Company Quick10K Filing
SandRidge Energy
Price5.46 EPS-4
Shares36 P/E-1
MCap195 P/FCF2
Net Debt56 EBIT-146
TTM 2019-09-30, in MM, except price, ratios
10-K 2019-12-31 Filed 2020-02-27
10-Q 2019-09-30 Filed 2019-11-12
10-Q 2019-06-30 Filed 2019-08-08
10-Q 2019-03-31 Filed 2019-05-09
10-K 2018-12-31 Filed 2019-03-05
10-Q 2018-09-30 Filed 2018-11-08
10-Q 2018-06-30 Filed 2018-08-09
10-Q 2018-03-31 Filed 2018-05-08
10-K 2017-12-31 Filed 2018-02-22
10-Q 2017-09-30 Filed 2017-11-03
10-Q 2017-06-30 Filed 2017-08-07
10-Q 2017-03-31 Filed 2017-05-10
10-K 2016-12-31 Filed 2017-03-03
10-Q 2016-09-30 Filed 2016-11-08
10-Q 2016-06-30 Filed 2016-08-15
10-Q 2016-03-31 Filed 2016-05-16
10-K 2015-12-31 Filed 2016-03-30
10-Q 2015-09-30 Filed 2015-11-05
10-Q 2015-06-30 Filed 2015-08-06
10-Q 2015-03-31 Filed 2015-05-07
10-K 2014-12-31 Filed 2015-02-27
10-Q 2014-06-30 Filed 2014-08-07
10-Q 2014-03-31 Filed 2014-05-08
10-K 2013-12-31 Filed 2014-02-28
10-Q 2013-12-31 Filed 2015-01-08
10-Q 2013-09-30 Filed 2013-11-06
10-Q 2013-06-30 Filed 2013-08-08
10-Q 2013-03-31 Filed 2013-05-08
10-K 2012-12-31 Filed 2013-03-01
10-Q 2012-09-30 Filed 2012-11-09
10-Q 2012-06-30 Filed 2012-08-06
10-Q 2012-03-31 Filed 2012-05-07
10-K 2011-12-31 Filed 2012-02-27
10-Q 2011-09-30 Filed 2011-11-07
10-Q 2011-06-30 Filed 2011-08-08
10-Q 2011-03-31 Filed 2011-05-09
10-K 2010-12-31 Filed 2011-02-28
10-Q 2010-09-30 Filed 2010-11-08
10-Q 2010-06-30 Filed 2010-08-09
10-Q 2010-03-31 Filed 2010-05-07
10-K 2009-12-31 Filed 2010-03-01
8-K 2020-05-08 Other Events
8-K 2020-04-14 Officers, Other Events
8-K 2020-04-06 Officers, Regulation FD, Exhibits
8-K 2020-04-05 Other Events
8-K 2020-02-26 Earnings, Exhibits
8-K 2020-02-04 Other Events
8-K 2019-12-12 Officers, Regulation FD, Exhibits
8-K 2019-11-12 Earnings, Exhibits
8-K 2019-08-07 Earnings, Exhibits
8-K 2019-06-21 Enter Agreement, Leave Agreement, Off-BS Arrangement, Exhibits
8-K 2019-05-30 Officers
8-K 2019-05-23 Shareholder Vote
8-K 2019-05-08 Earnings, Exhibits
8-K 2019-05-08 Earnings, Exhibits
8-K 2019-05-07 Accountant, Exhibits
8-K 2019-04-03 Officers
8-K 2019-03-25 Officers
8-K 2019-03-04 Earnings, Exhibits
8-K 2019-01-28 Officers, Exhibits
8-K 2018-11-07 Earnings, Exhibits
8-K 2018-09-17 Officers
8-K 2018-09-10 Regulation FD, Exhibits
8-K 2018-08-08 Earnings, Exhibits
8-K 2018-06-19 Enter Agreement, Officers, Shareholder Vote, Other Events, Exhibits
8-K 2018-06-18 Other Events, Exhibits
8-K 2018-06-15 Other Events, Exhibits
8-K 2018-06-11 Other Events, Exhibits
8-K 2018-06-06 Other Events, Exhibits
8-K 2018-06-05 Other Events, Exhibits
8-K 2018-06-04 Other Events, Exhibits
8-K 2018-05-29 Other Events, Exhibits
8-K 2018-05-22 Regulation FD
8-K 2018-05-07 Other Events, Exhibits
8-K 2018-05-07 Earnings, Exhibits
8-K 2018-04-16 Officers, Other Events, Exhibits
8-K 2018-04-09 Other Events, Exhibits
8-K 2018-03-10 Officers
8-K 2018-02-21 Earnings, Exhibits
8-K 2018-02-08 Officers, Regulation FD, Exhibits
8-K 2018-01-22 Enter Agreement, Shareholder Rights, Regulation FD, Exhibits

SD 10K Annual Report

Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
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. Quantitative 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 Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
EX-4.6 ex46-descriptionofsecu.htm
EX-10.4.2 ex1042-severanceplan2n.htm
EX-10.11 ex1011-suterletteragre.htm
EX-21.1 ex211subsidiarieslisti.htm
EX-23.1 ex231consentofdeloitte.htm
EX-23.2 ex232consentofpricewat.htm
EX-23.3 ex233consentofcawleygi.htm
EX-23.4 ex234consentofrydersco.htm
EX-23.5 ex235consentofnetherla.htm
EX-31.1 ex311ceo302certificati.htm
EX-31.2 ex312cfo302certificati.htm
EX-32.1 ex321section906certifi.htm
EX-99.1 ex991reportofcawleygil.htm
EX-99.2 ex992reportofryderscot.htm

SandRidge Energy Earnings 2019-12-31

Balance SheetIncome StatementCash Flow
Assets, Equity
Rev, G Profit, Net Income
Ops, Inv, Fin

2019FYFALSE10-KDecember 31, 2019123 Robert S. Kerr AvenueOklahoma CityOklahoma405429-5500Accelerated 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Washington, D.C. 20549
Form 10-K
(Mark One)
For the fiscal year ended December 31, 2019
For the transition period from            to            
Commission File Number: 001-33784
(Exact name of registrant as specified in its charter)

(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
(Address of principal executive offices)(Zip Code)
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of each exchange on which registered
Common Stock, $0.001 par valueSDNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  ☐
Accelerated filer
Non-accelerated filer ☐
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes No 

The aggregate market value of our common stock held by non-affiliates on June 28, 2019 was approximately $211.1 million based on the closing price as quoted on the New York Stock Exchange. As of February 21, 2020, there were 35,772,204 shares of our common stock outstanding.

