and Investor Relations~~Board. The ~~agreement~~resignations ~~provides~~of Michael ~~for~~Allen, aJoseph ~~base~~Drysdale ~~salary~~and ofCullen ~~$156,000~~Schaar ~~per~~were ~~year,~~effective immediately. anNone ~~initial~~of ~~term~~the ~~expiring~~resignations onexpressed ~~December~~any ~~31,~~disagreement with ~~2018~~either ~~with~~the anCompany ~~automatic~~or ~~renewal~~its ~~for~~Board ~~successive~~of ~~one-year~~Directors. ~~periods~~At ~~unless~~this ~~terminated~~time, the inBoard ~~accordance~~of ~~with~~Directors ~~its~~plans ~~terms,~~to ~~and~~continue ~~provisions~~its ~~for~~work ~~termination~~with ~~and~~a ~~payment~~reduced membership of ~~severance~~six ~~under various circumstances~~directors. In

~~connection~~On ~~with~~April ~~the execution of the agreement~~2, 2019, the ~~employee~~Secured ~~was~~Lenders ~~granted~~delivered ~~66,700~~their ~~shares~~formal Notice of ~~restricted~~Default ~~stock and~~ under the ~~vesting~~terms of ~~200,000~~the ~~previously~~Secured ~~issued~~Credit ~~stock options were accelerated~~Facility.

On NOTE ~~June~~14 1,– ~~2017,~~UNAUDITED ~~the~~CRUDE ~~Company~~OIL ~~entered~~AND ~~into~~NATURAL anGAS employment agreement with its Senior Landman. The agreement provides for a base salary of $130,000 per year, an initial term expiring on May 31, 2018 with an automatic renewal for successive one-month periods unless terminated in accordance with its terms, and provisions for termination. In connection with the execution of the agreement, the employee was granted 50,000 shares of restricted stock and an option to purchase 200,000 shares of common stock at $1.89 per share.RESERVES INFORMATION

OnThe ~~June~~estimate 1of reserves at December 31, ~~2017~~2018, presented below, were prepared by the ~~Company~~independent ~~entered~~engineering ~~into~~firm Cawley, anGillespie ~~employment~~& ~~agreement~~Associates ~~with~~Inc. ~~its~~All ~~Chief~~reserves ~~Financial~~are ~~Officer~~located within the DJ Basin. ~~The~~Proved ~~agreement~~oil, ~~provides~~natural ~~for~~gas aand ~~base~~NGL ~~salary~~reserves are the estimated quantities of ~~$150~~oil,~~000~~ ~~per~~natural ~~year,~~gas anand ~~initial~~NGLs ~~term~~which geological ~~expiring~~and onengineering ~~December~~data 31demonstrate, ~~2018~~ with anreasonable certainty, ~~automatic~~to ~~renewal~~be ~~for~~recoverable ~~successive~~in ~~one-year~~future ~~periods~~years ~~unless~~from ~~terminated~~known inreservoirs under ~~accordance~~economic ~~with~~and ~~its~~operating ~~terms~~conditions (i.e., prices and ~~provisions~~costs) ~~for~~existing ~~termination~~at the time the estimate is made. Proved developed oil, natural gas and ~~payment~~NGL ofreserves ~~severance~~are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating ~~various~~methods ~~circumstances.~~being Inutilized ~~connection~~at ~~with~~the time the ~~execution~~estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of ~~the~~new ~~agreement,~~discoveries ~~the~~and ~~employee~~undeveloped locations ~~was~~are ~~granted~~more ~~50,000~~imprecise ~~shares~~than estimates of ~~restricted~~established ~~stock~~proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

75 60

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

2016

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

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

NOTE 14 – REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS

In connection with the preparation of its financial statements for the quarter ended March 31, 2017, the Company identified an error related to the manner in which it accounted for the fair value of convertible promissory notes and warrants issued in a private placement during December 2016 (Note 6). Specifically, the Company was required to apply the guidance of FASB ASC 470, and more specifically, ASC 470 20 25 2 and ASC 470 20 25 3. On the balance sheet at December 31, 2016, the Company recorded the face value of convertible notes payable issued in connection with the private placement under liabilities, discounted by (i) the value of the original issue discount and (ii) the value of the warrants issued to the placement agent. The Company did not, however, discount the value of the convertible notes by the fair value of the warrants issued to individual investors.

