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EX-99.2 - EX-99.2 - Chaparral Energy, Inc.cpr-ex992_396.htm
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EX-32.2 - EX-32.2 - Chaparral Energy, Inc.cpr-ex322_8.htm
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EX-31.2 - EX-31.2 - Chaparral Energy, Inc.cpr-ex312_6.htm
EX-31.1 - EX-31.1 - Chaparral Energy, Inc.cpr-ex311_12.htm
EX-21.1 - EX-21.1 - Chaparral Energy, Inc.cpr-ex211_10.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 number: 333-134748

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

 

73-1590941

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma

 

73114

(Address of principal executive offices)

 

(Zip code)

(405) 478-8770

(Registrant’s telephone number, including area code)

 

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

None.

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

None.

 

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

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

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

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934.)

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 (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  

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

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 common equity held by non-affiliates of the registrant is not determinable as such shares are privately held and there is no public market for such shares.

Documents incorporated by reference: Certain information called for in Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference to the registrant’s definitive proxy statement or will be included in an amendment to this Annual Report on Form 10-K.

Number of shares outstanding of each of the issuer’s classes of common stock as of March 31, 2017: 

 

 

Class

Number of shares

Class A Common Stock, $0.01 par value

37,048,110

 

Class B Common Stock, $0.01 par value

7,856,404

 

 

 

 


CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

Part I

 

 

 

 

 

Items 1. and 2.

Business and Properties

7

 

 

 

Item 1A.

Risk Factors

27

 

 

 

Item 1B.

Unresolved Staff Comments

39

 

 

 

Item 2.

Properties

39

 

 

 

Item 3.

Legal Proceedings

39

 

 

 

Item 4.

Mine Safety Disclosures

41

 

 

 

Part II

 

 

 

 

 

Item 5.

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

41

 

 

 

Item 6.

Selected Financial Data

42

 

 

 

Item 7.

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

43

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

65

 

 

 

Item 8.

Financial Statements and Supplementary Data

68

 

 

 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

111

 

 

 

Item 9A.

Controls and Procedures

111

 

 

 

Item 9B.

Other Information

111

 

 

 

Part III

 

 

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

112

 

 

 

Item 11.

Executive Compensation

112

 

 

 

Item 12.

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

112

 

 

 

Item 13.

Certain Relationships and Related Transactions and Director Independence

112

 

 

 

Item 14.

Principal Accounting Fee Services

112

 

 

 

Part IV

 

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

113

 

 

 

Signatures

114

 

 

 

1


CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:

 

fluctuations in demand or the prices received for oil and natural gas;

 

the amount, nature and timing of capital expenditures;

 

drilling, completion and performance of wells;

 

competition and government regulations;

 

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

 

costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;

 

changes in proved reserves;

 

operating costs and other expenses;

 

our future financial condition, results of operations, revenue, cash flows and expenses;

 

estimates of proved reserves;

 

exploitation of property acquisitions; and

 

marketing of oil and natural gas.

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described under the heading “Risk Factors,” the factors include:

 

worldwide supply of and demand for oil and natural gas;

 

volatility and declines in oil and natural gas prices;

 

drilling plans (including scheduled and budgeted wells);

 

the number, timing or results of any wells;

 

changes in wells operated and in reserve estimates;

 

supply of CO2;

 

future growth and expansion;

 

future exploration;

 

integration of existing and new technologies into operations;

 

future capital expenditures (or funding thereof) and working capital;

 

borrowings and capital resources and liquidity;

 

changes in strategy and business discipline;

 

future tax matters;

2


 

any loss of key personnel;

 

geopolitical events affecting oil and natural gas prices;

 

outcome, effects or timing of legal proceedings;

 

the effect of litigation and contingencies;

 

the ability to generate additional prospects; and

 

the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

3


GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this section are used throughout this annual report on Form 10-K:

Active EOR Areas

Areas where we are currently or plan to inject and/or recycle CO2 as a means of oil recovery.  

 

 

Basin

A low region or natural depression in the earth’s crust where sedimentary deposits accumulate.

 

 

Bankruptcy Court

United States Bankruptcy Court for the District of Delaware

 

 

Bbl

One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids.

 

 

BBtu

One billion British thermal units.

 

 

Boe

Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

 

 

Boe/d

Barrels of oil equivalent per day.

 

 

Btu

British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

 

Completion

The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

 

 

CO2

Carbon dioxide.

 

 

Developed acreage

The number of acres that are assignable to productive wells.

 

 

Development well

A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

 

Disclosure Statement

Disclosure Statement for the Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code.

 

 

Dry well or dry hole

An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

 

Enhanced oil recovery (EOR)

The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after Secondary Recovery.

 

 

Existing Credit Facility

Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among us, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent and each of the Lenders named therein, as amended.

 

 

Exploratory well

A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir.

 

 

Field

An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

 

 

Horizontal drilling

A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

 

 

Limestone/carbonate

A sedimentary rock composed primarily of calcium carbonate. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It can be composed of various calcium carbonate grains or chemically precipitated. It often contains variable amounts of silica, silt, and clay. It is highly soluble which often results in secondary porosity and karsting. This can vary greatly from place to place. These factors all generally make this rock type a more heterogeneous deposit than sandstone.

