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 - Supplemental Oil and Gas Information (Unaudited)
Note 13 - Quarterly Financial Data (Unaudited)
EX-10.33 ren-ex1033_1112.htm
EX-10.34 ren-ex1034_1111.htm
EX-12.1 ren-ex121_12.htm
EX-21 ren-ex21_10.htm
EX-23.1 ren-ex231_13.htm
EX-23.2 ren-ex232_7.htm
EX-31.1 ren-ex311_11.htm
EX-31.2 ren-ex312_8.htm
EX-32 ren-ex32_9.htm
EX-99.1 ren-ex991_1203.htm

Resolute Energy Earnings 2015-12-31

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_20151231.htm 10-K ren-10k_20151231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-K

 

x

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

For the fiscal year ended December 31, 2015

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  x

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  x

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  x    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 x    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.  x

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

 

x

 

 

 

 

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  x

The aggregate market value of registrant’s common stock held by non-affiliates on June 30, 2015, computed by reference to the price at which the common stock was last sold as posted on the New York Stock Exchange, was $53.5 million.

As of February 29, 2016, 77,430,057 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 2016 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, our production and cost guidance for 2016; anticipated capital expenditures in 2016 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 liquidity enhancing and de-levering transactions, including a mid-stream asset monetization, joint ventures, asset sales and potential restructuring of our existing debt facilities; liquidity and availability of capital including projections of free cash flow; additional future potential full cost ceiling impairments; future downward adjustments in estimated proved reserves as a result of low commodity prices; 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 such projects and the resource potential of such projects; and the prospectivity of our properties and acreage.  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:

 

·

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, secured term loan facility, the senior notes and any additional indebtedness we may incur;

 

·

constraints imposed on our business and operations by our revolving credit facility, secured term loan 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;

 

·

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;

 

·

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;

 

·

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;

 

·

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

 

·

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

 

·

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 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 saltwater 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;

 

·

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;

 

·

developments in 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;

 

·

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 Aneth Field;

 

·

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;

 

·

risks related to our common stock including potential delisting from the NYSE, complication of “penny stock” rules and potential declines in our stock prices and dilution to stockholders;

 

·

the risk of a transaction that could trigger a change of control under our debt agreements, and the higher likelihood of such a transaction occurring due to our current low stock price;

 

·

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;

 

·

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.

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.

Finally, 24 hour peak IP rates and 30 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 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 24 hour and 30 day peak IP rates and the methodologies employed by others may not be consistent, thus the values reported may not be directly and meaningfully comparable.

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

  

52

 

Item 3.

 

Legal Proceedings

  

52

 

Item 4.

 

Mine Safety Disclosures

  

53

 

PART II --

 

 

  

 

 

Item 5.

 

 

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

  

54

 

Item 6.

 

Selected Financial Data

  

57

 

Item 7.

 

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

  

58

 

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

73

 

Item 8.

 

Financial Statements and Supplementary Data

  

74

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

74

 

Item 9A.

 

Controls and Procedures

  

74

 

Item 9B.

 

Other Information

  

75

 

PART III --

 

 

  

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

75

 

Item 11.

 

Executive Compensation

  

75

 

Item 12.

 

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

  

75

 

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

  

75

 

Item 14.

 

Principal Accounting Fees and Services

  

75

 

PART IV --

 

 

  

 

 

Item 15.

 

Exhibits, Financial Statement Schedules

  

76

 

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 Aneth Field located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”) and the Permian Basin in Texas and southeast New Mexico (the “Permian Properties” or “Permian Basin Properties”). Our primary operational focus for 2016 is on executing a limited drilling program in our Reeves County, Texas, properties while maintaining reduced operating costs in the current depressed commodity price environment. Over the longer term, we plan to expand our reserve base and production through an organic growth strategy focused on the expansion of tertiary oil recovery in Aneth Field, the exploitation and development of oil-prone acreage, particularly in our Permian Properties, through carefully targeted exploration activities in our properties and through opportunistic acquisitions.

