10-K 1 a10-ksci20181231.htm 10-K Document


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

FORM 10-K


(Mark One)
 
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

OR

 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to ___________________

Commission file number:  001-35245

logovrt4ca16.jpg

SRC ENERGY INC.
(Exact name of registrant as specified in its charter)

COLORADO
20-2835920
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

1675 Broadway, Suite 2600, Denver, CO
80202
(Address of principal executive offices) 
(Zip Code)
 
Registrant's telephone number, including area code: (720) 616-4300

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
 
Name of each exchange on which registered
Common Stock
 
NYSE AMERICAN

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

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






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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an 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  ý
Accelerated filer  o
 
 
Non-accelerated filer  o  
Smaller reporting company  o
 
 
 
Emerging growth company  o

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

The aggregate market value of the voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 30, 2018, was approximately $2.0 billion.  Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.

As of February 14, 2019, the Registrant had 243,256,234 issued and outstanding shares of common stock.

DOCUMENTS INCORPORATED BY REFERENCE
We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Meeting of Stockholders.






SRC ENERGY INC.

Index

 
 
 
Page
PART I
 
 
Item 1.
Business
 
Item 1A.
Risk Factors
 
Item 1B.
Unresolved Staff Comments
 
Item 2.
Properties
 
Item 3.
Legal Proceeding
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
PART II
 
 
 
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 
Item 6.
Selected Financial Data
 
Item 7.
Management's Discussion and Analysis of Financial Condition and Result of Operations
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risks
 
Item 8.
Financial Statements and Supplementary Data
 
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
Item 9A.
Controls and Procedures
 
Item 9B.
Other Information
 
 
 
 
 
PART III
 
 
Item 10.
Directors, Executive Officers, and Corporate Governance
 
Item 11.
Executive Compensation
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
Item 13.
Certain Relationships and Related Transactions and Director Independence
 
Item 14.
Principal Accounting Fees and Services
 
 
 
 
 
PART IV
 
 
 
Item 15.
Exhibits, Financial Statement Schedules
 
 
 
 
 
SIGNATURES
 
 
 
 
GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS
 






PART I

Glossary of Units of Measurements and Industry Terms

Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report.

Cautionary Statement Concerning Forward-Looking Statements

This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should," "likely," or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, and future production relative to volume commitments.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Important factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:
declines in oil and natural gas prices;
the effects of, changes in and the costs of compliance with federal, state, and local regulations applicable to our business;
operating hazards that adversely affect our ability to conduct business;
uncertainties in the estimates of proved reserves;
the availability and capacity of gathering and processing systems, pipelines, and other midstream infrastructure for our production;
the effect of seasonal weather conditions and wildlife and plant species restrictions on our operations;
our ability to fund, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable;
our ability to obtain adequate financing;
the effect of local and regional factors on oil and natural gas prices;
incurrence of ceiling test write-downs;
our inability to control operations on properties that we do not operate;
the strength and financial resources of our competitors;
our ability to successfully identify, execute, and integrate acquisitions;
our ability to market our production;
the effect of environmental liabilities;
changes in U.S. tax laws;
our ability to satisfy our contractual obligations and commitments;
the amount of our indebtedness and our ability to maintain compliance with debt covenants;
the effectiveness of our disclosure controls and our internal controls over financial reporting;
the geographic concentration of our principal properties;
our ability to protect critical data and technology systems;
the availability of water for use in our operations; and
the risks and uncertainties described and referenced in "Risk Factors."

Note Regarding Change in Reserves and Production Volumes

As of January 1, 2017, our natural gas processing agreements with DCP Midstream, L.P. ("DCP Midstream") had been modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 and 2018 with prior periods.


1



Note Regarding Change in Fiscal Year

In February 2016, the Company changed its fiscal year-end to December 31 from August 31. Certain information in this report is presented as of and for the fiscal years ended August 31, 2015 and 2014.

2



ITEM 1.
BUSINESS

Overview

SRC Energy Inc. ("we," "us," "our," "SRC," or the "Company"), a Colorado corporation formed in 2005, is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be 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, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure, long reserve life, and multiple service providers.

Our oil and natural gas activities are focused in the Wattenberg Field, in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell formation as well as the three benches of the Niobrara formation, which are all characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 82% of our proved developed reserves and anticipate operating a majority of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.

During the year ended December 31, 2018, we continued to execute our plans for growth through development of our existing oil and gas properties and strategic acquisitions of leasehold and producing properties. The Company's consolidated core position in the Wattenberg Field is approximately 86,200 net acres.   This contiguous footprint creates further opportunities to drive operational efficiencies with over 1,600 identified gross well locations with predominantly mid- and long-lateral design.

As of December 31, 2018, we are the operator of 1,030 gross (985 net) producing wells, of which 406 gross (384 net) are Codell or Niobrara horizontal wells. The Company has also participated as a non-operator in 497 gross (115 net) producing wells. As we develop our acreage through horizontal drilling, we have an active program for plugging and reclaiming the vast majority of the operated vertical wellbores. During the year ended December 31, 2018, we reclaimed 203 wells and returned the associated surface acreage to the property owners.

For the year ended December 31, 2018, 2017 and 2016, our average net daily production was 50,543 BOED, 34,194 BOED, and 11,670 BOED, respectively. As of December 31, 2018, over 92% of our daily operated production was from horizontal wells.

Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves, and cash flow through development, exploitation, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:

Concentrate on our existing core area in the D-J Basin, where we have significant operating experience.  All of our current wells and our proved undeveloped acreage are located in the Wattenberg Field, and we seek to acquire developed and undeveloped oil and gas properties in the same contiguous area. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.

Maximize shareholder value and maintain financial flexibility by limiting the need for external capital.  We seek to align our capital expenditures with our cash flows by adjusting our operating activities depending on commodity prices and infrastructure capacity. We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which allows sufficient financial capacity to pursue strategic acquisitions.

Develop and exploit existing oil and gas properties.  A principal growth strategy has been to develop and exploit our properties to add reserves.  In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the safest and most efficient and economical way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells.  There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.


3



Use the latest technology to maximize returns and improve hydrocarbon recovery.  Our development objective for individual well optimization is to primarily drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs, coupled with production results, to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

Control and reduce emissions from our production facilities. We place high importance on achieving compliance with all applicable air quality rules and regulations and further reducing emissions continues to be a top priority. To minimize emissions, we employ best management practices such as using available direct pipeline take-away access and pneumatic actuated instrument devices and by working with suppliers to deploy diesel engines that meet the U.S. Environmental Protection Agency Tier 4 standard. We control emissions and minimize flaring of gas during the drilling and completion process. We use additional vapor recovery equipment during production for further emissions reduction. We continue to evolve the design of our production facilities to produce oil and natural gas with fewer air emissions, including those emissions for which there are public health standards (e.g. ozone and particulate matter).

Operate in a safe manner and work in partnership with our surrounding stakeholders.  While our scale of operations has increased significantly, we continue to focus on maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to utilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities. Such practices include building our infrastructure out ahead of operations to minimize traffic, working with our service providers to minimize dust and lighting issues, and constructing sound walls to minimize noise.  We value our positive relationship with local governing entities and the communities in which we operate and seek to continually achieve a status of operator of choice.

Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled.  This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit. Our high degree of operational control, as well as our focus on operating efficiencies that provide short return on investment cycle times, is central to our operating strategy.

Acquire and develop assets near established infrastructure. We target acquisitions of contiguous acreage to focus our development plans on areas where technically-capable, financially-stable midstream companies have existing assets and plans for additional investment. We work collaboratively with these companies to proactively identify expansion opportunities that complement our development plans enabling the use of gathering pipelines which reduces truck traffic.
      
Competitive Strengths
 
We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:

Core acreage position in the Wattenberg Field. Wells in our core properties in the Wattenberg Field generally exhibit high liquids content, and those properties are generally prospective for Niobrara A, B, and C bench and Codell development. We believe that these factors lead to a high success rate and attractive EURs per acres of leasehold, per unit capital and operating costs, and rates of return. Increased well density within the Codell and Niobrara formations, as well as our acquisition efforts and organic leasing efforts within the core Wattenberg Field, have added to our multi-year drilling inventory. Our core position is situated in an area where there is extensive infrastructure that continues to be expanded.

Financial flexibility. Our capital structure, along with our high degree of operational control, continues to provide us with significant financial flexibility. Our modest debt level has enabled us to make capital decisions with limited restrictions imposed by debt covenants, lender oversight, and/or mandatory repayment schedules. Additionally, as the operator of substantially all of our anticipated future drilling locations per our December 31, 2018 reserve report, we control the timing and selection of drilling locations as well as completion schedules. This allows us to modify our capital spending program depending on financial resources, leasehold requirements, infrastructure capacity, and market conditions.

Management experience.  Members of our key management team possess multiple years of experience in oil and gas exploration and production in multiple resource plays including the Wattenberg Field.
 

4



Balanced oil and natural gas reserves and production.  At December 31, 2018, approximately 77% of our total gross revenues were oil and condensate, 12% were natural gas, and 11% were natural gas liquids. We believe that this balanced commodity mix will provide diversification of sources of cash flow.

Focus on efficiency and cost control. We have continued to demonstrate our ability to drill wells in a safe and cost-efficient way and to successfully integrate acquired assets without incurring significant increases in overhead.

Safe workplace and reduced impact on surrounding areas. Our employees and contractors are important to us, so we strive to maintain a safety-first approach in our operations. Likewise, we seek to incorporate current technologies to meet regulatory requirements while reducing our impact on the environment and neighboring communities. Toward this effort, modern drilling and completion techniques allow us to concentrate our operations on a reduced number of surface locations. As the new locations are developed, we have decreased the overall number of wells by plugging and reclaiming older vertical wells, allowing us to return those sites to surface owners.

Properties

As of December 31, 2018, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott Company, L.P. ("Ryder Scott"), an independent reserve engineering firm, were 88.0 MMBbls of oil and condensate, 771.9 Bcf of natural gas, and 89.1 MMBbls of natural gas liquids. As of December 31, 2018, we had approximately 95,200 gross and 86,200 net acres under lease in the Wattenberg Field.

We currently operate over 82% of our proved producing reserves, and all of our drilling and completion expenditures during the year ended December 31, 2018 were focused on the Wattenberg Field. All of our drilling and completion expenditures for the 2019 calendar year are anticipated to be focused on the Wattenberg Field. A high degree of operational and capital control gives us both operational focus and development flexibility to maximize returns on our leasehold position.

2018 Significant Developments

Acquisitions and Trades

In September 2018, the Company completed the second closing contemplated by the purchase and sale agreement (the "GCII Agreement") relating to our 2017 acquisition of approximately 30,200 net acres in the Greeley-Crescent development area in Weld County, Colorado (the "GCII Acquisition"). At the second closing, we acquired the operated vertical and horizontal wells. The effective date for this second closing was September 1, 2018. The purchase and sale agreement for the GCII Acquisition was signed in November 2017, and the first closing was completed in December 2017.The total purchase price for the second closing was $96.9 million, composed of cash of $64.2 million and assumed liabilities of $32.7 million. The assumed liabilities included $25.8 million for asset retirement obligations.

In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for $37.2 million in cash and the assumption of certain liabilities, for a total purchase price of $37.5 million. The acreage increased our working interest in existing operations and planned wells.

In September and November 2018, we completed two trades with other parties totaling approximately 4,700 net acres. These transactions further enhance the contiguous nature of the Company's acreage position.

Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate (sometimes referred to as the "Revolver") to provide us with liquidity that can be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2018, the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of $500 million, and a borrowing base limitation of $650 million. The borrowing base is subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including substantially all of our producing wells and developed oil and gas leases, and bears a variable interest rate on borrowings with the effective rate varying with utilization.


5



Drilling and Completion Operations

During the periods presented below, we drilled or participated in the drilling of wells that reached productive status in each respective period.  During the year ended December 31, 2018, we turned 95 gross operated wells to sales.  None of the wells are classified as exploratory, and all of the gross operated wells are classified as development. 
    
