10-K 1 ren-10k_20171231.htm 10-K ren-10k_20171231.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2017

OR

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

Commission File No. 001-34464

 

RESOLUTE ENERGY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

  

Delaware

 

27-0659371

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 

1700 Lincoln Street, Suite 2800

Denver, CO

 

80203

(Address of principal executive offices)

 

(Zip Code)

Registrant’s telephone number, including area code: (303) 534-4600

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

 

Title of Each Class

 

Name of Exchange on Which Registered

Common Stock, par value $0.0001 per share

 

New York Stock Exchange

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

 

 

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES  NO 

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES  NO 

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). YES  NO 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of 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. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

 

 

 

 

 

 

 

Emerging growth company

 

 

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

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

The aggregate market value of registrant’s common stock held by non-affiliates on June 30, 2017, computed by reference to the price at which the common stock was last sold as posted on the New York Stock Exchange, was $629.0 million.

As of February 28, 2018, 23,066,559 shares of the Registrant’s $0.0001 par value Common Stock were outstanding.

The following documents are incorporated by reference herein: Portions of the definitive Proxy Statement of Resolute Energy Corporation to be filed pursuant to Regulation 14A of the general rules and regulations under the Securities Exchange Act of 1934, as amended, for the 2018 annual meeting of stockholders (“Proxy Statement”) are incorporated by reference into Part III of this Form 10-K.

 

 

 


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” as that term is defined in the Private Securities Litigation Reform Act of 1995. The use of any statements containing the “expect,” “estimate,” “project,” “budget,” “forecast,” “anticipate,” “intend,” “plan,” “may,” “will,” “could,” “should,” “poised,” “believes,” “predicts,” “potential,” “continue,” or similar expressions are intended to identify such statements; however the absence of these words does not mean the statements are not forward-looking. Forward-looking statements included in this report relate to, among other things, anticipated production in 2018; anticipated gas to oil ratios in 2018; anticipated lease operating expense in 2018; anticipated general and administrative expense in 2018; our production and cost guidance for 2018; anticipated capital expenditures and activity in 2018; future leverage ratios; the impact and amount of contingency payments from the Aneth Field purchaser; potential proceeds from a midstream transaction with the Bronco properties; future earnout payments; future infrastructure and other capital projects; our financial condition and management of the Company in the current commodity price environment, including expectations regarding price fluctuations; future financial and operating results; liquidity and availability of capital; future borrowing base adjustments and the effect thereof; future pad drilling timing and plans and expected resulting cost savings and production impact; future production, reserve growth and decline rates; our plans and expectations regarding our development activities including drilling and completing wells, the number of such potential projects, locations and anticipated acreage held by production by the end of 2018; the potential impact of well interference and the effectiveness of operational adjustments to mitigate it; the prospectivity of our properties and acreage; the expected benefits of the Aneth Disposition (defined below); and the anticipated accounting treatment of various activities. Although we believe that these statements are based upon reasonable current assumptions, no assurance can be given that the future results covered by the forward-looking statements will be achieved. Forward-looking statements can be subject to risks, uncertainties and other factors that could cause actual results to differ materially from future results expressed or implied by the forward-looking statements. The forward-looking statements in this report are primarily, although not exclusively, located under the heading “Risk Factors.” All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement. Factors that could cause actual results to differ materially from our expectations include, among others, those factors referenced in the “Risk Factors” section of this report and such things as:

 

uncertainties regarding future actions that may be taken by Monarch Alternative Capital LP in furtherance of its nomination of director candidates for election at the Company’s 2018 annual meeting of stockholders;

 

potential operational disruption caused by the actions of stockholder activists;

 

the Company’s ability to successfully implement its strategy to create long-term stockholder value;

 

volatility of oil and gas prices, including extended periods of depressed prices that would adversely affect our revenue, income, cash flow from operations and liquidity and the discovery, estimation and development of, and our ability to replace oil and gas reserves;

 

a lack of available capital and financing, including the capital needed to pursue our operations and other development plans for our properties, on acceptable terms, including as a result of a reduction in the borrowing base under our revolving credit facility;

 

our ability to achieve the growth and benefits we expect from our acquisitions;

 

our ability to achieve the benefits we expect from the Aneth Disposition;

 

the success of the development plan for and production from our oil and gas properties;

 

the completion, timing and success of drilling on our properties;

 

the potential for downspacing, infill or multi-lateral drilling in the Permain Basin or obstacles thereto;

 

the completion and success of exploratory drilling on our properties;

 

the timing and amount of future production of oil and gas;

 

risks related to our level of indebtedness;

 

our ability to fulfill our obligations under our revolving credit facility, the senior notes and any additional indebtedness we may incur;

 

constraints imposed on our business and operations by our revolving credit facility and senior notes which may limit our ability to execute our business strategy;

 

future write downs of reserves and the carrying value of our oil and gas properties;

 

acquisitions and other business opportunities (or lack thereof) that may be presented to and pursued by us, and the risk that any opportunity currently being pursued will fail to consummate or encounter material complications;

 

risks associated with unanticipated liabilities assumed, or title, environmental or other problems resulting from, our acquisitions;

 

our future cash flow, liquidity and financial position;

 

the success of our business and financial strategy, derivative strategies and plans;


 

risks associated with rising interest rates;

 

inaccuracies in reserve estimates;

 

operational problems, or uninsured or underinsured losses affecting our operations or financial results;

 

the amount, nature and timing of our capital expenditures, including future development costs;

 

the impact of any U.S. or global economic recession;

 

the ability to sell or otherwise monetize assets at values and on terms that are advantageous to us;

 

availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;

 

risks and uncertainties in the application of available horizontal drilling and completion techniques;

 

uncertainty surrounding occurrence and timing of identifying drilling locations and necessary capital to drill such locations;

 

our ability to fund and develop our estimated proved undeveloped reserves;

 

the effect of third party activities on our oil and gas operations, including our dependence on third party-owned water sourcing, gathering and disposal, oil gathering and gas gathering and processing systems;

 

the concentration of our credit risk as the result of depending on one primary oil purchaser and one primary gas purchaser in the Delaware Basin;

 

our operating costs and other expenses;

 

our success in marketing oil and gas;

 

the impact and costs related to compliance with, or changes in, laws or regulations governing our oil and gas operations and the potential for increased regulation of drilling and completion techniques, underground injection or fracing operations;

 

our relationship with the local communities in the areas where we operate;

 

the availability of water and our ability to adequately treat and dispose of water while and after drilling and completing wells;

 

potential regulation of waste water injection intended to address seismic activity;

 

the concentration of our producing properties in a single geographic area;

 

potential changes to regulations affecting derivatives instruments;

 

environmental liabilities under existing or future laws and regulations;

 

the impact of climate change regulations on oil and gas production and demand;

 

potential changes in income tax deductions and credits currently available to the oil and gas industry;

 

the impact of weather and the occurrence of disasters, such as fires, explosions, floods and other events and natural disasters;

 

competition in the oil and gas industry and failure to keep pace with technological development;

 

actions, announcements and other developments in OPEC and in other oil and gas producing countries;

 

risks relating to our joint interest partners’ and other counterparties’ inability to fulfill their contractual commitments;

 

loss of senior management or key technical personnel;

 

the impact of long-term incentive programs, including performance-based awards and stock appreciation rights;

 

timing of issuance of permits and rights of way, including the effects of any government shut-downs;

 

potential power disruptions or supply limitations in the electrical infrastructure serving our operations;

 

timing of installation of gathering infrastructure in areas of new exploration and development;

 

potential breakdown of equipment and machinery relating to the gathering and compression infrastructure;

 

losses possible from pending or future litigation;

 

cybersecurity risks;

 

the risk of a transaction that could trigger a change of control under our debt agreements;

 

risks related to our common stock, potential declines in stock prices and potential future dilution to stockholders;

 

risk factors discussed or referenced in this report; and

 

other factors, many of which are beyond our control.


Additionally, the Securities and Exchange Commission (“SEC”) requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. From time to time, we may elect to disclose “probable” reserves and “possible” reserves, excluding their valuation, in our SEC filings, press releases and investor presentations. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company applies these definitions when estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserves estimates or potential resources disclosed in our public filings, press releases and investor presentations that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines.

SEC rules prohibit us from including resource estimates in our public filings with the SEC. Our potential resource estimates include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or possible reserves, (ii) other areas to take into account the level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Potential resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon for such purpose. Potential resources might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors. In our press releases and investor presentations, we sometimes include estimates of quantities of oil and gas using certain terms, such as “resource,” “resource potential,” “EUR,” “oil in place,” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC definition of proved, probable and possible reserves. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Resolute. The Company believes its potential resource estimates are reasonable, but such estimates have not been reviewed by independent engineers. Furthermore, estimates of potential resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

Production rates, including “early time” rates, 24-hour peak IP rates, 30-day peak IP rates, 90-day peak IP rates, 60-day peak IP rates, 120-day peak IP rates and 150-day peak IP rates for both our wells and for those wells that are located near to our properties are limited data points in each well’s productive history and represent three stream gross production. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, EUR or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as leaseline offsets. Standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Midlength laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,000 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet.

You are urged to consider closely the disclosure in this Annual Report on Form 10-K, in particular the factors described under “Risk Factors.”

 

 

 


TABLE OF CONTENTS

 

PART I --

 

 

  

 

 

Item 1. and 2.

 

Business and Properties

  

1

 

Item 1A.

 

Risk Factors

  

19

 

Item 1B.

 

Unresolved Staff Comments

  

42

 

Item 3.

 

Legal Proceedings

  

41

 

Item 4.

 

Mine Safety Disclosures

  

41

 

PART II --

 

 

  

 

 

Item 5.

 

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  

42

 

Item 6.

 

Selected Financial Data

  

46

 

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

47

 

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

63

 

Item 8.

 

Financial Statements and Supplementary Data

  

64

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

63

 

Item 9A.

 

Controls and Procedures

  

63

 

Item 9B.

 

Other Information

  

64

 

PART III --

 

 

  

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

64

 

Item 11.

 

Executive Compensation

  

64

 

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  

64

 

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

  

64

 

Item 14.

 

Principal Accounting Fees and Services

  

64

 

PART IV --

 

 

  

 

 

Item 15.

 

Exhibits, Financial Statement Schedules

  

65

 

Item 16.

 

Form 10-K Summary

  

65

 

 

 

 

 

Signatures

  

72

 

 

 

i

 


Part I

ITEMS 1. and 2.    BUSINESS and properties

As used in this Annual Report on Form 10-K, unless the context otherwise requires or indicates, references to “Resolute,” “the Company,” “we,” “our,” “ours,” and “us” refers to Resolute Energy Corporation and its subsidiaries.

Business Overview

Resolute Energy Corporation, a Delaware corporation incorporated on July 28, 2009, is a publicly traded, independent oil and gas company engaged in the exploitation, development, exploration for and acquisition of oil and gas properties with assets located in the Delaware Basin in west Texas (the “Permian Properties”, “Permian Basin Properties” or “Delaware Basin”). Our development activity is focused on our 27,100 gross (21,100 net) acres, approximately 90% of which is located in what we believe to be the core of the Wolfcamp horizontal play in northern Reeves County, Texas. Our corporate strategy is to drive organic growth in production, cash flow and reserves through development of our Reeves County acreage and to pursue opportunistic acquisitions in the Delaware Basin.

On November 6, 2017, Resolute closed on the disposition of our Aneth Field Properties located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”) (the “Aneth Disposition”) to an affiliate of Elk Petroleum Limited (“Elk”). The historical results of operations of the Aneth Field Properties prior to the disposition are contained in our financial position and results as of December 31, 2017, and for the twelve months ended December 31, 2017.

During 2017 oil sales comprised approximately 84% of revenue, and our December 31, 2017, estimated net proved reserves were approximately 53.4 million barrels of oil equivalent (“MMBoe”), of which approximately 49% were classified as proved developed producing reserves (“PDP”). Approximately 47% of our estimated net proved reserves were oil and approximately 70% were oil and natural gas liquids (“NGL”). The December 31, 2017, pre-tax present value discounted at 10% (“PV-10”) of our net proved reserves was $434 million and the standardized measure of our estimated net proved reserves was $433 million. For additional information about the calculation of our PV-10 and standardized measure, please read “Business and Properties — Estimated Net Proved Reserves.”