During 2015 oil sales constituted approximately 89% of revenue, and our December 31, 2015, estimated net proved reserves were approximately 33.1 million barrels of oil equivalent (“MMBoe”), of which approximately 84% and 76% were proved developed reserves and proved developed producing reserves (“PDP”), respectively. Approximately 87% of our estimated net proved reserves were oil and approximately 93% were oil and natural gas liquids (“NGL”). The December 31, 2015, 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 $199 million. For additional information about the calculation of our PV-10 and standardized measure, please read “Business and Properties — Estimated Net Proved Reserves.”

In 2015 we adopted and implemented an operating and financial plan intended to hold production essentially flat while we conserved capital and focused on reducing operating and overhead costs across the business.  We accomplished our production goals for the year and we significantly reduced our lease operating and general and administrative expenses from historical levels. Additionally, in order to reduce leverage and enhance liquidity, we identified specific assets which management felt it would be prudent to divest.  This program included the divestiture of assets in Howard, Martin, Midland and Ector counties, Texas, as well as Campbell County, Wyoming, for total proceeds of nearly $275 million. All of these proceeds were used to reduce outstanding indebtedness.  We currently have a borrowing base of $145 million under our credit facility (the “Revolving Credit Facility”). Revolving Credit Facility debt was $0 at December 31, 2015, and February 29, 2016.  The Company’s success in both our operational and strategic initiatives in 2015 gave us the flexibility to increase our original capital budget during the fourth quarter of the year.  In November 2015 our board of directors approved a four well horizontal development drilling program in the Reeves County portion of the Delaware Basin which commenced in November 2015 with the spudding of the first well of this program, a 7,500-foot Wolfcamp A lateral followed by three additional Wolfcamp wells.

For 2016, our Board of Directors approved a capital budget primarily focused on continuing horizontal development of our Delaware Basin Wolfcamp resource base in Reeves County, Texas, (our “Reeves County Assets”) where we plan to drill and complete a total of nine wells (inclusive of the four wells above). Capital spending in Aneth Field will be limited to acquisition of CO2 and basic field maintenance.  This budget reflects our view that 2016 is a window of opportunity for Resolute 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 2016 and into 2017.  Our ability to make these investments results from the significant progress made by the Company in 2015 in lowering operating costs and improving our liquidity position, our 2016 derivative position, and the success of our Reeves County drilling efforts to date.

In 2016 we will consider and pursue such actions as are necessary to preserve our liquidity and to remain in compliance with the terms and conditions of our Revolving Credit Facility, our secured term loan facility (the “Secured Term Loan Facility”) and 8.5% senior notes (the “Senior Notes”).  We will also continue to explore other ways to enhance our liquidity, de-lever our balance sheet and increase drilling activity, including a potential monetization of certain of our Reeves County midstream assets, potential asset sales, potential joint ventures in the Permian Basin, and potential restructuring of our existing debt facilities. Such strategic initiatives are considered on an ongoing basis and decisions related thereto will be made if the terms are determined to be advantageous to us.

 

1


We expect to outspend our cash flows from operations during 2016. However, a further deterioration of commodity prices could negatively impact our results of operations, financial condition and future development plans. We may decrease our 2016 capital forecast during the year as a result of, among other things, a further decline in commodity prices, drilling results, cost increases, or unfavorable changes in our borrowing capacity. If commodity pricing falls short of our expectations, we would likely look to reduce our capital investment in the second half of 2016 to maintain liquidity.

Business Strategies

Our business strategies in the near term during the current period of depressed oil and gas prices are focused on maintaining liquidity, reducing operating costs and leverage and efficiently executing our limited capital program.

The key elements of our near term business strategy include:

Focus on Exploitation and Development of Oil and Liquids-Prone Formations on Existing Properties.  Our horizontal drilling program has been focused on our Reeves County Assets in the Wolfcamp play in the Reeves County portion of the Delaware Basin, where the Company has significant drilling and completion experience. This area has known geologic and reservoir characteristics, with production heavily weighted toward oil and NGL. Our board of directors approved a nine well horizontal development drilling program in the area (inclusive of the four wells approved in late 2015). We commenced drilling operations on the first well of this program, a 7,500-foot Wolfcamp A lateral, in November 2015 and have operated a continuous program since that time. We have drilled a total of three Wolfcamp wells and intend to continue drilling until the nine well program is complete.