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive:
 
 
 
 
 
 
 
 
 
 
 
Oil
152*

 
102

 
172**

 
112

 
21***

 
18

Gas

 

 

 

 

 

Nonproductive

 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
Exploratory Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive:
 
 
 
 
 
 
 
 
 
 
 
Oil

 

 

 

 
6

 
5

Gas

 

 

 

 

 

Nonproductive

 

 

 

 

 

*    Includes 57 gross (13 net) productive wells which we participated in on a non-operated basis.
**    Includes 63 gross (11 net) productive wells which we participated in on a non-operated basis.
***    Includes 3 gross (0.42 net) productive wells which we participated in on a non-operated basis.

All of the wells in the table above are located in the Wattenberg Field of the D-J Basin. As of December 31, 2018, we were the operator of 50 gross (44 net) wells in progress that were not included in the above well counts.

Production Data
          
The following table shows our net production of oil and natural gas, average sales prices, and average production costs for the periods presented:
 
Year Ended December 31,
 
2018
 
2017
 
2016
Production:
 
 
 
 
 
Oil (MBbls)
8,392

 
5,824

 
2,257

Natural Gas (MMcf)
37,123

 
24,834

 
8,472

NGLs (MBbls)
3,869

 
2,518

 

MBOE
18,448

 
12,481

 
4,271

BOED
50,543

 
34,194

 
11,670

 
 
 
 
 
 
Average sales price:
 
 
 
 
 
Oil ($/Bbl) *
$
57.79

 
$
44.35

 
$
34.43

Natural Gas ($/Mcf) *
$
2.09

 
$
2.33

 
$
2.44

NGLs ($/MBbls)
$
19.12

 
$
17.10

 
$

BOE *
$
34.50

 
$
28.79

 
$
25.09

 
 
 
 
 
 
Average lease operating expenses ("LOE") per BOE
$
2.35

 
$
1.56

 
$
4.67

* Adjusted to include the effect of transportation and gathering expenses.


6



Major Customers

We sell our crude oil, natural gas, and NGLs to various purchasers under multiple contractual arrangements. For crude oil, we have several arrangements, ranging from month-to-month to long-term commitments. Notably, we have secured contracts with oil purchasers who transport oil via pipelines. Under these contracts, we entered into delivery commitments covering a portion of our anticipated future production over the next two to three years. Our natural gas is sold under contracts with two midstream gas gathering and processing companies. We are working with our midstream providers in an effort to expand available gas gathering and processing and oil takeaway capacity. See further discussion in Note 16 to our consolidated financial statements. For the year ended December 31, 2018, five of our customers account for more than 10% of our revenues. Given the liquidity in the market, we believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling to alternative purchasers.

Oil and Gas Properties, Wells, Operations, and Acreage
    
We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:
royalties and other burdens and obligations, expressed or implied, under oil and gas leases;
overriding royalties and other burdens created by us or our predecessors in title;
a variety of contractual obligations arising under operating agreements, joint use agreements, production sales contracts, and other agreements that may affect the properties or title thereto;
back-ins and reversionary interests existing as a result of pooling under state orders;
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors, and contractual liens under operating agreements and the Revolver;
pooling, unitization and communitization agreements, declarations, and orders; and
easements, restrictions, rights-of-way, and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are customary in the industry for properties of the kind that we own.

The following table shows, as of December 31, 2018, our producing wells, developed acreage, and undeveloped acreage:
 
 
Productive Wells
 
Developed Acreage 2
 
Undeveloped Acreage 1,2
Field
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wattenberg
 
1,523

 
1,098

 
23,900

 
21,700

 
71,300

 
64,500


        1    Undeveloped acreage includes leasehold interests on which wells have not been horizontally 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 undeveloped reserves.

        2    In addition to our acreage in the Wattenberg Field, we also have non-core leasehold in other areas of Colorado, Kansas, and southwest Nebraska approximating 181,200 gross and 159,500 net acres. As of December 31, 2018, this leasehold has no unproved carrying value, and all associated costs are subject to depletion within the full cost pool.
 
The following table shows, as of December 31, 2018, the status of our gross undeveloped acreage within the Wattenberg Field:
Field
 
Held by Production
 
Not Held by Production
Wattenberg
 
68,200

 
3,100


Leases that are held by production generally remain in force so long as oil or natural gas is produced from the well on the particular lease.  Leased acres which are not held by production will expire pursuant to the terms of the lease, provided that the lease may permit us to extend it by making annual rental payments until production is established, at which time the lease will
generally be considered to be held by production.
 

7



The following table shows the calendar years during which our leases in the Wattenberg Field not currently held by production will expire unless a productive oil or natural gas well is drilled on the lease or the lease is renewed.
Leased Acres
(Gross)
 
Expiration
of Lease
900
 
2019
1,200
 
2020
700
 
2021
200
 
2022
100
 
After 2022

Oil and Natural Gas Reserves
 
Our estimated proved reserve quantities increased by 35% from December 31, 2017 to December 31, 2018.  At December 31, 2018, we had estimated proved reserves of 88.0 MMBbls of oil and condensate, 771.9 Bcf of natural gas, and 89.1 MMBbls of natural gas liquids. The estimated standardized measure of future net cash flow from our reserves at December 31, 2018 was $2.7 billion, and the estimated PV-10 value of our reserves at that date was $3.2 billion. PV-10 is a non-GAAP measure that reflects the present value, discounted at 10%, of estimated future net revenues from our proved reserves. We present a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows in Item 7 under "Non-GAAP Financial Measures." The PV-10 value as of December 31, 2018 increased compared to December 31, 2017 by $1.4 billion. The increase in estimated proved reserve quantities and PV-10 value is primarily due to extensions resulting in new proved reserves, increased pricing for oil and NGLs during 2018, and revisions resulting in probable reserves being recognized as proved reserves.

Ryder Scott prepared the estimates of our proved reserves, future production, and income attributable to our leasehold interests as of December 31, 2018.  Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years.  The estimates of proved reserves, future production, and income attributable to certain leasehold and royalty interests are based on technical analyses conducted by teams of geoscientists and engineers employed at Ryder Scott.  The office of Ryder Scott that prepared our reserves estimates is registered in the State of Texas (License #F-1580).  Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses, price differentials, authorizations for expenditure, and geological and geophysical data.
 
The report of Ryder Scott dated January 23, 2019, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott, as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

Our reserves technical team, which consists of our Reservoir Engineering Manager, VP of Exploration, Chief Operations Officer, and Chief Development Officer, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission.  Our technical team has multiple years of experience in oil and gas exploration and development.
 
Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and natural gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices, and with existing technology.  Accordingly, any changes in prices, operating and development costs, regulations, technology, or other factors could significantly increase or decrease estimates of proved reserves.
 
Estimates of volumes of proved reserves at year end are presented in barrels for oil, Mcf for natural gas, and barrels for NGL at the official temperature and pressure bases of the areas in which the natural gas reserves are located.
 
The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis, which incorporate extrapolations of historical production and pressure data available through December 31, 2018 in those cases where this data was considered to be definitive.  The data used in this analysis was obtained from public sources and was considered sufficient for calculating producing reserves. The undeveloped reserves were estimated by the analogy method.  The analogy method uses pertinent well data obtained from public sources that was available through December 31, 2018.
 

8



Below are estimates of our net proved reserves at December 31, 2018, all of which are located in Colorado:
 
Oil
(MBbls)
 
Natural Gas
(MMcf)
 
NGL
(MBbl)
 
MBOE
Proved:
 
 
 
 
 
 
 
Developed
37,102

 
324,169

 
36,427

 
127,557

Undeveloped
50,910

 
447,698

 
52,666

 
178,192

Total
88,012

 
771,867

 
89,093

 
305,749


The following tabulations present the PV-10 value of our estimated reserves as of December 31, 2018, 2017, and 2016 (in thousands):
 
Proved - December 31, 2018
 
Developed
 
 
 
Total
 
Producing
 
Non-producing
 
Undeveloped
 
Proved
Future cash inflow
$
2,684,787

 
$
990,373

 
$
5,156,159

 
$
8,831,319

Future production costs
(761,205
)
 
(235,139
)
 
(1,085,692
)
 
(2,082,036
)
Future development costs
(64,205
)
 
(34,394
)
 
(1,273,912
)
 
(1,372,511
)
Future pre-tax net cash flows
$
1,859,377

 
$
720,840

 
$
2,796,555

 
$
5,376,772

PV-10 (Non-U.S. GAAP)
$
1,268,305

 
$
492,183

 
$
1,400,663

 
$
3,161,151


 
Proved - December 31, 2017
 
Developed
 
 
 
Total
 
Producing
 
Non-producing
 
Undeveloped
 
Proved
Future cash inflow
$
1,804,029

 
$
291,678

 
$
3,397,800

 
$
5,493,507

Future production costs
(492,270
)
 
(63,278
)
 
(735,821
)
 
(1,291,369
)
Future development costs
(47,562
)
 
(18,384
)
 
(982,910
)
 
(1,048,856
)
Future pre-tax net cash flows
$
1,264,197

 
$
210,016

 
$
1,679,069

 
$
3,153,282

PV-10 (Non-U.S. GAAP)
$
861,685

 
$
142,996

 
$
751,603

 
$
1,756,284

 
Proved - December 31, 2016
 
Developed
 
 
 
Total
 
Producing
 
Non-producing
 
Undeveloped
 
Proved
Future cash inflow
$
414,230

 
$

 
$
1,766,443

 
$
2,180,673

Future production costs
(177,138
)
 

 
(466,955
)
 
(644,093
)
Future development costs
(29,634
)
 

 
(554,903
)
 
(584,537
)
Future pre-tax net cash flows
$
207,458

 
$

 
$
744,585

 
$
952,043

PV-10 (Non-U.S. GAAP)
$
154,261

 
$

 
$
322,087

 
$
476,348


The following table presents the prices used to prepare the reserve estimates, which are based on the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:
 
Oil (Bbl)
 
Natural Gas (Mcf)
 
NGL (Bbl)
December 31, 2018 (Average)
$
61.23

 
$
2.07

 
$
20.74

December 31, 2017 (Average)
$
46.57

 
$
2.21

 
$
16.06

December 31, 2016 (Average)
$
36.07

 
$
2.44

 
$

    
During the year ended December 31, 2018, the combined effect of our drilling, acquisition, and participation activities and increased commodity prices generated an increase in projected future cash inflow from proved reserves of $3.3 billion and

9



an increase in future pre-tax net cash flow of $2.2 billion from December 31, 2017 to December 31, 2018.  During the same period, our PV-10 from proved reserves increased by $1.4 billion.  During the year ended December 31, 2018, we incurred capital expenditures of approximately $720.3 million related to the acquisition and development of proved reserves.

During the year ended December 31, 2017, the combined effect of our drilling, acquisition, and participation activities and increased commodity prices generated an increase in projected future cash inflow from proved reserves of $3.3 billion and an increase in future pre-tax net cash flow of $2.2 billion from December 31, 2016 to December 31, 2017.  During the same period, our PV-10 from proved reserves increased by $1.3 billion.  During the year ended December 31, 2017, we incurred capital expenditures of approximately $600.0 million related to the acquisition and development of proved reserves.

During the year ended December 31, 2016, the combined effect of our drilling, acquisition, and participation activities, partially offset by declining commodity prices generated an increase in projected future cash inflow from proved reserves of $470.1 million and an increase in future pre-tax net cash flow of $44.0 million from December 31, 2015 to December 31, 2016.  During the same period, our PV-10 from proved reserves increased by $38.2 million.  During the year ended December 31, 2016, we incurred capital expenditures of approximately $283.3 million related to the acquisition and development of proved reserves.