Portions of the Company’s definitive proxy statement for the 2019 Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of December 31, 2019, are incorporated by reference in Part III.

Item Page

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References in this report to the “Company,” “SandRidge,” “we,” “our,” and “us” mean SandRidge Energy, Inc., including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary. References to the “Successor” or the “Successor Company” relate to SandRidge subsequent to October 1, 2016. References to the “Predecessor” or “Predecessor Company” refer to SandRidge on and prior to October 1, 2016. In addition, the following is a description of the meanings of certain terms used in this report.

2-D seismic or 3-D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions, respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.

ASC. Accounting Standards Codification.

ASU. Accounting Standards Update.

Bankruptcy Code. United States Bankruptcy Code.

Bankruptcy Court. United States Bankruptcy Court for the Southern District of Texas.

Bankruptcy Petitions. Voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bench. A geological horizon; a distinctive stratum useful for stratigraphic correlation.
Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. Although an equivalent barrel of condensate or natural gas may be equivalent to a barrel of oil on an energy basis, it is not equivalent on a value basis as there may be a large difference in value between an equivalent barrel and a barrel of oil. For example, based on the commodity prices used to prepare the estimate of the Company’s reserves at year-end 2019 of $55.69/Bbl for oil and $2.58/Mcf for natural gas, the ratio of economic value of oil to natural gas was approximately 22 to 1, even though the ratio for determining energy equivalency is 6 to 1.
Boe/d. Boe per day.
Bonanza Creek. Bonanza Creek Energy, Inc.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Building Note. Note with a principal amount of $35.0 million, as amended in February 2017, which was secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma.

CBP. Central Basin Platform.

Ceiling limitation. Present value of future net revenues from proved oil, natural gas and NGL reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects.

CO2. Carbon dioxide.

Completion. The process of treating a drilled well, primarily through hydraulic fracturing, 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.


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Counterparty. Counterparty to the Company’s drilling participation agreement.

Credit facility. Senior credit facility dated February 10, 2017.

Debtors. The Company and certain of its direct and indirect subsidiaries which collectively filed for reorganization under the Bankruptcy Code on May 16, 2016.

Developed acreage. The number of acres that are assignable to productive wells.
Developed oil, natural gas and NGL reserves. Reserves of any category that can be expected to be recovered (i) 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 and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development costs. Costs incurred to obtain access to proved reserves, complete wells and provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill, equip and complete development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.
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.
Dry well. 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.

Early settlements. Settlements of commodity derivative contracts prior to contractual maturity.

Emergence Date. Date the Debtors emerged from bankruptcy, October 4, 2016.

Exchange Act. Securities Exchange Act of 1934, 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.
Extended-reach lateral (“XRL”). Extended-reach lateral wells are horizontal wells where the horizontal segment or lateral is at least approximately 9,000-9,500 feet in length and may extend further. When referencing lateral counts, XRL’s are counted as more than one lateral depending on the relationship of length to an SRL length. E.g. a 9,000 foot lateral would be counted as two laterals.
FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal well. A well that is turned horizontally at depth, providing access to oil and gas reserves at a wide range of angles.

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Hydraulic fracturing. Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Hydraulic fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity.
IRS. Internal Revenue Service.
Lease. A contract in which the owner of minerals gives a company or working interest owner temporary and limited rights to explore for, develop, and produce minerals from the property, or; any transfer where the owner of a mineral interest assigns all or a part of the operating rights to another party but retains a continuing nonoperating interest in production from the property.
MBbls. Thousand barrels of oil or other liquid hydrocarbons.
MBoe. Thousand barrels of oil equivalent.
Mcf. Thousand cubic feet of natural gas.
MMBbls. Million barrels of oil or other liquid hydrocarbons.
MMBoe. Million barrels of oil equivalent.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcf/d. MMcf per day.
Mississippian Trust I. SandRidge Mississippian Trust I.

Mississippian Trust II. SandRidge Mississippian Trust II.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Netherland Sewell. Netherland, Sewell & Associates, Inc.

NGL. Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

NYMEX. The New York Mercantile Exchange.

NYSE. New York Stock Exchange.

Omnibus Incentive Plan. SandRidge Energy, Inc. 2016 Omnibus Incentive Plan.

Permian Divestiture. The November 1, 2018 sale of substantially all of the Company's oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, along with 13,125,000 common units representing a 25% equity interest in the Permian Trust to an independent third party.

Permian Trust. SandRidge Permian Trust.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues. The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10% and PV-9 is calculated using an annual discount rate of 9%.

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Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities that become part of the cost of oil and natural gas produced.
Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Prospect. A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that are both proved and developed.
Proved oil, natural gas and NGL reserves. Those quantities of oil, natural gas and NGLs 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, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For additional information, see the SEC’s definition in Rule 4-10(a) (22) of Regulation S-X, a link for which is available at the SEC’s website.
Proved undeveloped reserves. Reserves that are both proved and undeveloped.
PV-9. See “Present value of future net revenues” above.
PV-10. See “Present value of future net revenues” above.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a certain date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.

Royalty Trust. Individually, the SandRidge Mississippian Trust I, the SandRidge Mississippian Trust II and the SandRidge Permian Trust.

Royalty Trusts. Collectively, the SandRidge Mississippian Trust I, the SandRidge Mississippian Trust II and the SandRidge Permian Trust for the periods prior to November 1, 2018, and the SandRidge Mississippian Trust I and the SandRidge Mississippian Trust II for periods thereafter.

Ryder Scott. Ryder Scott Company, L.P.

SEC. Securities and Exchange Commission.

SEC prices. Unweighted arithmetic average oil and natural gas prices as of the first day of the month for the most recent 12 months as of the balance sheet date.

Securities Act. Securities Act of 1933, as amended.


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Standard-reach lateral (“SRL”). Standard-reach lateral wells are horizontal wells where the horizontal segment or lateral is approximately 4,000- 4,500 feet in length.

Standardized measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues.

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.
Undeveloped oil, natural gas and NGL reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.
i.Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
ii.Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
iii.Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
Warrants. Series A warrants and Series B warrants with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI. West Texas Intermediate.


