Company Quick10K Filing
Resolute Energy
Price37.52 EPS-1
Shares23 P/E-27
MCap869 P/FCF6
Net Debt707 EBIT-10
TEV1,576 TEV/EBIT-159
TTM 2018-09-30, in MM, except price, ratios
10-Q 2018-09-30 Filed 2018-11-05
10-Q 2018-06-30 Filed 2018-08-06
10-Q 2018-03-31 Filed 2018-05-07
10-K 2017-12-31 Filed 2018-03-12
10-Q 2017-09-30 Filed 2017-11-06
10-Q 2017-06-30 Filed 2017-08-07
10-Q 2017-03-31 Filed 2017-05-03
10-K 2016-12-31 Filed 2017-03-13
10-Q 2016-09-30 Filed 2016-11-07
10-Q 2016-06-30 Filed 2016-08-08
10-Q 2016-03-31 Filed 2016-05-09
10-K 2015-12-31 Filed 2016-03-07
10-Q 2015-09-30 Filed 2015-11-09
10-Q 2015-06-30 Filed 2015-08-10
10-Q 2015-03-31 Filed 2015-05-11
10-K 2014-12-31 Filed 2015-03-05
10-Q 2014-09-30 Filed 2014-11-10
10-Q 2014-06-30 Filed 2014-08-11
10-Q 2014-03-31 Filed 2014-05-12
10-K 2013-12-31 Filed 2014-03-10
10-Q 2013-09-30 Filed 2013-11-05
10-Q 2013-06-30 Filed 2013-08-05
10-Q 2013-03-31 Filed 2013-05-06
10-Q 2012-06-30 Filed 2012-08-06
10-Q 2012-03-31 Filed 2012-05-08
10-Q 2011-09-30 Filed 2011-11-07
10-Q 2011-06-30 Filed 2011-08-08
10-Q 2011-03-31 Filed 2011-05-06
10-K 2010-12-31 Filed 2011-03-15
10-Q 2010-09-30 Filed 2010-11-15
10-Q 2010-06-30 Filed 2010-08-12
10-Q 2010-03-31 Filed 2010-05-11
10-K 2009-12-31 Filed 2010-03-30
8-K 2019-03-01
8-K 2019-02-22
8-K 2019-02-14
8-K 2019-02-11
8-K 2018-11-19
8-K 2018-11-18
8-K 2018-10-11
8-K 2018-09-30
8-K 2018-09-14
8-K 2018-06-30
8-K 2018-06-19
8-K 2018-06-11
8-K 2018-05-15
8-K 2018-05-09
8-K 2018-04-05
8-K 2018-03-31
8-K 2018-03-16
8-K 2018-03-12
8-K 2018-02-26
8-K 2018-02-13
8-K 2018-02-08
8-K 2018-01-01

REN 10K Annual Report

Part I
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.Quantitive and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions and Director Independence
Item 14. Principal Accounting Fee and Services
Part IV
Item 15. Exhibits, Financial Statement Schedules
Note 1 - Organization and Nature of Business
Note 2 - Basis of Presentation and Summary of Significant Accounting Policies
Note 3 - Acquisitions and Divestitures
Note 4 - Earnings per Share
Note 5 - Long Term Debt
Note 6 - Income Taxes
Note 7 - Stockholders' Equity and Equity Based Awards
Note 8 - Asset Retirement Obligation
Note 9 - Derivative Instruments
Note 10 - Fair Value Measurements
Note 11 - Commitments and Contingencies
Note 12 - Subsequent Events
Note 13 - Supplemental Oil and Gas Information (Unaudited)
Note 14 - Quarterly Financial Data (Unaudited)
EX-10.37.1 ren-ex10371_1337.htm
EX-12.1 ren-ex121_6.htm
EX-23.1 ren-ex231_11.htm
EX-23.2 ren-ex232_8.htm
EX-31.1 ren-ex311_9.htm
EX-31.2 ren-ex312_12.htm
EX-32 ren-ex32_7.htm
EX-99.1 ren-ex991_105.htm

Resolute Energy Earnings 2016-12-31

Balance SheetIncome StatementCash Flow
1.71.30.90.40.0-0.42013201520172019
Assets, Equity
0.20.10.0-0.0-0.1-0.22013201520172019
Rev, G Profit, Net Income
0.30.20.0-0.1-0.3-0.42013201520172019
Ops, Inv, Fin

10-K 1 ren-10k_20161231.htm 10-K ren-10k_20161231.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2016

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, Suite 2800

Denver, CO

 

80203

(Address of principal executive offices)

 

(Zip Code)

(303) 534-4600

(Registrant’s telephone number, including area code)

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 Section 15 of the Exchange 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 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, indefinite 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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated  filer

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

 

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, 2016, computed by reference to the price at which the common stock was last sold as posted on the New York Stock Exchange, was $42.4 million.