In general, the volume of production from our oil and gas properties declines as reserves are depleted.  Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.  Accordingly, volumes generated from our future activities are highly dependent upon our success in acquiring or finding additional reserves, and the costs incurred in doing so.
Proved Undeveloped Reserves
Net Reserves
(MBOE)
Ending December 31, 2015
48,289

Converted to proved developed
(806
)
Extensions
3,110

Acquisitions
50,530

Divestitures
(6,479
)
Revisions
(19,155
)
Ending December 31, 2016
75,489

Converted to proved developed
(23,781
)
Extensions
46,913

Acquisitions
34,867

Divestitures
(235
)
Revisions
6,062

Ending December 31, 2017
139,315

Converted to proved developed
(27,627
)
Extensions
31,486

Acquisitions
12,207

Divestitures

Revisions
22,811

Ending December 31, 2018
178,192


At December 31, 2018, our proved undeveloped reserves were 178,192 MBOE. During 2018, our acquisitions led to an increase of 12,207 MBOE in proved undeveloped reserves.  Offsetting the 27,627 MBOE of prior year proved undeveloped reserves that were converted to proved developed reserves, we added 31,486 MBOE of proved undeveloped reserves, primarily as a result of extending our development plan by a year due to the passage of time. Consistent with prior years, we limited our undeveloped locations related to horizontal wells to be drilled within this three-year horizon.

During the year end December 31, 2018, we converted 27,627 MBOE, or 20%, of our proved undeveloped reserves as of December 31, 2017 into proved developed reserves, requiring $268.8 million of drilling and completion capital expenditures. All proved undeveloped reserves as of December 31, 2018 are expected to be converted to proved producing within three years and within five years of their initial booking. Based on our current drilling plans for the next three years, we expect to allocate

10



all funds to developmental drilling in areas of established production where ongoing and planned midstream infrastructure buildout continues. None of our proved undeveloped reserves as of December 31, 2018 have been in this category for more than five years.

At December 31, 2017, our proved undeveloped reserves were 139,315 MBOE. During 2017, the GCII Acquisition, along with other minor acquisitions, led to an increase of 34,867 MBOE in proved undeveloped reserves.  This increase was partially offset by a decrease of 235 MBOE as a result of divestitures. Offsetting the 23,781 MBOE of prior year proved undeveloped reserves that were converted to proved developed reserves, we added 46,913 MBOE of proved undeveloped reserves, primarily as a result of extending our development plan by a year due to the passage of time and the addition of a third rig for the second and third years of our development plan. Further, due to a better commodity market environment, our increase in expected drilling activity positively affected our proved undeveloped reserves.  During the year end December 31, 2017, we converted 23,781 MBOE, or 32%, of our proved undeveloped reserves as of December 31, 2016 into proved developed reserves, requiring $185.2 million of drilling and completion capital expenditures.

At December 31, 2016, our proved undeveloped reserves were 75,489 MBOE. During 2016, the Company's acquisition of approximately 33,100 net acres in the Greeley-Crescent development area in Weld County, Colorado ("GC Acquisition"), along with other minor acquisitions, led to an increase of 50,530 MBOE in proved undeveloped reserves.  These acquisitions allowed for the creation of spacing units with higher working interests, opportunities to drill longer laterals, and increased focus on our development program in the core Wattenberg area. This increase was partially offset by a decrease of 12,144 MBOE as a result of the GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from the three-year drilling plan. This significant change to our development plan resulted in many of the legacy proved undeveloped locations being removed from the development plan. Consequently, only 806 MBOE, or 2%, of prior year proved undeveloped reserves were converted to proved developed reserves during 2016. We also developed 3,217 MBOE of acquired proved undeveloped reserves during the year, and we drilled 5.4 net exploratory wells. Further, due to a better commodity market environment, our increase in expected drilling activity positively affected our proved undeveloped reserves.  While our 2015 reserves estimate assumed no rig initially then an increase to two rigs during the first year of the then-applicable development plan, our 2016 reserves estimate assumed two rigs working continually throughout the three-year plan period.

Delivery Commitments

See "Volume Commitments" in Note 16 to our consolidated financial statements included elsewhere in this report.

Competition and Marketing

We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many of which are very large, well-established energy companies with substantial capabilities and established earnings records.  We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these companies, many of which have greater financial resources and larger technical staffs.  It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.

Exploration for and production of oil and natural gas are affected by the availability of pipe, casing and other tubular goods, and certain other oil field equipment including drilling rigs and tools.  We depend upon independent contractors to furnish rigs, pressure pumping equipment, and tools to drill and complete our wells.  Higher prices for oil and natural gas may result in increased competition among operators for drilling and completion equipment, tubular goods, and drilling and completion crews, which may affect our ability to drill, complete, and work over wells in a timely and cost-effective manner.

The market for oil and natural gas is dependent upon a number of factors that are beyond our control and the effects of which are difficult to predict.  These factors include the proximity of wells to, and the capacity of, oil and natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation.  In addition, new legislation may be enacted that would impose price controls or additional excise taxes on oil, natural gas, or both.  Oversupplies of oil and natural gas can be expected to occur from time to time and may result in, among other things, producing wells being shut-in.  Imports of oil and natural gas may adversely affect the market for domestic oil and natural gas.

The market price for oil is significantly affected by policies adopted by the member nations of the Organization of the Petroleum Exporting Countries, or OPEC.  Members of OPEC establish production quotas among themselves for petroleum products from time to time with the intent of influencing the global supply of oil and consequently price levels.  We are unable to predict the effect, if any, that OPEC, its members, or other countries will have on the amount of, or the prices received for, oil and natural gas.


11



Natural gas prices are now largely influenced by competition.  Competitors in this market include producers, natural gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as coal.  Changes in government regulations relating to the production, transportation, and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.

General

Our offices are located at 1675 Broadway Suite 2600, Denver, Colorado 80202. Our office telephone number is (720) 616-4300, and our fax number is (720) 616-4301. 

Our Greeley, Colorado offices include field offices and an equipment yard.

As of December 31, 2018, we had 147 full-time employees.

Available Information
    
We make available on our website, www.srcenergy.com, under "Investor Relations, SEC Filings," free of charge, our annual and transition reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, and other documents such as proxy statements and registration statements, as soon as reasonably practicable after we electronically file them with, or furnish them to, the U.S. Securities and Exchange Commission ("SEC"). You may also obtain copies of such documents at the SEC's website at www.sec.gov.

12



Governmental Regulation

Our operations are subject to various federal, state, and local laws and regulations that change from time to time. Many of these regulations are intended to prevent pollution and protect environmental quality, including regulations related to permit requirements for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling, completing and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process, groundwater testing, air emissions, noise, lighting and traffic abatement, and the plugging and reclamation of wells. Other regulations are intended to prevent the waste of oil and natural gas and to protect the rights of owners in a common reservoir. These include regulation of the size of drilling and spacing units or proration units, the number or density of wells that may be drilled in an area, the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose requirements regarding the ratability or fair apportionment of production from fields and individual wells. In addition, our operations are subject to regulations governing the pipeline gathering and transportation of oil and natural gas as well as various federal, state, and local tax laws and regulations.

Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and gas industry are generally subject to similar regulatory requirements and restrictions. The regulatory burden on the industry increases the cost of doing business and affects profitability. We are unable to predict the future costs or impact of compliance with applicable laws and regulations.

Regulation of production

Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and gas exploration, production, and related operations.  Most states require drilling permits, drilling and operating bonds, the filing of various reports, and the satisfaction of other requirements relating to the exploration and production of oil and natural gas.  Many states also have statutes or regulations addressing conservation matters including provisions governing the size of drilling and spacing units or proration units, the density of wells, and the unitization or pooling of oil and gas properties. The number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. In addition, certain of the horizontal wells we intend to drill may require pooling of our lease interests with the interests of third parties.  Some states like Colorado allow the statutory pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on the voluntary pooling of lands and leases. In areas with voluntary pooling, it may be more difficult to develop a project if the operator owns less than 100% of the leasehold, or one or more of the leases do not provide the necessary pooling authority. Further, the statutes and regulations of some states limit the rate at which oil and natural gas is produced from properties, prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. This may limit the amount of oil and natural gas that we can produce from our wells and may limit the number of wells or locations at which we can drill.

The Colorado Oil and Gas Conservation Commission ("COGCC") is the primary regulator of exploration and production of oil and gas resources in the principal area in which we operate.  The COGCC regulates oil and gas operators through rules, policies, written guidance, orders, permits, and inspections. Among other things, the COGCC enforces specifications regarding drilling, development, production, reclamation, enhanced recovery, safety, aesthetics, noise, waste, flowlines, and wildlife.  In recent years, the COGCC has amended its existing regulatory requirements and adopted new requirements with increased frequency. For example, in January 2016, the COGCC approved new rules that require local government consultation and certain best management practices for large-scale oil and natural gas facilities in certain urban mitigation areas. These rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations. In February 2018, the COGCC comprehensively amended its regulations for oil, gas, and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection, and other matters. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection, and spill reporting. In December 2018, the COGCC approved new rules that require new oil and gas sites to be situated at least 1,000 feet away from school properties such as playgrounds and athletic fields.

Regulation of sales and transportation of natural gas

Historically, transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978, and Federal Energy Regulatory Commission ("FERC") regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all "first sales" of natural gas. As a result, our sales of natural gas may be made at market prices, subject to applicable contract provisions. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters, but we do not

13



believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers, and marketers with which we compete.

In August 2005, the Energy Policy Act of 2005 (the "2005 EPA") was signed into law. The 2005 EPA directs the FERC and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for "any entity," including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. FERC rules implementing this provision make it unlawful in connection with the purchase or sale of natural gas or transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. This anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" natural gas sales, purchases, or transportation subject to FERC jurisdiction.

In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements (as amended by subsequent orders on rehearing, "Order 704"). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.

Gathering is exempt from federal regulation under the NGA, but is subject to various state regulations, which include safety, environmental, and in some circumstances, nondiscriminatory take requirements. FERC has in the past reclassified transportation facilities previously considered to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and conversely, has also reclassified non-jurisdictional gathering facilities as subject to FERC jurisdiction. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

Transportation and safety of natural gas is also subject to other federal and state laws and regulations, including regulation by the U.S. Department of Transportation, through its Pipeline and Hazardous Materials Safety Administration ("PHMSA"), under the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements on the design, construction, operation, and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (the "PIPES Act 2006") and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the "PIPES Act 2011"). The failure to comply with these rules and regulations can result in substantial penalties.

Our production and gathering facilities are not subject to jurisdiction of the FERC. Our natural gas sales prices, however, continue to be affected by intrastate and interstate gas transportation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive, along with the availability and terms of such transportation. Competition among suppliers has greatly increased in recent years. Our natural gas sales are generally made at the prevailing market price at the time of sale.

Regulation of sales and transportation of oil

Our sales of oil are affected by the availability, terms, and cost of transportation. Interstate transportation of oil by pipeline is regulated by the FERC pursuant to the Interstate Commerce Act ("ICA"), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate transportation of oil, natural gas liquids, and refined products (collectively referred to as "petroleum pipelines") be just and reasonable and non-discriminatory and that such rates and terms and conditions of service are subject to FERC regulation.

Intrastate petroleum pipeline transportation rates and certain terms of service are subject to regulation by state regulatory commissions in some jurisdictions. The basis for intrastate petroleum pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate petroleum pipeline rates, varies from state to state.

Insofar as effective, interstate and intrastate rates and certain terms of service are equally applicable to all comparable shippers, and accordingly, we do not believe that the regulation of petroleum pipeline transportation rates or such terms of service will affect our operations in any way that is materially different than those of our competitors who are similarly situated.


14



Transportation and safety of petroleum products by pipeline is subject to regulation by PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as well as the PIPES Act of 2006 and the PIPES Act of 2011, which govern the design, installation, testing, construction, operation, replacement, and management of liquids pipeline facilities. Petroleum products that are transported by rail may also be subject to additional regulation by PHMSA.