Focus on Efficiency of Operations on Our Properties. We seek to maximize economic returns on our properties through operating and drilling efficiencies and cost control improvements. Our management team has significant experience in managing intensive oil and gas operations through commodity price cycles. As the operator of our Aneth Field Properties and the majority of the Permian Properties, we have the ability to more directly manage our costs, control the timing of our exploitation, drilling and producing activities and effectively implement programs to increase production and improve operational and drilling efficiency.

Upon returning to a normalized commodity price environment, our business strategies would return to strategies substantially similar to those that we have pursued over the last several years, which include creating value for our shareholders by growing reserves, production volumes and cash flow utilizing industry standard enhanced oil recovery techniques as well as advanced development, drilling and completion technologies to systematically explore for, develop and produce oil and gas reserves. Key elements of this medium to long term strategy include:

Expand Production Within our Aneth Field CO2 Flood. We intend to increase production in Aneth Field through activities targeted at converting non-producing reserves into production. These activities include the McElmo Creek Unit IIC subzone of the Desert Creek formation (the “DC IIC”) CO2 expansion, increasing the processing of CO2 in existing patterns, drilling in various areas of the field and bringing new reserves into the proved category by expanding the CO2 flood into the Ratherford Unit. In the Aneth Field Properties, proved developed non-producing (“PDNP”) and proved undeveloped reserves (“PUD”) at December 31, 2015, constitute 10% and 5%, respectively, of the proved reserves. These reserves primarily relate to the CO2 flood that we commenced in 2006, which followed a successful CO2 flood program in the McElmo Creek Unit implemented in 1985 by a prior operator. Using a phased approach, we have been expanding this CO2 flood within the field with demonstrable success.

Pursue Acquisitions of Properties with Development Potential in Core Areas. One component of our strategy has been to grow our reserves and production by acquiring domestic onshore properties with significant development potential. In December 2012 we acquired properties in the Permian Basin (the “Permian Acquisitions”). Prior to the Permian Acquisitions, our predecessor company acquired the majority of our Aneth Field Properties in 2004 and 2006. The original component of our Permian Properties was acquired in 2011. We expect to evaluate opportunities from time to time to acquire properties that are prospective for production of oil and NGL, particularly in the Permian Basin. Our knowledge of various producing basins and our experienced management team with long-standing industry relationships position us to continue to identify, consummate and integrate strategic acquisitions. Future acquisitions may require us to issue debt or equity securities and incur additional indebtedness.  

 

2


Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our 2016 and longer term business strategies, including:

Portfolio of Significant Organic Development and Drilling Opportunities in Premier U.S. Oil Producing Basin. We have a significant operational capability in the Delaware Basin portion of the Permian Basin, a premier U.S. onshore oil resource. We have identified a substantial inventory of approximately 220 prospective wells targeting three zones in the Wolfcamp formation based on 160-acre spacing. We believe that this inventory will allow us to grow our reserves and production, and that the majority of our projects will generate attractive rates of return at current commodity price projections and our current projected cost structure.

A High Quality Base of Long-Lived Oil Producing Properties. As of December 31, 2015, we had estimated net proved reserves of approximately 33.1 MMBoe, of which approximately 87% were oil and approximately 93% were oil and NGL. Based on our 2015 year-end reserve report, our total proved reserve to production ratio was 7.3 years. 77% of these reserves were located in Aneth Field, a field characterized by shallow decline rates which result in a slower reserve depletion rate and reduced reinvestment requirements relative to other producing areas in the United States.

Operating Control Over Our Properties. As operator, we have the ability to more directly control the timing, scope and costs of most development projects undertaken on our various properties. We operate our Aneth Field and the substantial majority of our Permian Properties, which constitute 98% of our proved reserves. Further, operatorship of our Aneth Field and Permian Basin Properties is secured for the foreseeable future, as approximately 80% of the acreage is held by production. Finally, our properties are largely concentrated acreage positions with high working interests.