 

 

MBbls

One thousand barrels of crude oil, condensate, or natural gas liquids.

 

 

4


MBoe

One thousand barrels of crude oil equivalent.

 

 

Mcf

One thousand cubic feet of natural gas.

 

 

MMBoe

One million barrels of crude oil equivalent.

 

 

MMBtu

One million British thermal units.

 

 

MMcf

One million cubic feet of natural gas.

 

 

MMcf/d

Millions of cubic feet per day.

 

 

Natural gas liquids (NGLs)

Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.

 

 

Net acres

The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres.

 

 

New Credit Facility

Ninth Restated Credit Agreement, dated as of March 21, 2017, by and among us, Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders and Prepetition Borrowers Party Hereto.

 

 

NYMEX

The New York Mercantile Exchange.

 

 

OPEC

Organization of the Petroleum Exporting Countries

 

 

Play

A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.

 

 

Productive well

A well that is currently producing oil or natural gas or is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

 

Proved developed reserves

Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

 

 

Proved reserves

The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

 

 

Proved undeveloped reserves

Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

 

 

PV-10 value

When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.

 

 

Registration Rights Agreement

Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein.

 

 

Reorganization Plan

First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code.

 

 

Sandstone

A clastic sedimentary rock composed mainly of cemented sand-sized minerals or rock grains. Most sandstone is composed of quartz or feldspar. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It is usually a more resistant rock than limestone and generally has less lateral variability in porosity.

 

 

SEC

The Securities and Exchange Commission.

 

 

5


Secondary recovery

The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

 

 

 

 

Seismic survey

Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.

 

 

Senior Notes

Collectively, our 9.875% senior notes due 2020, 8.25% senior notes due 2021, and 7.625% senior notes due 2022, of which all obligations have been discharged upon consummation of our Reorganization Plan.

 

 

Spacing

The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

 

 

STACK

An acronym standing for Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.

 

 

Undeveloped acreage

Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

 

 

Unit

The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

 

Wellbore

The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

 

 

Working interest

The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

 

 

Zone

A layer of rock which has distinct characteristics that differ from nearby layers of rock.

 

6


PART I

Unless the context requires otherwise, references in this annual report to the “Company,” “Chaparral,” “we,” “our” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of Certain Defined Terms” at the beginning of this annual report.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Overview

Founded in 1988, we are a Delaware corporation headquartered in Oklahoma City and a Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations. We also have significant production from CO2 EOR methods underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state.

During 2016, our average net daily production was 24.4 MBoe and our oil and natural gas revenues were $252.2 million. As of December 31, 2016, we had estimated proved reserves of 131.3 MMBoe with a PV-10 value of approximately $529 million and an estimated reserve life of approximately 14.7 years. These estimated proved reserves included 30.8 MMBoe of reserves in our STACK play. Our reserves were 43% proved developed, 74% crude oil, and 9% natural gas liquids. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.”

Chapter 11 Reorganization

On May 9, 2016, the Company and 10 of its subsidiaries filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware.  On March 10, 2017, the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017, the Reorganization Plan became effective and we emerged from bankruptcy. Upon our emergence, all existing equity was cancelled and we issued new common stock to the previous holders of our Senior Notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to certain other parties as set forth in the Reorganization Plan, including to parties participating in a $50.0 million rights offering. To facilitate our discussion in this report, we refer to the post-emergence reorganized company as the “Successor” and the pre-emergence company as the “Predecessor.” See “Note 2—Chapter 11 reorganization” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of our bankruptcy and resulting reorganization.

Business Strategy

Our business strategy is to create economic and shareholder value by applying our core strengths in execution and cost control to exploit our robust inventory of horizontal drilling opportunities in the high-return STACK unconventional resource play.  Key components of our long-term business strategy include:

Preserving a strong and flexible capital structure. Maintaining a strong capital structure that protects our balance sheet and liquidity remains central to our business strategy. With our recent emergence from bankruptcy on March 21, 2017, we have an improved balance sheet and additional liquidity. This should allow us to access capital if and as necessary to maintain, and in some cases, improve our asset base.

Volatility of pricing can significantly impact the amount of revenue received for oil and natural gas production and the level of economic returns we receive on capital invested in our exploration and development activities. Our goal will be to continue to preserve financial flexibility through a conservative balance sheet and ample liquidity as we seek to manage the continued weakness in both oil and gas prices. We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility. Additionally, we carefully high-grade the allocation of capital to drilling and completions and focus the majority of our capital on low-risk locations or projects that have a greater certainty of robust economic returns. Our 2017 capital expenditure budget for acquisition, exploration and development activities is approximately $145.9 million.

Efficiently develop our STACK leasehold position / resource play. We are developing our acreage position to maximize the value of our resource potential, while maintaining flexibility to preserve future value when oil prices are low. During 2016 our operated and non-operated drilling was almost entirely focused on this play where we completed 16 operated wells and participated in 36 gross non-operated wells. Our 2017 capital plan for this play includes drilling 19 operated wells.

Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques to maximize overall well economics. We have materially reduced the number of days that it takes to drill wells, and we

7


have significantly improved completion techniques and designs over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well. High intensity multi-stage completion techniques have been particularly effective at increasing production rates and recoverable hydrocarbons as compared to prior completion techniques. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. This continued evolution may enhance our initial production rates, increase ultimate recovery factors, lower well capital costs and improve rates of return on invested capital.

Continuously improving operations and returns. Managing the costs to find, develop and produce oil, natural gas and NGLs is critical to delivering robust returns on capital employed and creating shareholder value. Our focus areas in the STACK are characterized by large, contiguous acreage positions and multiple stacked geologic horizons. In 2016, we reduced our average well costs in all areas through faster drilling times and innovative optimizations of our completions. In addition, continued reduced service costs have positively impacted our business. We also have multiple initiatives underway to manage our base production, improve operational efficiencies and enhance future margins. We expect to be challenged in 2017 to control costs as the uptick in drilling and development activity from the recent oil price recovery has increased the demand for oilfield services which in turn is expected to result in higher prices for these services.

Selected monetization of assets.  We are continuing to evaluate options to monetize certain assets in our portfolio, which could result in increased liquidity and lower leverage. The proceeds from monetization of assets may be utilized for debt reduction and/or capital expenditure.

Stabilizing cash flow and managing risk exposure for a substantial portion of production by hedging production. As appropriate, we enter into derivative contracts to mitigate a portion of the commodity price volatility inherent in the oil and natural gas industry. By increasing the predictability of cash inflows for a portion of the company’s future production, we are better able to mitigate funding risks for our longer term development plans and lock in rates of return on our capital projects.

 2016 Highlights

The following are material events in 2016 with respect to our operations that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods. Events related to our bankruptcy petition and subsequent emergence are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report.

 

Capital expenditure. Our oil and natural gas capital expenditures, of $149.4 million in 2016 were significantly lower compared to $209.3 million in 2015. The reduction in capital spending was driven primarily by historic lows in crude oil prices experienced in 2016 as well as liquidity constraints. Cash outlays for capital during the year were almost fully funded by internally generated cash flows from operations and receipts from our derivative settlements. We began 2016 with three rigs which was reduced to one rig in March 2016 that we deployed through the completion of our 2016 drilling program in June 2016. We resumed drilling in December 2016 and had three wells in progress at the end of the year. During 2016 we drilled and completed 11 wells in our STACK play and completed five wells that were spudded in the previous year. All our operated drilling and completion activity during 2016 was focused solely on wells in our STACK play. We spent $54.9 million to develop our CO2 floods which included $37.5 million on our North Burbank Unit. In addition, we spent $15.9 million on selective leasehold acquisitions to protect and strengthen our position in the STACK. As result of our reduction in capital expenditure from the prior year, our net production on a year-over-year and fourth quarter-over-fourth quarter basis declined 12.5% and 9.5%, respectively.

 

Proved property impairments. Due to the depressed commodity price environment that prevailed throughout 2016, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of the first and second quarters of 2016, resulting in a ceiling test write-down of $281 million for the year as further discussed in “Management Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in Item 7 of this report.

 

Cost reduction initiatives. We continued our cost reduction initiatives that we initiated in 2015 which in 2016 included additional reductions in our workforce of 64 employees. Other operational efficiencies included cost reductions from third party service providers, temporary shut-in of marginal wells and limiting workovers to wells that meet a minimum payout threshold. These initiatives, among others, contributed to decreases of 18% and 46% from 2015 to 2016 in our lease operating and general and administrative expenses, respectively.

 

Derivative settlements. Our commodity price derivatives were early terminated in May 2016 as a result of our debt defaults and bankruptcy. Including the early terminations, our realized settlement gains from derivatives were $153.8 million in 2016 of which $103.6 million was utilized to reduce outstanding debt. We have 3.6 million barrels of crude production hedged in 2017 at an average of $54.97 per barrel and 9,729 BBtu of 2017 natural gas production hedged at an average of $3.34/MMBtu. We also have derivative contracts in place for 2018 and 2019 which are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

8


 

Costs to restructure capital. The costs of our efforts to restructure our capital, prior to and during our bankruptcy, along with all other costs incurred in connection with our reorganization under Chapter 11, have been significant. During 2016, we incurred $9.4 million of such costs prior to our bankruptcy petition and $16.7 million while in bankruptcy. We expect to incur at least $27 million of additional professional fees in 2017 related to our bankruptcy.

Operational Areas

The following table presents our proved reserves as of December 31, 2016, and average net daily production for both the year ended and quarter ended December 31, 2016, by our areas of operation. We have recently realigned our operational areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. Our operational areas currently include the following: the STACK, Active EOR Areas and Other. Reserves were estimated using a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements. Please see Item 8. Financial Statements and Supplementary Data of this report for the results of our operations and financial position.