Environmental Regulations

As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state, and local laws and regulations designed to protect and preserve natural resources and the environment.  Long-term trends in environmental legislation and regulation are generally toward stricter standards, and this trend is likely to continue.  These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling, and other activities on certain lands lying within wilderness and other protected areas; mandate requirements and standards for operations; impose substantial liabilities and remedial obligations for pollution; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification, and renewal by issuing authorities.  Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions, or both.  In March 2015, the COGCC implemented regulatory and statutory amendments that significantly increased the potential penalties for violating the Colorado Oil and Gas Conservation Act or its implementing regulations, orders, or permits.

The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and comparable state statutes impose strict and joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites.  Persons responsible for the release or threatened release of hazardous substances under CERCLA may be subject to liability for the costs of cleaning up those substances and for damages to natural resources. It is not uncommon for the 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.   Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations impose clean-up liability relating to petroleum and petroleum-related products.  The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance.  Although RCRA classifies certain oil field wastes as non-hazardous "solid wastes," such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. A proposed consent decree filed in December 2016 between the Environmental Protection Agency ("EPA") and certain environmental groups commits the EPA to deciding whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019.

Certain of our operations are subject to the federal Clean Air Act ("CAA") and similar state and local requirements. The CAA may require certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air-emission-related issues. Greenhouse gas recordkeeping and reporting requirements under the CAA took effect in 2011 and impose increased administrative and control costs. Federal New Source Performance Standards regarding oil and gas operations ("NSPS OOOO") took effect in 2012, with more subsequent amendments, all of which have likewise added administrative and operational costs. In June 2016, EPA finalized new regulations under the CAA to reduce methane emissions from new and modified sources in the oil and natural gas sector (the "NSPS OOOOa"). These new regulations impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, and additional control requirements for gathering, boosting, and compressor stations. In September 2018, EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. Concurrent with the proposed methane rules, the EPA also finalized a new rule regarding source determinations and permitting requirements for the onshore oil and gas industry under the CAA. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities.

In October 2015, the EPA lowered the national ambient air quality standard ("NAAQS") for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements, and increased permitting delays and costs. In addition, the ozone nonattainment status for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area was bumped up by the EPA from "marginal" to "moderate" as a result of the area failing to

15



attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. In 2016, the state of Colorado undertook a rulemaking to address the new "moderate" status, culminating in, among others, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable State Implementation Plan ("SIP"). During the fall of 2016, EPA also issued final Control Techniques Guidelines ("CTGs") for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, Colorado adopted new and more stringent air quality control requirements. The Denver Metro/North Front Range NAA is at risk of being reclassified again to "serious" if it does not meet the 2008 NAAQS. While the Colorado Department of Public Health and Environment ("CDPHE") may request an exception or other relief from the reclassification, it is possible that the Denver Metro/North Front Range NAA will be reclassified as "serious" by early 2020. A "serious" classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements becoming applicable to our operations and significant costs and delays in obtaining necessary permits. This process could result in new or more stringent air quality control requirements applicable to our operations.

The federal Clean Water Act ("CWA") and analogous state laws impose requirements regarding the discharge of pollutants into waters of the U.S. and the state, including spills and leaks of hydrocarbons and produced water. The CWA also requires approval for the construction of facilities in wetlands and other waters of the U.S., and it imposes requirements on storm water run-off. In June 2016, the EPA finalized new CWA pretreatment standards that would prevent onshore unconventional oil and natural gas wells from discharging wastewater pollutants to public treatment facilities. In June 2015, the EPA and the U.S. Army Corps of Engineers adopted a new regulatory definition of "waters of the U.S.," which governs which waters and wetlands are subject to the CWA. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the "waters of the U.S." until 2020. In August 2018, the U.S. District Court for South Carolina found that the EPA and the Corps failed to comply with the Administrative Procedure Act and struck the 2018 rule that attempted to delay the applicability date of the 2015 Clean Water Rule. Other district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself. Taken together, the 2015 Clean Water Rule is currently in effect in 23 states, and temporarily stayed in the remaining states, including Colorado. In those remaining states, the 1986 rule and guidance remain in effect. In December 2018, EPA and the Corps issued a proposed new rule that would differently revise the definition of "waters of the U.S." and essentially replace both the 1986 rule and the 2015 Clean Water Rule. According to the agencies, the proposed new rule is "intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act." If finalized, this new definition of "waters of the U.S." will likely be challenged and sought to be enjoined in federal court.

The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for threatened or endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. In such areas, we may be prohibited from conducting operations at certain locations or during certain periods, and we may be required to develop plans for avoiding potential adverse effects. In addition, certain species are subject to varying degrees of protection under state laws.

Federal laws including the CWA require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure, and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities.

In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") 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 conditions. Based on these findings, the EPA adopted regulations under the CAA that, among other things, established Prevention of Significant Deterioration ("PSD"), construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. In a subsequent ruling, the U.S. Supreme Court upheld a portion of EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG best available control technology ("BACT") requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require

16



us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the oil and natural gas that we produce.

In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future and, moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.

The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of GHGs associated with our operations. In March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of EPA's August 2015 Clean Power Plan.  The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017. The comment period on the proposed rule closed in April 2018. In August 2018, EPA proposed the Affordable Clean Energy ("ACE") rule, which would establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE would replace the Clean Power Plan.

Further GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth’s atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement.

Hydraulic Stimulation

We operate primarily in the Wattenberg Field of the D-J Basin where the rock formations are typically tight, and it is a common practice to use hydraulic stimulation to allow for or increase hydrocarbon production.  Hydraulic stimulation involves the process of injecting substances such as water, sand, and additives (some proprietary) under pressure into a targeted subsurface formation to create fractures, thus creating a passageway for the release of oil and gas.  Hydraulic stimulation is a technique that we commonly employ and expect to employ extensively in future wells that we drill and complete.

We outsource all hydraulic stimulation services to service providers with significant experience, and which we deem to be competent and responsible.  Our service providers supply all personnel, equipment, and materials needed to perform each stimulation, including the chemical mixtures that are injected into our wells.  We require our service companies to carry insurance covering various losses and liabilities that could arise in connection with their activities; however, insurance may not be available or adequate to cover losses and liabilities incurred, or may be prohibitively expensive relative to the perceived risk.  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.

In recent years, environmental opposition to hydraulic stimulation has increased, and various governmental and regulatory authorities have adopted or are considering new requirements for this process. To the extent that these requirements increase our costs or restrict our development activities, our business and prospects may be adversely affected.

The EPA has asserted that the Safe Drinking Water Act ("SDWA") applies to hydraulic stimulation 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 stimulation, 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 stimulation. In addition, from time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic stimulation under the SDWA. If such legislation were enacted, operators engaged in hydraulic stimulation 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 additional public disclosure of the chemicals used in the stimulation process.


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The EPA has also conducted a nationwide study into the effects of hydraulic stimulation on drinking water. In June 2015, the EPA released a draft study report for peer review and comment. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find a relatively small number of site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. In December 2016, EPA released the final report on impacts from hydraulic stimulation activities on drinking water, concluding that hydraulic stimulation activities can impact drinking water resources under some circumstances and identifying some factors that could influence these impacts.

Federal agencies have also adopted or are considering additional regulation of hydraulic stimulation. In March 2016, the U.S. Occupational Safety and Health Administration ("OSHA") issued a final rule, with effective dates of 2018 and 2021 for the hydraulic stimulation industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic stimulation. 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 stimulation. In March 2015, the Bureau of Land Management ("BLM") issued a new rule regulating hydraulic stimulation activities involving federal and tribal lands and minerals, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water. The BLM rescinded the rule in December 2017; however, the BLM’s rescission has been challenged by several states in the United States District Court of the District of Northern California.

In November 2016, the BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. In September 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.

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 stimulation operations. As part of these requirements, operators must report all chemicals used in hydraulically stimulation 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 stimulation 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 into memoranda of agreement with oil and gas producers to accomplish the same objective. In addition, during the past few years, five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic stimulation. Local district courts have struck down the ordinances for certain of those Colorado cities, and these 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 stimulation activities, and oil and gas operations generally, within their respective jurisdictions.

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ITEM 1A.
RISK FACTORS

Investors should be aware that any purchase of our securities involves risks, including those described below, which could adversely affect the value of our securities. We do not make, nor have we authorized any other person to make, any representation about the future market value of our securities. In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in our securities. Except where the context indicates otherwise, substantially all of the risks described below relating to oil and natural gas and related activities apply to NGLs as well.

Risks Relating to Our Business and the Industry

A decline in oil and natural gas prices may adversely affect our business, financial condition, or results of operations and our ability to meet our financial commitments.

The prices we receive for our oil and natural gas significantly affect many aspects of our business, including our revenue, profitability, access to capital, quantity and present value of proved reserves, and future rate of growth. Oil and natural gas are commodities, and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. In 2018, benchmark oil prices ranged from over $70 per Bbl to below $50 per Bbl, and swings from highs of over $100 per Bbl to lows below $30 per Bbl have occurred in recent years. Natural gas prices have also experienced significant declines in some recent periods. Oil and natural gas prices will likely continue to be volatile in the future and will depend on numerous factors beyond our control. These factors include the following:

worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
localized supply and demand fundamentals and gathering, processing, and transportation availability;
the actions, or inaction, of OPEC, its members and other oil-producing countries;
the price and quantity of imports of foreign oil;
political conditions or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, and Russia;
the level of global oil and domestic natural gas exploration and production;
the level of global oil and domestic natural gas inventories;
weather conditions and natural disasters;
domestic and foreign governmental regulations;
exports from the United States of liquefied natural gas and oil;
speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;
price and availability of competitors’ supplies of oil and natural gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
    
Sustained periods of reduced oil and natural gas prices and the resultant effect such prices have on our drilling economics and our ability to fund our operations could require us to re-evaluate and postpone or eliminate our development drilling, which would make it more difficult for us to achieve expected levels of production. Lower prices may also reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline, which would likely result in a reduction in our proved undeveloped reserves and PV-10 and standardized measure values.

Lower oil and natural gas prices may also reduce our borrowing ability. Our borrowing capacity is based substantially on the value of our oil and natural gas reserves which are, in turn, impacted by prevailing oil and natural gas prices. Our actual borrowings may not exceed the borrowing base, which is currently $650 million. The next semi-annual redetermination of the borrowing base is scheduled to occur in May 2019. If our borrowing base were to decline significantly, we could have to either raise additional capital or adjust our drilling plan. In addition, if the lenders reduce the borrowing base below the then-outstanding balance, we will be required to repay the difference between the outstanding balance and the reduced borrowing base, and we may not have or be able to obtain the funds necessary to do so.
    
We have historically relied on the availability of additional capital, including proceeds from the sale of equity, debt, and convertible securities, to execute our business strategy. Future acquisitions may require substantial additional capital, the availability of which will depend in significant part on current and expected commodity prices. If we are unable to raise capital on acceptable terms in the future, we may be unable to pursue future acquisitions.


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To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. If oil and natural gas prices decline, we will not be able to hedge future production at the same pricing level as our current hedges, and our results of operations and financial condition would be negatively impacted. In addition, hedging arrangements can expose us to risk of financial loss in some circumstances, including when production is less than expected, a counterparty to a hedging contract fails to perform under the contract, or there is a change in the expected differential between the underlying price in the hedging contract and the actual prices received.

Accordingly, any substantial or extended decline in the prices that we receive for our production would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations, and results of operations.

We are dependent on third-party pipeline, trucking, and rail systems to transport our production and gathering and processing systems to prepare our production. These systems have limited capacity, and we are currently experiencing curtailments. Curtailments, disruptions, or lack of availability in these systems interfere with our ability to produce and/or market the oil and natural gas we produce and could materially and adversely affect our cash flow and results of operations.