As of February 28, 2017, 22,437,470 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 2017 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 words “anticipate,” “intend,” “believe,” “estimate,” “project,” “expect,” “plan,” “should” or similar expressions are intended to identify such statements. Forward-looking statements included in this report relate to, among other things, the anticipated closing date and expected benefits of the Delaware Basin acquisitions, our production and cost guidance for 2017; anticipated capital expenditures in 2017 and the sources of such funding; availability of alternative oil purchase markets and oil takeaway systems; our financial condition and management of the Company in the current commodity price environment; future financial and operating results; our intention to evaluate and pursue the disposition of our Aneth Field properties, joint ventures and asset sales; liquidity and availability of capital including projections of free cash flow; additional future potential full cost ceiling impairments; future borrowing base adjustments and the effect thereof; future production, reserve growth and decline rates; our plans and expectations regarding our development activities including drilling, deepening, recompleting, fracing and refracing wells, the number of such potential projects, locations and productive intervals, the rates of return on our acreage and projects; the prospectivity of our properties and acreage; 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:

 

our ability to consummate and to realize the expected benefits from the interests acquired in the Delaware Basin acquisitions;

 

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;

 

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 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;

 

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

 

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;

 

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

 

risks associated with rising interest rates;

 

risks associated with all of our Aneth Field oil production being purchased by a single customer and connected to such customer with a pipeline that we do not own or control;

 

inaccuracies in reserve estimates;

 

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

 

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;

 

our relationship with the Navajo Nation, the local community in the area where we operate Aneth Field, and Navajo Nation Oil and Gas Company, as well as certain purchase rights held by Navajo Nation Oil and Gas Company;


 

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

 

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

 

the ability to sell or otherwise monetize assets, including our Aneth Field 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;

 

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, including changes in Navajo Nation laws, 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;

 

regulation of waste water injection intended to address seismic activity;

 

the concentration of our producing properties in a limited number of geographic areas;

 

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;

 

anticipated CO2 supply, which is currently sourced exclusively from Kinder Morgan CO2 Company, L.P. under a contract with take or pay obligations;

 

the effectiveness and results of our CO2 flood program at Aneth Field;

 

potential changes in income tax deduction 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 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 Aneth compression facility;

 

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 24-hour peak IP rates, 30-day peak IP rates, 90-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. 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 rate 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 6,500 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

  

27

Item 1B.

 

Unresolved Staff Comments

  

51

 

Item 3.

 

Legal Proceedings

  

51

 

Item 4.

 

Mine Safety Disclosures

  

51

 

PART II --

 

 

  

 

 

Item 5.

 

 

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

  

52

 

Item 6.

 

Selected Financial Data

  

54

 

Item 7.

 

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

  

55

 

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

71

 

Item 8.

 

Financial Statements and Supplementary Data

  

73

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

73

 

Item 9A.

 

Controls and Procedures

  

73

 

Item 9B.

 

Other Information

  

74

 

PART III --

 

 

  

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

74

 

Item 11.

 

Executive Compensation

  

74

 

Item 12.

 

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

  

74

 

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

  

74

 

Item 14.

 

Principal Accounting Fees and Services

  

74

 

PART IV --

 

 

  

 

 

Item 15.

 

Exhibits, Financial Statement Schedules

  

75

 

Signatures

  

82

 

 

 

 


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” refer to Predecessor Resolute (as defined below in “Selected Financial Data”) for all periods prior to September 25, 2009, and Resolute Energy Corporation and its subsidiaries for all periods thereafter.

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. Our asset base is comprised primarily of properties in the Delaware Basin in west Texas (the “Permian Properties” or “Permian Basin Properties”) and Aneth Field located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”). Our development activity is focused on our 20,000 gross (16,400 net) operated acreage position 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 opportunistic bolt-on acquisitions in the Delaware Basin while continuing to focus on improving margins in our Paradox Basin properties while de-risking certain future growth projects through selectively targeted capital investment.

During 2016 oil sales comprised approximately 90% of revenue, and our December 31, 2016, estimated net proved reserves were approximately 60.3 million barrels of oil equivalent (“MMBoe”), of which approximately 62% and 59% were proved developed reserves and proved developed producing reserves (“PDP”), respectively. Approximately 73% of our estimated net proved reserves were oil and approximately 85% were oil and natural gas liquids (“NGL”). The December 31, 2016, pre-tax present value discounted at 10% (“PV-10”) of our net proved reserves and the standardized measure of our estimated net proved reserves were $344 million. For additional information about the calculation of our PV-10 and standardized measure, please read “Business and Properties — Estimated Net Proved Reserves.”

For 2016, our Board of Directors approved a capital budget of between $115 million and $135 million, primarily focused on continuing horizontal development of our Delaware Basin Wolfcamp resource base in Reeves County, Texas, (the “Reeves County Assets”) where we planned to drill and complete a total of nine wells. Capital spending in Aneth Field was limited to acquisition of CO2, upgrades in electrical infrastructure and basic field maintenance. The drilling success achieved in our Reeves County Assets during the first half of 2016 led us to expand our 2016 drilling program by adding five additional wells (for a total of fourteen wells during 2016). Because these additional wells were drilled in the third and fourth quarters, they did not materially contribute to aggregate 2016 production. However, these wells added to our 2016 exit production rate and will provide momentum to our 2017 production volumes. Our 2016 capital plan reflected our intention to make investments in assets that are accretive to net asset value at current prices and to grow proved reserves and production that will benefit the Company as we move through 2017.

For 2017, we expect to incur capital expenditures of $210 to $240 million, primarily focused on following our successful 2016 performance in the Delaware Basin with a two rig drilling program spudding 22 gross wells. We expect the 2017 program to accomplish a number of important initiatives for the Company. We will further delineate our development inventory as we drill wells across our acreage block, conduct multiple spacing tests and complete wells in multiple landing zones in the Wolfcamp A as well as in the Wolfcamp B. The success of this program will help confirm the more than 370 Wolfcamp A and B development locations we believe exist in our Mustang and Appaloosa project areas. We also expect that substantially all of our acreage will be held by production by the end of 2017.