Favorable Commodity Price Hedges in Place for 2016 and 2017.  As of February 29, 2016, the Company’s 2016 hedging program covers 6,538 barrels of oil per day, at a weighted average floor price of $80.23 per barrel and 3,700 MMBtu of gas per day at $2.42 per MMBtu. In 2017, we have swaps covering 1,033 barrels of oil per day at a weighted average price of $49.35, as well as a three-way collar covering 1,000 barrels of oil per day with a short put price of $45.00, a floor price of $60.00 and a ceiling price of $71.73. In 2017 we have swaps covering 2,025 MMBtu of gas per day with a weighted average price of $2.69 and a two-way collar covering 1,625 MMBtu of gas per day with a floor price of $2.25 and a ceiling price of $2.64.

Management and Technical Teams with Extensive Operational, Transactional and Financial Experience in the Energy Industry. With an average industry work experience of 25 years, our senior management team has considerable experience in acquiring, exploring, exploiting, developing and operating oil and gas properties, particularly in operationally intensive oil and gas fields. Three members of our executive management worked together previously as part of the senior management team of HS Resources, Inc., an independent oil and gas company that was listed on the New York Stock Exchange and operated primarily in the Denver-Julesburg Basin in northeast Colorado. HS Resources, Inc. was acquired by Kerr-McGee Corporation in 2001 for $1.8 billion. We also employ about 43 oil and gas technical professionals, including geologists, petroleum engineers, and land and financial specialists, who have an average of approximately 21 years of experience in their respective technical fields. We continually leverage the extensive experience of our senior management and technical staff to benefit all aspects of our operations.

 

3


Summary Reserve Information

The following table presents summary information related to our estimated net proved reserves that are derived from our December 31, 2015, 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, 2015 (MMBoe)

 

 

 

Proved

 

 

Proved

 

 

 

 

 

 

 

 

 

 

2015 Net Daily

 

 

 

Developed

 

 

Developed

 

 

Proved

 

 

Total

 

 

Production

 

 

 

Producing

 

 

Non-Producing

 

 

Undeveloped

 

 

Proved

 

 

(Boe per day)

 

Aneth Field Properties

 

 

21.6

 

 

 

2.6

 

 

 

1.3

 

 

 

25.5

 

 

 

6,279

 

Permian Properties

 

 

3.7

 

 

 

 

 

 

3.9

 

 

 

7.6

 

 

 

4,883

 

Wyoming Properties

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,265

 

Total

 

 

25.3

 

 

 

2.6

 

 

 

5.2

 

 

 

33.1

 

 

 

12,427

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future operating costs ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

601

 

 

 

 

 

Future production taxes ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

173

 

 

 

 

 

Future capital costs ($ millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

180

 

 

 

 

 

Future operating costs ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

18.15

 

 

 

 

 

Future production taxes ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5.22

 

 

 

 

 

Future capital costs ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5.43

 

 

 

 

 

 

Description of Properties

Aneth Field Properties

Aneth Field, a giant legacy oil field in southeast Utah, holds 77% of our net proved reserves as of December 31, 2015, and accounted for 51% of our production during 2015, averaging 6,279 equivalent barrels of oil (“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 43,000 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%, 67.5% and 59%, respectively, at December 31, 2015. We had interests in and operated 387 gross (245 net) producing wells and 331 gross (209 net) active water and CO2 injection wells.

Aneth Field was discovered in 1956 by Texaco and has produced approximately 444 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 93 producing wells in the first three 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 197% from 2006. During 2016 CO2 injection will continue into the currently developed patterns of Phase 1, 2, 3 and 4, although at reduced levels due to the current low commodity price environment.

 

4


The CO2 flood expansions within the Aneth Unit and the projected CO2 flood 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 PUD. Following installation of the necessary infrastructure, these CO2-related reserves are reclassified as PDNP. Once a response is exhibited at a producing well, the tertiary reserves associated with that well are then reclassified to PDP. In Aneth Field at December 31, 2015, we had estimated net proved reserves of 3.9 MMBoe that were classified as PDNP. As a result of low commodity prices, there were no proved reserves classified as PUD. Of these reserves, 2.3 MMBoe are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods.

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. Within the Ratherford Unit, we have two CO2 flood projects, one targeting both the Desert Creek I and II zones and a second targeting primarily the Desert Creek I zone.

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.