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Cautionary Note Regarding Forward-Looking Statements

This report includes "forward-looking statements" as defined by the SEC. These forward-looking statements may include projections and estimates concerning our capital expenditures, liquidity, capital resources and debt profile, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the potential effects on our financial condition and other statements concerning our operations, financial performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements are based on certain assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected. The Company disclaims any obligation to update or revise these forward-looking statements unless required by law, and cautions readers not to rely on them unduly. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in “Risk Factors” in Item 1A of this report, as well as the following:
risks associated with drilling oil and natural gas wells;
the volatility of oil, natural gas and NGL prices;
uncertainties in estimating oil, natural gas and NGL reserves;
the need to replace the oil, natural gas and NGL reserves the Company produces;
our ability to execute our growth strategy by drilling wells as planned;
the amount, nature and timing of capital expenditures, including future development costs, required to develop our undeveloped areas;
concentration of operations in the Mid-Continent region of the United States;
limitations of seismic data;
the potential adverse effect of commodity price declines on the carrying value of our oil and natural properties;
severe or unseasonable weather that may adversely affect production;
availability of satisfactory oil, natural gas and NGL marketing and transportation options;
availability and terms of capital to fund capital expenditures;
amount and timing of proceeds of asset monetizations;
potential financial losses or earnings reductions from commodity derivatives;
potential elimination or limitation of tax incentives;
risks and uncertainties related to the adoption and implementation of regulations restricting oil and gas development in states where we operate;
competition in the oil and natural gas industry;
general economic conditions, either internationally or domestically affecting the areas where we operate;
costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water; 
risks and uncertainties related to the potential sale or lease of our corporate headquarters; and
the need to maintain adequate internal control over financial reporting.

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Item 1.  Business


We are an oil and natural gas company, organized in 2006 as a Delaware corporation, with a principal focus on exploration and production activities in the U.S. Mid-Continent and North Park Basin of Colorado.

As of December 31, 2019, we had an interest in 1,728 gross (1,013.0 net) producing wells, approximately 1,169 of which we operate, and approximately 701,000 gross (511,000 net) total acres under lease. As of December 31, 2019, we had no rigs drilling. Total estimated proved reserves as of December 31, 2019, were 89.9 MMBoe, of which approximately 69% were proved developed.

Our principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and our telephone number is (405) 429-5500. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available free of charge on our website at as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. Any materials that we have filed with the SEC may be accessed via the SEC’s website address at

Reorganization Under Chapter 11 and Emergence from Bankruptcy

On May 16, 2016, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the reorganization plan, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016. Pursuant to the reorganization plan, all of the Predecessor Company's common stock and other equity and debt securities were cancelled and on October 4, 2016, the Successor Company issued an aggregate of 18.9 million shares of common stock at $.001 par value and commenced trading on the New York Stock Exchange.

Our Business Strategy

Our business strategy in 2020 will be focused on maximizing free cash flow through the strategic rationalization of corporate and field-level costs, limiting our drilling capital to locations that we believe will provide high rates of return in the present commodity price environment and that allow for near-term payouts. We will continue our pursuit of acquisitions and business combinations that are accretive to earnings and cash flow per share, and which provide high margin properties with attractive returns at current commodity prices. The execution of this strategy will be coupled with the continued exercise of financial discipline and prudent capital allocation. We intend to spend between $25.0 million and $30.0 million in our 2020 capital budget plan in contemplation of continued depressed commodity prices, and will be prepared to expand our capital program if commodity prices increase sufficiently.


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Our primary operations are the exploration, development and production of oil and natural gas. The following table presents information concerning our exploration and production activities by geographic area of operation as of December 31, 2019.
Estimated Net
Capital Expenditures (In millions) (3)
Mid-Continent61.4  23.9  7.0  578,667  399,912  $29.2  
North Park Basin28.5  4.6  16.9  117,564  109,579  129.3  
Other—  —  —  4,628  1,456  3.3  
Total89.9  28.5  8.6  700,859  510,947  $161.8  
(1) Average daily net production for the month of December 2019.
(2) Estimated net proved reserves as of December 31, 2019 divided by average daily net production for the month of December 2019, annualized.
(3) Capital expenditures for the year ended December 31, 2019, on an accrual basis and including acquisitions.



We held interests in approximately 579,000 gross (400,000 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2019. Associated proved reserves at December 31, 2019 totaled 61.4 MMBoe, 91.0% of which were proved developed reserves. Our interests in the Mid-Continent as of December 31, 2019 included 1,675 gross (960.0 net) producing wells with an average working interest of 57%. We had no rigs operating in the Mid-Continent as of December 31, 2019. At December 31, 2019, our Mid-Continent properties included an inventory of 15 operated proved undeveloped wells. Additionally, we estimate there are approximately 100 undeveloped probable horizontal locations. During 2019, we completed a total of 12 horizontal producing wells in this area, which consisted primarily of SRLs.

NW STACK. The Meramec and Osage formations are the primary targets in the NW STACK in Garfield, Major, Dewey, and Woodward Counties. These formations are Mississippian in age, lying above the Woodford Shale and below Chester formations. The Meramec is composed of interbedded shales, sands, and carbonates while the Osage is composed of low porosity, fractured limestone and chert. The top of these target formations ranges in depth from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin. Meramec formation thickness ranges from about 50 feet to over 400 feet and the Osage formation thickness ranges from about 450 to 1,400 feet. The Woodford Shale is the primary hydrocarbon source for both the Meramec and Osage. Similar to the STACK, there is an over-pressured area and normally pressured area in the NW STACK. We completed 12 wells in the Meramec formation during 2019 and no Osage wells. Of our total Mid-Continent acreage at December 31, 2019, approximately 99,000 gross (56,000 net) acres are associated with the NW STACK play area.

In the third quarter of 2017, we entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of our undeveloped leasehold acreage within the Meramec formation in the NW STACK. Under this agreement, the Counterparty paid 90% of the net drilling and completion costs, up to $100.0 million in the first tranche, in exchange for an initial 80% net working interest in each new well, subject to certain reversionary hurdles. As a result, we received a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. The last well under this agreement was completed in the second quarter of 2019. See "Operational Activities" included in Item 7 of this report for further discussion of the drilling participation agreement.