We expect to outspend our cash flows from operations during 2017. A deterioration of commodity prices from current levels could negatively impact our results of operations, financial condition and future development plans. We may decrease our 2017 capital investment forecast during the year as a result of, among other things, a decline in commodity prices, drilling results, cost increases, or unfavorable changes in our borrowing capacity. We may also change our capital expenditure plan depending upon our ability to consummate the Delaware Basin Orla Acquisition (defined below) and/or the potential divestiture of our Aneth Field assets described below.

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, subject to customary purchase price adjustments (the “New Mexico Sale”). The effective date of this sale is October 1, 2016. The proceeds of the sale will be used for general corporate purposes.

On March 3, 2017, Resolute Natural Resources Southwest, LLC (“Buyer”), a wholly-owned subsidiary of the Company, entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with undisclosed private sellers (“Sellers”) pursuant to which Buyer

 

1


agreed to acquire certain producing and undeveloped oil and gas properties in the Delaware Basin in Reeves County, Texas (the “Delaware Basin Orla Acquisition”).

Consideration for the acquisition will be $160 million in cash, subject to customary purchase price adjustments. The closing of the acquisition is expected to occur on or about May 15, 2017, and is subject to the satisfaction or waiver of certain customary conditions, including the material accuracy of the representations and warranties of Buyer and Sellers, and performance of covenants. The Delaware Basin Orla Acquisition has an effective date of May 1, 2017. The Purchase Agreement contains terms and conditions customary to transactions of this type. Subject to the right of Buyer to be indemnified for certain liabilities for a limited period of time and for breaches of representations, warranties and covenants, Buyer will assume substantially all liabilities associated with the acquired properties. The Purchase Agreement also contains certain customary termination rights for each of Buyer and Sellers.

The properties to be acquired include approximately 4,600 net acres in Reeves County, Texas, consisting of 2,187 net acres adjacent to the Company’s existing operating area in Reeves County and 2,405 net acres in southern Reeves County. In addition, the Company will acquire interests in (i) two operated 4,500 foot lateral horizontal Wolfcamp wells that currently produce approximately 800 net Boe per day, (ii) six operated drilled but uncompleted Wolfcamp wells, four of which have lateral lengths of approximately 4,500 feet and two with approximately 7,500 foot laterals; and (iii) one non-operated 10,000 foot lateral Wolfcamp A well that is currently drilling.

To complete our repositioning as a pure-play Delaware Basin company, Resolute’s board of directors has directed management to explore and take preparatory steps toward a disposition of the Company’s Aneth Field assets.  The potential disposition of Aneth Field, if consummated, would provide meaningful additional capital to Resolute. This capital can be deployed either to our Delaware Basin drilling program where we see our highest rates of return or as a component of the optimal long-term financing for the Delaware Basin Orla Acquisition. 

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 2017 our board of directors approved a two rig drilling program spudding 22 gross wells. Upon closing the Delaware Basin Orla Acquisition, we plan to complete six drilled but uncompleted wells on the acquired properties sequentially and will evaluate adding a third rig in the second half of 2017 to accelerate the development of the acquired properties.

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 five year operating history in the Delaware Basin and our strong technical team to identify the best opportunities. The Delaware Basin Firewheel Acquisition (defined below) and the recently announced Delaware Basin Orla Acquisition represent examples of such opportunities.

Focus on the Profitability of Aneth Field. We will continue to focus on cost control and production maintenance in our Aneth Field Properties. In addition, we expect to develop a strategy to derisk additional growth opportunities in the field. To complete our repositioning as a pure-play Delaware Basin company, Resolute’s board of directors has directed management to explore and take preparatory steps toward a disposition of the Company’s Aneth Field assets. 

 

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 increased production in lower cost areas and divestitures of higher cost properties, (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.

 

Divest of NonCore Assets. We entered into a Purchase and Sale Agreement to sell our producing properties in southeast New Mexico for a purchase price of $14.5 million. The closing of the sale occurred on February 22, 2017, effective as of October 1, 2016. These noncore assets did not contribute to our organic growth strategy. The net proceeds were used to reduce leverage, which we expect will ultimately enable us to accelerate drilling in Reeves County. We intend to continue our evaluation and execution of additional non-core asset sales, when and as appropriate.

 

Strategically Use Equity to Manage Leverage. The Delaware Basin Firewheel Acquisition (defined below) was financed with a significant issuance of both common and convertible preferred equity. With respect to the recently announced Delaware Basin Orla Acquisition, we anticipate that the ultimate financing may have components of long-term debt and equity, although we are still

 

2


evaluating the optimal financing structure, particularly in light of our recent decision to explore a potential divestiture of Aneth Field. As we look at additional acquisition opportunities, we will continue to consider the possibility of utilizing equity as consideration or a financing component.

Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our 2017 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. Based only on zones that have established production from our nearby horizontal wells, we have identified a substantial inventory of more than 370 gross horizontal well locations in the Wolfcamp A and B. Upon closing the Delaware Basin Orla Acquisition, we expect that inventory to increase substantially. We believe that this inventory will allow us to grow our reserves and production, while generating attractive rates of return at current commodity price levels and our current projected cost structure. Recent developments in the area lead us to conclude that we may be able to increase our drilling opportunity inventory through tighter spacing and increasing the number of productive horizons above and below existing producing zones.

 

Operational Staff with Deep Expertise; Operating Control of Our Properties. 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, particularly in Reeves County. The work of our drilling team has led to reductions in drilling days and larger completion designs which we believe ultimately result in more productive and economic wells. 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. Further, operatorship of our Reeves County Assets is secured for the foreseeable future, as approximately 77% of the gross acreage is held by production.