 

 

Average daily production (MBoe per day)

 

 

Proved reserves as of December 31, 2016

 

 

 

Year ended December 31, 2016

 

 

Quarter ended December 31, 2016

 

 

Oil

(MBbls)

 

 

Natural gas

(MMcf)

 

 

Natural

gas liquids

(MBbls)

 

 

Total

(MBoe)

 

 

Percent of

total MBoe

 

 

PV-10

value

($MM)

 

STACK

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STACK - Meramec

 

 

1.8

 

 

 

2.3

 

 

 

2,920

 

 

 

16,499

 

 

 

1,624

 

 

 

7,294

 

 

 

5.6

%

 

 

33

 

STACK - Osage

 

 

2.0

 

 

 

1.9

 

 

 

3,971

 

 

 

27,950

 

 

 

3,004

 

 

 

11,633

 

 

 

8.9

%

 

 

44

 

STACK - Oswego

 

 

1.2

 

 

 

1.1

 

 

 

3,797

 

 

 

3,899

 

 

 

385

 

 

 

4,832

 

 

 

3.7

%

 

 

48

 

STACK - Woodford

 

 

1.4

 

 

 

1.1

 

 

 

290

 

 

 

10,435

 

 

 

1,560

 

 

 

3,589

 

 

 

2.7

%

 

 

13

 

STACK - Vertical

 

 

0.9

 

 

 

0.9

 

 

 

842

 

 

 

12,387

 

 

 

544

 

 

 

3,451

 

 

 

2.6

%

 

 

14

 

Total STACK

 

 

7.3

 

 

 

7.3

 

 

 

11,820

 

 

 

71,170

 

 

 

7,117

 

 

 

30,799

 

 

 

23.5

%

 

 

152

 

Active EOR Areas

 

 

5.7

 

 

 

5.7

 

 

 

72,188

 

 

 

5

 

 

 

0

 

 

 

72,189

 

 

 

54.9

%

 

 

216

 

Other

 

 

11.4

 

 

 

10.3

 

 

 

12,613

 

 

 

64,274

 

 

 

4,988

 

 

 

28,313

 

 

 

21.6

%

 

 

161

 

Total

 

 

24.4

 

 

 

23.3

 

 

 

96,621

 

 

 

135,449

 

 

 

12,105

 

 

 

131,301

 

 

 

100.0

%

 

$

529

 

STACK Area

The STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher which is indicative of a play area in the Anadarko Basin of Oklahoma in which we operate. It is a horizontal drilling play in an area with multiple productive reservoirs which had previously been drilled with vertical wells. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. Our STACK play’s borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and include the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK area. The organic-rich Woodford Shale is the primary source of hydrocarbon migration into and present in the target reservoirs, which act as natural conduits for the oil migration from the Woodford. These complex carbonate-silt-shale stratigraphic intervals have proven to be very conducive to horizontal drilling and completion techniques. The stacking of plays allows us to effectively recover oil and gas from multiple formations using pad drilling, well spacing techniques and other operational efficiencies, which result in significant cost savings, reduced environmental impacts and attractive rates of return. We currently own approximately 98,000 net surface acres in this play. Within this play, we have 52 gross operated horizontal wells and are participating in an additional 94 gross horizontal wells operated by others.

Primarily as a result of our drilling activity, our production from this area was 2,667 MBoe in 2016 compared to 1,975 MBoe in 2015 and 1,603 MBoe in 2014. During 2016, we spent $61.2 million on drilling activities in our STACK play, compared to a budget of $50.3 million, where we drilled and/or participated in the drilling of 49 (16 net) horizontal wells. For 2017, our capital budget includes drilling and completing 19 wells, completing three wells that we drilled and rig-released in 2016 and participating in non-operated wells for a total budget of $81.8 million. Our drilling opportunities across the different intervals of the STACK are described below where acreage is duplicated for the stacked play position.

STACK – Meramec. We currently own approximately 68,500 net acres targeting the Meramec interval within our STACK play. Within this area, our drilling locations are in Kingfisher county, Canadian county and Garfield county. For a typical one mile lateral well in the Meramec, our estimated cost to drill and complete a well is approximately $3.5 million.

STACK – Osage. We currently own approximately 78,000 net acres targeting the Osage interval within our STACK play primarily located in Garfield, Kingfisher and Major counties. Within this area, our drilling locations are primarily in Garfield and Kingfisher counties. For a typical one mile lateral well, our estimated cost to drill and complete a well is approximately $3.3 million.

9


STACK – Oswego. We currently own approximately 19,500 net acres targeting the Oswego interval within our STACK play. Within this area, our drilling locations are primarily in Kingfisher county where we estimate a typical one mile lateral well will cost approximately $2.7 million to drill and complete.

STACK – Woodford. We currently own approximately 78,000 net acres targeting the Woodford interval within our STACK play. Within this area, our drilling locations are primarily located within Canadian and Garfield counties. Our primary Woodford drilling focus is in Canadian county where we estimate a typical well will cost approximately $4.0 million to drill and complete.