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, 2015, 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 40 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 oil production from Aneth Field under a purchase agreement dated July 2014. On December 31, 2014, the Company entered into an amendment to the purchase agreement with Western, 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 provides that the term of the purchase agreement shall continue automatically after December 31, 2014, until March 31, 2015, and 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 another amendment to the purchase agreement with Western, which now provides for Resolute to receive a price equal to the NYMEX oil price minus a differential of $7.50 per barrel of oil. 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.

In 2012 we and NNOGC entered into an amendment to our Cooperative Agreement. Among other changes, this amendment allowed NNOGC to exercise options to purchase 10% of our interest in Aneth Field, before giving effect to a subsequent transaction that. This option was exercised for consideration of $100 million prior to customary closing adjustments. The purchase and sale agreement relating to the option exercise provided that the transaction be closed and paid for in two equal transfers in July 2012 and January 2013, each with an effective date of January 1, 2012. Each transfer was to be for 5% of our interest in the properties. The first transfer took place in July 2012 and the second transfer took place in January 2013.

The Cooperative Agreement amendment also cancelled a second set of options held by NNOGC to purchase an additional 10% interest in the Aneth Field Properties and stipulates that NNOGC has one remaining option to purchase an additional 10% of our interest in the Aneth Field Properties (as it stood prior to the 2012 option exercise and excluding interests acquired in subsequent transactions and certain other minority interests), exercisable in July 2017 at the then-current fair market value of such interest.

 

5


The following table presents, as of December 31, 2015, our estimate of the future capital expenditures, net to our interest, for purchases of CO2 required to complete the CO2 flood project in the Aneth Unit through 2031. 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, 2015 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)

 

Aneth Unit -- Phase 1, 2, 3 and 4 (PDNP)

 

$

 

 

 

2.3

 

 

$

 

 

$

18.4

 

Total

 

$

 

 

 

2.3

 

 

$

 

 

$

18.4

 

 

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 fifty miles to a gas processing plant in Lisbon, Utah, operated by CCI LLC, although the gas stream may be processed at the San Juan Gas Plant (also operated by CCI LLC) in the future. We are paid on a percent of proceeds basis that resulted in an average price of $1.87 per Mcf during 2015.

Permian Properties

As of December 31, 2015, we had interests in 27,750 gross (17,574 net) acres in the Permian Basin of Texas and southeast New Mexico. Our position is divided between two principal project areas: the Delaware Basin project area in Reeves County and the Northwest Shelf project area located in the Denton, Gladiola and Knowles fields in the Northwest Shelf area in Lea County, New Mexico. Approximately 7.6 MMBoe of proved reserves are associated with these assets as of December 31, 2015. During the year, we completed 6.0 gross (2.2 net) wells in the Permian Properties and had 81 gross (64 net) producing wells at year-end 2015. As of December 31, 2015, we were in the process of drilling 1.0 gross (0.2 net) well and had 3.0 gross (1.3 net) wells awaiting completion operations. During 2015, average net daily production from the Permian Properties was 4,883 Boe and was 76% 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 project area includes approximately 23,060 gross (13,603 net) acres. The primary objective in this area is the Wolfcamp formation. Within the Wolfcamp formation, we have targeted primarily the Wolfcamp A and B subzones. Within our project area, other operators are also developing the Wolfcamp C and D subzones as well as the third Bone Spring formation. Based on drilling activity to date, approximately 47% of the acreage is held by production. Approximately 6.9 MMBoe of proved reserves are associated with these assets as of December 31, 2015. We believe that growth potential exists from approximately 220 gross prospective wells targeting three zones in the Wolfcamp formation based on 160-acre spacing. We believe that significant additional opportunity exists from reduced spacing as well as additional subzones.

During the fourth quarter of 2015, the Company recommenced the horizontal drilling program in the Delaware Basin Project with a four-well program comprised of two 7,500 foot horizontals and two 10,000 foot horizontals. For 2016, this program has been expanded to include five additional planned 10,000 foot horizontals.