 

Stable Longlived Oil Production from Aneth Field. Our field staff has been operating Aneth Field since before its purchase by the Company. Aneth Field has exhibited a long, shallow decline. With only modest capital expenditures, production has remained essentially flat over the last eight quarters. Additionally, our operating teams have found ways to reduce operating costs more than 25% since the second quarter of 2014. Because Aneth Field is held by production, it can serve as a long term source of production and cash flow.

Summary Reserve Information

The following table presents summary information related to our estimated net proved reserves that are derived from our December 31, 2016, reserve report, which were prepared by Resolute and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.

 

 

 

Estimated Net Proved Reserves at December 31, 2016 (MMBoe)

 

 

 

Proved

 

 

Proved

 

 

 

 

 

 

 

 

 

 

2016 Net Daily

 

 

 

Developed

 

 

Developed

 

 

Proved

 

 

Total

 

 

Production

 

 

 

Producing

 

 

Non-Producing

 

 

Undeveloped

 

 

Proved

 

 

(Boe per day)

 

Aneth Field Properties

 

 

19.9

 

 

 

2.4

 

 

 

2.1

 

 

 

24.4

 

 

 

6,161

 

Permian Properties

 

 

15.4

 

 

 

 

 

 

20.5

 

 

 

35.9

 

 

 

7,996

 

Total

 

 

35.3

 

 

 

2.4

 

 

 

22.6

 

 

 

60.3

 

 

 

14,157

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future operating costs ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

756.6

 

 

 

 

 

Future production taxes ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

175.4

 

 

 

 

 

Future capital costs ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

287.9

 

 

 

 

 

Future operating costs ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12.6

 

 

 

 

 

Future production taxes ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.9

 

 

 

 

 

Future capital costs ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11.5

 

 

 

 

 

 

Description of Properties

Permian Basin Properties

As of December 31, 2016, we had interests in approximately 23,900 gross (20,000 net) acres in the Permian Basin of Texas and southeast New Mexico. Approximately 35.9 MMBoe of proved reserves are associated with these assets as of December 31, 2016.

 

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During the year, we completed 14 gross (12.0 net) wells in the Permian Basin Properties and had 86 gross (76.7 net) producing wells at year-end 2016. As of December 31, 2016, we were in the process of drilling 1 gross (1.0 net) well and had 1 gross (1.0 net) well awaiting completion operations. During 2016, average net daily production from the Permian Basin Properties was 7,996 equivalent barrels of oil (“Boe”) and was 77% liquids. See “Business and Properties – Marketing and Customers” for more information on how production from this area is sold.

Delaware Basin Project. The Delaware Basin is our principal project area and includes approximately 20,000 gross (16,400 net) acres. The primary objective in this area is the Wolfcamp formation, particularly the Wolfcamp A and B subzones. Near our project area other operators are also developing the Wolfcamp C and D subzones, the X/Y and the Third Bone Spring formation. Based on drilling activity to date, approximately 77% of the gross acreage is held by production. Approximately 35.4 MMBoe of proved reserves are associated with these assets as of December 31, 2016. We believe that growth potential exists from more than 370 gross prospective wells targeting upper Wolfcamp A, lower Wolfcamp A and upper Wolfcamp B formations, which includes twenty proved undeveloped locations. We believe that significant additional opportunity exists from reduced spacing as well as additional subzones. For 2017, the Board has approved a two rig drilling program spudding 22 gross wells (provided that this program does not take into account additional potential drilling following the anticipated consummation of the Delaware Basin Orla Acquisition).

Divestiture of Southeast New Mexico Properties in the Permian Basin. In February 2017 we sold our Denton and South Knowles properties in the Northwest Shelf project area in Lea County, New Mexico, for approximately $14.5 million, subject to customary purchase price adjustments (the “New Mexico Sale”). The closing of the New Mexico Sale occurred on February 22, 2017, with an effective date of October 1, 2016. The proceeds of the sale will be used for general corporate purposes.

Acquisition of Reeves County Properties in the Delaware Basin. 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 common stock of the Company, par value $0.0001 per share, issued to Firewheel Energy, LLC (“Firewheel”) upon the closing of the purchase of the Firewheel properties (the “Firewheel Properties”) in the Delaware Basin (the “Delaware Basin Firewheel Acquisition”).

Divestiture of Midstream Assets in the Delaware Basin. In July 2016 Resolute Natural Resources Southwest, LLC (“Resolute Southwest”), a wholly owned subsidiary of Resolute, entered into a definitive Purchase and Sale Agreement (the “Mustang Agreement”) with Caprock Permian Processing LLC and Caprock Field Services LLC, as buyers (collectively, “Caprock”) pursuant to which Resolute Southwest and a then existing minority interest holder (collectively, the “Sellers”) 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), of which approximately $2 million was placed in an escrow account for a period of time to secure Resolute’s indemnity obligations under the Mustang Agreement and the Appaloosa Agreement. As the sale did not significantly alter the relationship between capital costs and proved reserves, no gain or loss was recognized.

The net proceeds of the midstream sale were used to repay amounts outstanding under our Revolving Credit Facility (as defined below) and for general corporate purposes.

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. On March 10, 2017, the Earn-out Agreement was amended by the parties to provide for an increase in earn-out payments for wells drilled and completed in 2017. Earn-out payments are contingent on future drilling, and therefore will be recognized when received.

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 and processing 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

 

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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.

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.