In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, the Company evaluated the error and determined that the related impact was not material to the Company’s results of operations or financial position for any prior annual or interim period. Accordingly, the Company corrected these errors for the year ended December 31, 2016 by revising the financial statements beginning in the period ended March 31, 2017. Periods not presented herein will be revised, as applicable, in future filings.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

The following tables present the revisions to the balance sheet as of, and the statement of operations for the year ended, December 31, 2016:

Balance Sheet

	As of December 31, 2016
	As Reported		Adjustments		As Revised
Convertible notes payable, net	$	814,989	$	(809,681)	$	5,308
Total Liabilities	$	17,260,318	$	(809,681)	$	16,450,637
Shareholders’ Equity
Additional paid-in capital	$	10,593,324	$	811,901	$	11,405,225
Accumulated deficit		(9,848,822)		(2,220)		(9,851,042)
Total Shareholders’ Equity	$	766,466	$	809,681	$	1,576,147
Total Liabilities and Shareholders’ Equity	$	18,026,784	$	—	$	18,026,784

Statement of Operations

	Year Ended
	December 31, 2016
Net (loss), as reported	$	(4,479,052)
Adjustments:
Previously reported accretion of debt discount (conversion feature and warrants) (interest expense)		2,529
Corrected accretion of debt discount (interest expense)		4,749
Total adjustment		(2,220)
Net (loss), as revised	$	(4,481,272)
Net (loss) per share, as reported	$	(0.21)
Net (loss) per share, as revised	$	(0.21)

NOTE 15 – RESTATEMENT OF PRIOR PERIOD CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In connection with the preparation of its consolidated financial statements for the year ended December 31, 2017, the Company identified a mathematical error related to the calculation of the depletion, depreciation and amortization of oil and gas properties as recorded during the periods ended March 31, 2017, June 30, 2017 and September 30, 2017. The issue resulted from the application of an incorrect conversion factor when evaluating NGL volumes. The impact of the correction of this issue has been recorded during the quarter ended December 31, 2017.

In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, the Company evaluated the error and determined that the related impact was not material to the Company’s results of operations or financial position for any prior interim period. Accordingly, the Company has corrected these errors in total for the year ended December 31, 2017 by revising the consolidated financial statements. Periods presented herein will be revised, as applicable, in future filings.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

The following tables present the restatements to the consolidated balance sheets as of, and the consolidated statements of operations for the periods presented:

Consolidated Balance Sheets

	As of March 31, 2017
	As Reported		Adjustments		As Restated
Crude oil and natural gas properties, net:
Accumulated depletion, depreciation and amortization	$	(1,229,486)	$	115,254	$	(1,114,232)
Crude oil and natural gas properties, net	$	20,510,001	$	115,254	$	20,625,255
Total assets	$	28,739,336	$	115,254	$	28,854,590
Shareholders’ equity:
Accumulated deficit	$	(11,990,181)	$	115,254	$	(11,874,927)
Total shareholders’ equity	$	6,756,017	$	115,254	$	6,871,271
Total liabilities and shareholders’ equity	$	28,739,336	$	115,254	$	28,854,590
	As of June 30, 2017
	As Reported		Adjustments		As Restated
Crude oil and natural gas properties, net:
Accumulated depletion, depreciation and amortization	$	(2,765,660)	$	549,096	$	(2,216,564)
Crude oil and natural gas properties, net	$	24,958,027	$	549,096	$	25,507,123
Total assets	$	35,682,868	$	549,096	$	36,231,964
Shareholders’ equity:
Accumulated deficit	$	(12,723,650)	$	549,096	$	(12,174,554)
Total shareholders’ equity	$	7,532,947	$	549,096	$	8,082,043
Total liabilities and shareholders’ equity	$	35,682,868	$	549,096	$	36,231,964
	As of September 30, 2017
	As Reported		Adjustments		As Restated
Crude oil and natural gas properties, net:
Accumulated depletion, depreciation and amortization	$	(3,918,935)	$	865,697	$	(3,053,238)
Crude oil and natural gas properties, net	$	28,698,193	$	865,697	$	29,563,890
Total assets	$	32,918,686	$	865,697	$	33,784,383
Shareholders’ equity:
Accumulated deficit	$	(14,754,722)	$	865,697	$	(13,889,025)
Total shareholders’ equity	$	6,343,080	$	865,697	$	7,208,777
Total liabilities and shareholders’ equity	$	32,918,686	$	865,697	$	33,784,383

Consolidated Statements of Operations

	Three months ended		Three months ended		Six months ended		Three months ended		Nine months ended
	March 31, 2017		June 30, 2017		June 30, 2017		September 30, 2017		September 30, 2017
Net (loss), as reported	$	(2,139,139)	$	(733,469)	$	(2,872,608)	$	(2,031,072)	$	(4,903,680)
Adjustments:
Previously reported depletion, depreciation and amortization	$	(446,166)	$	(1,536,174)	$	(1,982,341)	$	(1,153,273)	$	(3,135,614)
Total adjustment		115,254		433,842		549,096		316,600		865,696