For 2017 the Board initially approved a capital expenditure plan primarily focused on a two rig drilling program spudding 22 gross wells in the Delaware Basin. This original capital program did not contemplate the Delaware Basin Bronco Acquisition or any related capital activities. Due to the continuing efficiency of our drilling and with the closing of the Aneth Disposition, our Board approved an expansion to our 2017 capital program, which allowed us to retain the rigs and completion crews that provided these excellent results. As a result of increased drilling and completion efficiency, Resolute was able to complete drilling operations on 25 wells and had three wells drilling over year-end, while still completing and bringing on line 21 wells in these areas. Excluding the three wells that were drilling over year-end, Resolute carried six drilled but uncompleted wells (“DUCs”) into 2018.

Resolute’s 2018 board-approved plan includes net capital spending of $365 million to $395 million, including $350 million to $375 million in drilling and completion capital to support two rigs throughout the year, and a third rig which commenced work in late February and is expected to be released in mid-September. Additionally, the Company expects to spend an incremental $42 million to $49 million on field facilities and other corporate capital, and to receive estimated earn-out payments of $27 million to $29 million from Caprock Permian Processing LLC and Caprock Field Services LLC (collectively “Caprock”). Overall, Resolute expects to drill 42 wells during the year and bring 38 wells on production, carry six DUCs and have two wells drilling over year-end 2018.

Each of the three rigs will be primarily pad drilling three-well stacks with all the rigs in the same spacing unit at the same time. Operations will focus in the Sandlot unit in Mustang and the Mitre/Ranger units in Appaloosa, with Wolfcamp Upper A, Lower A, and Upper B as the primary target zones. This approach to pad drilling will provide us with the opportunity to batch complete groups of up to nine wells simultaneously. 

Beginning in late 2017 the Company shifted focus to building an inventory of drilled wells to batch complete. Two completions are expected in first quarter 2018, and in mid-March we will begin completing our first nine-well group. With the first nine-well group coming on line in May and another nine-well group coming on line in July we expect production growth to accelerate in the middle part of the year. Further groups of completed wells are expected to come on line throughout the remainder of the year. 

This 2018 development plan was put in place based on the Company’s experience with the impact of infill drilling on well performance. In estimating its 2018 total production, Resolute believes it has fully incorporated the anticipated effects of frac interference on older wells and the expected modestly reduced production from newly drilled infill wells. In addition the Company has taken into consideration potential operational events that could reduce production further such as power outages, weather, well shut-ins and downstream gas constraints.

1


On February 22, 2017, we closed on the sale of our Denton and South Knowles properties in the Northwest Shelf project area in Lea County, New Mexico, for approximately $14.5 million in cash, subject to customary purchase price adjustments. The proceeds of the sale were used for general corporate purposes. As part of the sale, the Company was also no longer liable for asset retirement obligations of $3.6 million at March 31, 2017.

On April 27, 2017, Resolute Natural Resources LLC (“Resolute Southwest”) entered into a Crude Oil Connection and Dedication Agreement with Caprock Permian Crude LLC (“Caprock Crude”), an affiliate of Caprock. Pursuant to the agreement, Caprock Crude has constructed the gathering systems, pipelines and other infrastructure for the gathering of crude oil from our Mustang and Appaloosa operating areas in exchange for customary fees based on the volume of crude oil produced and delivered. Resolute Southwest has agreed to dedicate and deliver all crude oil produced from its acreage in Mustang and Appaloosa to Caprock Crude for gathering for a term through July 31, 2031, coterminous with our other commercial agreements with Caprock. For the first five years of the agreement, the crude oil will be delivered to Midland Station under a joint tariff arrangement between Caprock Crude and Plains Pipeline, L.P. On April 27, 2017, Resolute Southwest also entered into a Crude Oil Purchase Contract with Plains Marketing, L.P. (“Plains”) providing for the sale to Plains of substantially all of the crude oil produced from the Mustang and Appaloosa areas for a price equal to an indexed market price less a $1.75 differential that will cover the joint tariff payable to Caprock Crude under the Crude Oil Connection and Dedication Agreement.

On May 15, 2017, Resolute Southwest closed on a Purchase and Sale Agreement with CP Exploration II, LLC and Petrocap CPX, LLC pursuant to which Resolute Southwest acquired certain producing and undeveloped oil and gas properties (the “Bronco Assets”) in the Delaware Basin in Reeves County, Texas (the “Delaware Basin Bronco Acquisition”). The acquisition was accounted for as an asset acquisition. The Company acquired these properties for $161.3 million, which it financed substantially with proceeds received from the offering of $125 million of 8.50% Senior Notes due 2020 that closed in May 2017 (the “Incremental Senior Notes”). The properties acquired included approximately 4,600 net acres in Reeves County, Texas, which were considered predominantly unproved, consisting of 2,187 net acres adjacent to the Company’s existing operating area in Reeves County and 2,400 net acres in southern Reeves County.

On November 6, 2017, to complete our repositioning as a pure-play Delaware Basin company, we completed the sale of our Aneth Field Properties. Total consideration will be up to $195 million, comprised of $160 million ($150 million of which was received at closing and $10 million of which was a deposit received in the third quarter 2017), adjusted for normal closing purchase price adjustments and up to an additional $35 million if oil prices exceed certain levels in the three years following the closing. The net proceeds of the Aneth Disposition were used to repay amounts outstanding under our Revolving Credit Facility and for other corporate purposes.

Business Strategies

The key elements of our business strategy include:

Organically Grow Production, Cash Flow and Reserves. Our primary business strategy is to generate growth in production, cash flow and reserves through organic development of the Wolfcamp formation in our Reeves County assets in the Delaware Basin. For 2018 our Board of Directors approved a drilling program drilling 42 gross wells with two and three rigs.  

Pursue Acquisition Opportunities in Delaware Basin. We will continue to seek out attractive opportunities to expand our acreage and inventory of development locations through strategic acquisitions relying on our more than six year operating history in the Delaware Basin and our strong technical team to identify the best opportunities. The Delaware Basin Firewheel Acquisition and the Delaware Basin Bronco Acquisition represent examples of such opportunities.

Improve Corporate Profitability. We will continue to focus on improving the profitability of the Company through a multipronged strategy, including, (a) improved unit operating costs resulting from cost control and increased production, (b) improved well economics as we continue to focus on drilling efficiencies, shift to infill drilling which leverages existing infrastructure and realize economies from a larger sustained drilling program, and (c) focus on improving overhead expenses per unit of production and optimizing efficiency within our corporate organization.

 

Manage Capital Structure. The execution of our 2018 operating plan is expected to lead to organic deleveraging of our balance sheet, as measured by the ratio of debt to Adjusted EBITDA.  We will consider raising additional capital as required to fund accretive, high rate of return projects and attractive acquisition opportunities.  We may also consider potential future issuances of equity to further delever our balance sheet if equity valuations are deemed favorable.

2


Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our 2018 and longer term business strategies, including:

Multiyear Portfolio of Significant Organic Drilling and Development Opportunities in One of the Premier U.S. Oil and Gas Producing Basins. We have a significant inventory of drilling and development locations in Reeves County, Texas, in what we believe to be the core of the Delaware Basin portion of the Permian Basin. This part of the Delaware Basin is a premier U.S. onshore oil and gas resource. We will move to full field development mode while continuing to drill wells across our acreage block and complete wells in multiple landing zones in the Wolfcamp A as well as in the Wolfcamp B and C.

Operational Staff with Deep Expertise. Our operating and technical staff has significant experience in the drilling, completing and operating of horizontal wells. This expertise has led to cost and production enhancements. The work of our operations team has led to reductions in drilling days and enhancements to our completion designs which we believe ultimately result in more productive and economic wells. During 2017, the Company set internal spud-to-TD records of 14 days drilling mid-length laterals in Mustang and 17 days drilling long laterals in Appaloosa.

Operating Control of Our Properties.  Because we are the operator of substantially all of our properties we have the ability to more directly control the timing, scope and costs of our activity. Operatorship of our assets is secured for the foreseeable future, as approximately 89% of our core acreage in the Delaware Basin) (and 77% of our gross acreage) is held by production.

Summary Reserve Information

The following table presents summary information related to our estimated net proved reserves that are derived from our December 31, 2017, reserve report, which was prepared by Resolute and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.

 

 

 

Estimated Net Proved Reserves at December 31, 2017 (MMBoe)

 

 

 

Proved

 

 

Proved

 

 

 

 

 

 

 

 

 

 

2017 Net Daily

 

 

 

Developed

 

 

Developed

 

 

Proved

 

 

Total

 

 

Production

 

 

 

Producing

 

 

Non-Producing

 

 

Undeveloped

 

 

Proved

 

 

(Boe per day)

 

Permian Properties (Total)

 

 

26.0

 

 

 

0.2

 

 

 

27.2

 

 

 

53.4

 

 

 

20,112

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future operating costs ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

512.3

 

 

 

 

 

Future production taxes ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

116.8

 

 

 

 

 

Future capital costs ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

285.4

 

 

 

 

 

Description of Properties

Permian Basin Properties

As of December 31, 2017, we had interests in approximately 27,100 gross (21,100 net) acres in the Permian Basin of Texas. Our principal project area located in the Delaware Basin portion of the Permian Basin, in Reeves County, targets the Wolfcamp formation (the “Delaware Basin Wolfcamp Project”). Our development activity in the Delaware Basin Wolfcamp Project is focused on our 23,600 gross (18,700 net) acreage position. All 53.4 MMBoe of our proved reserves are associated with these assets as of December 31, 2017. During the year, we completed 31 gross (25.0 net) wells, which includes 6 DUCs and 4 non-operated wells, and had 81 gross (66.4 net) producing wells at year-end 2017. As of December 31, 2017, we were in the process of drilling 3 gross (3.0 net) wells and had 6 gross (5.8 net) wells awaiting completion operations. During 2017, average net daily production from the Permian Basin Properties was 20,112 equivalent barrels of oil (“Boe”) and was 74% liquids. See “Business and Properties – Marketing and Customers” for more information on how production from this area is sold. Based on drilling activity to date, approximately 89% of the gross acreage is held by production. We are currently evaluating the 3,500 gross acres and 2,400 net acres we acquired in the Delaware Basin Bronco Acquisition in southern Reeves County for drilling opportunities in the Wolfcamp, Woodford and Barnett formations.

Acquisition of the Delaware Basin Bronco Properties. In May 2017, we acquired certain undeveloped and developed oil and gas properties in the Delaware Basin in Reeves County, Texas in the Delaware Basin Bronco Acquisition. The Company acquired these properties for $161.3 million, which it financed substantially with proceeds received from the offering of Incremental Senior Notes. The properties acquired include approximately 4,600 net acres in Reeves County, Texas, which were considered predominantly unproved, consisting of 2,187 net acres adjacent to the Company’s existing operating area in Reeves County and 2,400 net acres in southern Reeves County.

3


Divestiture of Southeast New Mexico Properties in the Permian Basin. In February 2017 the Company closed on the sale of its Denton and South Knowles properties in the Northwest Shelf project area in Lea County, New Mexico, for approximately $14.5 million in cash, subject to customary purchase price adjustments. The proceeds of the sale were used for general corporate purposes.

Acquisition of Delaware Basin Firewheel Properties. In October 2016 we acquired certain Reeves County interests in the Delaware Basin, for consideration consisting of $90 million in cash and 2,114,523 shares of our common stock, issued to Firewheel Energy, LLC (“Firewheel”) upon the closing of the purchase of the Firewheel properties (the “Firewheel Properties”) in the Delaware Basin Firewheel Acquisition (the “Delaware Basin Firewheel Acquisition”). The cash paid for this acquisition was funded in part by net proceeds from the sale of preferred stock and borrowings on our Revolving Credit Facility.

Divestiture of Midstream Assets in the Delaware Basin. In July 2016 Resolute Southwest entered into a definitive Purchase and Sale Agreement (the “Mustang Agreement”) with Caprock pursuant to which Resolute Southwest and an existing minority interest holder agreed to sell certain gas gathering and produced water handling and disposal systems owned by them in the Mustang project area in Reeves County, Texas, (“Mustang”) for a cash payment of $35 million, plus certain earn-out payments described below.