Northwest Shelf Project. In 2012 we acquired assets in Lea County, New Mexico, in Denton, Gladiola and South Knowles fields, which are legacy conventional oil fields that produce from fractured carbonate reservoirs and cover 4,700 gross acres in which we hold an approximate 85% working interest, all held by production. Our interest in Denton Field, the largest of the three fields, consists of 2,900 gross acres, all of which are held by production. Approximately 0.7 MMBoe of proved reserves are associated with our Denton Field interests. We believe that growth potential and upside may exist from activities such as deepening existing wells and infill drilling from 40-acre to 20-acre spacing. In 2013 we completed a three-dimensional (“3D”) seismic shoot across Denton Field which will provide further insight into the development opportunities that may exist in this area. We are the operator of the Lea County assets.

 

6


Divestiture of Properties in the Midland Basin. In November 2015 we sold our Gardendale interests in the Midland Basin for approximately $177.5 million. The sale was consummated on December 22, 2015, with an effective date of September 1, 2015. In May 2015 we sold our Howard and Martin County properties in the Permian Basin for approximately $42 million. The sale was consummated on May 1, 2015, with an effective date of March 1, 2015.

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.

Divestiture of North Dakota Properties

In 2013 we sold all of our non-operated properties located in the Bakken trend of North Dakota through three separate transactions for net proceeds of approximately $70.1 million. In March 2014 we sold our remaining operated properties in North Dakota for approximately $6.6 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, 2015, 2014 and 2013 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,

 

 

 

2015

 

 

2014

 

 

2013

 

Net proved developed reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

25,672

 

 

 

34,359

 

 

 

38,791

 

Gas (MMcf)

 

 

7,098

 

 

 

25,775

 

 

 

29,488

 

NGL (MBbl)

 

 

1,019

 

 

 

2,791

 

 

 

3,136

 

MBoe (1)

 

 

27,874

 

 

 

41,446

 

 

 

46,842

 

Net proved undeveloped reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

3,076

 

 

 

29,356

 

 

 

8,720

 

Gas (MMcf)

 

 

6,761

 

 

 

11,023

 

 

 

12,901

 

NGL (MBbl)

 

 

1,043

 

 

 

1,579

 

 

 

1,681

 

MBoe (1)

 

 

5,246

 

 

 

32,772

 

 

 

12,552

 

Total net proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

28,747

 

 

 

63,715

 

 

 

47,511

 

Gas (MMcf)

 

 

13,859

 

 

 

36,798

 

 

 

42,389

 

NGL (MBbl)

 

 

2,063

 

 

 

4,370

 

 

 

4,817

 

MBoe (1)

 

 

33,120

 

 

 

74,218

 

 

 

59,394

 

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

 

 

199

 

 

 

973

 

 

 

1,054

 

Discounted future income taxes ($ in millions)

 

 

 

 

 

(140

)

 

 

(161

)

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

 

 

199

 

 

 

833

 

 

 

893

 

 

 

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, 2015, 2014 and 2013, were determined utilizing prices equal to the respective twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX WTI oil price of $50.28, $94.99 and $96.94 per Bbl for the Aneth Properties and Plains Marketing, L.P. posted WTI oil price of $46.79, $91.48 and $93.42 per Bbl for the Permian Properties, and an average Henry Hub spot market gas price of $2.59, $4.35 and $3.67 per MMBtu, 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.”

 

7


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 2015 estimates, are significantly in excess of 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 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 12 — 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 2015.

Our operated drilling focus in 2015 was to preserve term leasehold acreage in the Permian Properties by primarily targeting non-proved locations. During 2015, 576 ultimate MBoe of proved undeveloped reserves were converted into proved developed producing as a result of successful operated drilling of one gross proved undeveloped location. Additionally non-proved reserves were added to the proved reserve base through a blend of both operated and non-operated drilling. An incremental three gross wells were drilled yielding additions of 970 MBoe net of proved developed producing reserves and 3,632 MBoe net of proved undeveloped reserves through the addition of eight immediate offset proved undeveloped locations. The above numbers include 2015 net production of 143 MBoe for the 576 MBoe figure and 206 MBoe for the 970 MBoe figure.

With respect to the properties included in our prior year reserve reports, we incurred development costs of $39.8 million in 2015 as compared to $50.3 million in 2014. The year over year change in developmental costs is also reflective of our operated drilling focus in 2015 to preserve term leasehold acreage in the Permian Basin. With respect to the total proved value, no drilling locations are scheduled to be drilled after primary term leasehold expiration. Total proved reserves would not be adversely affected by any lease expirations.