Market conditions or the unavailability of satisfactory oil and gas transportation and processing arrangements may hinder our access to oil and natural gas markets or delay our production. The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of gathering, processing, pipeline, trucking, and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as when pipeline interruptions occur due to scheduled or unscheduled maintenance, accidents, excessive pressure, physical damage to the gathering or transportation system, lack of contracted capacity on such systems, inclement weather, labor or regulatory issues, or other reasons. A portion of our production may be interrupted, or shut in, from time to time as a result of these factors. For example, the gas gathering systems serving the Wattenberg Field have in recent years experienced a shortage of gas processing and high line pressures from time to time, and this has on occasion reduced capacity and caused production to be shut in. Curtailments and disruptions in the systems we use may last from a few days to several months or longer. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities, or lack of availability of transport would interfere with our ability to market the oil and natural gas that we produce and could materially and adversely affect our cash flow and results of operations and the expected results of our drilling program.

We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations, including as a result of the actions of third parties.

We are affected significantly by a substantial number of governmental regulations relating to, among other things, the release or disposal of materials into the environment, health and safety, land use, and other matters. A summary of the principal environmental rules and regulations to which we are currently subject is set forth in "Business and Properties-Governmental Regulation-Environmental Regulations." Compliance with such laws and regulations often increases our cost of doing business and thereby decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

The environmental laws and regulations to which we are subject may, among other things:

require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;
restrict the types, quantities, and concentrations of substances that can be released into the environment in connection with drilling, hydraulic stimulation, and production activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other "waters of the United States," threatened and endangered species habitat, and other protected areas;
require remedial measures to mitigate pollution from former operations, such as plugging non-producing wells;
require us to add procedures and/or staff in order to comply with applicable laws and regulations; and
impose substantial liabilities for pollution resulting from our operations.

In addition, we could face liability under applicable environmental laws and regulations as a result of the activities of previous owners of our properties or other third parties. For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA, and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of our fault, whether we were responsible for the release or whether the operations at the time of the release were lawful.

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Compliance with, or liabilities associated with violations of or remediation obligations under, environmental laws and regulations could have a material adverse effect on our results of operations and financial condition.

New or amended environmental legislation or regulatory initiatives could result in increased costs, additional operating restrictions, or delays or have other adverse effects on us.

The environmental laws and regulations to which we are subject change frequently, often to become more burdensome and/or to increase the risk that we will be subject to significant liabilities. New or amended federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of resources (especially from shale formations that are not commercial without the use of hydraulic stimulation), or alter the demand for and consumption of our products. Any such outcome could have a material and adverse impact on our cash flows and results of operations.

For example, in 2014, 2016, and 2018, opponents of hydraulic stimulation sought statewide ballot initiatives in Colorado that would have restricted oil and gas development in Colorado and could have had materially adverse impacts on us. The 2018 proposal, which qualified for the November 2018 ballot but was not approved by voters, would have made the vast majority of the surface area of the state, including substantially all of our planned future drilling locations, ineligible for drilling. Although none of the proposed initiatives were implemented, future initiatives are likely, including in 2020. Similarly, proposals are made from time to time to adopt new, or amend existing, laws and regulations to address hydraulic stimulation or climate change concerns through further regulation of exploration and development activities. The "Business and Properties-Governmental Regulation-Environmental Matters" section of this report includes a discussion of some recent environmental regulatory changes that have affected us. We cannot predict the nature, outcome, or effect on us of future regulatory initiatives, but such initiatives could materially impact our results of operations, production, reserves, and other aspects of our business.

Substantially all of our producing properties are located in the D-J Basin in Colorado, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the D-J Basin in Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production, or interruption of transportation and processing services, and any resulting delays or interruptions of production from existing or planned new wells. For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition, or results of operations.

Operating hazards may adversely affect our ability to conduct business.

Our environmental protection, safety, training, maintenance, and similar programs may not be effective in preventing all accidents and hazards associated with our operations. The occurrence of an accident or hazard, such as an equipment failure or loss of well control, could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. We do not maintain insurance for all of these risks, nor in amounts that cover all of the losses to which we may be subject, and the insurance that we have may not continue to be available on acceptable terms. Moreover, some risks that we face are not insurable. For example, a leak or other pollution event may occur without our knowledge, making it impossible for us to notify the insurer within the time period required by the policy. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, we incur substantial costs in designing and implementing our environmental protection, safety, training, and maintenance in order to prevent operating hazards from occurring.


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Our actual production, revenues, and expenditures related to our reserves are likely to differ from those underlying our estimates of proved reserves. We may experience production that is less than estimated, and drilling costs that are greater than estimated, in our reserve report. These differences may be material.

Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

historical production from the area compared with production from similar producing wells;
the assumed effects of regulations by governmental agencies;
assumptions concerning future oil and natural gas prices;
assumptions concerning future operating costs, severance and excise taxes, development costs, and workover and remedial costs; and
assumptions concerning future midstream availability.

Because all reserve estimates are based on assumptions that may prove to be incorrect and are to some degree subjective, each of the following items may differ from those assumed in estimating proved reserves:

the quantities of oil and natural gas that are ultimately recovered;
the production and operating costs incurred;
the amount and timing of future development expenditures; and
future cash flows from the development of reserves.

Historically, there has been a difference between our actual production and the production estimated in prior reserve reports. We cannot assure you that these differences will not be material in the future.

Approximately 58% of our estimated proved reserves at December 31, 2018 are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our estimates of proved undeveloped reserves reflect our plans to make significant capital expenditures to convert those reserves into proved developed reserves, including approximately $1,273.9 million in estimated capital expenditures during the five years ending December 31, 2023. The estimated development costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. If we choose not to develop proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade to probable or possible any proved undeveloped reserves that are not developed or expected to be developed within this five-year time frame.

You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2018 is based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. Each of the foregoing considerations also impacts the PV-10 values of our reserves.

Seasonal weather conditions, wildlife and plant species conservation restrictions, and other constraints could adversely affect our ability to conduct operations.

Our operations could be adversely affected by weather conditions and wildlife and plant species conservation restrictions. In Colorado, certain activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt operations. These constraints and resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operational and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.

Similarly, some of our properties are located in relatively populous areas in the Wattenberg Field, and our operations in those areas may be subject to additional expenses and limitations. For example, we may incur additional expenses in those areas

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to mitigate visual impacts, noise, and odor issues relating to our operations, and we may find it more difficult to obtain drilling permits and other governmental approvals. In addition, the risk of litigation related to our operations may be higher in those areas. Any of these factors could have a material impact on our operations in the Wattenberg Field and could have a material adverse effect on our business, financial condition, and results of operations.

Furthermore, a critical habitat designation for certain wildlife under the U.S. Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of particular species as threatened or endangered could have a material adverse effect on our operations in areas where those species are found.

Our future success depends upon our ability to find, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable. Drilling activities may be unsuccessful or may be less successful than anticipated.

In order to maintain or increase our reserves, we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance our exploration, development, and acquisition activities. Without successful exploration, development, or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs, drilling results, and the accuracy of our assumptions and estimates regarding potential well communication issues and other matters affecting the spacing of our wells. Because of these uncertainties, we do not know if the numerous potential drilling locations that we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other potential drilling locations.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient quantities to cover drilling, operating, and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Our estimates of per-well performance may prove to be incorrect if the data we use to generate the estimates is not representative of typical wells in the relevant area, well performance in the area is more variable than we anticipated or for other reasons. There can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such proved or unproved property or wells.

Acquisitions we pursue may not achieve their intended results and may result in us assuming unanticipated liabilities.

Pursuing acquisitions is an important part of our growth strategy. However, achieving the anticipated benefits of any acquisition is subject to a number of risks and uncertainties. For example, we may discover title defects or adverse environmental or other conditions related to the acquired properties of which we are unaware at the time that we enter into the relevant purchase and sale agreement. Environmental, title, and other problems could reduce the value of the acquired properties to us, and depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We may assume all or substantially all of the liabilities associated with the acquired properties and may be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure that such potential remedies will be adequate for any liabilities that we incur, and such liabilities could be significant. Even though we perform due diligence reviews (including a review of title and other records) of the major properties that we seek to acquire that we believe are generally consistent with industry practices, these reviews are inherently incomplete. It is typically not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. Moreover, even an in-depth review of records and properties may not necessarily reveal existing or potential liabilities or other problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. The discovery of any material liabilities associated with our acquisitions could materially and adversely affect our business, financial condition, and results of operations. In addition, completing the integration process for any acquisition may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of any acquired operations smoothly or efficiently or that the anticipated benefits of any transaction will be achieved. Further, acquisitions may require additional debt or equity financing, resulting in additional leverage or dilution of ownership.


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The success of any acquisition will depend on, among other things, the accuracy of our assessment of the number and quality of the drilling locations associated with the properties to be acquired, future oil and natural gas prices, reserves and production, and future operating costs and various other factors. These assessments are necessarily inexact. Our assessment of certain of these factors will typically be based in part on information provided to us by the seller, including historical production data. Our independent reserve engineers typically will not provide a report regarding the estimated reserves associated with properties to be acquired. The assumptions on which our internal estimates are based may prove to be incorrect in a number of material ways, resulting in our not realizing the expected benefits of the acquisition. As a result, we may not recover the purchase price for the acquisition from the sale of production from the acquired properties or recognize an acceptable return from such sales.

We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.

Our ability to execute our long-term operating strategy is highly dependent on our having access to capital when the need arises. Historically, we have addressed our liquidity needs through credit facilities, issuances of equity, debt, and convertible securities, sales of assets, joint ventures, and cash provided by operating activities. We will examine the following alternative sources of capital in light of economic conditions in existence at the relevant time:

borrowings from banks or other lenders;
the sale of non-core assets;
the issuance of debt securities;
the sale of common stock, preferred stock, or other equity securities;
joint venture financing; and
production payments.

The availability of these sources of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value, and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises, and this would adversely affect our production, cash flows, and capital expenditure plans.

Oil and natural gas prices may be affected by local and regional factors.

The prices to be received for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price that we receive for our production. Our average differential for the year ended December 31, 2018 was $(7.15) per barrel for oil and $(1.00) per Mcf for natural gas. These differentials are difficult to predict and may widen or narrow in the future based on market forces. The unpredictability of future differentials makes it more difficult for us to effectively hedge our production. Our hedging arrangements are generally based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.

Lower oil and natural gas prices and other adverse market conditions may cause us to record ceiling test write-downs or other impairments, which could negatively impact our results of operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "full cost ceiling" which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If, at the end of any fiscal period, we determine that the net capitalized costs of oil and gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a ceiling test write-down is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we

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experience substantial downward adjustments to our estimated proved reserves or our unproved property values or if estimated future development costs increase.

We may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining commodity prices or other adverse market conditions could result in reductions in proved reserve estimates that would adversely affect our results of operations.

We cannot control activities on properties that we do not operate, and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others, therefore, will depend upon a number of factors outside of our control, including the operator’s:

timing and amount of capital expenditures;
expertise and diligence in adequately performing operations and complying with applicable agreements, laws, and regulations;
financial resources;
inclusion of other participants in drilling wells; and
use of technology.

As a result of an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected. In addition, our lack of control over non-operated properties makes it more difficult for us to forecast future capital expenditures and production.

We may be unable to satisfy our contractual obligations, including obligations to deliver oil and natural gas from our own production or other sources.

We have entered into agreements that require us to deliver minimum amounts of oil to four counterparties that transport oil via pipelines. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next three years. Since 2016, we have been obligated to deliver a combined volume of 11,157 Bbls of oil per day to three of these counterparties. We also committed to deliver 2,500 Bbls of oil per day to the fourth counterparty for approximately one and a quarter years beginning in the first quarter of 2019. If we are unable to fulfill all of our contractual obligations from our own production or from oil and natural gas that we acquire from third parties, we may be required to pay penalties or damages pursuant to these agreements.

Furthermore, in collaboration with several other producers and DCP Midstream, we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The first agreement includes a new 200 MMcf per day processing plant and the expansion of a related gathering system, both of which were completed during the third quarter of 2018. Our share of the commitment requires 46.4 MMcf per day to be delivered for a period of seven years starting in the third quarter of 2018. The second agreement also includes a new 200 MMcf per day processing plant and the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of seven years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. Subject to this potential limitation, we will incur penalties under these agreements if we fail to provide at least the minimum required quantities of natural gas.