In July 2016 Resolute Southwest also entered into a definitive Purchase and Sale Agreement (the “Appaloosa Agreement”) with Caprock, pursuant to which Resolute Southwest agreed to sell certain gas gathering and produced water handling and disposal systems owned by Resolute Southwest in the Appaloosa project area in Reeves County, Texas, (“Appaloosa”) for a cash payment of $15 million, plus certain earn-out payments described below.

In August 2016 Resolute Southwest closed the transactions contemplated by the Mustang Agreement and the Appaloosa Agreement. Resolute Southwest received aggregate consideration of approximately $36 million (including earn-out payments earned as of the closing).

In July 2016, in connection with the Appaloosa Agreement and the Mustang Agreement, Resolute Southwest also entered into a definitive Earn-out Agreement (the “Earn-out Agreement”), pursuant to which Resolute Southwest will be entitled to receive certain earn-out payments based on drilling and completion activity in Appaloosa and Mustang through 2020 that will deliver gas and produced water into the system. Earn-out payments for each qualifying well will vary depending on the lateral length of the well and the year in which the well is drilled and completed. In March 2017 the Earn-out Agreement was amended by the parties to provide for an increase in earn-out payments for the wells drilled and completed in 2017. Earn-out payments are contingent on future drilling, and therefore will be recognized when earned.

In connection with the closing of the transactions contemplated by the Appaloosa Agreement and the Mustang Agreement, Resolute Southwest entered into fifteen year commercial agreements with Caprock for gas gathering services and water handling and disposal services for all current and future gas and water produced by Resolute Southwest in Mustang and Appaloosa in exchange for customary fees based on the volume of gas and water produced and delivered. Resolute Southwest has agreed to dedicate and deliver all gas and water produced from its acreage in Mustang and Appaloosa to Caprock for gathering, processing, compression and disposal services for a term of fifteen years.

In April 2017, Resolute Southwest entered into a Crude Oil Connection and Dedication Agreement with Caprock Crude, an affiliate of Caprock. Pursuant to the agreement, Caprock Crude has constructed the gathering systems, pipelines and other infrastructure for the gathering of crude oil from our Mustang and Appaloosa operating areas in exchange for customary fees based on the volume of crude oil produced and delivered. Resolute Southwest has agreed to dedicate and deliver all crude oil produced from its acreage in Mustang and Appaloosa to Caprock Crude for gathering for a term through July 31, 2031, coterminous with our other commercial agreements with Caprock. For the first five years of the agreement, the crude oil will be delivered to Midland Station under a joint tariff arrangement between Caprock Crude and Plains Pipeline, L.P. In April 2017, Resolute Southwest also entered into a Crude Oil Purchase Contract with Plains providing for the sale to Plains of substantially all of the crude oil produced from the Mustang and Appaloosa areas for a price equal to an indexed market price less a $1.75 differential that will cover the joint tariff payable to Caprock Crude under the Crude Oil Connection and Dedication Agreement.

Divestiture of Properties in the Midland Basin. In December 2015 we sold our Gardendale properties in the Midland Basin in Midland and Ector Counties, Texas, for approximately $172 million. In May 2015 we sold our Howard and Martin County properties in the Permian Basin for approximately $42 million.

4


Divestiture of Aneth Field Properties

Aneth Field, a giant legacy oil field in southeast Utah, accounted for 20% of our production during 2017, averaging 4,974 Boe per day, of which 96% was oil.

In November 2017 we completed the sale of our Aneth Field Properties for total consideration of up to $195 million, comprised of $160 million received at closing, adjusted for normal closing purchase price adjustments, and up to an additional $35 million if oil prices exceed certain levels in the three years following the closing.

Divestiture of Wyoming Properties

In October 2015 we sold our Hilight Field interests in the Powder River Basin for approximately $55 million.

Estimated Net Proved Reserves

The following table presents our estimated net proved oil, gas and NGL reserves and the present value of our estimated net proved reserves as of December 31, 2017, 2016 and 2015 according to SEC standards. The standardized measure shown in the table below is not intended to represent the current market value of our estimated oil and gas reserves.

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Net proved developed reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

12,274

 

 

 

30,026

 

 

 

25,672

 

Gas (MMcf)

 

 

46,827

 

 

 

24,209

 

 

 

7,098

 

NGL (MBbl)

 

 

6,136

 

 

 

3,595

 

 

 

1,019

 

MBoe (1)

 

 

26,215

 

 

 

37,656

 

 

 

27,874

 

Net proved undeveloped reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

13,045

 

 

 

13,778

 

 

 

3,076

 

Gas (MMcf)

 

 

47,987

 

 

 

28,238

 

 

 

6,761

 

NGL (MBbl)

 

 

6,173

 

 

 

4,127

 

 

 

1,043

 

MBoe (1)

 

 

27,215

 

 

 

22,611

 

 

 

5,246

 

Total net proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

25,319

 

 

 

43,804

 

 

 

28,747

 

Gas (MMcf)

 

 

94,814

 

 

 

52,448

 

 

 

13,859

 

NGL (MBbl)

 

 

12,309

 

 

 

7,722

 

 

 

2,063

 

MBoe (1)

 

 

53,430

 

 

 

60,267

 

 

 

33,120

 

PV-10 ($ in millions) (2)(3)

 

 

434

 

 

 

344

 

 

 

199

 

Discounted future income taxes ($ in millions)

 

 

(1

)

 

 

 

 

 

 

Standardized measure ($ in millions) (2)(4)

 

 

433

 

 

 

344

 

 

 

199

 

 

 

(1)

Boe is determined using one Bbl of oil or NGL to six Mcf of gas.

(2)

In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, our estimated net proved reserves and standardized measure at December 31, 2017, 2016 and 2015, were determined utilizing prices equal to the twelve-month unweighted arithmetic average using first day of the month prices, resulting in an average Plains Marketing, L.P. posted WTI oil price of $47.79, $39.25 and $46.79 per Bbl and an average Platts Gas Daily El Paso Permian Basin spot gas price of $2.62, $2.31, and $2.45 per MMBtu for the Permian Properties, respectively. Our estimated net proved reserves and standardized measure at December 31, 2016 and 2015 for the Aneth Properties, were determined utilizing prices equal to the respective twelve-month unweighted arithmetic average using the first day of the month prices, resulting in an average NYMEX WTI oil price of $42.75 and $50.28 per Bbl, and an average Platts Gas Daily El Paso San Juan Basin spot gas price of $2.33 and $2.46, respectively.

(3)

PV-10 is a non-GAAP measure and incorporates all elements of the standardized measure, but excludes the effect of income taxes. Management believes that pre-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company’s unique tax position and strategies, can make after-tax amounts less comparable.

(4)

Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC and FASB, less future development costs and production and income tax expenses, discounted at a 10% annual rate to reflect the timing of future net revenue. Calculation of standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Quantitative and Qualitative Disclosures About Market Risk.”

5


The data in the above table are estimates only. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by SEC and FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to the timing of future production, among other factors, which may prove to be inaccurate. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary, perhaps significantly, from the quantities of oil and gas that are ultimately recovered.

As an operator of domestic oil and gas properties, we are required to file Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein, largely attributable to the fact that Form EIA-23 requires that an operator report on the total reserves attributable to wells that it operates, without regard to level of ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis).

Producing oil and gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploitation and development activities or acquisitions, our reserves and production will ultimately decline over time. Please read “Risk Factors — Risks Related to Our Business, Operations and Industry” and “Note 13 — Supplemental Oil and Gas Information (unaudited)” to the audited consolidated financial statements for a discussion of the risks inherent in oil and gas estimates and for certain additional information concerning our estimated proved reserves.

Proved Developed and Undeveloped Reserves. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled within five years into known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Our operated drilling focus in 2017 was to preserve term leasehold acreage in the Permian Basin Properties by drilling both proved and non-proved locations. During 2017, 19,871 net MBoe of proved developed reserves were added to the proved reserves base through a successful blend of both operated and non-operated drilling of 8 gross proved and 16 gross non-proved locations and through the addition of 2 gross producing wells and successful completion of 7 gross DUC locations, 6 operated and 1 non-operated, acquired in the Delaware Basin Bronco Acquisition. We acquired 362 MBoe net of proved developed producing reserves in the Delaware Basin Bronco Acquisition. An incremental 31 gross wells were drilled or completed in 2017 which yielded 19,509 MBoe net of proved developed reserves and 11,939 MBoe net of proved undeveloped reserves through the addition of 15 gross immediate offset proved undeveloped Permian locations. These numbers include 2,722 MBoe of net proved producing reserves and 1,387 MBoe of net proved undeveloped reserves attributable to successful completion of the Delaware Basin Bronco Acquisition DUC wellbores during 2017. The numbers above also include 2017 production of 3,958 net MBoe. An incremental 6,217 net MBoe of proved undeveloped reserves were also added to the proved reserves base during 2017 through the addition of 9 gross locations (6 operated and 3 non-operated) offset to wells drilled prior to 2017. The 9 gross locations were previously uneconomic at lower SEC pricing.

Included in the sale of our Aneth Field Properties in November 2017 were 371 gross (235.3 net) operated oil producing wells and their associated injection wells. Aneth Field accounted for approximately 41% of our total proved reserves at December 31, 2016, of which 99% was oil. In conjunction with the divestiture of Aneth Field, 18,033 MBoe net of total proved developed producing, 2,394 MBoe of net total proved developed non-producing and 2,169 MBoe net of proved undeveloped reserves were removed during 2017. These numbers are net of 2017 Aneth Field production of 1,816 net MBoe.

With respect to the properties included in our prior year reserve reports, we incurred development costs of $133.1 million in 2017 as compared to $31.1 million in 2016. The year over year change in developmental costs is also reflective of our operated drilling focus in 2017 to preserve term leasehold acreage in the Permian Basin. With respect to the total proved value, no proved undeveloped drilling locations are scheduled to be drilled after any corresponding portion of primary term leasehold within each is set to expire.

At December 31, 2017, no proved undeveloped reserves have remained, or are scheduled to remain, undeveloped beyond five years from the booking date.

6


Changes in Proved Reserves

Proved reserves reported by us at December 31, 2017, decreased from those reported at December 31, 2016, as follows:

 

 

 

 

Oil Equivalent

 

 

 

 

 

(MBoe)

 

Proved reserves as of December 31, 2016

 

 

 

 

60,267

 

Production

 

 

 

 

(9,156

)

Extensions, discoveries and other additions

 

 

 

 

31,619

 

Purchases of minerals in place

 

 

 

 

362

 

Sales of minerals in place

 

 

 

 

(23,026

)

Revisions of previous estimates

 

 

 

 

(6,636

)

Proved reserves as of December 31, 2017

 

 

 

 

53,430

 

Proved developed reserves:

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

26,215

 

Proved undeveloped reserves:

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

27,215

 

Production consisted of 7,341 MBoe from the Permian properties during 2017 and 1,816 MBoe from the Aneth Field properties prior to their sale in November 2017.

Extensions, discoveries and other additions in 2017 consisted primarily of 10,741 MBoe net from 16 gross newly drilled Permian wells and 2,722 MBoe net from 7 gross completions of DUC locations acquired in the Delaware Basin Bronco Acquisition together with 11,939 MBoe net from 15 gross immediate offset proved undeveloped Permian locations. These numbers include 2,469 MBoe net of 2017 production. Also included in additions are 6,217 MBoe net of proved undeveloped reserves from 9 gross offset locations to Permian wells drilled prior to 2017 which were uneconomic under previous reports' SEC pricing.

Purchases of minerals in place consisted of 362 MBoe net from 2 gross producing wells acquired in the Delaware Basin Bronco Acquisition closed May 15, 2017.

Sales of minerals in place during 2017 consisted of 431 MBoe net from 36 gross producing wells in the Denton and Knowles South Fields New Mexico divestiture, which closed February 22, 2017, plus 22,595 MBoe net from 371 gross producing wells, and their associated injectors, in the Aneth Field Utah divestiture, which closed November 6, 2017. These numbers are net of 1,847 MBoe net of 2017 production, 32 MBoe net in Denton and Knowles South Fields, and 1,816 MBoe net in Aneth Field.