As a result of the recent increase in seismic activity, the Oklahoma Corporation Commission (the “OCC”) issued multiple directives in 2016 to operators of salt water disposal wells to reduce salt water injection volumes in various “areas of interest.” These areas include those in central Oklahoma that encompass our STACK play. However, these directives do not significantly impact our operations in the STACK. Please see “Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens” in  Item 1A. Risk Factors of this report for a further discussion of the OCC seismic-related directives.

During 2016, we incurred $15.9 million in capital expenditures on acquisitions to lease approximately 24,000 net acres in Garfield and Kingfisher counties, Oklahoma, which are prospective for drilling in our STACK play.

Active EOR Areas and Facilities

We have been actively implementing and managing CO2 EOR since 2001. We currently have CO2 supply agreements in place for the Burbank (Osage County, Oklahoma) and the Panhandle areas, and have built CO2 pipelines to reach several of our field locations in both of these areas.

The U.S. Department of Energy–Office of Fossil Energy published reports in February 2006 estimating that significant oil reserves could be economically recovered in Oklahoma and Texas through CO2 EOR processes. CO2 miscible flooding is implemented and managed as a closed system consisting of the reservoir and surface facilities. The physical material balance of the system means that the CO2 is produced and recycled numerous times after initial injection. Combined with the incoming purchased CO2 supply, the recycled CO2 supply allows us to systematically develop additional flood patterns in contiguous acreage to the active patterns, or to expand into new projects. If larger volumes of CO2 become economically available and commodity prices are supportive, projects can be developed on accelerated timelines, while a more limited supply dictates a prolonged expansion. Due to the size of our EOR projects and the limitation of third party services, we expect the development of our EOR projects will extend beyond five years in many cases. Significant projects within our Active EOR Areas are discussed below.

The following table presents proved reserves, production, number of wells and average working interest related to our major Active EOR Areas:

 

 

Proved reserves as of December 31, 2016

 

 

Production (MBoe)

 

 

Number of wells as of December 31, 2016

 

 

 

 

 

 

 

Proved developed (MBoe)

 

 

Proved undeveloped

(MBoe)

 

 

2016

 

 

2015

 

 

Producing

 

 

Active water & CO2 injection

 

 

Shut-in and temporarily abandoned

 

 

Average working interest

 

North Burbank Unit

 

 

6,540

 

 

 

60,541

 

 

 

962

 

 

 

814

 

 

 

233

 

 

 

186

 

 

 

575

 

 

 

99.3

%

Panhandle

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Camrick Area Units

 

 

1,786

 

 

 

827

 

 

 

319

 

 

 

399

 

 

 

60

 

 

 

29

 

 

 

61

 

 

 

52.6

%

Booker Area Units

 

 

503

 

 

 

 

 

217

 

 

 

298

 

 

 

11

 

 

 

9

 

 

 

4

 

 

 

99.8

%

Farnsworth Unit

 

 

1,992

 

 

 

 

 

570

 

 

 

625

 

 

 

32

 

 

 

19

 

 

 

43

 

 

 

100.0

%

Total Panhandle

 

 

4,281

 

 

 

827

 

 

 

1,106

 

 

 

1,322

 

 

 

103

 

 

 

57

 

 

 

108

 

 

 

86.3

%

Total Active EOR Areas

 

 

10,821

 

 

 

61,368

 

 

 

2,068

 

 

 

2,136

 

 

 

336

 

 

 

243

 

 

 

683

 

 

 

92.3

%

North Burbank Unit. As of December 31, 2016, our North Burbank Unit, which is our largest property and for which we are the operator, accounted for 51%, of our total proved reserves and 93% of our Active EOR proved reserves. The producing zones are the Red Fork and Bartlesville formations and occur at a depth of approximately 3,000 feet. Our average net daily production from this Unit increased from 2014 to 2016 as a result of our CO2 injection and its associated response, as well as optimizations that were made to facilities and in day-to-day operations. Due to the size of our North Burbank Unit the development cannot be completed within five years, and as a result the development of our North Burbank Unit will be an ongoing project.

The CO2 utilized at this location is sourced from an existing nitrogen fertilizer plant in Coffeyville, Kansas as described further below. In 2013, we completed the Coffeyville CO2 compression facility and a 68-mile pipeline to transport the CO2 to the Burbank field. We began CO2 injection at our North Burbank Unit in June 2013. Since 2013 we have injected CO2 into additional patterns and

10


as a result of the observed response, we gradually added CO2 EOR reserves for all remaining phases of this unit. Development of remaining phases will follow in future years as a sufficient volume of purchased and recycled CO2 is utilized.

Our total investment in our North Burbank Unit during 2016 was $37.5 million for infrastructure build out, development of a limited number of additional patterns, continuing CO2 injection and field maintenance. Our budgeted capital expenditure in 2017, for which we have allocated $33.8 million, will be utilized to continue developing our North Burbank Unit, primarily for infrastructure build out, development of a limited number of additional patterns, continuing CO2 injection and field maintenance. Significant additional capital expenditures will be required over multiple years to fully develop the North Burbank Unit.