Any future penalties or damages of the types described above could adversely impact our cash flows, profit margins, net income, and reserve values.


25



We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.

We operate in the highly competitive areas of oil and gas exploration, development, and production. Factors that affect our ability to compete successfully in the marketplace include:

the availability of funds for, and information relating to, properties;
the standards established by us for the minimum projected return on investment; and
the transportation of natural gas and oil.

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines, and national and local gas gatherers, many of which possess greater financial and other resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition, and results of operations may be adversely affected.

We may be unable to successfully identify, execute, or effectively integrate future acquisitions, which may negatively affect our results of operations.

Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or if the acquisition occurs, effectively integrate the acquired business or properties into our existing business. Negotiations of potential acquisitions and the integration of acquired assets may require a disproportionate amount of management’s attention and our resources. Moreover, our debt agreements contain covenants that may limit our ability to finance an acquisition. Even if we complete additional acquisitions, new assets may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized, and the assets may not be integrated successfully or operated profitably. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

From time to time, legislative proposals are made that would, if enacted, result in the elimination of the immediate deduction for intangible drilling and development costs, the repeal of the percentage depletion allowance for oil and gas properties, and an extension of the amortization period for certain geological and geophysical expenditures. Such changes, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

Any failure to meet our debt obligations could harm our business, financial condition, and results of operations.

As of December 31, 2018, the net aggregate amount of our outstanding indebtedness was $695 million. Our ability to make payments on and/or to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a significant extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions, and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness or to fund our other liquidity needs. For example, decreases in oil and natural gas prices in the recent past have adversely affected our ability to generate cash flow from operations and future decreases would have similar effects. If our cash flow and existing capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital, or restructure our debt, and any of these actions, if completed, could adversely affect our business and/or the holders of our securities. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, in a timely manner or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.


26



Our credit facility also requires us to satisfy certain financial tests on an ongoing basis. A breach of any of these covenants could result in a default under the agreement. As with a failure to pay interest and principal when due, a default, if not cured or waived, could result in all indebtedness outstanding under the agreement and other debt agreements becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

In addition, the amount of our interest expense may increase because amounts borrowed under our credit facility bear interest at variable rates; if interest rates increase, this could result in higher interest expense.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.

Our credit facility and the indenture governing our 2025 Senior Notes contain, and future debt agreements may contain, covenants that restrict or limit our ability to:

pay dividends or distributions on our capital stock or issue preferred stock;
repurchase, redeem, or retire our capital stock or subordinated debt;
make certain loans and investments;
sell assets;
enter into certain transactions with affiliates;
create or assume certain liens on our assets;
enter into sale and leaseback transactions;
merge or enter into other business combination transactions; or
engage in certain other corporate activities.

These requirements could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the restrictive covenants under our debt agreements. Future debt agreements may have similar, or more restrictive, provisions.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing, and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, including unpaid costs and liabilities arising from the actions of those working interest owners. Declines in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, will not be able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover them from other parties. This could materially adversely affect our financial position.

Our disclosure controls and procedures may not prevent or detect potential acts of fraud.

Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, and recorded, processed, summarized, and reported within the time periods specified in applicable SEC rules and forms.

Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our company have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly,

27



because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, we are required to furnish a report by our management in this report regarding the effectiveness of our internal control over financial reporting. The management report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, investors could lose confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. We sell production to a small number of customers, as is customary in the industry. For the year ended December 31, 2018, we had five major customers, which represented 13%, 13%, 17%, 20%, and 22%, respectively, of our revenue during the period. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.

Failure to adequately protect critical data and technology systems could materially affect our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. "Phishing" and other types of attempts to obtain unauthorized information or access are often sophisticated and difficult to detect or defeat. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems.

Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. A system failure, data security breach, cyber-attack or similar event could have a material adverse effect on our financial condition, results of operations, or cash flows.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain or dispose of water at a reasonable cost and in compliance with applicable regulations may have a material adverse effect on our financial condition, results of operations, and cash flows.

Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic stimulation processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic stimulation to protect local water supplies. Colorado has a relatively arid climate and experiences drought conditions from time to time. If we are unable to obtain water to use in our operations from local sources or dispose of or recycle water used in operations, or if the price of water or water disposal increases significantly, we may be unable to produce oil and natural gas economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

28




Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could materially and adversely affect our business. The risk of lease expiration typically increases at times when commodity prices are depressed, as the pace of our exploration and development activity tends to slow during such periods.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2018, we operated 406 gross horizontal producing wells, with an additional 50 horizontal wells in progress, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore, and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to hydraulically stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations, and not successfully cleaning out the wellbore after completion of the final hydraulic stimulation stage. Also, we generally use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. Ultimately, the success of new drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less successful than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, unfavorable commodity prices, or other factors, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties, and the value of our undeveloped acreage could decline.

Risks Relating to our Common Stock

We do not intend to pay dividends on our common stock, and our ability to pay dividends on our common stock is restricted.

Since inception, we have not paid any cash dividends on our common stock. Cash dividends are restricted under the terms of our debt agreements, and we presently intend to continue the policy of using retained earnings for expansion of our business. Any future dividends also may be restricted by future agreements.


29



The price of our stock price has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.

The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events, including, among others:

the identification of and severity of environmental events and governmental and other third-party responses to the events;
changes in production volumes, worldwide demand and prices for oil and natural gas;
changes in market prices of oil and natural gas;
changes in securities analysts’ estimates of our financial performance;
fluctuations in stock market prices and volumes, particularly among securities of energy companies;
changes in market valuations of similar companies;
changes in interest rates;
announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing oil and natural gas resources;
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;
decreases in the amount of capital available to us;
operating results that fall below market expectations or variations in our quarterly operating results;
loss of a relationship with a partner;
other regulatory developments; or
additions or departures of key personnel,

could trigger significant declines in the price of our common stock. External events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and gas exploration and production industries, actual and expected production levels from OPEC members and other oil-producing countries and the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock.

Additional financings may subject our existing stockholders to significant dilution.

To the extent that we raise additional funds or complete acquisitions by issuing equity securities, our stockholders may experience significant dilution. In addition, debt financing, if available, may involve restrictive covenants. We may seek to access the public or private capital markets whenever conditions are favorable, even if we do not have an immediate need for additional capital at that time. Our access to the financial markets and the pricing and terms that we receive in those markets could be adversely impacted by various factors, including changes in general market conditions and commodity prices.

Equity compensation plans will result in future dilution of our common stock.

To the extent options to purchase common stock under our equity incentive plans are exercised, or shares of restricted stock or other equity awards are issued based on satisfaction of vesting requirements, holders of our common stock will experience dilution.

As of December 31, 2018, there were 12,849,308 shares reserved for issuance under our equity compensation plans, of which 1,639,918 restricted shares have been granted and are subject to vesting in the future based on the satisfaction of certain criteria established pursuant to the respective awards, 780,028 performance-vested restricted shares have been granted and are subject to future issuance based on the Company's total shareholder return relative to a selected peer group of companies over the performance period, 274,898 performance-vested restricted shares have been granted and are subject to future issuance based on a discretionary assessment by the Compensation Committee, which is anticipated to measure the performance of the Company and the executives over the defined vesting period, and 4,652,634 of which are issuable upon the exercise of outstanding options to purchase common stock. Our outstanding options have a weighted average exercise price of $10.06 per share as of December 31, 2018.


30



Non-U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon sale, exchange, or disposition of our common stock.

        It is likely that we are, and will remain for the foreseeable future, a U.S. real property holding corporation for U.S. federal income tax purposes because our assets consist primarily of "United States real property interests" as defined in the applicable Treasury regulations. As a result, under the Foreign Investment in Real Property Tax Act ("FIRPTA"), certain non-U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they would also be required to file U.S. tax returns with respect to such gain, and may be subject to a withholding tax. In general, whether these FIRPTA provisions apply depends on the amount of our common stock that such non-U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market within the meaning of the applicable Treasury regulations. So long as our common stock continues to be regularly traded on an established securities market, only a non-U.S. investor who has owned, actually or constructively, more than 5% of our common stock at any time during the shorter of (i) the five-year period ending on the date of disposition and (ii) the non-U.S. investor's holding period for its shares may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA.

ITEM 1B.
UNRESOLVED STAFF COMMENTS

None.

ITEM 2.    PROPERTIES

See Item 1 of this report.

ITEM 3.
LEGAL PROCEEDINGS

None.

ITEM 4.
MINE SAFETY DISCLOSURES

Not applicable.

31



PART II

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

Our common stock is listed on the NYSE American under the symbol "SRCI."

As of February 14, 2019, we had 243,256,234 outstanding shares of common stock and 59 shareholders of record.

Since inception, we have not paid any cash dividends on common stock.  Cash dividends are restricted under the terms of our debt agreements, and we presently intend to continue the policy of using retained earnings for expansion of our business.

Issuer Purchases of Equity Securities
Period
 
Total Number of Shares (or Units) Purchased
 
Average Price Paid per Share (or Unit)
 
Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs)
October 1, 2018 - October 31, 2018 (1)
 

 
$

 

 

November 1, 2018 - November 30, 2018 (1)
 
2,487

 
$
5.88

 

 

December 1, 2018 - December 31, 2018 (1)
 

 
$

 

 


(1) Pursuant to statutory minimum withholding requirements, certain of our employees and executives exercised their right to "withhold to cover" as a tax payment method for the vesting and exercise of certain shares. These elections were outside of a publicly announced repurchase plan.


32



Comparison of Cumulative Return

The performance graph below compares the cumulative total return of our common stock over the 64-month period ended December 31, 2018, with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the companies with a Standard Industrial Code ("SIC") of 1311. The SIC Code 1311 consists of a weighted average composite of publicly traded oil and gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on August 31, 2013 and in the S&P 500 Index and all companies with the SIC Code 1311 on the same date. The results shown in the graph below are not necessarily indicative of future performance.
ctr2018v2.gif

 
 
 As of August 31,
 
As of December 31,
 
 
2013
 
2014
 
2015
 
2015
 
2016
 
2017
 
2018
SRC Energy Inc.
 
100.00

 
143.80

 
114.74

 
91.03

 
95.19

 
91.13

 
50.21

S&P 500
 
100.00

 
125.25

 
125.84

 
131.37

 
147.09

 
179.20

 
171.34

SIC Code 1311
 
100.00

 
127.92

 
71.73

 
60.12

 
79.21

 
86.10

 
78.43



33



ITEM 6.
SELECTED FINANCIAL DATA

The selected financial data presented in this item has been derived from our audited consolidated financial statements that are either included in this report or in reports previously filed with the SEC.  The information in this item should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included in this report.
 