Revisions of previous estimates of 6,636 MBoe during 2017 were a function of well performance resulting from interference between existing, mature producers and newly drilled wells. The 2018 development plan has been designed to minimize further such interference.

Controls Over Reserve Report Preparation, Technical Qualification and Methodologies Used

Reserve estimates as of December 31, 2017, were prepared by Resolute and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineers. Please read “Risk Factors — Risks Related to Our Business, Operations and Industry” in evaluating the material presented below.

Our reserve report was prepared under the direct supervision of the Company’s Corporate Reserves Manager, Mr. Michael White. Mr. White has more than 33 years of experience in the oil and gas industry including general reservoir engineering, corporate engineering, exploration support and economic analysis support. During his career, Mr. White has resided and worked in Texas, Louisiana, Florida and Colorado. Additionally, he has performed evaluations in other basins in Utah, Wyoming, North Dakota and Washington state. He has onshore, shallow water and deep water project experience. Mr. White has a Bachelor of Science degree in Petroleum Engineering from Mississippi State University (1984) and a Masters of Business Administration from the University of Houston (1997). He is registered as a Professional Engineer in the states of Colorado, Texas and Wyoming. His qualifications meet or exceed the qualifications of reserve estimators and auditors as set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Mr. White is a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.

7


The reserve report is based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information as prescribed by the SEC. The reserve estimates are reviewed internally by Resolute’s senior management prior to an audit of the reserve estimates by NSAI. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advanced production type curve matching, volumetrics, material balance, petrophysics/log analysis and analogy reservoir simulation. Some combination of these methods is used to determine reserve estimates in substantially all of our areas of operation.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for auditing the estimates set forth in the NSAI reserves audit letter incorporated herein is Mr. Joseph J. Spellman. Mr. Spellman, a Licensed Professional Engineer in the State of Texas (No. 73709), has been practicing consulting petroleum engineering at NSAI since 1989 and has more than nine years of prior industry experience. He graduated from University of Wisconsin-Platteville in 1980 with a Bachelor of Science Degree in Civil Engineering. Mr. Spellman meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  He is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

A report of NSAI regarding its audit of the estimates of proved reserves at December 31, 2017, has been filed as Exhibit 99.1 to this report and is incorporated herein.

Production, Price and Cost History

The table below summarizes our operating data for 2017, 2016 and 2015.

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

5,499

 

 

 

3,821

 

 

 

3,271

 

Gas (MMcf)

 

 

12,101

 

 

 

4,811

 

 

 

5,194

 

NGL (MBbl)

 

 

1,640

 

 

 

559

 

 

 

400

 

Combined volumes (MBoe)

 

 

9,156

 

 

 

5,182

 

 

 

4,535

 

Daily combined volumes (Boe per day)

 

 

25,086

 

 

 

14,157

 

 

 

12,427

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

46.30

 

 

$

38.83

 

 

$

42.16

 

Gas ($/Mcf)

 

 

2.11

 

 

 

2.22

 

 

 

2.43

 

NGL ($/Bbl)

 

 

14.20

 

 

 

9.80

 

 

 

10.32

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

8.66

 

 

$

12.29

 

 

$

17.50

 

Production and ad valorem taxes

 

 

2.55

 

 

 

3.14

 

 

 

4.41

 

8


Total estimated proved reserves attributed to the Delaware Basin exceeded fifteen percent of our total proved reserves expressed on an equivalent basis. The Delaware Basin area consists of mineral interests in the Wolfcamp formation. Due to the disposition of Aneth Field in November 2017, the Aneth proved reserve value would not exceed the fifteen percent threshold for disclosure. Therefore, the table below summarizes our operating data for the Delaware Basin for 2017, 2016 and 2015.

Delaware Basin:

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

3,765

 

 

 

1,489

 

 

 

393

 

Gas (MMcf)

 

 

11,612

 

 

 

3,989

 

 

 

1,579

 

NGL (MBbl)

 

 

1,641

 

 

 

549

 

 

 

224

 

Combined volumes (MBoe)

 

 

7,341

 

 

 

2,704

 

 

 

880

 

Daily combined volumes (Boe per day)

 

 

20,112

 

 

 

7,387

 

 

 

2,412

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

48.08

 

 

$

42.25

 

 

$

43.50

 

Gas ($/Mcf)

 

 

2.13

 

 

 

2.40

 

 

 

2.29

 

NGL ($/Bbl)

 

 

14.20

 

 

 

9.64

 

 

 

7.89

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

5.46

 

 

$

4.62

 

 

$

7.47

 

Production and ad valorem taxes

 

 

1.94

 

 

 

2.14

 

 

 

2.67

 

Oil and Gas Wells

The following table sets forth information as of December 31, 2017, relating to the productive wells in which we own a working interest. A well with multiple completions in the same bore hole is considered one well. Wells are considered oil or gas wells according to the predominant production stream, except that a well with multiple completions is considered an oil well if one or more is an oil completion. Productive wells consist of producing wells and wells capable of producing, including wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have a working interest and net wells are the sum of our working interests owned in gross wells.

 

 

Productive Wells(1)

 

 

 

Gross

 

 

Net

 

Oil

 

 

80

 

 

 

66.3

 

Gas

 

 

1

 

 

 

0.1

 

Total

 

 

81

 

 

 

66.4

 

 

 

(1)

We operated 69 gross (64.3 net) productive wells at December 31, 2017.


9


Drilling Activity

The following table sets forth information with respect to exploration, development and extension wells we completed during 2017, 2016 and 2015. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. An extension well is a well drilled to extend the limits of a known reservoir. Fluid injection wells for waterflood and other enhanced recovery projects are not included as gross or net wells.

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Gross exploration wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

 

 

 

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total exploration wells

 

 

 

 

 

 

 

 

 

Gross development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

8

 

 

 

 

 

 

1

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total development wells

 

 

8

 

 

 

 

 

 

1

 

Gross extension wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(3)

 

 

23

 

 

 

14

 

 

 

5

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total extension wells

 

 

23

 

 

 

14

 

 

 

5

 

Total gross wells drilled

 

 

31

 

 

 

14

 

 

 

6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Net exploration wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

 

 

 

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total exploration wells

 

 

 

 

 

 

 

 

 

Net development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

7.7

 

 

 

 

 

 

0.7

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total development wells

 

 

7.7

 

 

 

 

 

 

0.7

 

Net extension wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(3)

 

 

17.3

 

 

 

12.0

 

 

 

1.5

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total extension wells

 

 

17.3

 

 

 

12.0

 

 

 

1.5

 

Total net wells drilled

 

 

25.0

 

 

 

12.0

 

 

 

2.2

 

 

 

(1)

A productive well is a well we have cased. Wells classified as productive do not always result in wells that provide economic production.

(2)

A dry well is a well that is incapable of producing oil or gas in sufficient quantities to justify completion.

(3)

An extension well is a well drilled to extend the limits of a known reservoir.

(4)

Included in the 2015 count is 1 gross (0.1 net) productive extension well sold to Qstar, LLC in May 2015.


10


Acreage

All of our leasehold acreage is categorized as developed or undeveloped. The following table sets forth information as of December 31, 2017, relating to our leasehold acreage.

 

 

 

 

Developed Acreage (1)

 

Area

 

 

 

Gross (2)

 

 

Net (3)

 

Permian Basin (TX)

 

 

 

 

19,010

 

 

 

15,608

 

North Dakota

 

 

 

 

516

 

 

 

99

 

Total

 

 

 

 

19,526

 

 

 

15,707

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped Acreage (4)

 

Area

 

 

 

Gross (2)

 

 

Net (3)

 

Permian Basin (TX)

 

 

 

 

8,048

 

 

 

5,472

 

Total

 

 

 

 

8,048

 

 

 

5,472

 

 

 

(1)

Developed acreage is acreage attributable to wells that are capable of producing oil or gas.

(2)

The number of gross acres is the total number of acres in which we own a working interest and/or unitized interest.

(3)

Net acres are calculated as the sum of our working interests in gross acres.

(4)

Undeveloped acreage includes leases either within their primary term or held by production.

Approximately 900 net acres, 2,200 net acres and 1,000 net acres of undeveloped acreage will revert or expire in 2018, 2019 and 2020, respectively, absent activity to develop such acreage or exercising extension options.

Present Activities

As of December 31, 2017, we were in the process of drilling 3 gross (3.0 net) wells and there were 6 gross (5.8 net) wells waiting on completion operations. Please read “Business and Properties – Descriptions of Properties” for additional discussion regarding our present activities.

Marketing and Customers

Crude Oil Sales

Materially all of our crude oil produced from the Mustang and Appaloosa areas is sold via pipe to Plains under a contract that extends through May 1, 2022. Crude oil produced from our Bronco acreage is sold to Enterprise Crude Oil, LLC under a month-to-month contract with a 30-day cancellation provision.

Gas and NGL Sales

Our gas and NGL from the Mustang and Appaloosa areas are sold to Energy Transfer Partners, L.P. under a fee-based contract that expires December 31, 2018. Gas and NGL produced from the Bronco acreage are sold to Delaware Basin Midstream through ConocoPhillips under a fee-based agreement with a primary term extending until June 30, 2018, and month-to-month thereafter.

Other Factors

The market for our production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil and gas, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of transportation facilities and overall economic conditions. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Derivatives

We enter into derivative transactions from time to time with unaffiliated third parties for portions of our oil and gas production to achieve more predictable cash flows and to reduce exposure to short-term fluctuations in oil and gas prices. For a more detailed discussion, please read –“Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 

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Title to Properties

Producing Property Acquisitions

We believe we have satisfactory title to all of our material proved properties in accordance with standards generally accepted in the industry. Prior to completing an acquisition of proved hydrocarbon leases we perform title reviews on the most significant leases, and, depending on the materiality of properties, we may obtain a new title opinion or review previously obtained title opinions.  

Non-Producing Leasehold Acquisitions

We participate in the normal industry practice of engaging consulting companies to research public records before making payment to a mineral owner for non-producing leasehold. Prior to drilling a well on these properties, a title attorney is engaged to give an opinion of title.

Our properties are also subject to certain other encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and gas industry. We believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with the intended operation of our business.

Competition

Competition is intense in all areas of the oil and gas industry. Major and independent oil and gas companies actively seek to hire qualified employees and bid for desirable properties, as well as for the equipment and labor required to operate and develop such properties. Many of our competitors have financial and personnel resources that are substantially greater than our own and such companies may be able to pay more for productive properties and to define, evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Seasonality

Our operations have not historically been subject to seasonality in any material respect although they may be affected by extreme weather.

Environmental, Health and Safety Matters and Regulation

General. We are subject to various stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment, and protection of human health and safety. These laws and regulations may, among other things:

 

require the acquisition of various permits before drilling commences or other operations are undertaken;

 

require the installation and operation of expensive pollution control equipment;

 

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production, transportation and processing activities;

 

suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas;

 

require remedial measures to mitigate pollution from historical and ongoing operations, such as the closure of pits and plugging of abandoned wells, and the remediation of releases of oil or other substances; and

 

require preparation of an Environmental Assessment and/or an Environmental Impact Statement.

The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunctive action, as well as administrative, civil and criminal penalties. Furthermore, regulatory and overall public scrutiny focused on the oil and gas industry is increasing significantly. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on our business, financial condition and results of operations.

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We believe our operations are in substantial compliance with all existing environmental, health and safety laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. Spills, unpermitted releases or other deviations from applicable requirements may occur in the course of our operations. There can be no assurance that we will not incur substantial costs and liabilities as a result of such spills, unpermitted releases or deviations, including those relating to claims for damage to property, persons and the environment, nor can there be any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on our business, financial condition, or results of operations.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which oil and gas business operations are generally subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position, as well as a discussion of certain matters that specifically affect our operations.

Comprehensive Environmental Response, Compensation, and Liability Act. CERCLA, also known as the “Superfund law,” and comparable state laws may impose strict, joint and several liability, without regard to fault, on classes of persons who are considered to be responsible for the release or threat of release of CERCLA “hazardous substances” into the environment. These persons include the current and former owners and operators of the site where a release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Such claims may be filed under CERCLA, as well as state common law theories or state laws that are modeled after CERCLA. In the course of our operations, we handle materials and generate waste that may fall within CERCLA’s definition of hazardous substances. Therefore, governmental agencies or third parties could seek to hold us responsible for all or part of the costs to clean up a site at which such hazardous substances may have been released or deposited, or other damages resulting from a release.