At December 31, 2015, no proved undeveloped reserves have remained, or are scheduled to remain, undeveloped beyond five years from its corresponding initial booking date.

 

8


Changes in Proved Reserves

Proved reserves reported by us at December 31, 2015, decreased from those reported at December 31, 2014, as follows:

 

 

 

 

 

Oil Equivalent

 

 

 

 

 

(MBoe)

 

Proved reserves as of December 31, 2014

 

 

 

 

74,218

 

Production

 

 

 

 

(4,535

)

Extensions, discoveries and other additions

 

 

 

 

4,602

 

Sales of minerals in place

 

 

 

 

(12,072

)

Revisions of previous estimates

 

 

 

 

(29,093

)

Proved reserves as of December 31, 2015

 

 

 

 

33,120

 

Proved developed reserves:

 

 

 

 

 

 

As of December 31, 2015

 

 

 

 

27,874

 

Proved undeveloped reserves:

 

 

 

 

 

 

As of December 31, 2015

 

 

 

 

5,246

 

 

Extensions, discoveries and other additions to proved reserves were the result of drilling wells in the Permian Basin. Sales of minerals in place reflect the divestiture of certain properties in the Powder River and the Midland Basins.

 

The Permian Basin 2015 drilling program resulted in the addition of 970 MBoe to proved developed producing from successful drilling of non-proved locations and the conversion from proved undeveloped to proved developed producing of 576 MBoe net reserves. Furthermore, these successful wells created additional proved undeveloped offset locations carrying 3,632 MBoe of net proved reserves.

 

In accordance with SEC requirements, the oil reserves at December 31, 2015 and 2014, utilized average NYMEX posted West Texas Intermediate oil prices of $50.28 and $94.99 per Bbl, respectively, for the Aneth Properties and average Plains Marketing, L.P. West Texas Intermediate oil prices of $46.79 and $91.48 per Bbl, respectively, for the Permian Properties. For gas, the reserves at December 31, 2015 and 2014, utilized average Henry Hub spot market gas prices of $2.59 and $4.35 per MMBtu, respectively. All prices were then adjusted for quality and basis differentials.

 

Revisions of previous estimates primarily relate to projects that had economically proved reserves at December 2014 average prices, but were not economically proved reserves at December 2015 average prices.

 

Controls Over Reserve Report Preparation, Technical Qualification and Methodologies Used

 

Reserve estimates as of December 31, 2015, 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 31 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 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.

 

9


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. 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 34 years of practical experience in petroleum engineering, with more than eighteen 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, 2015, 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 2015, 2014 and 2013.

 

 

 

Year Ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

3,271

 

 

 

3,488

 

 

 

3,499

 

Gas (MMcf)

 

 

5,194

 

 

 

5,023

 

 

 

4,565

 

NGL (MBbl)

 

 

400

 

 

 

320

 

 

 

207

 

Combined volumes (MBoe)

 

 

4,536

 

 

 

4,645

 

 

 

4,467

 

Daily combined volumes (Boe per day)

 

 

12,427

 

 

 

12,727

 

 

 

12,239

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

42.16

 

 

$

84.28

 

 

$

91.75

 

Gas ($/Mcf)

 

 

2.43

 

 

 

5.23

 

 

 

4.70

 

NGL ($/Bbl)

 

 

10.32

 

 

 

28.58

 

 

 

35.18

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

17.50

 

 

$

24.26

 

 

$

23.12

 

Production and ad valorem taxes

 

 

4.41

 

 

 

8.01

 

 

 

9.04

 

 

In each of the years presented above, total estimated proved reserves attributed to our Aneth Field exceeded fifteen percent of our total proved reserves expressed on an equivalent basis. Therefore, the table below summarizes our operating data for Aneth Field for 2015, 2014 and 2013.