Aneth Field Properties

Aneth Field, a giant legacy oil field in southeast Utah, holds 41% of our net proved reserves as of December 31, 2016, and accounted for 44% of our production during 2016, averaging 6,161 Boe per day, of which 95% was oil. We own a majority of the working interests in, and are the operator of, three federal production units covering approximately 44,000 gross acres which constitute the Aneth Field Properties. These are the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit, in which we own working interests of 62.4%, 67.5% and 58.6%, respectively, at December 31, 2016. We had interests in and operated 376 gross (238.5 net) producing wells and 324 gross (204.4 net) active water and CO2 injection wells.

Aneth Field was discovered in 1956 by Texaco and has produced approximately 448 million barrels (“MMBbl”) of oil to date. Aneth Field covers a single geologic structure with production coming from Pennsylvanian age Ismay and Desert Creek formations. For operational reasons, it was divided into the three separate operating units. In 1985, Mobil Oil Corporation (now “ExxonMobil”), as the operator of McElmo Creek Unit, initiated a successful CO2 enhanced oil recovery project that has been in operation since then, resulting in significant incremental oil reserve production from the McElmo Creek Unit. While there is some reservoir heterogeneity in Aneth Field, development of the reserves has been accomplished generally with well-tested methodologies, including drilling and infilling vertical wells, horizontal drilling, waterflood activities and CO2 flooding.

The majority of our interests in the field were acquired through two separate transactions from each of Chevron Corporation and its affiliates (“Chevron”) and ExxonMobil, in 2004 and 2006, respectively. In November 2004, our predecessor company acquired a 53% operating working interest in the Aneth Unit, a 15% non-operating working interest in the McElmo Creek Unit and a 3% non-operating working interest in the Ratherford Unit from Chevron (the “Chevron Properties”). In April 2006 our predecessor company acquired an additional 7.5% working interest in the Aneth Unit, a 60% operating working interest in the McElmo Creek Unit and a 56% operating working interest in the Ratherford Unit from ExxonMobil (the “ExxonMobil Properties”). In each transaction, the remaining available interest was acquired by Navajo Nation Oil and Gas Company (“NNOGC”) in a strategic alliance that benefits both us and NNOGC. We have a Cooperative Agreement with NNOGC that outlines how future acquisitions in a defined area will be shared and divides responsibilities between the parties to assist in the efficient development of Aneth Field. Please read “Business and Properties — Relationship with the Navajo Nation.”

In 2006, after becoming operator of the entire field, we began the infrastructure improvements required for us to expand the CO2 flood to the Aneth Unit and began injecting CO2 in 2007. Approximately 96 producing wells in the first four phases of this expansion are experiencing incremental oil production response due to the CO2 flood. Production from the area covered by the first three phases of the Aneth CO2 flood has increased by approximately 171% from 2006. During 2017 CO2 injection will continue into the currently developed patterns of Phase 1, 2, 3 and 4.

The existing Aneth Unit CO2 flood expansions and the projected CO2 flood expansion in the Ratherford Unit are in the same field and producing formation as the existing McElmo Creek Unit CO2 project. Initially, oil and gas reserves associated with expansions are classified as proved undeveloped (“PUD”). Following installation of the necessary infrastructure, these CO2-related reserves are reclassified as proved developed non-producing (“PDNP”). Once a response is exhibited at a producing well, the tertiary reserves associated with that well are then reclassified to proved developed producing (“PDP”).

We believe significant opportunity exists to increase production from existing proved reserves. We began recompleting the DC IIC in early 2010 with notable increases in production. This subzone was waterflooded by a previous operator, but was shut-in by the early 1980s due to high water cuts and low oil prices prevalent at the time, and has never been directly CO2 flooded. We have reactivated the DC IIC as a waterflood with highly economic results and plan to implement a CO2 flood in this zone. In the Ratherford Unit, we have two potential CO2 flood projects, one targeting both the Desert Creek I and II zones and a second targeting primarily the Desert Creek I zone. In Aneth Field at December 31, 2016, we had estimated net proved reserves of 2.4 MMBoe classified as PDNP and 2.1 MMBoe classified as PUD. These reserves are largely comprised of newly identified compression and deepening projects.

Beyond those projects included in our proved reserves, we believe that there are opportunities to increase reserves and production in Aneth Field through infill drilling, projects designed to increase processing rates within the CO2 floods and through technological improvements that may allow for greater recovery efficiency across the field. Projects in 2017 will be focused on testing these concepts for potential development.

 

5


CO2 is available from McElmo Dome, the largest naturally occurring CO2 source in the United States. McElmo Dome is operated by Kinder Morgan CO2 Company, L.P. (“Kinder Morgan”), with whom we have a long-term contract, with CO2 pricing based on a percentage of current NYMEX West Texas Intermediate (“WTI”) oil prices. Aneth Field is connected directly to McElmo Dome through a 28 mile pipeline that we operate and in which we own a 68% interest. We believe our long-term contract with Kinder Morgan and our ownership and operatorship of the pipeline provide a high degree of certainty and visibility with regard to meeting our CO2 supply needs. We are required to take, or pay for if not taken, 75% of the total of the maximum daily quantities for each month during the term of the Kinder Morgan contract. There are make-up provisions allowing any take-or-pay payments we make to be applied against future purchases for specified periods of time. At December 31, 2016, we have a credit of $0.2 million to be applied to future CO2 purchases. We do not have the right to resell CO2 required to be purchased under the Kinder Morgan contract.