Mississippian Lime Formation. The Mississippian Lime formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and southern Kansas, and is a target for exploration and development within the Mid-Continent. The top of this formation is encountered between approximately 4,000 and 7,000 feet and stratigraphically between various formations of Pennsylvanian age and the Devonian-aged Woodford Shale formation. The Mississippian formation is approximately 350 to 650 feet in gross thickness across our lease position and has targeted porosity

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zone(s) ranging between 20 and 150 feet in thickness. At December 31, 2019, we had approximately 480,000 gross (344,000 net) acres under lease and 1,211 gross (776.7 net) producing wells in the Mississippian formation. We did not complete any wells in the Mississippian Lime formation in 2019.

North Park Basin

Our North Park Basin properties consisted of approximately 118,000 gross (110,000 net) acres, and 53 gross and net producing wells with a working interest of 100%, at December 31, 2019. Associated proved reserves at December 31, 2019 totaled approximately 28.5 MMBoe, of which 21.7% were proved developed reserves. The North Park Basin acreage is located in north central Colorado, and similar to the DJ Basin next to Colorado’s Front Range, has multiple potential pay targets in addition to the Niobrara Shale play, where our activity is currently focused. Although untested, zones shallower and deeper than the Niobrara have indications of potentially commercial hydrocarbons. The Niobrara Shale is characterized by stacked pay benches at depths of 5,500 to 9,000 feet with overall reservoir thickness over 450 feet. Based on our delineation drilling on acreage inside and outside federal units, we are developing a proved area where we have 55 operated proved undeveloped wells. Across our entire acreage position, we estimate there are approximately 900 undeveloped probable horizontal lateral locations. We had no rigs operating in the North Park Basin as of December 31, 2019. We completed a total of 16 horizontal producing wells, including 12 XRLs and four SRLs, in this area during 2019.

Proved Reserves

The portion of a reservoir considered to contain proved reserves includes (i) the portion identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Existing economic conditions include prices, costs, operating methods and government regulations existing at the time the reserve estimates are made. SEC prices are used to determine proved reserves, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. See further discussion of prices in “Risk Factors” included in Item 1A of this report.

Preparation of Reserves Estimates

Over 90% of the proved oil, natural gas and NGL reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. A small portion of the proved reserves disclosed in this report were determined by internal reserve engineers. To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers. This consultation included review of properties, assumptions and available data. Internal reserve estimates were compared to those prepared by independent reserve engineers to test the estimates and conclusions before the reserves were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following:

the quality and quantity of available data and the engineering and geological interpretation of that data;
estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
the accuracy of economic assumptions; and
the judgment of the personnel preparing the estimates.

SandRidge’s Senior Vice President—Reserves, Technology and Business Development is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering with over 30 years of practical industry experience, including over 30 years of estimating and evaluating

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reserve information. He has also been a certified professional engineer in the state of Oklahoma since 2007 and a member of the Society of Petroleum Engineers since 1980.

SandRidge’s reserve engineers monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected. The information used to prepare reserve estimates includes production histories as well as other geologic, economic, ownership and engineering data. The Corporate Reserves department currently has a total of three full-time employees, comprised of two degreed engineers and one engineering and business analyst with a four-year degree in mathematics.

We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets.

In order to ensure the reliability of reserves estimates, the Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate and report proved reserves including:
confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;
ensuring the information provided by other departments within the Company such as Accounting is accurate;
communicating, collaborating, and analyzing with technical personnel in our business units;
comparing and reconciling the internally generated reserves estimates to those prepared by third parties;
utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates; and
ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded.

Each quarter, the Senior Vice President—Reserves, Technology and Business Development presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, the five year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, and the Senior Vice President - Reserves, Technology and Business Development.

The Corporate Reserves department works closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

The percentage of total proved reserves prepared by each of the independent petroleum consultants is shown in the table below.
 December 31,
Cawley, Gillespie & Associates, Inc.50.2 %51.6 %62.6 %
Ryder Scott Company, L.P.43.0 %43.5 %29.0 %
Netherland, Sewell & Associates, Inc.— %— %3.8 %
Total93.2 %95.1 %95.4 %

The remaining 6.8%, 4.9% and 4.6% of estimated proved reserves as of December 31, 2019, 2018 and 2017, respectively, were based on internally prepared estimates, primarily for the Mid-Continent area.

Copies of the reports issued by our independent reserve consultants with respect to our oil, natural gas and NGL reserves as of December 31, 2019 are filed with this report as Exhibits 99.1 and 99.2. The geographic location of our estimated proved reserves prepared by each of the independent reserve consultants as of December 31, 2019 is presented below.
Geographic Locations—by Area by State
Cawley, Gillespie & Associates, Inc.Mid-Continent—KS, OK
Ryder Scott Company, L.P.North Park Basin—CO, Mid-Continent—OK


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The qualifications of the technical personnel at each of these firms primarily responsible for overseeing the firm’s preparation of the Company’s reserves estimates included in this report are set forth below. These qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

Cawley, Gillespie & Associates, Inc.
more than 25 years of practical experience in the estimation and evaluation of petroleum reserves;
a registered professional engineer in the state of Texas; and
Bachelor of Science Degree in Petroleum Engineering.

Ryder Scott Company, L.P.
more than 30 years of practical experience in the estimation and evaluation of petroleum reserves;
a registered professional engineer in the states of Alaska, Colorado, Texas and Wyoming; and
Bachelor of Science Degree in Petroleum Engineering and MBA in Finance;

Netherland, Sewell & Associates, Inc.
practicing consultant in petroleum engineering since 2013 and over 14 years of prior industry experience;
licensed professional engineers in the state of Texas; and
Bachelor of Science Degree in Chemical Engineering

Reporting of Natural Gas Liquids

NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2019, NGLs comprised approximately 18% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels based on a conversion rate of 42 gallons per barrel. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs.