 

 

Year Ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Sales Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

2,172

 

 

 

2,249

 

 

 

2,238

 

Gas (MMcf)

 

 

717

 

 

 

276

 

 

 

52

 

NGL (MBbl)

 

 

 

 

 

 

 

 

 

Combined volumes (MBoe)

 

 

2,292

 

 

 

2,295

 

 

 

2,246

 

Daily combined volumes (Boe per day)

 

 

6,279

 

 

 

6,287

 

 

 

6,154

 

Average Realized Prices (excluding

   derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

 

$

40.81

 

 

$

84.76

 

 

$

91.55

 

Gas ($/Mcf)

 

 

1.87

 

 

 

4.76

 

 

 

5.64

 

NGL ($/Bbl)

 

 

 

 

 

 

 

 

 

Average Production Costs ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

21.55

 

 

$

27.08

 

 

$

28.33

 

Production and ad valorem taxes

 

 

5.98

 

 

 

11.04

 

 

 

12.18

 

 

 

10


Oil and Gas Wells

The following table sets forth information as of December 31, 2015, 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 333 gross (211 net) active water and CO2 injection wells as of December 31, 2015.

 

 

 

Productive Wells(1)

 

 

 

Gross

 

 

Net

 

Oil

 

 

472

 

 

 

313

 

Gas

 

 

1

 

 

 

 

Total

 

 

473

 

 

 

313

 

 

 

1)

We operated 466 gross (312 net) productive wells at December 31, 2015.

Drilling Activity

The following table sets forth information with respect to exploration, development and extension wells we completed during 2015, 2014 and 2013. 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,

 

 

 

2015

 

 

2014

 

 

2013

 

Gross exploration wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

1

 

 

 

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total exploration wells

 

 

 

 

 

1

 

 

 

 

Gross development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(3)

 

 

1

 

 

 

8

 

 

 

40

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total development wells

 

 

1

 

 

 

8

 

 

 

40

 

Gross extension wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(4)

 

 

5

 

 

 

11

 

 

 

4

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total extension wells

 

 

5

 

 

 

11

 

 

 

4

 

Total gross wells drilled

 

 

6

 

 

 

20

 

 

 

44

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Net exploration wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)

 

 

 

 

 

 

 

 

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total exploration wells

 

 

 

 

 

 

 

 

 

Net development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(3)

 

 

1

 

 

 

4

 

 

 

30

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total development wells

 

 

1

 

 

 

4

 

 

 

30

 

Net extension wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive (1)(4)

 

 

2

 

 

 

6

 

 

 

3

 

Dry (2)

 

 

 

 

 

 

 

 

 

Total extension wells

 

 

2

 

 

 

6

 

 

 

3

 

Total net wells drilled

 

 

2

 

 

 

10

 

 

 

33

 

 

 

1)

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

 

11


2)

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

3)

Included in this 2013 count are 8 gross (1.9 net) productive development wells sold to HRC Energy, LLC effective March 1, 2013, closed July 15, 2013.

4)

Included in the 2015 count is 1 gross (0.1 net) productive extension well sold to Qstar, LLC effective March, 1, 2015, closed May 1, 2015. An extension well is defined as a well drilled to extend the limits of a known reservoir.

Acreage

All of our leasehold acreage is categorized as developed or undeveloped. The following table sets forth information as of December 31, 2015, relating to our leasehold acreage.

 

 

 

 

 

Developed Acreage (1)

 

Area

 

 

 

Gross (2)

 

 

Net (3)

 

Wyoming

 

 

 

 

1,357

 

 

 

1,357

 

Aneth Field (UT)

 

 

 

 

43,218

 

 

 

27,157

 

Permian Basin (TX)

 

 

 

 

9,368

 

 

 

5,518

 

Permian Basin (NM)

 

 

 

 

4,690

 

 

 

3,971

 

North Dakota

 

 

 

 

516

 

 

 

99

 

Total

 

 

 

 

59,149

 

 

 

38,102

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped Acreage (4)

 

Area

 

 

 

Gross (2)

 

 

Net (3)

 

Aneth Field (UT)

 

 

 

 

1,173

 

 

 

1,173

 

Wyoming

 

 

 

 

58,635

 

 

 

33,431

 

Permian Basin (TX)

 

 

 

 

13,692

 

 

 

8,085

 

Black Warrior Basin (AL)

 

 

 

 

205

 

 

 

205

 

North Dakota