Outside of our North Burbank Unit, we also actively inject CO2 at our Camrick Area Units, our Booker Area Units and our Farnsworth Unit. Our capital plan for these units is one of judicious spending to efficiently and economically produce these units with production decline. Total investment in these units during 2016 was $17.4 million which we incurred for the purchase of CO2 and remedial infrastructure and well work. Our capital budget for 2017 includes $13.6 million directed towards similar activities.

CO2 Sources and Pipelines

We capture, compress and transport CO2 to our Active EOR Areas from the following separate CO2 sources.

Coffeyville. Our CO2 source for the North Burbank Unit is located in Coffeyville, Kansas. In March 2011, we signed a 20-year contract with renewal options to purchase up to 100% of CO2 emissions from the Coffeyville nitrogen fertilizer plant. The fertilizer plant reserves the right to install additional equipment and use some of the CO2 to make certain fertilizer products, which could reduce our CO2 purchases. We own and operate the Coffeyville CO2 compression facility on land leased from the owner of the fertilizer plant, and 68 miles of CO2 pipeline to transport the CO2 to the Burbank field, both of which were completed in 2013. During 2016, we purchased an average of 28 MMcf/d from this source. By securing this contract and completing the compression facility and pipeline, we can provide CO2 to our North Burbank Unit on an acceptable runtime basis and at a reasonably predictable cost, which will allow us to establish the platform to facilitate our CO2 recovery operations in the North Burbank Unit.

Borger. We have a long-term contract to purchase up to approximately 20 MMcf/d of CO2 produced at the Agrium nitrogen fertilizer plant in Borger, Texas. The fertilizer plant reserves the right to install additional equipment and use some of the CO2 to make certain fertilizer products, and has commenced installation of such additional equipment in 2014. We own and operate the Borger CO2 compression facility on land leased from Agrium, and 80 miles of CO2 pipelines to deliver the Borger-sourced CO2 to our active EOR units in our Camrick Area and Farnsworth Units. During 2016 we purchased an average of 5 MMcf/d from this source. The Agrium fertilizer plant is currently undergoing a modification to allow additional fertilizer production and as a result of this modification, our CO2 volumes could be reduced in 2017. If the available CO2 volume is decreased below 5 MMcf/d in the immediate future, which is the minimum threshold required to operate the compression facility, we will not be able to continue CO2 compression at this facility.  Unless modified or replaced, the CO2 purchase contract expires in 2021.

Arkalon. We have a long-term contract to purchase up to approximately 15 MMcf/d of CO2 produced at the Arkalon ethanol plant near Liberal, Kansas. We own and operate the Arkalon CO2 compression and processing facility on land leased from Arkalon, as well as the 91 miles of CO2 pipeline to deliver the Arkalon-sourced CO2 to our active EOR units in our Booker Area and Farnsworth Units. With the installation of the “Twitchell Co2 Booster Pump” east of Perryton, Texas, we will have the ability to supply CO2 to our Camrick and North Perryton Units from Arkalon beginning in the first quarter of 2017. This additional capacity allows us to replace the CO2 from Borger once if we are no longer able to operate the facility. During 2016 we purchased an average of 8 MMcf/d from this source.

Enid. We previously had a contract to purchase CO2 produced at the Koch nitrogen fertilizer plant in Enid, Oklahoma. The fertilizer plant reserves the right to install additional equipment and use some of the CO2 to make certain fertilizer products, which could reduce our CO2 purchases. We own a partial interest in the Enid CO2 compression facility and 142 miles of CO2 pipeline, which delivered the Enid-sourced CO2 to our active EOR unit in southern Oklahoma. During 2016 we purchased an average of approximately 2 MMcf/d from this Enid CO2 source. Both the CO2 purchase contract and the operations agreement for the compression facility and pipeline expired December, 31 2016. Our interest in the pipeline is currently being marketed for sale.

Other Areas

We also have additional oil and gas properties throughout Oklahoma and the Texas Panhandle which includes the Mississippi Lime play. Our properties in these areas include mature properties and are held by production. In 2014, this category also included non-core properties that were disposed of at various times during that year. Acreage in this location is not attractive for drilling in the current $40- $60 per barrel price environment and therefore we have not allocated any significant capital to these areas in our 2017 budget. As we have not focused our capital spending in these areas in recent years, production has declined from 7,647 Mboe in 2014 to 6,089 MBoe in 2015 and 4,191 MBoe in 2016.

11


Oil and Natural Gas Reserves

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and exclude escalations based upon future conditions.

Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with Securities and Exchange Commission (“SEC”)  regulations. Users of this information should be aware that the process of estimating quantities of crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, all of which are currently prepared by independent petroleum engineers. To achieve reasonable certainty, our engineers relied on an analysis and reporting software system designed specifically for reserves management that has been demonstrated to yield results with consistency and repeatability. Technical and economic data used include, but are not limited to, updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information.

Our Vice President - Corporate Reserves is the technical person primarily accountable for overseeing the preparation of our reserve estimates. He has a Bachelor of Sciences degree in Petroleum Engineering and a Masters of Business Administration, and has 28 years of industry experience that includes diverse petroleum engineering roles and reserves management. In addition, he is a member of the Society of Petroleum Engineers.