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Reserve Quantities, PV-10 and Standardized Measure

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2019, 2018 and 2017, over 90% of which were prepared by independent reserve engineers. The reserve reports were based on our drilling schedule at the time year-end reserve estimates were prepared. Our year-end 2019 PUD development plan established that 100% of our current proved undeveloped reserves will be developed within five years from when they were originally recorded. See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.
 December 31,
Estimated Proved Reserves(1)
Oil (MMBbls)14.1  18.7  25.9  
NGL (MMBbls)14.5  22.3  29.9  
Natural gas (Bcf)200.9  307.9  408.0  
Total proved developed (MMBoe)62.1  92.3  123.8  
Oil (MMBbls)21.2  45.3  35.9  
NGL (MMBbls)1.3  5.9  4.4  
Natural gas (Bcf)31.5  100.0  80.9  
Total proved undeveloped (MMBoe)27.8  67.9  53.8  
Total Proved
Oil (MMBbls)35.3  64.0  61.8  
NGL (MMBbls)15.9  28.2  34.3  
Natural gas (Bcf)232.3  407.9  488.9  
Total proved (MMBoe)89.9  160.2  177.6  
Standardized Measure of Discounted Net Cash Flows (in millions)(2)

$364.3  $1,045.6  $749.3  
PV-10 (in millions)(3)$364.3  $1,045.6  $749.3  
(1) Estimated proved reserves, PV-10 and Standardized Measure were determined using SEC prices, and do not reflect actual prices received or current market prices. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below. 
 Index prices (a)
Weighted average 
wellhead prices (b) 
(per Bbl)
Natural gas
(per Mcf)
(per Bbl)
(per Bbl)
Natural gas
(per Mcf)
December 31, 2019$55.69  $2.58  $50.63  $12.45  $1.16  
December 31, 2018$65.56  $3.10  $60.86  $25.62  $1.77  
December 31, 2017$51.34  $2.98  $48.47  $20.28  $1.90  
(a) Index prices are based on average West Texas Intermediate (“WTI”) Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.
(b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials.

(2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes. At December 31, 2019, 2018 and 2017, the difference between the standardized measure and PV-10 was insignificant due to an excess of tax basis in oil and natural gas properties over projected undiscounted future cash flows from our proved reserves.


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(3) PV-10 is a non-GAAP financial measure. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas properties. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. The following table provides a reconciliation of our Standardized Measure to PV-10:
 December 31,
 (In millions)
Standardized Measure of Discounted Net Cash Flows$364.3  $1,045.6  $749.3  
Present value of future income tax discounted at 10%—  —  —  
PV-10$364.3  $1,045.6  $749.3  

Proved Reserves - Mid-Continent. Proved reserves in the Mid-Continent, primarily the Mississippian formation, decreased from 110.9 MMBoe at December 31, 2018 to 61.4 MMBoe at December 31, 2019. This reserve reduction is due primarily to downward revisions of 26.1 MMBoe associated with the decrease in year-end SEC commodity pricing consisting of (i) 17.8 MMBoe from downgrading PUDs, and (ii) 8.3 MMBoe from remaining proved reserves, 11.3 MMBoe negative revisions associated with increased commodity price differentials, and 2019 production totaling 10.4 MMBoe. Additional reserve decreases amounting to 5.2 MMBoe were the result of wells being shut-in during 2019, largely due to economic conditions, sales, and other revisions to prior estimates. Partially offsetting these reductions were a 3.6 MMBoe increase associated with changes to lease operating costs, extensions, and other reserve parameters.

Proved Reserves - North Park Basin. Our North Park Basin proved reserves in the Niobrara decreased from 49.3 MMBoe at December 31, 2018 to 28.5 MMBoe at December 31, 2019. This reserve reduction is due primarily to downward revisions of 24.8 MMBoe associated with the decrease in year-end SEC commodity pricing consisting of (i) 21.9 MMBoe from downgrading PUDs, and (ii) 2.9 MMBoe from remaining proved reserves, 3.7 MMBoe associated with changes to lease operating costs, 3.1 MMBoe negative revisions to prior estimates stemming from changes in well performance, 2019 production totaling 1.5 MMBoe, and other reductions amounting to 1.4 MMBoe. Partially offsetting these reductions are a 12.6 MMBoe increase associated with converting undeveloped well locations from SRLs to planned XRLs as well as reduced future estimated development capital on these undeveloped locations, and 1.0 MMBoe associated with extensions and commodity price differentials.

Our Niobrara proved developed reserves are attributed to 51 horizontal producing wells. Reservoir characteristics of the Niobrara in the North Park Basin are similar to those of the Niobrara in the DJ Basin, consisting of multiple stratigraphic benches. In the North Park Basin, production performance and reservoir data gathered from Niobrara producing wells confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. Using the performance of the proved developed producing wells, proved undeveloped reserves were recorded for 20 sections of the 35 section proved development area predominantly at a well density of up to eight wells per section. Performance from recent spacing tests provide preliminary indications that a spacing density of up to 16 wells per section may be viable.

Proved Undeveloped Reserves. The following table summarizes activity associated with proved undeveloped reserves during the periods presented:
Year Ended December 31,
Reserves converted from proved undeveloped to proved developed (MMBoe)
3.7  4.2  1.1  
Drilling and infrastructure capital expended to convert proved undeveloped reserves to proved developed reserves (in millions)
$95.3  $63.2  $21.0  

Total estimated proved undeveloped reserves were 27.8 MMBoe at December 31, 2019, which is a decrease of 40.1 MMBoe from the prior year. This decrease is primarily due to 39.8 MMBoe associated with removing PUDs due to the decrease in year-end SEC commodity pricing consisting of 17.8 MMBoe of Midcon PUD reserves and 21.9 MMBoe of North Park Basin PUD reserves. Additional decreases included 1.1 MMBoe associated with a minor type curve revision on the remaining 55 North Park PUDs to account for recent PDP performance, 3.7 MMBoe of 2019 PUD conversions, and 8.1 MMBoe related to revisions in estimates for operating expenses, differentials, and other reserve parameters. These were partially offset by a 12.6 MMBoe increase associated with converting undeveloped well locations from SRLs to planned XRLs as well as reduced future estimated development capital.


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Total estimated proved undeveloped reserves were 67.9 MMBoe at December 31, 2018, which is an increase of 14.1 MMBoe from the prior year. This increase is primarily due to 18.0 MMBoe from extensions and discoveries which consisted largely of 8.5 MMBoe in the North Park Basin from increased well density and successful development drilling in the Niobrara shale, and 9.5 MMBoe in the Mid-Continent from horizontal drilling in our NW STACK play. These extensions were offset by 4.2 MMBoe of PUD conversions.

Total estimated proved undeveloped reserves as of December 31, 2017 were 53.8 MMBoe, an increase of 10.6 MMBoe from the prior year. Reserves added from extensions and discoveries totaled 14.7 MMBoe, which consisted of 10.1 MMBoe in North Park from horizontal wells drilled in the Niobrara Shale, and 4.6 MMBoe in the Mid-Continent from horizontal drilling in our NW STACK play. These extensions were offset by 137 MBoe of proved undeveloped reserves at December 31, 2016 that were converted to proved developed reserves during 2017, and net downward revisions of 4.0 MMBoe primarily due to removing PUDs attributable to expiring Mid-Continent undeveloped acreage outside of our NW STACK play that was not scheduled to be developed prior to lease expiry. Approximately 1.0 MMBoe of proved undeveloped reserves were booked and converted during the year 2017.