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

Corrected depletion, depreciation and amortization		(330,912)		(1,102,332)		(1,433,245)		(836,673)		(2,269,918)
Net (loss), as restated	$	(2,023,885)	$	(299,627)	$	(2,323,512)	$	(1,714,472)	$	(4,037,984)
Net (loss) per share, as reported	$	(0.10)	$	(0.03)	$	(0.13)	$	(0.09)	$	(0.22)
Net (loss) per share, as restated	$	(0.09)	$	(0.01)	$	(0.10)	$	(0.08)	$	(0.18)

NOTE 16 – SUBSEQUENT EVENTS

On February 1, 2018, the Company entered into a Secured Term Credit Agreement (“Credit Agreement”) with Providence Wattenberg, LP and 5NR Wattenberg, LLC (the “Secured Lenders”). Each of Providence and 5NR are affiliates of the Lenders under the Letter Agreement.

Under the Credit Agreement, the Secured Lenders agreed to loan the Company a total of $25.0 million (the “Loan”), including the $5.0 million previously advanced pursuant to the Letter Agreement. Interest on the outstanding principal balance of the Loan accrues at the rate of 14% per year plus the greater of three-month LIBOR or 1%, but in no event to exceed 17%. Interest payments are due monthly beginning March 1, 2018. Repayment of the Loan is secured by a lien on all of the Company’s assets, which is equal in priority to the lien securing the remaining indebtedness owed to PEP III. All principal and accrued interest under the Credit Agreement is due February 1, 2020 (“Maturity Date”).

At any time, the Lenders may convert 20% of the outstanding principal of the Loan into common stock of the Company at a price of $1.15 per share and the remaining principal at a price of $1.55 per share. The Company also granted to the Lenders:

 a warrant entitling the Lenders to purchase in the aggregate 1,500,000 shares of common stock at a price of $0.01 per share, exercisable until the Maturity Date; and

· an option to purchase up to 50% of any securities offered by the Company in any private or public offering until December 31, 2018, and 25% of any securities offered thereafter; and

 an option to purchase up to $25.0 million of the Company’s common stock at a 10% discount from the 30-day volume-weighted average trading price of the common stock at the time the option is exercised, but in no event less than $1.85 per share, which the option will become exercisable on the Maturity Date and expire on February 1, 2021; and

 registration rights in connection with the common stock that may be issued upon exercise of the foregoing rights.

The Company also agreed to certain affirmative and negative covenants in connection with the Loan, including the obligation to appoint up to three persons to the Company’s Board of Directors, two of whom would be designated by Providence and one by 5NR, and at least one of whom shall qualify as independent under the rules of the NYSE American.

NOTE 17 – UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION

The reserves at December 31, 2017, presented below, were prepared by the independent engineering firm Cawley, Gillespie & Associates Inc. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine the proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of the Company’s fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