Our Corporate Reserves department continually monitors asset performance in collaboration with our Resource Development and EOR departments, making reserve estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities. Reporting to our Vice President - Corporate Reserves, our Corporate Reserve Department currently has a total of three full-time employees, comprised of two degreed engineers and one engineering analyst/technician.

We have internal guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. Internal controls within the reserve estimation process include:

 

The Corporate Reserve Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:

 

confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;

 

reviewing and using in the estimation process data provided by other departments within the Company such as Accounting; and

 

comparing and reconciling internally generated reserves estimates to those prepared by third parties.

 

The Corporate Reserve Department reports directly to our Chief Financial Officer, independently of any of our operating divisions.

 

Our reserves are reviewed by senior management, which includes the Chief Executive Officer and the Chief Financial Officer, and they are responsible for verifying that the estimate of proved reserves is reasonable, complete, and accurate. Members of senior management may also meet with the key representatives from Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. to discuss their processes and findings. Final approval of the reserves is required by our Chief Executive Officer and Chief Financial Officer.

Our Corporate Reserve Department works closely with the independent petroleum consultants to ensure the integrity, accuracy and timeliness of annual independent reserve estimates. Our internal reserve data is provided each year to the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. who prepare reserve estimates for the majority of our proved reserves using their own engineering assumptions and the economic data which we provide. The person responsible for overseeing the preparation of our reserve estimates at Cawley, Gillespie & Associates, Inc. is a registered Professional Engineer with more than 30 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a licensed Professional Engineer with over 30 years of practical experience in the

12


estimation and evaluation of petroleum reserves. Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits 99.1 and 99.2 to this annual report.

The table below shows the percentage of the PV-10 value of our total proved reserves of oil, natural gas and NGLs prepared by us and each of our independent petroleum consultants for the years shown.

 

 

December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Cawley, Gillespie & Associates, Inc.

 

 

51

%

 

 

42

%

 

 

39

%

Ryder Scott Company, L.P.

 

 

49

%

 

 

48

%

 

 

50

%

Internally prepared

 

 

0

%

 

 

10

%

 

 

11

%

Proved Reserves

The following table summarizes our estimates of net proved oil and natural gas reserves, estimated future net revenues from proved reserves, the PV-10 value, the standardized measure of discounted future net cash flows, and the prices used in projecting those measures over the past three years. All of our reserves are located in the United States. We set forth our definition of PV-10 value (a non-GAAP measure) in the Glossary of Certain Defined Terms at the beginning of this annual report and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.”

 

 

As of December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Estimated proved reserve volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

96,621

 

 

 

113,766

 

 

 

101,247

 

Natural gas (MMcf)

 

 

135,449

 

 

 

178,218

 

 

 

247,756

 

Natural gas liquids (MBbls)

 

 

12,105

 

 

 

12,071

 

 

 

16,853

 

Oil equivalent (MBoe)

 

 

131,301

 

 

 

155,541

 

 

 

159,393

 

Proved developed reserve percentage

 

 

43

%

 

 

46

%

 

 

58

%

Estimated proved reserve values (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Future net revenue

 

$

1,490,090

 

 

$

2,120,608

 

 

$

5,943,028

 

PV-10 value

 

$

528,781

 

 

$

731,426

 

 

$

2,547,204

 

Standardized measure of discounted future net cash flows

 

$

528,781

 

 

$

684,689

 

 

$

1,894,700

 

Oil and natural gas prices: (1)

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

42.75

 

 

$

50.28

 

 

$

94.99

 

Natural gas (per Mcf)

 

$

2.49

 

 

$

2.58

 

 

$

4.35

 

Natural gas liquids (per Bbl)

 

$

13.47

 

 

$

15.84

 

 

$

36.10

 

Estimated reserve life in years (2)

 

 

14.7

 

 

 

15.2

 

 

 

14.5

 

_____________________________________

(1)

Prices were based upon the average first day of the month prices for each month during the respective year and do not reflect differentials.

(2)

Calculated by dividing net proved reserves by net production volumes for the year indicated.

Our net proved oil and natural gas reserves and PV-10 values consisted of the following:

 

Net proved reserves as of December 31, 2016

 

 

Oil

(MBbls)

 

 

Natural gas

(MMcf)

 

 

Natural gas

liquids (MBbls)

 

 

Total

(MBoe)

 

 

PV-10 value

(in thousands)

 

Developed—producing

 

27,886

 

 

 

106,326

 

 

 

9,326

 

 

 

54,933

 

 

$

408,609

 

Developed—non-producing

 

704

 

 

 

2,474

 

 

 

26

 

 

 

1,143

 

 

 

6,674

 

Undeveloped

 

68,031

 

 

 

26,649

 

 

 

2,753

 

 

 

75,225

 

 

 

113,498

 

Total proved

 

96,621

 

 

 

135,449

 

 

 

12,105

 

 

 

131,301

 

 

$

528,781

 

 

13


Proved Undeveloped Reserves

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2016.