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous wastes. Under the auspices of the federal EPA, the individual states may administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and many of the other wastes associated with the exploration, development and production of oil or gas are currently exempt under federal law from regulation as RCRA hazardous wastes and instead are regulated as non-hazardous solid wastes. It is possible, however, that oil and gas exploration and production wastes now classified federally as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our operating expenses, which could have a material adverse effect on the results of operations and financial position. Also, in the course of operations, we generate some amounts of industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes under RCRA and state laws and regulations.

Air Emissions. The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. These regulatory programs may require us to install and operate expensive emissions control equipment, modify our operational practices and obtain permits for existing operations. Before commencing construction on a new or modified source of air emissions, these laws may require us to reduce our emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated federal and state laws and regulations.

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In August 2012, the EPA published final rules that established new air emission control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment as well as more stringent leak detection requirements for natural gas processing plants. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, as well as court challenges to the rules, and in 2013 issued revised rules that were responsive to some industry concerns. In December 2014, the EPA issued still further final revisions in response to stakeholder petitions for reconsideration of various regulatory provisions. In June 2016 EPA published final amendments to the 2012 NSPS Subpart OOOO rules as well as new final rules focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The new final rules in NSPS Subpart OOOOa impose requirements for leak detection and repair (“LDAR”), control requirements at hydraulically fractured oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations, among other things. These final revised and new rules issued in 2013, 2014 and 2016 require modifications to our operations as promulgated, increasing our capital and operating costs. In June 2017, the EPA published a proposed rule to stay for 2 years certain provisions of the final rules in NSPS Subpart OOOOa, including the LDAR requirements; however, at this time, the rule remains in effect. Actual air emissions reported for our facilities are in material compliance with the terms of existing air permits and the emissions limits contained in the pending permit applications.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls on the discharge of “pollutants” into waters of the United States, including wetlands, without appropriate permits. Pollutants under the Clean Water Act, are defined to include produced water and sand, drilling fluids, drill cuttings, dredge and fill material, and other substances related to the oil and gas industry. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for unauthorized discharges or noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. They also can impose substantial liability for the costs of removal or remediation associated with discharges of oil, hazardous substances or other pollutants.

The Clean Water Act also regulates stormwater discharges from industrial properties and construction sites, and requires separate permits and implementation of a Stormwater Pollution Prevention Plan (“SWPPP”) establishing best management practices, training, and periodic monitoring of covered activities. Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure (“SPCC”) plans or facility response plans to address potential oil spills.

In September 2013, the EPA and U.S. Army Corps of Engineers released a Connectivity Report that determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. In June 2015, the U.S. Army Corps of Engineers issued a final rule clarifying the definition of “Waters of the United States”. The rule expanded, in a number of ways, the scope of activities subject to Clean Water Act permitting. This rule, known as the Clean Water Rule, was challenged by various parties in multiple federal courts, and as a result of this litigation is currently stayed. In July 2017, the EPA and U.S. Army Corps of Engineers issued a Notice of Intention to review and rescind or revise the Clean Water Rule, and in November 2017, the agencies issued a proposed rule delaying the effective date of the Clean Water Rule for 2 years to allow for such review.

In addition, the Oil Pollution Act of 1990, or OPA, augments the Clean Water Act and imposes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, certain operators of oil and gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to oil spills. In addition, owners and operators of oil and gas facilities may be subject to liability for cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Environmental Impact Assessments. Significant federal decisions, such as the issuance of federal permits or authorizations for many oil and gas exploration and production activities are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment of the potential direct, indirect and cumulative impacts of a proposed project and/or, will prepare a more detailed Environmental Impact Statement that is made available for public review and comment. Any exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay such oil and gas development projects.

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Other Laws and Regulations

Climate Change. Recent scientific studies have suggested that human-caused emissions of gases commonly referred to as “greenhouse gases” or “GHGs”, including CO2, nitrogen dioxide and methane, are contributing to warming of the Earth’s atmosphere, or climate change. Many other nations already have agreed to regulate their emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, (“UNFCCC”) and the Kyoto Protocol, an international treaty (not including the United States) pursuant to which many UNFCCC member countries agreed to reduce their emissions of GHGs to below 1990 levels by 2012, with a subsequent emissions reduction commitment for the period from 2013 through 2020. Although a successor treaty to the Kyoto Protocol has not been developed to date, further GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris (the Paris Agreement). Pursuant to the Paris Agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emission by 2025 against a 2005 baseline and committed to periodically update its pledge in five-year intervals starting in 2020. In response to such studies and international action, the U.S. Congress has considered but not passed legislation to reduce emissions of GHGs; however, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts. v. EPA, the EPA has taken steps to regulate GHG emissions from mobile sources (e.g., cars and trucks) even though Congress has not enacted new legislation specifically addressing GHG emissions. The Court’s holding in Massachusetts v. EPA that GHGs fall under the federal Clean Air Act’s definition of “air pollutant” has also resulted in the regulation and permitting of GHG emissions from major stationary sources under the Clean Air Act, due to EPA’s “endangerment finding” that links global warming to human-caused emissions of GHG, and the EPA’s subsequent GHG Tailoring Rule, which subjects certain major sources of GHG emissions to Title V operating permit and New Source Review permitting requirements for the first time. The permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs will require affected facilities to meet emissions limits that are based on “best available control technology,” which will be established by the permitting agencies on a case-by-case basis. In July 2012, the GHG Tailoring Rule became effective for all new facilities that emit at least 100,000 tons of GHG per year, but the rule was challenged in federal court on various legal grounds.  In June 2014, the United States Supreme Court’s holding in Utility Air Regulatory Group v. EPA upheld a portion of EPA’s GHG stationary source permitting program, but also invalidated a portion of it. Upon remand, the EPA is considering how to implement the Court’s decision. The Court’s holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels. Additionally, the EPA promulgated a mandatory GHG reporting rule that took effect January 1, 2010. The mandatory reporting rule (MRR) and subsequent amendments included reporting requirements for operators that emit more than 25,000 metric tons of CO2-equivalent GHG across an entire producing basin. On November 13, 2014, the EPA finalized additional portions of the MRR.  The new provisions went into effect on January 1, 2015, and included revised monitoring and data disclosure requirements for the petroleum and natural gas industry clarifying that the engines, boilers, heaters, flares, and separation and processing equipment are among the emission sources that must provide greenhouse gas reports. In addition, the EPA also issued a final rule on October 22, 2015 that expanded the types of sources that are covered by the MRR. These sources include oil well completions and workovers with hydraulic fracturing, petroleum and natural gas gathering and boosting systems, and transmission pipeline blowdowns between compressor stations. Currently, Resolute’s Permian Basin operations are subject to the MRR requirements. A number of states also have taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional cap-and-trade programs, but we do not currently conduct business in those states. The passage or adoption of additional legislation or regulations that restrict emissions of GHG or require reporting of such emissions in areas where we conduct business could adversely affect our operations.

 

In addition, former President Obama released a Strategy to Reduce Methane Emissions in March 2014. Consistent with that strategy, the EPA issued a final rule in 2016 that set additional standards for methane and volatile organic compound emissions from oil and gas production sources, including hydraulically fractured oil wells and natural gas processing and transmission sources. As noted above, certain provisions of the new final rules in NSPS Subpart OOOOa are the subject of a proposed two-year stay, although the rules remain effective. In addition, the Federal Bureau of Land Management (BLM) has finalized standards for reducing venting and flaring on public lands. The final rule was published in the Federal Register in November 2016. The final rule is the subject of pending litigation in the District of Wyoming federal court by industry members and certain states seeking to overturn the rule in part. Although the court denied a request for preliminary injunction to prevent the rule from taking effect in January 2017, the District of Wyoming litigation is ongoing. In addition to the Wyoming litigation, there was litigation over a proposed stay of the rule in the Norther District of California. The 2016 final rule included two different categories of requirements and implementation deadlines one set 2017 and one in 2018. The 2017 requirements that included, among others, a “waste minimization plan,” are still in effect and implementation is ongoing. In December 2017, the BLM published a final rule suspending the remaining 2018 requirements for two years.  Continued litigation and/or updates to the rule are expected. In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant GHG emissions. Such cases may seek to challenge air emissions permits that GHG emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

 

Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require us to incur additional operating costs, such as costs to purchase and operate emissions control systems or other compliance costs, and could reduce demand for our products.

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Department of Homeland Security. The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“DHS”) to issue regulations establishing risk-based performance standards for the security at chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS is in the process of adopting regulations that will determine whether some of our facilities or operations will be subject to additional DHS-mandated security requirements. Under this authority, in April 2007, the DHS promulgated the Chemical Facilities Anti-Terrorism Standards (“CFATS”) regulations. Facilities that possessed any chemical on the CFATS Appendix A: DHS Chemicals of Interest List at or above the listed Screening Threshold Quantity for each chemical on the day Appendix A was published (November 2007) are subject to CFATS regulation. We are currently not aware of any affected Company facilities subject to the CFATS regulations.

Occupational Safety and Health Act. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that strictly govern protection of the health and safety of workers. The Occupational Safety and Health Administration’s hazard communication standard and Process Safety Management (“PSM”) regulations, the Emergency Planning and Community Right-to-Know Act, and similar state statutes require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public. PSM requirements applicable to gas processing activities are an intended focus of OSHA enforcement in recent years, and emphasize the need for process safety information disclosure, including short- and long-term off-site consequence analyses. We believe that we are in substantial compliance with applicable requirements of these and other OSHA and comparable state health and safety requirements.  

 

Significant Changes to U.S. Federal Income Tax Laws. On December 22, 2017, President Trump signed Public Law No. 115-97, commonly referred to as the “Tax Cuts and Jobs Act” (the “Tax Act”).  The Tax Act makes significant changes to the U.S. federal income taxation of individuals and corporations, generally effective for taxable years beginning on or after January 1, 2018. Among the changes to U.S. federal income tax laws, the Tax Act: (1) permanently replaces the progressive corporate income tax rate structure with a flat corporate income tax rate of 21%, (2) limits the current deductibility of net business interest expense to 30% of the Company’s “adjusted taxable income” (as defined in the Tax Act), (3) limits the utilization of net operating losses (“NOLs”) generated in taxable years beginning after December 31, 2017 to 80% of taxable income and repeals the rule allowing for carryback of such NOLs to offset taxable income in prior taxable years, (4) permits the unlimited carryforward of NOLs generated in taxable years beginning after December 31, 2017, (5) temporarily permits 100% expensing of certain business assets, (6) permanently repeals the deduction for domestic production activities, (7) permanently repeals the corporate alternative minimum tax (“corporate AMT”), which favorably impacts the deductibility of intangible drilling costs, (8) places additional limitations on certain general and administrative expenses, and (9) changes executive compensation rules.

 

In accordance with ASC 740, Accounting for Income Taxes, companies are required to recognize the effect of tax law changes in the period of enactment. Adjustments to our tax provision that were recorded in the three months ended December 31, 2017 principally relate to the reduction in the U.S. corporate income tax rate from a maximum 35% rate to a flat 21% rate, which resulted in the Company remeasuring its deferred tax assets and associated valuation allowance on those deferred tax assets, that will reverse at the new 21% flat rate. In addition, the repeal of the corporate AMT has resulted in the Company recognizing a current tax benefit of $0.3 million related to newly refundable AMT credits. 

Currently, we do not anticipate paying cash federal income taxes in the near term due to any of the federal income tax law changes enacted by the Tax Act, primarily due to our ability to expense intangible drilling costs and the utilization of our pre January 1, 2018 NOL carryforwards which can be utilized to offset 100% of taxable income. Based on the Company's current interpretation and subject to the release of regulations promulgated by the U.S. Department of Treasury (“Treasury Regulations”) and any other future interpretive guidance relating to the Tax Act, the Company believes the effects of the change in U.S. federal income tax laws incorporated herein are substantially complete.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and individual companies, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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Drilling and Production. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, also regulate one or more of the following:

 

the location of wells;

 

the method of drilling and casing wells;

 

the rates of production or “allowables”;

 

the surface use and restoration of properties upon which wells are drilled;

 

the plugging and abandoning of wells; 

 

the underground injection of salt water; and

 

notice to surface owners and other third-parties.

Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third-parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit or limit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas that we can produce from our wells or limit the number of wells or the locations where we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and gas within its jurisdiction.

Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of gas and the manner in which our production is marketed. Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce by gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic gas sold in “first sales,” which include all of our sales of our own production.

FERC also regulates interstate gas transportation rates and service conditions, which affects the marketing of gas that we produce, as well as the revenue we receive for sales of our gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach, recently pursued by FERC and Congress, will continue indefinitely into the future nor can it determine what effect, if any, future regulatory changes might have on gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on-shore and in-state waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

Hydraulic Fracturing Disclosure and Possible Regulation or Prohibition. Hydraulic fracturing or “fracing” is a process used by oil and gas producers in the completion or re-working of some oil and gas wells. Water, sand and certain chemical additives are injected under high pressure into subsurface formations to create and prop open fractures in the rock and thus enable fluids that would otherwise remain trapped in the formation to flow to the surface. Fracing has been in use for many years in a variety of geologic formations. Combined with advances in drilling technology, recent advances in fracing technology have contributed to a large increase in production of gas and oil from shales that would otherwise not be economically productive. Fracing is typically subject to state oil and gas agencies’ regulatory oversight, and has not been regulated at the federal level. However, due to assertions that fracing may adversely affect drinking water supplies, the federal EPA has released a final report on the potentially adverse impacts that fracing may have on water quality and public health, and in April 2015, the EPA proposed regulations under the Clean Water Act to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. In December 2016, the EPA released its final report on the potential impacts to drinking water resources from hydraulic fracturing, which concludes that hydraulic fracturing activities can impact drinking water resources under some circumstances.

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Also, EPA has initiated a stakeholder and potential rulemaking process under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing.  The EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to such TSCA rulemaking. In October 2015, EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” to the environment under the Toxics Release Inventory (“TRI”) program under of the Emergency Planning and Community Right-to-Know Act (EPCRA). That action resulted in EPA’s publication in the Federal Register in January 2017, of proposed rules to achieve the inclusion of gas processing in EPCRA reporting requirements.  Comments on the proposed rules were due in May 2017.

The U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing. In addition, in December 2015 the U.S. Department of Labor and the U.S. Department of Justice (“DOJ”) released a Memorandum of Understanding ("MOU"), announcing an interagency effort to increase enforcement of worker endangerment violations under environmental statutes (such as the Clean Water Act, the Clean Air Act, and the Resource Conservation and Recovery Act) and Title 18 criminal statutes that carry harsher penalties that the Occupational Safety and Health Act of 1970. Consistent with this MOU, where appropriate, DOJ will seek felony charges (such as false statements, conspiracy, and obstruction of justice) when prosecuting worker endangerment violations. In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act (“SDWA”) to encompass hydraulic fracturing activities. Past proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements, in addition to those already applicable to well site reclamation under various federal and state laws. We routinely utilize hydraulic fracturing techniques in many of our reservoirs. As noted above, the EPA finalized a wide-ranging study on the effects of hydraulic fracturing on drinking water resources in 2016. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. Adoption of legislation and implementing regulations placing restrictions on fracing could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and gas being produced, as well as increased costs of compliance and doing business. We disclose information pertaining to frac fluids, additives, and chemicals used in our operations to the FracFocus databases in compliance with statewide requirements established by the Texas Railroad Commission.

Employees

As of December 31, 2017, we had 128 full-time employees. We believe that we have a satisfactory relationship with our employees.

Offices

We currently lease approximately 56,000 square feet of office space in Denver, Colorado, and approximately 22,000 square feet of office space in Midland, Texas. Our principal office is located at 1700 Lincoln Street, Suite 2800, Denver, CO 80203. Of the 56,000 square feet leased space in Denver, as a result of the Aneth Disposition, we currently sublease approximately 8,000 square feet to an affiliate of Elk. The sublease is expected to expire on July 5, 2018, at which time we expect to resume occupancy of the space. We also own and maintain field offices in Texas and lease other, less significant, office space in locations where staff are located. We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.

Available Information

We maintain a link to investor relations information on our website, www.resoluteenergy.com, where we make available, free of charge, our filings with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, (“Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also make available on our website copies of the charters of the audit, compensation and corporate governance/nominating committees of our Board of Directors, our code of business conduct and ethics, audit committee whistleblower policy, stockholder and interested parties communication policy and corporate governance guidelines. Stockholders may request a printed copy of these governance materials or any exhibit to this report by writing to the Secretary, Resolute Energy Corporation, 1700 Lincoln Street, Suite 2800, Denver, CO 80203. You may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains the documents we file with the SEC. Our website and the information contained on or connected to our website is not incorporated by reference herein and our web address is included as an inactive textual reference only.

 

 

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ITEM 1A.

RISK FACTORS

You should consider carefully the following risk factors, as well as the other information set forth in this Form 10-K.

Risks Related to Our Business, Operations and Industry

The risk factors set forth below are not the only risks that may affect our business. Our business could also be affected by additional risks not currently known or that we currently deem to be immaterial. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Developing and producing oil and gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations, and insurance may not be available or may not fully cover losses.

There are numerous risks associated with developing, completing and operating a well, and cost factors can adversely affect the economics of a well. Our development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

reductions in oil or gas prices or increases in the differential between index oil or gas prices and prices received;

 

high costs, shortages or delivery delays of rigs, equipment, labor or other services;

 

unexpected operational events and/or conditions;

 

increases in severance or other taxes;

 

limitations on our ability to sell our oil or gas production;

 

adverse weather conditions and natural disasters;

 

facility or equipment malfunctions, and equipment failures or accidents;

 

pipe or cement failures and casing collapses;

 

compliance with environmental and other governmental regulations and requirements;

 

environmental hazards, such as leaks, oil spills, pipeline ruptures and discharges of toxic gases;

 

lost or damaged oilfield development and service tools;

 

unusual or unexpected geological formations, and pressure or irregularities in formations;

 

seismicity in the areas where we operate and the potential that drilling and completion activity or produced water injection/disposal would be limited in connection therewith;

 

fires, blowouts, surface craterings and explosions;

 

shortages or delivery delays of supplies, equipment and services;

 

midstream constraints or downtime;

 

title problems;

 

objections from surface owners and nearby surface owners in the areas where we operate; and

 

uncontrollable flows of oil, gas or well fluids.

Any of these or other similar occurrences could reduce our cash from operations or result in the disruption of our operations, substantial repair costs, significant damage to property, environmental pollution and impairment of our operations. The occurrence of these events could also affect third parties, including persons living near our operations, our employees and employees of our contractors, leading to injuries or death.

Insurance against all operational risk is not available to us, and pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. We do not maintain business interruption insurance and also may not maintain insurance on all of our equipment. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms, and any insurance coverage we do obtain may contain large deductibles or it may not cover all hazards or potential losses. Losses and liabilities from uninsured and underinsured events or a delay in the payment of insurance proceeds could adversely affect our business, financial condition and results of operations.

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Oil and gas prices are volatile and change for reasons that are beyond our control. Sustained periods of low prices or decreases in the price we receive for our oil and gas production can adversely affect our business, financial condition, results of operations and liquidity and impede our growth.

The oil and gas markets are highly volatile, and we cannot predict future prices. Our revenue, profitability and cash flow depend upon the prices and demand for oil, gas and NGL. The markets for these commodities are very volatile and even relatively modest reductions in prices can significantly affect our financial results and impede our growth. Prices for oil, gas and NGL may fluctuate widely in response to relatively minor changes in the supply of and demand for the commodities, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

domestic and foreign supply of and demand for oil and gas, including as a result of technological advances affecting energy consumption and supply;

 

actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;

 

weather conditions;

 

overall domestic and global political and economic conditions;

 

the price of foreign imports;

 

political and economic conditions in oil producing countries, including the Middle East, Russia and South America;

 

variations between product prices at sales points and applicable index prices;

 

domestic and foreign governmental regulations and taxation;

 

the effect of energy conservation efforts;

 

the capacity, cost and availability of oil and gas pipelines and other transportation and gathering facilities, and the proximity of these facilities to our wells;

 

the availability of refining and processing capability;

 

factors specific to the local and regional markets where our production occurs; and

 

the price and availability of alternative fuels.

In the past, the price of oil has been extremely volatile, and we expect this volatility to continue. Oil and gas prices have declined substantially since mid 2014.  For example, during the twelve months ended December 31, 2017, the NYMEX price for light sweet crude oil ranged from a high of $60.42 per Bbl to a low of $42.53 per Bbl. For calendar year 2016, the range was from a high of $54.06 per Bbl to a low of $26.21 per Bbl, and for the five years ended December 31, 2017, the price ranged from a high of $110.53 per Bbl to a low of $26.21 per Bbl.

A prolonged period of low oil and gas prices or a decline in oil and gas prices will significantly affect many aspects of our business, including financial condition, revenue, results of operations, liquidity, cash flow, rate of growth, reserves, the carrying value of our oil and gas properties, and the borrowing base under our revolving credit facility with a syndicate of lenders (the “Revolving Credit Facility”), all of which depend primarily or in part upon those prices. For example, declines in the prices we receive for our oil and gas adversely affect our ability to repay indebtedness, finance capital expenditures, make acquisitions, raise capital and otherwise satisfy our financial obligations. In addition, declines in prices reduce the amount of oil and gas that we can produce economically and, as a result, adversely affect our quantities and present values of proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, as the maximum amount of available borrowing under our Revolving Credit Facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantities and value of those reserves.

Inadequate liquidity could materially and adversely affect our business operations.

Our ability to generate cash flow depends upon numerous factors related to our business that may be beyond our control, including:

 

the price at which we sell our oil and gas production and the costs we incur to market our production;

 

the amount of oil and gas we produce;

 

our ability to borrow under our Revolving Credit Facility or future debt agreements;

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debt service requirements contained in our Revolving Credit Facility, 8.5% senior notes due 2020 (the “Senior Notes”) or future debt agreements;

 

the effectiveness of our commodity price hedging strategy;

 

the development of proved undeveloped and other prospective properties and the success of our enhanced oil recovery activities;

 

the level of our operating and general and administrative costs;

 

our ability to replace produced reserves;

 

prevailing economic conditions;

 

government regulation and taxation;

 

the level of our capital expenditures required to implement our development projects and make acquisitions of additional reserves and prospective properties;

 

fluctuations in our working capital needs; and

 

timing and collectability of receivables.

Failure to maintain adequate liquidity could result in an inability to replace reserves and production, to maintain ownership of undeveloped leasehold and adverse borrowing base determinations. Any or all of the foregoing could materially and adversely affect our business and results of operations.

In addition, our estimate of proved reserves as of December 31, 2017, was based on a pricing methodology required by SEC rules. If low oil and gas prices result in our having to make substantial downward adjustments to our estimated proved reserves, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to make downward adjustments, as a non-cash impairment charge to earnings, to the carrying value of our oil and gas properties. When we incur impairment charges in the future, we could have a material adverse effect on our results of operations in the period incurred. In addition, a reduction in the future net cash flow from our properties would negatively affect our ability to borrow funds under our Revolving Credit Facility.

Availability under our Revolving Credit Facility depends on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under our Revolving Credit Facility.

Under the terms of our Revolving Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their evaluation of our proved reserves and their internal criteria. In addition, under certain circumstances, interim redeterminations may be conducted, including in the event of acquisitions or dispositions of properties.

In the event the amount outstanding under our Revolving Credit Facility at any time exceeds the borrowing base at such time, we would be required to repay the amount of our outstanding borrowings exceeding the new borrowing base over the 120 days following the redetermination. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our Revolving Credit Facility, incur additional indebtedness, sell assets or sell additional debt or equity securities in order to cure such borrowing base deficiency. We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment could result in a default under our Revolving Credit Facility and a cross default under our Senior Notes.

Our substantial indebtedness could adversely affect our business, results of operations and financial condition.