Oil production from our Aneth Field is characterized as a light, sweet crude oil with an API gravity of 41 degrees. The field is connected by pipeline to a refinery located near Gallup, New Mexico, that is owned and operated by Western Refining Southwest, Inc., a subsidiary of Western Refining Inc. (“Western”). Western currently purchases all of the non-royalty oil production of Resolute and NNOGC from Aneth Field under a purchase agreement initially entered into in July 2014. On December 31, 2014, the Company entered into an amendment to the agreement, which provides for Resolute to receive a price equal to the NYMEX oil price minus a differential of $8.00 per barrel of oil. The amendment also extended the term of the agreement until March 31, 2015, and provided that the term would continue thereafter on a month-to-month basis until terminated by a party with ninety days prior notice. On December 8, 2015, the Company entered into a second amendment to the agreement, which provided for a reduction of the differential to $7.50 per barrel of oil. On May 9, 2016, the Company entered into a third amendment to the agreement which provided that Resolute and NNOGC will receive a price equal to NYMEX oil price minus a differential of $7.50 per barrel of oil for the first 6,000 barrels of oil purchased per day and differential of $5.50 per barrel for amounts in excess of 6,000 barrels per day, with such pricing effective on May 1, 2016. In 2016, Western entered into a pre-merger agreement with Tesoro Corporation. Upon closing of this agreement, we do not anticipate that our business relationship will be negatively impacted; however, we cannot provide assurance of such conclusion. If, for any reason, Western is unable to process our oil, there is alternative access to markets through rail and truck facilities or through the FERC-regulated Texas-New Mexico pipeline owned by Western. Furthermore, oil can be trucked to the refineries or oil pipelines in southern New Mexico, west Texas or Salt Lake City, Utah.

Resolute is party to a cooperative agreement with NNOGC related to the Aneth Field Properties (the “Cooperative Agreement”). Pursuant to the Cooperative Agreement, as modified on March 9, 2017, NNOGC holds an option to purchase an additional 10% of Resolute’s interest in the Aneth Field Properties. The option is exercisable until July 2017 at the fair market value of such interest.

The following table presents, as of December 31, 2016, our estimate of the future capital expenditures, net to our interest, for purchases of CO2 required to implement compression upgrades in the McElmo Creek Unit through 2036. The table also presents the estimated net PDNP reserves that we anticipate will be produced as a result of this project, as included in our December 31, 2016, reserve report.

 

 

 

Estimated Future Capital Expenditures (excluding CO2)

 

 

Proved Reserves (MMBoe)

 

 

Estimated Future Development Cost ($/Boe,

excluding CO2)

 

 

Estimated Future CO2 Purchases

 

 

 

(in $ millions, except as otherwise indicated)

 

McElmo Creek Unit — C5 Upgrade and New

   Compressor (PDNP)

 

$

7.6

 

 

 

2.3

 

 

$

3.28

 

 

$

15.1

 

 

Aneth Field — Gas Compression. Currently there are two types of gas production in Aneth Field, saleable gas and gas that is contaminated by CO2. The contaminated gas stream, which is rich in valuable NGL and gas, is currently compressed and re-injected into the reservoir. As we continue our CO2 injection and expansion plans, the volume of contaminated gas will increase. During 2011, we completed rebuilding of the gas compression plant at Aneth Unit, which processes all contaminated gas from the expansion project. This plant dehydrates and recovers condensate from the recycled gas stream, and we are exploring options to expand the plant to separate CO2 and hydrocarbon gas as well. If economically feasible, the hydrocarbon gas would be sold, adding income streams to the field economics while the separated CO2 stream would be reinjected into the producing zone. The plant hydrocarbon extraction expansion project has been through early stages of engineering design and is currently on hold pending recovery of gas and NGL prices.

The saleable gas stream is currently transported to the San Juan Gas Plant in Fruitland, New Mexico. We are paid on a percent of proceeds basis that resulted in an average price of $1.31 per Mcf during 2016.

Divestiture of Wyoming Properties

In October 2015 we sold our Hilight Field interests in the Powder River Basin for approximately $55 million. The sale was consummated on October 6, 2015, with an effective date of July 1, 2015.

 

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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, 2016, 2015 and 2014 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,

 

 

 

2016

 

 

2015

 

 

2014

 

Net proved developed reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

30,026

 

 

 

25,672

 

 

 

34,359

 

Gas (MMcf)

 

 

24,209

 

 

 

7,098

 

 

 

25,775

 

NGL (MBbl)

 

 

3,595

 

 

 

1,019

 

 

 

2,791

 

MBoe (1)

 

 

37,656

 

 

 

27,874

 

 

 

41,446

 

Net proved undeveloped reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

13,778

 

 

 

3,076

 

 

 

29,356

 

Gas (MMcf)

 

 

28,238

 

 

 

6,761

 

 

 

11,023

 

NGL (MBbl)

 

 

4,127

 

 

 

1,043

 

 

 

1,579

 

MBoe (1)

 

 

22,611

 

 

 

5,246

 

 

 

32,772

 

Total net proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

43,804

 

 

 

28,747

 

 

 

63,715

 

Gas (MMcf)

 

 

52,448

 

 

 

13,859

 

 

 

36,798

 

NGL (MBbl)

 

 

7,722

 

 

 

2,063

 

 

 

4,370

 

MBoe (1)

 

 

60,267

 

 

 

33,120

 

 

 

74,218

 

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

 

 

344

 

 

 

199

 

 

 

973

 

Discounted future income taxes ($ in millions)

 

 

 

 

 

 

 

 

(140

)

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

 

 

344

 

 

 

199

 

 

 

833

 

 

 

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, 2016, 2015 and 2014, were determined utilizing prices equal to the respective twelve-month unweighted arithmetic average using first day of the month prices, resulting in an average NYMEX WTI oil price of $42.75, $50.28 and $94.99 per Bbl for the Aneth Properties and Plains Marketing, L.P. posted WTI oil price of $39.25, $46.79 and $91.48 per Bbl for the Permian Properties, and an average Platts Gas Daily El Paso San Juan Basin spot gas price of $2.33, $2.46, and $4.31 per MMBtu for the Aneth Properties and Platts Gas Daily El Paso Permian Basin spot gas price of $2.31, $2.45, and $4.25 per MMBtu for the Permian Properties, 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.”