 

 

MBoe

 

Proved undeveloped reserves as of January 1, 2016

 

 

84,017

 

Undeveloped reserves transferred to developed (1)

 

 

(1,447

)

Purchases of minerals

 

 

 

Sales of minerals in place

 

 

 

Extensions and discoveries

 

 

4,968

 

Improved recoveries

 

 

 

Revisions and other

 

 

(12,313

)

Proved undeveloped reserves as of December 31, 2016

 

 

75,225

 

 

(1)

Approximately $29.1 million of developmental costs incurred during 2016 related to undeveloped reserves that were transferred to developed.

Productive Wells

The following table sets forth the number of productive wells in which we have a working interest and the number of wells we operated as of December 31, 2016, by area. Productive wells consist of producing wells and wells capable of producing. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells.

 

 

Oil

 

 

Natural Gas

 

 

Total

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STACK

 

 

130

 

 

 

102

 

 

 

99

 

 

 

73

 

 

 

229

 

 

 

175

 

Active EOR  Areas

 

 

432

 

 

 

404

 

 

 

 

 

 

 

 

 

432

 

 

 

404

 

Other

 

 

972

 

 

 

857

 

 

 

222

 

 

 

157

 

 

 

1,194

 

 

 

1,014

 

Total

 

 

1,534

 

 

 

1,363

 

 

 

321

 

 

 

230

 

 

 

1,855

 

 

 

1,593

 

Non-Operated Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STACK

 

 

256

 

 

 

18

 

 

 

276

 

 

 

24

 

 

 

532

 

 

 

42

 

Active EOR  Areas

 

 

93

 

 

 

5

 

 

 

 

 

 

 

 

 

93

 

 

 

5

 

Other

 

 

1,230

 

 

 

118

 

 

 

764

 

 

 

63

 

 

 

1,994

 

 

 

181

 

Total

 

 

1,579

 

 

 

141

 

 

 

1,040

 

 

 

87

 

 

 

2,619

 

 

 

228

 

Total Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STACK

 

 

386

 

 

 

120

 

 

 

375

 

 

 

97

 

 

 

761

 

 

 

217

 

Active EOR  Areas

 

 

525

 

 

 

409

 

 

 

 

 

 

 

 

 

525

 

 

 

409

 

Other

 

 

2,202

 

 

 

975

 

 

 

986

 

 

 

220

 

 

 

3,188

 

 

 

1,195

 

Total

 

 

3,113

 

 

 

1,504

 

 

 

1,361

 

 

 

317

 

 

 

4,474

 

 

 

1,821

 

_____________________________________

(1)

Within the STACK, we have 51 gross (39 net) operated horizontal oil wells and 1 gross (1 net) operated horizontal natural gas wells.

 

14


Drilling Activity

The following table sets forth information with respect to wells drilled and completed during the periods indicated. Development wells are wells drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return. As of December 31, 2016, we had three gross operated wells drilling, completing or awaiting completion.

 

 

2016

 

 

2015

 

 

2014

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

20

 

 

 

12

 

 

 

46

 

 

 

22

 

 

 

174

 

 

 

100

 

Dry

 

 

 

 

 

 

1

 

 

 

1

 

 

 

2

 

 

 

2

 

Exploratory wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

32

 

 

 

4

 

 

 

16

 

 

 

6

 

 

 

26

 

 

 

19

 

Dry

 

 

 

 

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

 

Total wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

52

 

 

 

16

 

 

 

62

 

 

 

28

 

 

 

200

 

 

 

119

 

Dry

 

 

 

 

 

 

2

 

 

 

2

 

 

 

3

 

 

 

3

 

Total

 

 

52

 

 

 

16

 

 

 

64

 

 

 

30

 

 

 

203

 

 

 

122

 

Percent productive

 

 

100

%

 

 

100

%

 

 

97

%

 

 

93

%

 

 

99

%

 

 

98

%

 

Developed and Undeveloped Acreage

The following table sets forth our gross and net interest in developed and undeveloped acreage as of December 31, 2016, by state. This does not include acreage in which we hold only royalty interests.

 

 

Developed

 

 

Undeveloped

 

 

Total

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Oklahoma

 

 

482,136

 

 

 

257,030

 

 

 

82,545

 

 

 

63,446

 

 

 

564,681

 

 

 

320,476

 

Texas

 

 

76,705

 

 

 

47,893

 

 

 

4,968

 

 

 

3,424

 

 

 

81,673

 

 

 

51,317

 

Other

 

 

10,111

 

 

 

8,101

 

 

 

 

 

 

 

10,111

 

 

 

8,101

 

Total

 

 

568,952

 

 

 

313,024

 

 

 

87,513

 

 

 

66,870

 

 

 

656,465

 

 

 

379,894

 

 

Many of our leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2016 the expiration periods and net acres that are subject to leases in the undeveloped acreage summarized in the above table.

 

 

Acres Expiring

 

Twelve Months Ending

 

Gross

 

 

Net

 

December 31, 2017

 

 

63,285

 

 

 

46,736

 

December 31, 2018

 

 

7,917

 

 

 

6,042

 

December 31, 2019

 

 

16,071

 

 

 

13,882

 

December 31, 2020

 

 

240