For additional information regarding changes in proved reserves during each of the three years ended December 31, 2019, 2018 and 2017 see “Note 22—Supplemental Information on Oil and Natural Gas Producing Activities” to the consolidated financial statements in Item 8 of this report.

Significant Fields

Oil, natural gas and NGL production for fields containing more than 15% of our total proved reserves at each year end are presented in the table below. The Mississippian Lime Horizontal field and the Niobrara field each contained more than 15% of total proved reserves at December 31, 2019, 2018 and 2017.

NGL (MBbls)
Natural Gas
Year Ended December 31, 2019  
Mississippian Lime Horizontal1,312  2,535  28,447  8,588  
Niobrara1,531   —  1,533  
Year Ended December 31, 2018
Mississippian Lime Horizontal1,558  2,477  31,663  9,312  
Niobrara1,034  —  —  1,034  
Year Ended December 31, 2017
Mississippian Lime Horizontal2,382  2,995  38,834  11,849  
Niobrara673  —  —  673  

Mississippian Lime Horizontal Field. The Mississippian Lime Horizontal Field is located on the Anadarko Shelf in northern Oklahoma and Kansas and produces from the Mississippian formation. Our interests in the Mississippian Lime Horizontal Field as of December 31, 2019 included 1,211 gross (776.7 net) producing wells and a 64% average working interest in the producing area.

Niobrara Field. The Niobrara field is located in Colorado and produces from the Niobrara Shale. Currently only oil is marketed while evaluation and appraisal of midstream options for gas processing and marketing is ongoing, including engineering design work, pipeline route surveying, and permitting. Our interests in the Niobrara Field as of December 31, 2019, included 53 gross and net producing wells with a 100% average working interest in the producing area.


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Production and Price History

The following table includes information regarding our net oil, natural gas and NGL production and certain price and cost information for each of the periods indicated.

Year Ended December 31,
Production data (in thousands)
Oil (MBbls)3,519  3,477  4,157  
NGL (MBbls)2,910  2,829  3,376  
Natural gas (MMcf)33,164  36,175  44,237  
Total volumes (MBoe)11,956  12,335  14,906  
Average daily total volumes (MBoe/d)32.8  33.8  40.8  
Average prices—as reported(1)
Oil (per Bbl)$52.96  $61.73  $48.72  
 NGL (per Bbl)$12.23  $23.72  $18.16  
Natural gas (per Mcf)$1.33  $1.85  $2.09  
Total (per Boe)$22.26  $28.27  $23.90  
Expenses per Boe
Production costs(2)$7.60  $7.12  $6.64  
(1)Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.
(2)Represents production costs per Boe excluding production and ad valorem taxes.

Productive Wells

The following table presents the number of productive wells in which we owned a working interest at December 31, 2019. We operate substantially all of our wells. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells in which we have a working interest and net wells are the sum of the fractional working interests owned in gross wells.
 OilNatural GasTotal
Mid-Continent1,413  833.9  262  126.1  1,675  960.0  
North Park Basin53  53.0  —  —  53  53.0  
Total1,466  886.9  262  126.1  1,728  1,013.0  


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Drilling Activity

The following table presents information with respect to wells completed during the periods indicated. This information is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. As of December 31, 2019, we had no operated wells drilling, completing or awaiting completion.
Completed Wells
Productive28  20.6  29  15.5  22  16.4  
Dry—  —  —  —  —  —  
Total28  20.6  29  15.5  22  16.4  
Productive—  —  —  —   1.0  
Dry—  —  —  —  —  —  
Total—  —  —  —   1.0  
28  20.6  29  15.5  23  17.4  
—  —  —  —  —  —  
Total28  20.6  29  15.5  23  17.4  

We had no third-party rigs operating on our Mid-Continent or North Park Basin acreage at December 31, 2019.

Developed and Undeveloped Acreage

The following table presents information regarding our developed and undeveloped acreage at December 31, 2019:
 Developed AcreageUndeveloped Acreage
Mid-Continent489,411  357,673  89,256  42,239  
North Park Basin18,079  18,054  99,485  91,525  
Other1,440  389  3,188  1,067  
Total508,930  376,116  191,929  134,831  

Many of the leases included in the undeveloped acreage above will expire at the end of their respective primary terms. To prevent expiration, we may exercise our contractual rights to pay delay rentals to extend the terms of leases we value, or establish production from the leasehold acreage prior to expiration, which will keep the lease from expiring until production has ceased.


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As of December 31, 2019, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows:
 Acres Expiring
Twelve Months Ending
December 31, 202026,179  14,846  
December 31, 202119,481  17,745  
December 31, 20223,954  2,367  
December 31, 2023 and later1,002  776  
Other(1)141,313  99,097  
Total191,929  134,831  
(1)Leases remaining in effect until development efforts or production on the particular lease has ceased.

The acreage due to expire during the twelve months ending December 31, 2020, includes approximately 19,146 gross (9,791 net) acres in the Mid-Continent and 7,033 gross (5,055 net) acres in the North Park Basin.

Marketing and Customers

We sell our oil, natural gas and NGLs to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. We had three customers that individually accounted for more than 10% of our total revenue during the 2019 period. See “Note 1—Summary of Significant Accounting Policies” to the consolidated financial statements in Item 8 of this report for additional information on our major customers. The number of readily available purchasers in the areas where we sell our production makes it unlikely that the loss of a single customer would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

Title to Properties

As is customary in the oil and natural gas industry, we conduct a preliminary review of the title to our properties. Prior to commencing drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects typically at our expense. In addition, prior to completing an acquisition of producing oil and natural gas assets, we perform title reviews on the most significant leases and depending on the materiality of properties, may obtain a drilling title opinion or review previously obtained title opinions. To date, we have obtained drilling title opinions on substantially all of our producing properties and believe that we have good and defensible title to our producing properties. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe does not materially interfere with the use of, or affect the carrying value of the properties.


We compete with major oil and natural gas companies and independent oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil, natural gas and NGLs. We believe our leasehold acreage position, geographic concentration of operations and technical and operational capabilities enable us to compete effectively with other exploration and production operations. However, the oil and natural gas industry is intensely competitive. See “Item 1A. Risk Factors” for additional discussion of competition in the oil and natural gas industry.