In addition to making it more difficult for us to satisfy our obligations to pay principal and interest on our outstanding indebtedness, our substantial indebtedness could limit our ability to respond to changes in the markets in which we operate and otherwise limit our activities. For example, our indebtedness, and the terms of agreements governing that indebtedness:

 

require us to dedicate a substantial portion of our cash flow from operations to service our existing debt obligations, thereby reducing the cash available to fund our operations, exploration and development efforts, acquisitions, working capital, capital expenditures and other general corporate purposes;

 

increase our vulnerability to economic downturns and impair our ability to withstand sustained declines in oil and gas prices;

 

subject us to covenants that limit our ability to fund future working capital, capital expenditures, exploration costs and other general corporate requirements;

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may prevent us from borrowing additional funds for operational or strategic purposes (including to fund future acquisitions), disposing of assets or paying cash dividends;

 

may prevent counterparties (including lenders) from entering into derivative transactions with us;

 

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

 

place us at a competitive disadvantage relative to our competitors that have less debt outstanding.

Covenants in our Revolving Credit Facility and the indenture governing our Senior Notes, currently impose, and future financing agreements may impose, significant operating and financial restrictions.

Our Revolving Credit Facility and the indenture governing our Senior Notes each contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to:

 

incur additional debt;

 

pay dividends on, redeem or repurchase stock;

 

create liens;

 

make specified types of investments;

 

apply net proceeds from certain asset sales and equity offerings other than to repay indebtedness;

 

engage in transactions with our affiliates;

 

engage in sale and leaseback transactions;

 

merge or consolidate;

 

make payments from restricted subsidiaries;

 

sell equity interests of restricted subsidiaries; and

 

sell, assign, transfer, lease, convey or dispose of assets.

As amended in October 2017, our Revolving Credit Facility will mature in 2021 (unless there is a maturity of material indebtedness prior to such date) and is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The Revolving Credit Facility contains various affirmative and negative covenants, measured on a quarterly basis, including but not limited to financial covenants that (i) require us to maintain a ratio of current assets to current liabilities of no less than 1.0 to 1.0 and (ii) do not permit our maximum leverage ratio (total debt to consolidated Adjusted EBITDA as defined in the Revolving Credit Facility) to exceed 4.0 to 1.0.

These restrictions may prevent us from taking actions that we believe would be in the best interest of our business, may require us to sell assets or take other actions to reduce indebtedness to meet our covenants, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We cannot provide assurance that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.

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If we are unable to comply with the restrictions and covenants in the agreements governing the Revolving Credit Facility, Senior Notes and other debt, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would affect our ability to make principal and interest payments on our debt.

If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including our Revolving Credit Facility or the Senior Notes), we could be in default under the terms of the agreements governing such indebtedness, and any such default could cause a cross-default under the terms of our other indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Revolving Credit Facility could elect to terminate their commitments, cease making further loans and our secured lenders could institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. We may in the future need to seek to obtain waivers from the required lenders under our Revolving Credit Facility to avoid being in default. If we breach our covenants under our Revolving Credit Facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our Revolving Credit Facility or Senior Notes, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation.

In addition, any default under the agreements governing our indebtedness, including a default under our Revolving Credit Facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal, premium, if any, and interest on the Senior Notes and other indebtedness and substantially decrease the market value of the Senior Notes.

The marketability of our production is dependent upon gathering, transportation and processing facilities the capacity and operation of which we do not control.

The marketability of our oil and gas production depends in part upon the availability, proximity and capacity of pipelines, gas gathering systems, gas processing facilities, water sourcing, gathering and disposal systems and oil gathering systems owned by third parties. In general, we do not control these facilities and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely affect our ability to deliver to market the oil and gas we produce, and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our oil and gas is dependent upon coordination among third parties who own pipelines, transportation and processing facilities that we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. Additionally, the amount of our oil and gas production in the Delaware Basin could exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in that area. Federal and state regulation of oil and gas production and transportation, local government activity, adverse court rulings, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints and general economic conditions could also adversely affect our ability to produce, gather, process, transport and market oil and gas.  These are risks for which we generally do not maintain insurance. 

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

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

 

landing our wellbore in the desired drilling zone;

 

staying in the desired drilling zone while drilling horizontally through the formation;

 

running our casing the entire length of the wellbore; and

 

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, the following:

 

the ability to fracture stimulate the planned number of stages;

 

the ability to run tools the entire length of the wellbore during completion operations; and

 

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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The drilling process and the results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no drilling or production history and, consequently, we are more limited in assessing future drilling costs and results in these areas. If our drilling costs are greater or our results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Any acquisitions we complete are subject to substantial risks that could negatively affect our financial condition and results of operations.

Even if we do make acquisitions that we believe will enhance our growth, financial condition or results of operations, any acquisition involves potential risks including, among other things:

 

the validity of our assumptions about the acquired properties’ or company’s reserves, future production, the future prices of oil and gas, infrastructure requirements, environmental and other liabilities, revenue and costs;

 

an inability to integrate successfully the properties and businesses we acquire;

 

a decrease in our liquidity to the extent we use a significant portion of our available cash or borrowing capacity to finance acquisitions or operations of the acquired properties;

 

a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions or operations of the acquired properties;

 

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

 

the diversion of management’s attention from other business concerns;

 

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

 

unforeseen difficulties encountered in operating in new geographic areas; and

 

customer or key employee losses at the acquired businesses.

Our decision to acquire a property or business will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our review of acquired properties is inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential problems. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. The potential risks in making acquisitions could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.

We and our subsidiary guarantors may be unable to fulfill our debt service obligations under our debt agreements.

We have a substantial amount of indebtedness. As a result, a significant portion of our cash flow will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flow from operations, or have future borrowing capacity available, to enable us to pay amounts due on, or pay when due at maturity, our indebtedness, including the Revolving Credit Facility or the Senior Notes, or to fund other liquidity needs. As of December 31, 2017, we had $555.0 million in outstanding indebtedness.

Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic and industry conditions and financial, business and other factors, many of which are beyond our control. 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 Revolving Credit Facility or otherwise, in an amount sufficient to fund our liquidity needs, including the payment of principal and interest on the Revolving Credit Facility or the Senior Notes.

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Declines in product prices decrease our operating cash flow. An increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including curtailing our exploration and drilling programs, selling assets, issuing equity, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our Revolving Credit Facility and the indenture governing the Senior Notes do, restrict us from implementing some of these alternatives. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations or issue equity at depressed prices to meet our debt service and other obligations. We may not be able to consummate these dispositions or equity issuances for fair market value or at all. Furthermore, any proceeds that we could realize from any dispositions or equity issuances may not be adequate to meet our debt service obligations then due.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities of our proved reserves.  Estimates of resource potential are also based on many assumptions and may turn out to be inaccurate.

Our estimate of proved reserves at December 31, 2017, is based on the quantities of oil and gas that engineering and geological analyses demonstrate with reasonable certainty to be recoverable from established reservoirs in the future under current operating and economic parameters. NSAI audited, on a well-by-well basis, the reserve and economic evaluations of all properties that were prepared by us. Oil and gas reserve engineering is not exact; it relies on subjective interpretations of data that may be inaccurate or incomplete and requires predictions and assumptions of future reservoir behavior and economic conditions. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:

 

the assumed accuracy of field measurements and other reservoir data, including type curve forecast models;

 

assumptions regarding expected reservoir performance relative to historical analog reservoir performance;

 

the assumed effects of regulations by governmental agencies;

 

assumptions concerning the availability of capital and its costs;

 

assumptions concerning future oil and gas prices; and

 

assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserve estimates are necessarily subjective, each of the following items may differ materially from those assumed in estimating reserves:

 

the quantities of oil and gas that are ultimately recovered;

 

the timing of the recovery of oil and gas reserves;

 

the production and operating costs incurred; and

 

the amount and timing of future development expenditures.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. As a result of all these factors, we may make material changes to reserves estimates to take into account changes in our assumptions and the results of our development activities and actual drilling and production.

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

In addition, the present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the arithmetic average of the prior year’s first day of the month oil and gas index prices.

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In our press releases and investor presentations, we include estimates of quantities of oil and gas using certain terms, such as “resource,” “resource potential,” “EUR,” “oil in place,” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC definition of proved, probable and possible reserves, and which the SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Resolute. In addition, “peak IP rates” for both our wells and for those wells that are located near to our properties are limited data points in each well’s productive history and not necessarily indicative or predictive of future production rates, EUR or economic rates of return from such wells and should not be relied upon for such purpose. Our investor presentations also include type curve forecast models for well performance. Type curve forecast models are derived from the actual production of historical comparably drilled and completed wells and forecast expected well production, but actual production results may differ significantly from production forecasted by type curves. Type curve forecast models have an inherent degree of variability and may change over time, and as a result, may not be indicative of the actual well data for the type curve areas.

Sustained low commodity prices could result in additional impairments charges and we may be required to write down the carrying value of our properties in the future.

We use the full cost accounting method for oil and gas exploitation, development and exploration activities. Under the full cost method rules, we perform a ceiling test and if the net capitalized costs for a cost center exceed the ceiling for the relevant properties, we write down the book value of the properties. If low oil and gas prices result in our having to make substantial downward adjustments to our estimated proved reserves, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to make downward adjustments, as a non-cash impairment charge to earnings, to the carrying value of our oil and gas properties.

Our planned operations, as well as replacement of our production and reserves, will require significant additional capital that may not be available.

Our business is capital intensive, and requires substantial expenditures to maintain currently producing wells, to make the acquisitions of additional reserves and/or conduct the exploration, exploitation and development program necessary to replace our reserves, to pay expenses and to satisfy our other obligations. These activities will require cash flow from operations, additional borrowings or proceeds from the issuance of equity or asset sales, or some combination thereof, which may not be available to us.

For example, in 2018 we expect capital expenditures of between $365 million and $395 million. Additionally, based on our SEC-case reserve projections, we expect to spend $285.4 million of capital expenditures over the next five years to implement and complete our proved undeveloped projects. We expect to incur all of these future capital expenditures during 2018 through 2022 based on the capital plan contemplated by our year-end 2017 SEC reserve report. To the extent our production and reserves decline faster than we anticipate, we will require a greater amount of capital to maintain our production. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants in our Revolving Credit Facility or the Senior Notes, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary for future activities could materially affect our business, results of operations and financial condition. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our activities and our ability to pay dividends. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity may result in significant equity holder dilution.

If we are unable to acquire adequate supplies of water for our operations or are unable to dispose of the water we use and produce at a reasonable cost and within applicable environmental rules, our ability to produce oil and gas commercially and in commercial quantities could be impaired.

We use a substantial amount of water in our drilling and completion. Our inability to locate sufficient amounts of water, or treat and dispose of water after drilling and completion, and generated from production could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas. Furthermore, future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance.

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Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Revolving Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt or make certain restricted payments, which could exacerbate the risks described above.

We may be able to incur additional debt in the future. In addition, although the Revolving Credit Facility and the indenture governing the Senior Notes contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under our Revolving Credit Facility. We expect to be able to issue additional notes under the indenture in some circumstances. In addition, if we are able to designate some of our restricted subsidiaries under the indenture as unrestricted subsidiaries, including in connection with the formation of master limited partnerships, those unrestricted subsidiaries would be permitted to borrow beyond the limitations specified in the indenture and engage in other activities in which restricted subsidiaries may not engage. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. In addition, under the indenture, we will be able to make restricted payments in certain circumstances. We may also be able to obtain waivers from the lenders under our Revolving Credit Facility and the holders of our Senior Notes that would permit us to increase the amount of indebtedness we are permitted to incur. Adding new debt to current debt levels or making otherwise restricted payments could intensify the related risks that we and our subsidiaries now face.

Although the Senior Notes are referred to as “senior,” rights to receive payments on the Senior Notes are effectively subordinated to the rights of our and our restricted subsidiaries’ existing and future secured creditors.

The lenders under our Revolving Credit Facility will have claims that are prior to the claims of holders of the Senior Notes to the extent of the value of the assets securing the Revolving Credit Facility. The Revolving Credit Facility is secured by liens on substantially all of our assets and the assets of our restricted subsidiaries. The Senior Notes are effectively subordinated to any secured indebtedness incurred under the Revolving Credit Facility and any future secured facilities of the Company. In the event of any distribution or payment of our or any guarantor’s assets in any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of secured indebtedness will have prior claim to those of our or our restricted subsidiaries’ assets that constitute their collateral. Holders of Senior Notes will participate ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as such notes, and potentially with all of our or any restricted subsidiary’s other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the Senior Notes. As a result, holders of Senior Notes may receive less, ratably, than holders of secured indebtedness.