Year Ended December 31,
 
Four Months Ended December 31, 2015
 
Year Ended August 31,
 
2018
 
2017
 
2016
 
 
2015
 
2014
Results of Operations
(in thousands):
 
 
 
 
 
 
 
 
 
 
 
Revenues

$645,641

 

$362,516

 

$107,149

 

$34,138

 

$124,843

 

$104,219

Net income (loss)
260,022

 
142,482

 
(219,189
)
 
(122,932
)
 
18,042

 
28,853

 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
 
 
Basic

$1.07

 

$0.69

 

($1.26
)
 

($1.14
)
 

$0.19

 

$0.38

Diluted

$1.07

 

$0.69

 

($1.26
)
 

($1.14
)
 

$0.19

 

$0.37

 
 
 
 
 
 
 
 
 
 
 
 
Certain Balance Sheet Information (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Total Assets

$2,754,714

 

$2,079,564

 

$1,024,113

 

$672,616

 

$746,449

 

$448,542

Working (Deficit) Capital
(121,393
)
 
(42,272
)
 
(38,056
)
 
24,992

 
93,129

 
(35,338
)
Long-term Obligations
734,941

 
538,359

 
75,614

 
78,000

 
78,000

 
37,000

Total Liabilities
1,168,422

 
771,130

 
183,374

 
166,106

 
174,052

 
167,052

Equity
1,586,292

 
1,308,434

 
840,739

 
506,510

 
572,397

 
281,490

 
 
 
 
 
 
 
 
 
 
 
 
Certain Operating Statistics:
 
 
 
 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
8,392

 
5,824

 
2,257

 
742

 
1,970

 
941

Natural Gas (MMcf)
37,123

 
24,834

 
12,086

 
3,468

 
7,344

 
3,747

NGLs (MBbls)
3,869

 
2,518

 

 

 

 

MBOE
18,448

 
12,481

 
4,271

 
1,320

 
3,194

 
1,566

BOED
50,543

 
34,194

 
11,670

 
10,822

 
8,750

 
4,290

Average sales price per BOE 1

$34.50

 

$28.79

 

$25.09

 

$25.86

 

$39.09

 

$66.56

LOE per BOE

$2.35

 

$1.56

 

$4.67

 

$4.41

 

$4.70

 

$5.10

DD&A2 per BOE

$9.74

 

$9.00

 

$10.93

 

$14.22

 

$20.62

 

$21.05

1 Adjusted to include the effect of transportation and gathering expenses
2 Depletion, Depreciation, & Accretion

As of January 1, 2017, our natural gas processing agreements with DCP Midstream have been modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2018 and 2017 with prior periods.

On February 25, 2016, we changed our fiscal year from the period beginning on September 1 and ending on August 31 to the period beginning on January 1 and ending on December 31. As a result, the selected financial data above includes financial information for the transition period from September 1, 2015 through December 31, 2015. This financial information may not be directly comparable to the prior periods as it covers a shorter time frame.


34



See Note 19 to the consolidated financial statements included as part of this report for our quarterly financial data. See Note 1 and Note 3 to the consolidated financial statements included as part of this report for information concerning significant accounting policies and acquisitions, respectively.

35



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

Introduction

On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 or August 31 of each year. The following discussion and analysis was prepared to supplement information contained in the accompanying consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of December 31, 2018, and its results of operations for the years ended December 31, 2018, December 31, 2017, and December 31, 2016.  It should be read in conjunction with the "Selected Financial Data" and the accompanying audited consolidated financial statements and related notes thereto contained in this Annual Report on Form 10-K. The unaudited results of operations for the year ended December 31, 2015 were derived from data previously reported in the Company's Transition Report on Form 10-K as filed with the SEC on April 22, 2016.

This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties.  See the "Cautionary Statement Concerning Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K.  Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements.  Factors that might cause such differences include, but are not limited to, those discussed in "Risk Factors."  We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

As of January 1, 2017, our natural gas processing agreements with DCP Midstream were modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2018 and 2017 with prior periods.

Overview

SRC Energy Inc. is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be 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, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure, long reserve life, and multiple service providers.

Our oil and natural gas activities are focused in the Wattenberg Field, in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell formation as well as the three benches of the Niobrara formation, which are all characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 82% of our proved developed reserves and anticipate operating a majority of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for oil, natural gas, and NGLs are inherently volatile.  To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five fiscal years.

 
Year Ended December 31,
 
Year Ended August 31,
 
2018
 
2017
 
2016
 
2015
 
2015
 
2014
Average NYMEX prices
 
 
 
 
 
 
(unaudited)
 
 
 
 
Oil (per Bbl)
$
64.94

 
$
50.93

 
$
43.20

 
$
48.73

 
$
60.65

 
$
100.39

Natural gas (per Mcf)
$
3.09

 
$
3.00

 
$
2.52

 
$
2.58

 
$
3.12

 
$
4.38


36




For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.
 
Year Ended December 31,
 
2018
 
2017
 
2016
Oil (NYMEX WTI)
 
 
 
 
 
Average NYMEX Price
$
64.94

 
$
50.93

 
$
43.20

Realized Price *
$
57.79

 
$
44.35

 
$
34.43

Differential *
$
(7.15
)
 
$
(6.58
)
 
$
(8.77
)
 
 
 
 
 
 
Gas (NYMEX Henry Hub)
 
 
 
 
 
Average NYMEX Price
$
3.09

 
$
3.00

 
$
2.52

Realized Price *
$
2.09

 
$
2.33

 
$
2.44

Differential *
$
(1.00
)
 
$
(0.67
)
 
$
(0.08
)
 
 
 
 
 
 
NGL Realized Price
$
19.12

 
$
17.10

 
$

* Adjusted to include the effect of transportation and gathering expenses.
    
Market conditions in the Wattenberg Field require us to sell oil and natural gas at prices less than the prices posted by the NYMEX. The differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. With regard to the sale of oil, substantially all of the Company's first quarter 2017 oil production was sold to the counterparties of its firm sales commitments. Beginning in the second quarter of 2017 and continuing through the current period, the Company's oil production exceeded its firm sales commitments, and the surplus oil production was sold at a reduced differential as compared to our committed volumes.

Our revenues, results of operations, profitability, future growth, and carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production. There has been significant volatility in the price of oil and natural gas since mid-2014.  During the year ended December 31, 2018, the NYMEX-WTI oil price ranged from a high of $77.41 per Bbl on June 27, 2018 to a low of $44.48 per Bbl on December 27, 2018, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.55 per MMBtu on February 12, 2018 to a high of $4.84 per MMBtu on November 14, 2018. As reflected in published data, the price for NYMEX-WTI oil settled at $60.46 per Bbl on Friday, December 29, 2017.  Comparably, the price of oil settled at $45.15 per Bbl on Friday, December 28, 2018, a decline of 25% from December 31, 2017. NYMEX-Henry Hub natural gas traded at $2.95 per Mcf on December 29, 2017, but increased approximately 12% as of December 28, 2018 to $3.30. While we use NYMEX-Henry Hub to calculate our natural gas differentials, our natural gas sales tend to trend more closely with Colorado Interstate Gas – Rocky Mountains as published in Inside FERC’s Gas Market Report, published by Platts ("CIG"). Average CIG prices for the fourth quarter of 2018 increased to $3.06 from $2.42 in the first quarter of 2018, and the basis difference for CIG to NYMEX-Henry Hub remained flat.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and impact the calculation of the "ceiling test" required under the accounting principles for companies following the "full cost" method of accounting.  At December 31, 2018, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.


37



Core Operations        

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of December 31, 2018:
Vertical Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
624

 
601

 
183

 
56

 
807

 
657

Horizontal Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
406
 
384

 
314

 
59

 
720

 
443


In addition to the producing wells summarized in the preceding table, as of December 31, 2018, we were the operator of 50 gross (44 net) wells in progress. As of December 31, 2018, we are participating in 12 gross (1.6 net) non-operated horizontal wells in progress.

As we develop our acreage through horizontal drilling, we have an active program for plugging and reclaiming the vast majority of the operated vertical wellbores. During the year ended December 31, 2018, we reclaimed 203 wells and returned the associated surface acreage to the property owners.

Properties

As of December 31, 2018, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott, were 88.0 MMBbls of oil and condensate, 771.9 Bcf of natural gas, and 89.1 MMBbls of natural gas liquids. As of December 31, 2018, we had approximately 95,200 gross and 86,200 net acres under lease in the Wattenberg Field. We also have non-core leasehold in other areas of Colorado and southwest Nebraska approximating 181,200 gross and 159,500 net acres, respectively.

Production

For the year ended December 31, 2018, our average net daily production increased to 50,543 BOED as compared to 34,194 BOED for the year ended December 31, 2017. By comparison, our production increased from 11,670 BOED for the year ended December 31, 2016 to 34,194 BOED for the year ended December 31, 2017. As of December 31, 2018, approximately 92% of our daily operated production was from horizontal wells.

Significant Developments

Acquisitions and Trades

In September 2018, the Company completed the second closing contemplated by the purchase and sale agreement relating to our 2017 acquisition of approximately 30,200 net acres in the Greeley-Crescent development area in Weld County, Colorado. At the second closing, we acquired the operated vertical and horizontal wells. The effective date for this second closing was September 1, 2018. The purchase and sale agreement for the GCII Acquisition was signed in November 2017, and the first closing was completed in December 2017.The total purchase price for the second closing was $96.9 million, composed of cash of $64.2 million and assumed liabilities of $32.7 million. The assumed liabilities included $25.8 million for asset retirement obligations.

In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for $37.2 million in cash and the assumption of certain liabilities for a total purchase price of $37.5 million. The acreage increased our working interest in existing operations and planned wells.

In September and November 2018, the Company completed two trades with other parties totaling approximately 4,700 net acres. These transactions further enhance the contiguous nature of the Company's acreage position.


38



Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate (sometimes referred to as the "Revolver") to provide us with liquidity that can be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2018, the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of $500 million, and a borrowing base limitation of $650 million. The borrowing base is subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including substantially all of our producing wells and developed oil and gas leases, and bears a variable interest rate on borrowings with the effective rate varying with utilization.

Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return. Should commodity prices weaken or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher, we may choose to accelerate drilling and completion activities.

During the year ended December 31, 2018, we drilled 117 operated horizontal wells and turned 95 operated horizontal wells to sales. As of December 31, 2018, the Company had 23 gross (22 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the first quarter of 2019. As of December 31, 2018, we are the operator of 50 gross (44 net) horizontal wells in progress. For 2019, we expect to drill 99 gross (90 net) operated horizontal wells and complete approximately 68 gross (62 net) operated horizontal wells with mostly mid-length and long laterals targeting the Codell and Niobrara zones.

For the year ended December 31, 2018, we participated in completion activities on 57 gross (13 net) non-operated horizontal wells. As of December 31, 2018, we are participating in 12 gross (1.6 net) non-operated horizontal wells in progress.

Trends and Outlook

NYMEX-WTI oil traded at $60.46 per Bbl on December 29, 2017, but has since declined approximately 25% as of December 28, 2018 to $45.15. NYMEX-Henry Hub natural gas traded at $2.95 per Mcf on December 29, 2017, but increased approximately 12% as of December 28, 2018 to $3.30. NYMEX-WTI oil prices increased during the first nine months of 2018, but fell significantly during the fourth quarter. If oil prices decrease, this could (i) reduce our cash flow which could, in turn, reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) reduce our Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) reduce the number of oil and gas prospects which have reasonable economic returns, (iv) cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) result in marginally productive oil and natural gas wells being shut-in as non-commercial, and (vi) cause ceiling test impairments.

We continually focus on managing drilling and completion costs through a combination of well design optimization, reductions in the average days to drill, and employment of current technological advancements. This focus on cost management helps support well-level economics under varying oil and natural gas pricing environments.

Midstream companies that operate the natural gas processing facilities and gathering pipelines in the Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. From time to time, our production has been, and may continue to be, adversely impacted by a lack of available processing capacity, which results in high natural gas gathering line pressures and an inability to maintain consistent production flows. As a result of DCP Midstream’s high gathering system operating pressures, a system-wide volume allocation was implemented limiting each producer’s throughput. Our 2018 results were impacted by this processing capacity allocation and the continuation of regionalized high line pressures stemming from a lack of associated field compression. Further exacerbating the midstream constraints were above average temperatures in Colorado in June and continuing into July as well as unplanned shutdowns of natural gas processing facilities. As a result, many of the Company's wells could not be produced consistently, and the Company was unable to turn recently completed wells to sales as desired. 

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream is developing multiple projects including new processing plants, an expansion of its low and high pressure gathering systems, additional compression, and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed

39



to support the expansion of natural gas gathering and processing capacity through agreements that impose baseline and incremental volume commitments, which we are currently exceeding.  The initial plans included a new 200 MMcf per day processing plant ("Mewbourn 3"), and the expansion of a related gathering system, which became operational in August 2018. Through the same framework, all of the parties agreed to a development plan to add another 200 MMcf per day plant ("O'Connor 2") as well as an incremental 100 MMcf per day of bypass, that is expected to be in service in the second and third quarters of 2019. In addition, DCP Midstream has announced that they secured the land and permits for the the development of a third facility ("Bighorn"), which could have processing capacity up to 1 Bcf per day, including bypass, which is expected to be placed into service in phases with the initial in-service date in 2020.