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

		Natural		~~Natural~~
	Oil	~~Oil~~Gas	NGL’s	~~Gas~~Total	~~NGL’s~~	~~Total~~
	(Bbls)	(~~Bbls~~Mcf)	(Bbls)	(~~Mcf~~BOE)	~~(Bbls)~~	~~(BOE)~~
Proved Reserves:
Balance as of December 31, 2016	2,761,204	11,492,855	1,631,188	6,307,868
Balance as of December 31, 2014		159		—	—	159
Revisions of previous estimates	(388,211)	292,477	38,668	(300,797)
Revisions of previous estimates		(122)		—	—	(122)
Extensions and discoveries	839,738	4,183,757	631,149	2,168,180
Extensions and discoveries		—		—	—	—
Sales of reserves in place	—	—	—	—
Sales of reserves in place		—		—	—	—
Improved recovery	—	—	—	—
Improved recovery		—		—	—	—
Purchase of reserves	—	—	—	—
Purchase of reserves		—		—	—	—
Production	(188,529)	(549,846)	(50,111)	(330,281)
Production		(37)		—	—	(37)
Balance as of December 31, 2017	3,024,202	15,419,243	2,250,894	7,844,970
Balance as of December 31, 2015		—		—	—	—
Revisions of previous estimates	569,936	3,444,889	(877,172)	266,912
Revisions of previous estimates		—		—	—	—
Extensions and discoveries	36,858	244,043	—	77,532
Extensions and discoveries		2,710,437		10,498,397	1,570,454	6,030,624
Sales of reserves in place	(150,554)	(820,564)	(97,396)	(384,710)
Sales of reserves in place		—		—	—	—
Improved recovery	—	—	—	—
Improved recovery		—		—	—	—
Purchase of reserves	678	18,533	222	3,988
Purchase of reserves		55,669		1,020,516	62,244	287,999
Production	(287,984)	(773,396)	(66,986)	(483,870)
Production		(4,902)		(26,058)	(1,510)	(10,755)
Balance as of December 31, 2018	3,193,136	17,532,748	1,209,562	7,324,822
Balance as of December 31, 2016		2,761,204		11,492,855	1,631,188	6,307,868
Proved Developed Reserves, included above
Revisions of previous estimates		(388,211)		292,477	38,668	(300,797)
Balance as of December 31, 2016	260,284	1,788,895	181,655	740,088
Extensions and discoveries		839,738		4,183,757	631,149	2,168,180
Balance as of December 31, 2017	521,354	3,752,330	387,430	1,534,172
Sales of reserves in place		—		—	—	—
Balance as of December 31, 2018	1,187,985	6,300,116	672,725	2,910,729
Improved recovery		—		—	—	—
Proved Undeveloped Reserves, included above
Purchase of reserves		—		—	—	—
Balance as of December 31, 2016	2,500,920	9,703,960	1,449,533	5,567,780
Production		(188,529)		(549,846)	(50,111)	(330,281)
Balance as of December 31, 2017	2,502,847	11,666,911	1,863,465	6,310,797
Balance as of December 31, 2017		3,024,202		15,419,243	2,250,894	7,844,970
Balance as of December 31, 2018	2,005,151	11,232,632	536,837	4,414,093
Proved Developed Reserves, included above
Balance as of December 31, 2015		—		—	—	—
Balance as of December 31, 2016		260,284		1,788,895	181,655	740,088
Balance as of December 31, 2017		521,354		3,752,330	387,430	1,534,172
Proved Undeveloped Reserves, included above
Balance as of December 31, 2015		—		—	—	—
Balance as of December 31, 2016		2,500,920		9,703,960	1,449,533	5,567,780
Balance as of December 31, 2017		2,502,847		11,666,911	1,863,465	6,310,797

The values for the ~~2017~~2018 oil, natural gas and NGL reserves are based on the twelve-month arithmetic average of the first day of the month prices for the period from January through December 31, ~~2017~~2018. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months was $5165.3456 per barrel (West Texas Intermediate price) for crude oil and NGLs and $23.9810 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, ~~2017~~2018 was $4559.0323 per barrel for oil, $13.7164 per Mcf for natural gas and $2024.4228 per barrel for NGLs.

81 61

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

The values for the 2017 oil, natural gas and NGL reserves are based on the twelve-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months was $51.34 per barrel (West Texas Intermediate price) for crude oil and NGLs and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2017 was $45.03 per barrel for oil, $1.71 per Mcf for natural gas and $20.42 per barrel for NGLs.

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

~~The~~For the year ended December 31, 2018, the Company ~~did~~reported ~~not~~extensions and ~~assign~~discoveries aof ~~value~~77,532 toBOE ~~its~~primarily ~~proved~~from the recognition of reserves asassociated with new wells drilled by its working interest partners. There were also revisions to previous estimates to reflect net upward revisions of ~~December~~266,912 31BOE, ~~2015~~primarily ~~due~~from tothe improved ~~immaterial~~economics ~~quantity~~provided ~~estimates~~by ~~and~~the increased hydrocarbon pricing, somewhat offset by a ~~volatile~~negative ~~price~~revision ~~environment.~~in NGL quantities as certain previous engineering estimates were adjusted for revised production information received during 2018.

For the year ended December 31, 2017, the Company reported extensions and discoveries of 2,168,180 BOE primarily as result of the conversion of 18 PUD locations in the Todd Creek Farms prospect area during 2017 coupled with the addition of new PUD locations due to economic field extensions adjacent to Company leases. The Company reported downward revisions of previous estimates of 300,797 BOE primarily related to the removal of uneconomic PUD locations.

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

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

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

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

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) the estimated future cash flows are compiled by applying the twelve-month average of the first-day-of-the-month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves; (3) the future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; and (4) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value

82 62

Table of Contents

PetroShare Corp.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ~~2017~~2018 and ~~2016~~ 2017

would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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

	For the years ended December 31,
	2018	2017	2016

Future cash inflows	$282,293	$208,459	$148,596
Future cash outflows:
Production cost

Filing Compare · PetroShare Corp.