The Senior Notes are subordinated to all indebtedness of those of our existing or future subsidiaries that are not, or do not become, guarantors of the notes.

Although all of our current subsidiaries are guarantors of the Senior Notes, if any future subsidiaries do not become guarantors of the notes, they will have no obligation, contingent or otherwise, to pay amounts due under the notes or to make any funds available to pay those amounts, whether by dividend, distribution, loan or other payment. The notes will be structurally subordinated to all indebtedness and other obligations of any non-guarantor subsidiary such that, in the event of insolvency, liquidation, reorganization, dissolution or other winding up of any subsidiary that is not a guarantor, all of the subsidiary’s creditors (including trade creditors and preferred stockholders, if any) would be entitled to payment in full out of the subsidiary’s assets before we would be entitled to any payment. In addition, the indenture governing the notes will, subject to some limitations, permit non-guarantor subsidiaries to incur additional indebtedness and will not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries.

We may not be able to repurchase the Senior Notes upon a change of control as required by the indenture governing the notes. A change of control is also an event of default under our Revolving Credit Facility.

Upon the occurrence of certain kinds of change of control events, we will be required to offer to repurchase all outstanding Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the date of repurchase, unless all notes have been previously called for redemption. The holders of other debt securities that we may issue in the future, which rank equally in right of payment with the notes, may also have this right. Our failure to purchase tendered notes would constitute an event of default under the indenture governing the notes, which in turn, would constitute an event of default under our Revolving Credit Facility. A “change of control” under the indenture governing our Senior Notes includes the acquisition by a third party of more than 50% of our outstanding common stock, which is a transaction that may occur without the approval of the Company’s Board of Directors.

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It is possible that we may not have sufficient funds at the time of the change of control to make the required repurchase of notes. Moreover, our Revolving Credit Facility restricts, and any future indebtedness we incur may restrict, our ability to repurchase the notes, including following a change of control event. As a result, following a change of control event, we would not be able to repurchase notes unless we first repay all indebtedness outstanding under our Revolving Credit Facility and any of our other indebtedness that contains similar provisions, or obtain a waiver from the holders of such indebtedness to permit us to repurchase the notes. We may be unable to repay all of that indebtedness or obtain a waiver of that type. Any requirement to offer to repurchase outstanding notes may therefore require us to refinance our other outstanding debt, which we may not be able to do on commercially reasonable terms, if at all. These repurchase requirements may also delay or make it more difficult for others to obtain control of us.

In addition, the occurrence of a change of control (as defined under the debt agreement) in itself would constitute an event of default under our Revolving Credit Facility.

Certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, may not constitute a “Change of Control” under the indenture.

Following a sale of “substantially all” of our assets, we may not be able to determine if a change of control that would give rise to a right to have the Senior Notes repurchased has occurred or if a change of control that would give rise to an event of default under the Revolving Credit Facility has occurred.

The definition of change of control in the Revolving Credit Facility and the Senior Notes include a phrase relating to the sale of “all or substantially all” of our assets. There is no precise, established definition of the phrase “substantially all” under applicable law. Accordingly, the ability of a holder of Senior Notes to require us to repurchase its notes, and the occurrence of an event of default under the Revolving Credit Facility, as a result of a sale of less than all our assets to another person, may be uncertain. Further, a holder or holders of Senior Notes could take the position that a transaction or series of transactions constituted a “sale of substantially all assets” giving rise to the right to have the Senior Notes repurchased.

Provisions in the indenture governing our Senior Notes and in our Revolving Credit Facility may discourage third parties from seeking to consummate a change of control transaction that could otherwise be beneficial for our stockholders.

Upon the occurrence of certain kinds of change of control events, we will be required to offer to repurchase all outstanding Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the date of repurchase, unless all notes have been previously called for redemption.  In addition, the occurrence of a change of control (as defined under the respective debt agreements) in itself would constitute an event of default under our Revolving Credit Facility, which would cause amounts outstanding under the Revolving Credit Facility to become immediately due and payable.  The potential trigger of an event of default under the Revolving Credit Facility, as well as the potential repurchase obligation under the Senior Notes, may discourage potential third parties from entering into a change of control transaction with us that may otherwise be beneficial for our stockholders.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended.

As of December 31, 2017, we had approximately 4,300 net acres in the Permian Basin that are not currently held by production. Unless production in paying quantities is established on units containing these leases during their primary term, their continuous drilling term or we obtain extensions of the leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

Our drilling plans for these areas are subject to change based on various factors, including factors that are beyond our control, including drilling results, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.  

Adverse U.S. and global economic conditions could have a material adverse effect on our business and operations.

Any or all of the following may occur if domestic and global economic conditions worsen:

 

We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

 

An economic slowdown could lead to lower demand for oil and gas by individuals and industries, which may result in lower prices for the oil and gas sold by us, lower revenues and possibly losses.

 

The lenders under our Revolving Credit Facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and

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operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.

 

The losses incurred by financial institutions as well as the bankruptcy of some financial institutions heightens the risk that a counterparty to our derivative instruments could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy may affect the ability of the counterparties to meet their obligations to us on derivative transactions, which could reduce our revenues from derivatives at a time when we are also receiving a lower price for our gas and oil sales. As a result, our financial condition could be materially adversely affected.

 

Our Revolving Credit Facility bears a floating interest rate based on the London Interbank Offered Rate, or LIBOR. If LIBOR were to increase, this would cause higher interest expense.

 

Our Revolving Credit Facility requires the lenders to re-determine our borrowing base semi-annually. The redeterminations are based largely on our proved reserves using price assumptions determined by each lender, with effect given to our derivative positions. It is possible that the lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base and our borrowing base could be reduced. This would reduce our funds available to borrow and could require us to repay any amounts outstanding in excess of the then-determined borrowing base.

 

Bankruptcies of purchasers of our oil and gas could lead to the delay or failure of us to receive the revenues from those sales.

A financial failure by us or our subsidiaries may result in the assets of any or all of those entities becoming subject to the claims of all creditors of those entities.

A financial failure by us or our subsidiaries could affect payment of the Revolving Credit Facility and the Senior Notes if a bankruptcy court were to substantively consolidate us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would become subject to the claims of creditors of all entities. This would expose holders of Senior Notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the Senior Notes could occur through the “cramdown” provisions of the bankruptcy code. Under these provisions, the notes could be restructured over the objections of holders as to their general terms, primarily interest rate and maturity.

Exploration and development drilling may not result in commercially productive reserves.

We may not encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling whether we will find oil or gas or, if found, that the hydrocarbons will be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;

 

unexpected drilling conditions;

 

title problems;

 

pressure or irregularities in formations;

 

equipment failures or accidents;

 

adverse weather conditions; and

 

compliance with environmental and other governmental requirements.

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Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing, distribution and disposal systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know with certainty if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

The development of our estimated PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUD reserves may not be ultimately developed or produced.

As of December 31, 2017, 51% of our total estimated proved reserves were classified as proved undeveloped. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUD reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. If we choose not to develop our PUD reserves or suffer delays in their development as a result of such factors we could have to reclassify our PUD reserves as unproved reserves. Under the SEC’s reserve reporting rules, we may be required to write down our PUD reserves if we do not drill those wells within five years after their respective dates of initial booking.

Shortages of qualified personnel or field supplies, equipment and services could affect our ability to execute our plans on a timely basis, reduce our cash flow and adversely affect our results of operations.

The demand for qualified and experienced geologists, geophysicists, engineers, field operations specialists, landmen, financial experts and other personnel in the oil and gas industry can fluctuate significantly, often in correlation with oil and gas prices, causing periodic shortages. From time to time, there have also been shortages of drilling rigs and other field supplies, equipment and services, as demand for rigs and equipment increased along with the number of wells being drilled. These factors can also result in significant increases in costs for equipment, services, supplies and personnel. Higher oil and gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. In the event of such shortages, our cash flow and operating results could be adversely affected and our ability to conduct our operations in accordance with our plans and budgets could be restricted.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Exploration, exploitation, development, production and marketing operations in the oil and gas industry are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and properly abandon oil and gas wells and other recovery operations. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations or denial or revocation of permits and subject us to administrative, civil and criminal penalties.

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Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production activities. Delays or failures in obtaining regulatory approvals or permits or the receipt of an approval or permit with unreasonable conditions could have a material adverse effect on our ability to exploit our properties. Additionally, the oil and gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. The expansion of GHG mandatory reporting rules (MRR) affecting onshore oil and gas activities and proposed GHG cap-and-trade legislation are two examples of recent and of proposed changes in the regulatory climate that do and would affect us. Also, the EPA announced a comprehensive strategy for further reducing methane emissions from oil and gas operations and issued a final rule in June 2016 (Clean Air Act NSPS Subpart OOOOa), although parts of those regulations are currently the subject of a proposed two-year stay by the EPA to allow for review, reconsideration, and possible rescission, as noted above. We may be placed at a competitive disadvantage to larger companies in the industry with respect to such expanded regulatory requirements, which can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business and Properties — Environmental, Health and Safety Matters and Regulation” and “Business and Properties — Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect us.

Certain federal income tax deductions and credits currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Certain legislative proposals have been made that would terminate various tax incentives currently available to companies engaged in oil and gas development and production. These proposed changes have included (i) the elimination of the current deduction for intangible drilling and development costs and for qualified tertiary injectant expenses, (ii) the repeal of the percentage depletion allowance for oil and gas wells, and (iii) the extension of the amortization period for certain geological and geophysical expenditures. While these specific changes were not included in the Tax Act, additional legislative proposals affecting these tax incentives may be introduced, and, if such a proposal were to be enacted, the resulting impact could increase the cost of exploration and development of oil and gas resources. No accurate prediction can be made as to whether these or similar changes will be proposed or enacted in the future, but any such changes could have a material adverse effect on our financial position, results of operations and cash flows.

Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is a common process in our industry of creating artificial cracks, or fractures, in deep underground rock formations through the pressurized injection of water, sand and other additives to enable fluids (including oil and gas) to move more easily through the rock to a production well. This process often is necessary to produce commercial quantities of oil and gas from many reservoirs, especially shale rock formations. We routinely utilize hydraulic fracturing techniques in many of our reservoirs, including all of our wells in the Permian Basin. Current regulation of hydraulic fracturing primarily is conducted at the state level through permitting and other compliance requirements, but proposed regulations at the federal level have been under consideration by EPA, BLM and OSHA. The EPA is conducting a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2015, the EPA issued a draft final report for public comment and peer review. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. For example, a federal BLM rulemaking for hydraulic fracturing practices on federal and Indian lands was promulgated in 2015, and then challenged in federal court on numerous grounds. In June 2016, the United States District Court for the District of Wyoming held that the new regulations were invalid. Although the district court ruling was appealed, the rule was rescinded by BLM on December 29, 2017, and all related litigation is now concluded. Additionally, the U.S. Congress has considered legislation, and in the future may consider additional legislation, that would amend the SDWA to eliminate an existing exemption from federal regulation of hydraulic fracturing activities and require the disclosure of chemical additives used by the oil and gas industry in the hydraulic fracturing process. If adopted, the proposed amendments to the SDWA or these federal agencies’ possible expansion of their existing regulatory programs affecting hydraulic fracturing could result in additional regulations and permitting requirements at the federal level. In addition, various states and localities are also studying or considering various additional regulatory measures related to hydraulic fracturing, and public referendums for moratoriums or additional restrictions on fracing have recently been presented in many state and local jurisdictions. These and similar developments could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and of doing business. Additional regulations and permitting requirements could lead to significant operational delays and increased operating costs, and make it more difficult to perform hydraulic fracturing. We cannot assure you that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.  Please read “Business and Properties —Other Regulation of the Oil and Gas Industry—Hydraulic Fracturing Disclosure and Possible Regulation or Prohibition” for a description of the potential further laws and regulations that may affect us.

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Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of saltwater produced in connection with our oil and gas production, which could limit our ability to produce oil and gas economically and have a material adverse effect on our business.

We dispose of large volumes of saltwater produced in connection with our drilling and production operations, pursuant to permits issued to us or third-party op