We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe these gathering lines have several benefits, including a) reduced need to use trucks, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines are currently being expanded, we have experienced and expect to continue to experience some delays in placing our pads on production.

Oil pipeline takeaway capacity utilization has increased as oil production in the basin continues to grow. Furthermore, the capacity will decrease early in the second quarter of 2019 when a portion of a third-party crude oil pipeline system is converted to NGL service. To address the projected demand for additional capacity, several open seasons have been announced for the expansion of certain interstate pipelines servicing the Wattenberg Field. We continuously strive to reduce the negative differential realized on our oil production depending on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."

For 2019, we expect to drill 99 gross operated horizontal wells with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate that total capital expenditures, including operated drilling and completion costs, limited leasehold acquisition costs and selected non-operated drilling and completion costs, will be between $425 million and $450 million and will lead to an increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Our initial estimates is that full-year 2019 production will average between 59,000 BOED and 62,000 BOED with oil making up 42% - 45% of production.

Other than the foregoing, we do not know of any trends, events, or uncertainties that have had, during the periods covered by this report, or are reasonably expected to have, a material impact on our sales, revenues, expenses, liquidity, or capital resources.

Results of Operations

Material changes of certain items in our consolidated statements of operations included in our consolidated financial statements for the periods presented are discussed below.

For the year ended December 31, 2018 compared to the year ended December 31, 2017

For the year ended December 31, 2018, we reported net income of $260.0 million compared to net income of $142.5 million during the year ended December 31, 2017. Net income per basic and diluted share was $1.07 for the year ended December 31, 2018 compared to net income per basic and diluted share of $0.69 for the year ended December 31, 2017.

40



Oil and Natural Gas Production and Revenues - For the year ended December 31, 2018, we recorded total oil, natural gas, and NGL revenues of $645.6 million compared to $362.5 million for the year ended December 31, 2017, an increase of $283.1 million or 78%. The following table summarizes key production and revenue statistics:
 
Year Ended December 31,
 
 
 
2018
 
2017
 
Change
Production:
 
 
 
 
 
Oil (MBbls)
8,392

 
5,824

 
44
 %
Natural Gas (MMcf)
37,123

 
24,834

 
49
 %
NGLs (MBbls) 1
3,869

 
2,518

 
54
 %
MBOE
18,448

 
12,481

 
48
 %
    BOED
50,543

 
34,194

 
48
 %
 
 
 
 
 
 
Revenues (in thousands):
 
 
 
 
 
Oil
$
494,052

 
$
261,505

 
89
 %
Natural Gas
77,628

 
57,956

 
34
 %
NGLs
73,961

 
43,055

 
72
 %
 
$
645,641

 
$
362,516

 
78
 %
Average sales price:
 
 
 
 
 
Oil 1
$
57.79

 
$
44.35

 
30
 %
Natural Gas 1
$
2.09

 
$
2.33

 
(10
)%
NGLs
$
19.12

 
$
17.10

 
12
 %
BOE 1
$
34.50

 
$
28.79

 
20
 %
1 Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas and NGL production for the year ended December 31, 2018 averaged 50,543 BOED, an increase of 48% over average production of 34,194 BOED in the year ended December 31, 2017. From December 31, 2017 to December 31, 2018, our well count increased by 175 net horizontal wells, growing our reserves and daily production totals. The 48% increase in production and the 20% increase in average sales prices resulted in a significant increase in revenues.

LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 
Year Ended December 31,
 
2018
 
2017
Production costs
$
42,778

 
$
18,900

Workover
513

 
596

Total LOE
$
43,291

 
$
19,496

 
 
 
 
Per BOE:
 
 
 
Production costs
$
2.32

 
$
1.51

Workover
0.03

 
0.05

Total LOE
$
2.35

 
$
1.56


Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the year ended December 31, 2018, we experienced increased production expense compared to the year ended December 31, 2017 primarily due to an increase in net operated wells. In addition, elevated line pressures temporarily drove operating costs on a unit basis higher in the second and third quarters of 2018 as the Company incurred incremental costs without the typical benefit of flush production from its new wells.

Transportation and gathering - Transportation and gathering was $9.1 million, or $0.50 per BOE, for the year ended December 31, 2018, compared to $3.2 million for the year ended December 31, 2017. In the first half of 2017, a majority of the

41



Company's production was delivered to the purchaser at the wellhead whereas in 2018 the Company increased the proportion of its production that is sold and delivered at the downstream interconnect. This has the effect of increasing both the net price received for the production and transportation and gathering costs. While costs attributable to volumes sold at the interconnect of the pipeline are reported as an expense, the Company analyzes these charges on a net basis within revenue for comparability with wellhead sales.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $59.8 million, or $3.24 per BOE, for the year ended December 31, 2018, compared to $36.3 million, or $2.91 per BOE, for the year ended December 31, 2017. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 9.3% and 10.0% for the years ended December 31, 2018 and 2017, respectively.

DD&A - The following table summarizes the components of DD&A:
 
Year Ended December 31,
(in thousands)
2018
 
2017
Depletion of oil and gas properties
$
175,441

 
$
109,287

Depreciation and accretion
4,332

 
3,022

Total DD&A
$
179,773

 
$
112,309

 
 
 
 
DD&A expense per BOE
$
9.74

 
$
9.00


For the year ended December 31, 2018, DD&A was $9.74 per BOE compared to $9.00 per BOE for the year ended December 31, 2017. The increase in the DD&A rate was the result of recent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, whereby the ratio of production volumes for the quarter to the beginning of the quarter estimated total reserves determines the depletion rate.

Goodwill impairment - During the year ended December 31, 2018, we recorded a non-cash impairment of our goodwill of $40.7 million, reducing the carrying value of goodwill to zero. See further discussion in Note 1 to our consolidated financial statements.

General and Administrative ("G&A") - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 
Year Ended December 31,
(in thousands)
2018
 
2017
G&A costs incurred
$
51,505

 
$
43,338

Capitalized costs
(12,887
)
 
(10,373
)
Total G&A
$
38,618

 
$
32,965

 
 
 
 
Non-Cash G&A
$
12,287

 
$
11,225

Cash G&A
26,331

 
21,740

Total G&A
$
38,618

 
$
32,965

 
 
 
 
Non-Cash G&A per BOE
$
0.67

 
$
0.90

Cash G&A per BOE
1.43

 
1.74

G&A Expense per BOE
$
2.10

 
$
2.64


G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $38.6 million for the year ended December 31, 2018 were 17% higher than G&A for the year ended December 31, 2017. This increase is primarily due to a 20% increase in employee headcount from 122 at December 31, 2017 to 147 at December 31, 2018. Additionally, G&A for the year ended December 31, 2018 was elevated by expenses incurred in support of Colorado oil and gas legislative activities during the third and fourth quarter of 2018.


42



Our G&A expense for the year ended December 31, 2018 includes stock-based compensation of $12.3 million compared to $11.2 million for the year ended December 31, 2017.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the year ended December 31, 2017 to the year ended December 31, 2018 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivatives - As more fully described in "-Liquidity and Capital Resources-Oil and Gas Commodity Contracts," we use commodity contracts to help mitigate the risks inherent in the volatility of oil and natural gas prices. For the year ended December 31, 2018, we realized a cash settlement loss of $19.4 million. In 2017, we realized a cash settlement gain of $39.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts.

In addition, for the year ended December 31, 2018, we recorded an unrealized gain of $42.8 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the year ended December 31, 2017, we reported an unrealized loss of $4.3 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported income tax expense of $38.0 million for the year ended December 31, 2018, calculated at an effective tax rate of 13%. In 2017, we reported income tax benefit of $0.1 million, calculated at an effective tax rate of 0%. As explained in more detail below, during the year ended December 31, 2017, the effective tax rate was substantially reduced by the recognition of a full valuation allowance on the net deferred tax asset. For 2018, the effective tax rate differed from the statutory rate due primarily to the release of valuation allowances previously recorded against deferred tax assets.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of December 31, 2017. However in 2018, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carryforward and have therefore included it in our inventory of deferred tax assets as of December 31, 2018. This conclusion was based upon the Company’s cumulative positive net income for the three-year period ended December 31, 2018.

For the year ended December 31, 2017 compared to the year ended December 31, 2016

For the year ended December 31, 2017, we reported net income of $142.5 million compared to net loss of $219.2 million during the year ended December 31, 2016. Net income per basic and diluted share was $0.69 for the year ended December 31, 2017 compared to net loss per basic and diluted share of $1.26 for the year ended December 31, 2016.

43



Oil and Natural Gas Production and Revenues - For the year ended December 31, 2017, we recorded total oil, natural gas, and NGL revenues of $362.5 million compared to $107.1 million for the year ended December 31, 2016, an increase of $255.4 million or 238%. The following table summarizes key production and revenue statistics:
 
Year Ended December 31,
 
 
 
2017
 
2016
 
Change
Production:
 
 
 
 
 
Oil (MBbls)
5,824

 
2,257

 
158
 %
Natural Gas (MMcf)
24,834

 
12,086

 
105
 %
NGLs (MBbls) 1
2,518

 

 
nm

MBOE
12,481

 
4,271

 
192
 %
    BOED
34,194

 
11,670

 
193
 %
 
 
 
 
 
 
Revenues (in thousands):
 
 
 
 
 
Oil
$
261,505

 
$
77,699

 
237
 %
Natural Gas
57,956

 
29,450

 
97
 %
NGLs 1
43,055

 

 
nm

 
$
362,516

 
$
107,149

 
238
 %
Average sales price:
 
 
 
 
 
Oil 2
$
44.35

 
$
34.43

 
29
 %
Natural Gas
$
2.33

 
$
2.44

 
(5
)%
NGLs 1
$
17.10

 
$

 
nm

BOE 2
$
28.79

 
$
25.09

 
15
 %
1 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.
2 Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas, and NGL production for the year ended December 31, 2017 averaged 34,194 BOED, an increase of 193% over average production of 11,670 BOED in the year ended December 31, 2016. From December 31, 2016 to December 31, 2017, our well count increased by 140 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 192% increase in production and the 15% increase in average sales prices resulted in a significant increase in revenues.

LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 
Year Ended December 31,
 
2017
 
2016
Production costs
$
18,900

 
$
19,251

Workover
596

 
698

Total LOE
$
19,496

 
$
19,949

 
 
 
 
Per BOE:
 
 
 
Production costs
$
1.51

 
$
4.51

Workover
0.05

 
0.16

Total LOE
$
1.56

 
$
4.67


Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the year ended December 31, 2017, we experienced decreased production expense compared to the year ended December 31, 2016 primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and the continued consolidation of our operations into a more central geographic operating area. Unit operating costs benefited from larger volumes of early production on the 101 net horizontal wells turned to sales during the

44



year ended December 31, 2017.

Transportation and gathering - During 2017, the Company entered into new gathering agreements which resulted in new transportation and gathering charges. Transportation and gathering was $3.2 million, or $0.26 per BOE, for the year ended December 31, 2017, compared to nil for the year ended December 31, 2016. While reported as an expense, the Company analyzes these charges on a net basis within revenue.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $36.3 million, or $2.91 per BOE, for the year ended December 31, 2017, compared to $5.7 million, or $1.34 per BOE, for the year ended December 31, 2016. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 10.0% and 5.3% for the years ended December 31, 2017 and 2016, respectively. During the year ended December 31, 2017, the Company adjusted its estimates for production taxes to reflect significant increases in production. During the year ended December 31, 2016, the Company reduced its estimate for ad valorem taxes, resulting in an approximate $3.6 million reduction to our production taxes.

DD&A - The following table summarizes the components of DD&A:
 
Year Ended December 31,
(in thousands)
2017
 
2016
Depletion of oil and gas properties
$
109,287

 
$