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, which, in the case of year-end 2016 estimates, are significantly lower than prevailing prices. 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

 

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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 from 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 facility construction and well development activities began on CO2 flood projects in Aneth Field in 2006, with CO2 injection commencing in 2007 in Aneth Unit, and are ongoing although at reduced levels due to the current low commodity price environment. No CO2 flood project proved undeveloped reserves were converted to proved developed in 2016.

Our operated drilling focus in 2016 was to preserve term leasehold acreage in the Permian Basin Properties primarily by targeting drilling on non-proved locations. During 2016, 22,491 gross MBoe of proved developed producing reserves were added to the proved reserves base through a successful blend of both operated and non-operated drilling of 15 gross non-proved locations in 2016 and late 2015, and through acquisition of additional ownership in those wells during 2016. No proved undeveloped reserves were converted into proved developed producing during 2016. An incremental 14 gross 2016 wells were drilled which, together with one later 2015 gross well, yielded total additions of 14,762 MBoe net of proved developed producing reserves and 17,957 MBoe net of proved undeveloped reserves through the addition of 20 gross immediate offset proved undeveloped Permian locations. These numbers include 907 MBoe of net proved producing reserves and 1,755 MBoe of net proved undeveloped reserves attributable to the acquisition of additional ownership in wells drilled, and existing leasehold, during 2016. These numbers also include 2016 production of 3,519 gross (2,214 net) MBoe.

Additionally, 4,486 MBoe of net proved developed non-producing and proved undeveloped reserves were added to Aneth Field in connection with newly identified compression and well deepening projects

With respect to the properties included in our prior year reserve reports, we incurred development costs of $31.1 million in 2016 as compared to $39.8 million in 2015. The year over year change in developmental costs is also reflective of our operated drilling focus in 2016 to preserve term leasehold acreage in the Permian Basin. With respect to the total proved value, 2 gross (1.7 net) horizontal proved undeveloped drilling locations are scheduled to be drilled after some corresponding portion of primary term leasehold within each is set to expire. The Company plans to drill two alternative non-proven locations that will convert the leasehold to held-by-production status prior to any lease expiration. Without consideration of continuous drilling operations and lease conversion activity, total proved reserves would be adversely affected by 2.2% on a volumetric basis and 0.4% on a value basis.

At December 31, 2016, no proved undeveloped reserves have remained, or are scheduled to remain, undeveloped beyond five years from its corresponding initial booking date.

 

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Changes in Proved Reserves

Proved reserves reported by us at December 31, 2016, increased from those reported at December 31, 2015, as follows:

 

 

 

 

 

Oil Equivalent

 

 

 

 

 

(MBoe)

 

Proved reserves as of December 31, 2015

 

 

 

 

33,120

 

Production

 

 

 

 

(5,182

)

Extensions, discoveries and other additions

 

 

 

 

34,543

 

Purchases of minerals in place

 

 

 

 

3,323

 

Sales of minerals in place

 

 

 

 

 

Revisions of previous estimates

 

 

 

 

(5,537

)

Proved reserves as of December 31, 2016

 

 

 

 

60,267

 

Proved developed reserves:

 

 

 

 

 

 

As of December 31, 2016

 

 

 

 

37,656

 

Proved undeveloped reserves:

 

 

 

 

 

 

As of December 31, 2016

 

 

 

 

22,611

 

 

Extensions, discoveries and other additions to proved reserves were the result of drilling wells in the Permian Basin and new compression and well deepening projects in Aneth Field.

 

The Permian Basin 2016 drilling program resulted in total additions of 14,762 net MBoe of proved developed producing reserves, which included 13,855 net MBoe from the successful drilling of non-proved locations and 907 net MBoe from the acquisition of additional interests in these wells during 2016. These successful wells also created additional proved undeveloped offset locations of 17,957 net MBoe, which included 16,202 net MBoe related to the addition of the 20 immediate offset proved undeveloped Permian location and 1,755 net MBoe related to the acquisition of additional ownership in existing leases. No proved undeveloped locations were developed during 2016.

 

Additionally, 4,486 MBoe of net proved developed non-producing and proved undeveloped reserves were added to Aneth Field in connection with newly identified compression and well deepening projects.

 

In accordance with SEC requirements, the oil reserves at December 31, 2016 and 2015, utilized average NYMEX West Texas Intermediate oil prices of $42.75 and $50.28 per Bbl, respectively, for the Aneth Properties and average Plains Marketing, L.P. posted West Texas Intermediate oil prices of $39.25 and $46.79 per Bbl, respectively, for the Permian Basin Properties. For gas, the reserves at December 31, 2016 and 2015, utilized average Platts Gas Daily El Paso San Juan Basin spot gas price of $2.33, $2.46, and $4.31 per MMBtu for the Aneth Properties and Platts Gas Daily El Paso Permian Basin spot gas price of $2.31, $2.45, and $4.25 per MMBtu for the Permian Properties, respectively.

 

Revisions of previous estimates primarily relate to projects that had economically proved reserves at December 2015 average prices, but were not economically proved reserves at December 2016 average prices.

 

Controls Over Reserve Report Preparation, Technical Qualification and Methodologies Used

Reserve estimates as of December 31, 2016, were prepared by Resolute and audited by Netherland Sewell and 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 32 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.

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

 

9


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.

NSAI is a worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI delivers high quality, fully integrated engineering, operational, geologic, geophysical, petrophysical and economic solutions for all facets of the upstream energy industry. Within NSAI, the technical person primarily responsible for the NSAI audit is Mr. David Miller. Mr. Miller has been practicing consulting petroleum engineering at NSAI since 1997. He is a Registered Professional Engineer in the States of Texas and Louisiana and has more than 35 years of practical experience in petroleum engineering, with more than nineteen years of experience in the estimation and evaluation of reserves. He graduated from the University of Kentucky in 1981 with a Bachelor of Science degree in Civil Engineering and from Southern Methodist University in 1994 with a Master of Business Administration degree. Mr. Miller’s qualifications meet or exceed 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, 2016, 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 2016, 2015 and 2014.

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

3,821

 

 

 

3,271

 

 

 

3,488

 

Gas (MMcf)

 

 

4,811

 

 

 

5,194

 

 

 

5,023

 

NGL (MBbl)

 

 

559

 

 

 

400

 

 

 

320

 

Combined volumes (MBoe)

 

 

5,182

 

 

 

4,536

 

 

 

4,645

 

Daily combined volumes (Boe per day)

 

 

14,157

 

 

 

12,427

 

 

 

12,727

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

38.83

 

 

$

42.16

 

 

$

84.28

 

Gas ($/Mcf)

 

 

2.22

 

 

 

2.43

 

 

 

5.23

 

NGL ($/Bbl)

 

 

9.80

 

 

 

10.32

 

 

 

28.58

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

12.29

 

 

$

17.50

 

 

$

24.26

 

Production and ad valorem taxes

 

 

3.14

 

 

 

4.41

 

 

 

8.01

 

 

 

10


In each of the years presented above, total estimated proved reserves attributed to our Delaware Basin Project area and Aneth Field exceeded fifteen percent of our total proved reserves expressed on an equivalent basis. Therefore, the tables below summarize our operating data for the Delaware Basin Project area and Aneth Field for 2016, 2015 and 2014.

 

Delaware Basin Project area:

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

1,489

 

 

 

393

 

 

 

209

 

Gas (MMcf)

 

 

3,989

 

 

 

1,579

 

 

 

615

 

NGL (MBbl)

 

 

549

 

 

 

224

 

 

 

90

 

Combined volumes (MBoe)

 

 

2,704

 

 

 

880

 

 

 

401

 

Daily combined volumes (Boe per day)

 

 

7,387

 

 

 

2,412

 

 

 

1,099

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

42.25

 

 

$

43.50

 

 

$

75.51

 

Gas ($/Mcf)

 

 

2.40

 

 

 

2.29

 

 

 

4.20

 

NGL ($/Bbl)

 

 

9.64

 

 

 

7.89

 

 

 

22.32

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

4.62

 

 

$

7.47

 

 

$

14.63

 

Production and ad valorem taxes

 

 

2.14

 

 

 

2.67

 

 

 

3.92

 

 

Aneth Field:

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

2,132

 

 

 

2,172

 

 

 

2,249

 

Gas (MMcf)

 

 

739

 

 

 

717

 

 

 

276

 

NGL (MBbl)

 

 

 

 

 

 

 

 

 

Combined volumes (MBoe)

 

 

2,255

 

 

 

2,292

 

 

 

2,295

 

Daily combined volumes (Boe per day)

 

 

6,161

 

 

 

6,279

 

 

 

6,287

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

36.37

 

 

$

40.81

 

 

$

84.76

 

Gas ($/Mcf)

 

 

1.31

 

 

 

1.87

 

 

 

4.76

 

NGL ($/Bbl)

 

 

 

 

 

 

 

 

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

20.24

 

 

$

21.55

 

 

$

27.08

 

Production and ad valorem taxes

 

 

4.31

 

 

 

5.98

 

 

 

11.04

 

 

 

11


Oil and Gas Wells

The following table sets forth information as of December 31, 2016, 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. In addition to the wells below, we had interests in and operated 326 gross (206 net) active water and CO2 injection wells as of December 31, 2016.

 

 

 

Productive Wells(1)

 

 

 

Gross

 

 

Net

 

Oil

 

 

466

 

 

 

319

 

Gas

 

 

1

 

 

 

 

Total

 

 

467

 

 

 

319

 

 

 

1)

We operated 458 gross (318 net) productive wells at December 31, 2016.

Drilling Activity

The following table sets forth information with respect to exploration, development and extension wells we completed during 2016, 2015 and 2014. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. Fluid injection wells for waterflood and other enhanced recovery projects are not included as gross or net wells.

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Gross exploration wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

 

 

 

1

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total exploration wells

 

 

 

 

 

 

 

 

1

 

Gross development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

1

 

 

 

8

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total development wells

 

 

 

 

 

1

 

 

 

8

 

Gross extension wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(3)

 

 

14

 

 

 

5

 

 

 

11

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total extension wells

 

 

14

 

 

 

5

 

 

 

11

 

Total gross wells drilled

 

 

14

 

 

 

6

 

 

 

20

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Net exploration wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

 

 

 

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total exploration wells

 

 

 

 

 

 

 

 

 

Net development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

1

 

 

 

4

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total development wells

 

 

 

 

 

1

 

 

 

4

 

Net extension wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(3)

 

 

12

 

 

 

2

 

 

 

6

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total extension wells

 

 

12

 

 

 

2

 

 

 

6

 

Total net wells drilled