Oil, natural gas and NGLs compete with other forms of energy available to customers, including alternate forms of energy such as electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas and NGLs or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil, natural gas and NGLs.


Generally, demand for natural gas decreases during the summer months and increases during the winter months and demand for oil peaks during the summer months. Certain natural gas purchasers utilize natural gas storage facilities and acquire some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations

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in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives, delay the installation of production facilities, and increase competition for equipment, supplies and personnel during certain times of the year, which could lead to shortages and increase costs or delay operations.



Our oil and natural gas exploration, development and production operations are subject to stringent and complex federal, state, tribal, regional and local laws and regulations governing worker safety and health, the discharge and disposal of substances into the environment, and the protection of the environment and natural resources. Numerous governmental entities, including the EPA and analogous state and local agencies, (and, under certain laws, private individuals) have the power to enforce compliance with these laws and regulations and any permits issued under them. These laws and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal, wastewater disposal and other production related activities; (ii) govern the types, quantities and concentrations of substances that may be disposed or released into the environment or injected into formations in connection with drilling or production activities, and the manner of any such disposal, release, or injection; (iii) limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; (iv) require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; (v) impose safety and health restrictions designed to protect employees from exposure to hazardous or dangerous substances; and (vi) impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects and the issuance of orders enjoining operations in affected areas.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. Any changes in or more stringent enforcement of these laws and regulations that result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements could have a material adverse effect on the Company. We may be unable to pass on increased compliance costs to our customers. Moreover, accidental releases, including spills, may occur in the course of our operations, and there can be no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property and natural resources or personal injury. While we do not believe that compliance with existing environmental laws and regulations and that continued compliance with existing requirements will have an adverse material effect on us, we can provide no assurance that we will not incur substantial costs in the future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition, and results of operations.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on the Company.

Hazardous Substances and Wastes

We currently own, lease, or operate, and in the past have owned, leased, or operated, properties that have been used in the exploration and production of oil and natural gas. We believe we have utilized operating and disposal practices that were standard in the industry at the applicable time, but hazardous substances, hydrocarbons, and wastes may have been disposed or released on, from or under the properties owned, leased, or operated by us or on or under other locations where these substances and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose storage treatment and disposal or release of hazardous substances, hydrocarbons, and wastes were not under our control. These properties and the substances or wastes disposed or released on them may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the federal Resource Conservation and Recovery Act, (“RCRA”), and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed substances or wastes (including substances or wastes disposed of or released by prior owners or operators or third parties whose waste was commingled with ours), to investigate and clean up contaminated property, to perform corrective actions to prevent future contamination, or to pay some or all of the costs of any such action.

CERCLA, also known as the Superfund law, and comparable state laws may impose strict, joint and several liability without regard to fault or legality of conduct on certain classes of persons who are considered to be responsible for the release

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of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release of a hazardous substance occurred as well as entities that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, these “responsible persons” may be liable for the costs of cleaning up sites where the hazardous substances have been released into the environment, for damages to natural resources resulting from the release and for the costs of certain environmental and health studies. Additionally, landowners and other third parties may file claims for personal injury and natural resource and property damage allegedly caused by the release of hazardous substances into the environment. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment from a hazardous substance release and to pursue steps to recover costs incurred for those actions from responsible parties. Although petroleum, natural gas and natural gas liquids are excluded from the definition of "hazardous substance" under CERCLA, despite this so-called "petroleum exclusion,” certain products used in the course of our operations may be regulated as CERCLA hazardous substances. To date, no Company-owned or operated site has been designated as a Superfund site, and we have not been identified as a responsible party for any Superfund site.

We also generate wastes that are subject to the requirements of RCRA and comparable state statutes. RCRA imposes strict “cradle-to-grave” requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and other wastes associated with the exploration, production and/or development of oil and natural gas, including naturally-occurring radioactive material, if properly handled, are currently excluded from regulation as hazardous wastes under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste requirements. However, it is possible that these wastes could be classified as hazardous wastes in the future. Any change in the exclusion for such wastes could potentially result in an increase in costs to manage and dispose of wastes which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that are subject to regulation under RCRA if they have hazardous characteristics.

Air Emissions

The federal Clean Air Act (the “CAA”), as amended, and comparable state laws and regulations restrict the emission of air pollutants through emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions. The need to acquire such permits has the potential to delay or limit the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare. The EPA was required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017, but missed the deadline. Subsequently, in November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendation for designating non-attainment areas. In November 2018, the EPA issued final rules implementing the non-attainment area designations. While the EPA has determined that all counties in which we operate are in attainment with the new ozone standard, these determinations may be revised in the future. With the EPA lowering the ground-level ozone standard, certain states may be required to implement more stringent regulations, which could apply to our operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures. In addition, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities to be aggregated for permitting purposes, resulting in treatment as a major source, and thereby triggering more stringent air permitting requirements. On August 28, 2019, the EPA proposed amendments that would remove all sources in the transmission and storage segment of the oil and natural gas industry from these rules; however, the rules still apply to the extraction sector. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.

Water Discharges

The federal Water Pollution Control Act, also known as the Clean Water Act (the “CWA”), and analogous state laws and implementing regulations, impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States. Pursuant to these laws and regulations, the discharge of pollutants into regulated waters is prohibited unless it is permitted by the EPA, the Army Corps of Engineers ("Corps") or an analogous state or tribal agency. We do not presently

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discharge pollutants associated with the exploration, development and production of oil and natural gas into federal or state waters. The CWA and analogous state laws and regulations also impose restrictions and controls regarding the discharge of sediment via storm water run-off from a wide variety of construction activities. Such activities are generally prohibited from discharging sediment unless permitted by the EPA or an analogous state agency. The EPA issued a final rule in September 2015 that attempts to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”). The EPA and the Corps then proposed a rulemaking in June 2017 to repeal the June 2015 WOTUS rule and also announced their intent to issue a new rule redefining the CWA’s jurisdiction. The EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 WOTUS rule for two years. Subsequently, on December 11, 2018, the EPA and the Corps proposed a new rule defining the CWA’s jurisdiction. On October 22, 2019, EPA and the Corps published a final rule repealing the 2015 WOTUS rule and recodifying the regulatory language that existed prior to that rule. This action, which became effective on December 23, 2019, resolved a nationwide patchwork of jurisdictional applicability that had developed due to litigation and court rulings regarding the WOTUS rules. The 2019 final rule has been challenged in federal court, however, and the scope of the CWA’s jurisdiction may remain fluid until all litigation is concluded. To the extent the litigation over the new rule is successful, it may yet result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.

Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills from reaching nearby water bodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. We have developed and implemented SPCC plans for properties as required under the CWA.

Subsurface Injections

Underground injection operations performed by us are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although the Company monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal injuries. Some states have considered laws mandating flowback and produced water recycling. Other states have undertaken studies, in some cases such as New Mexico in conjunction with the EPA, to assess the feasibility of recycling produced water on a large scale. If such laws are adopted in areas where we conduct operations, our operating costs may increase significantly.

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has issued rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents. For example, in February

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2016, the OCC issued a plan to reduce disposal well volume in the Arbuckle formation by 40 percent, covering approximately 5,281 square miles and 245 disposal wells injecting wastewater into the Arbuckle formation. In the plan, the OCC identified 76 SandRidge-operated disposals wells, prescribed a four stage volume reduction schedule and set April 30, 2016 as the final date for compliance with the tiered volume reduction plan. In March 2016, the OCC reduced the injection volume of additional Arbuckle disposal wells, including wells we operate. Following earthquakes in August, September and November 2016, the OCC and the EPA further limited the disposal volumes that can be disposed in Arbuckle wells, although these actions did not cover our disposal wells. While induced seismic events generally decreased in 2017, the OCC expanded restrictions on the use of existing Arbuckle disposal wells and imposed new reporting requirements related to disposal volumes on wells injecting produced water into the Arbuckle formation. In February 2018, the OCC instituted a new protocol to further address seismicity in the Sooner Trend Anadarko Basin Canadian and Kingfisher County and South Central Oklahoma Oil Province Plays which requires various actions, such as a pause in operations for several hours, when certain seismic data is observed. These and similar future protocols that may be adopted in response to future seismicity concerns may reduce the productivity of our operations in relevant areas.

Additionally, the Governor of Kansas has established a task force composed of various administrative agencies to study and develop an action plan for addressing seismic activity in the state. The task force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the Governor of Kansas announced a plan to enhance seismic monitoring in the state. In March 2015, the Kansas Corporation Commission issued its Order Reducing Saltwater Injection Rates (the "Order"). The Order identified five areas of heightened seismic concern within Harper and Sumner Counties and mandated that, within 100 days of the Order’s issuance, operators must limit saltwater injection volumes to no more than 8,000 barrels per day for any well located in one of these five areas. SandRidge and other operators of injection wells were required to reduce the injection volume, and any injection well drilled deeper than the Arbuckle Formation was required to be plugged back to a shallower formation in a manner approved by the Kansas Corporation Commission. In August 2016, the Kansas Corporation Commission issued an order that put a 16,000 barrels per day limit on additional Arbuckle disposal wells not previously identified in the Order. While no additional regulatory actions were taken in Kansas with respect to induced seismicity concerns since 2017, permit applications for new saltwater disposal well facilities have faced increased local opposition.

Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed. The adoption of any new laws, regulations, or directives that restrict our ability to dispose of saltwater generated by production and development activities , whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring us to shut down disposal wells, could significantly increase our costs to manage and dispose of this saltwater, which could negatively affect the economic lives of the affected properties. In addition, we could find ourselves subject to third party lawsuits alleging damages resulting from seismic events that occur in our areas of operation.

Climate Change

The EPA previously has published its findings that emissions of CO2, methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emission. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are established by the states. This rule could adversely affect our operations and restrict or delay its ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing. More recently, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program to minimize methane emissions, under the CAA’s New Source Performance Standards, Subpart OOOOa (“Quad Oa”). In June 2017, the EPA proposed a two-year stay of the rules and in October 2018 the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain Quad Oa requirements is technically infeasible. Regardless of the stay and potential regulatory revisions, it is possible that these rules will continue to require oil and gas operators to expend material sums. In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on public lands that are substantially similar to the EPA Quad Oa requirements. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain

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requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, however, the 2018 rule is currently being challenged in federal court. As a result of these developments, future implementation of the EPA and the BLM methane rules remains uncertain, but given the long-term trend towards increasing regulation, future federal GHG regulations for the oil and gas industry remain a possibility. Moreover, several states where we operate, including Colorado, have already adopted rules requiring operators of both new and existing sources to develop and implement a LDAR program and to install devices on certain equipment to capture 95 percent of methane emissions. Compliance with these rules could require us to purchase pollution control equipment and optical gas imaging equipment for LDAR inspections, and to hire additional personnel to assist with inspection and reporting requirements.

In addition, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”). However, the Paris Agreement does not impose any binding obligations on the United States. Moreover, in June 2017, President Trump announced that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The United States formally initiated withdrawal proceedings on November 4, 2019. The withdrawal cannot be effective before November 4, 2020; thus, whether the United States may reenter the Paris Agreement or a separately negotiated agreement is unclear at this time. Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement. The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation.

Endangered or Threatened Species

The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats without first obtaining an incidental take permit and implementing mitigation measures. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act. While compliance with the ESA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. In addition, certain of our federal and state leases may contain stipulations that require us to take measures to safeguard certain species, including the sage grouse, and their habitats known to be located within the area of the lease. Although the U.S. Fish and Wildlife Service (“USFWS”) declined to list the sage grouse under the ESA in 2015 and subsequently developed a conservation plan to protect existing habit, some environmental groups have continued to raise concerns about sufficient protections for the sage grouse population. Under the plan, the USFWS committed to review the status of the species every five years to evaluate conservation actions, with the plan to be next reviewed and revised if necessary in 2020. In addition, the U.S. Department of Interior (“DOI”) proposed in December 2018 revisions to the existing sage grouse conservation plan that, amongst other things, was intended to give the DOI and individual states flexibility to allow for increased activity in grouse habitat management areas encompassing parts of Colorado, Idaho, Nevada, Northern California, Oregon, Utah and Wyoming. Several conservation groups challenged the rules, and on October 16, 2019, the U.S. District Court for the District of Idaho issued a preliminary injunction blocking implementation of the new rules in Idaho, Wyoming, Colorado, Utah, Nevada, Oregon, and part of California. While the BLM can still issue new permits in these areas, it must follow the restrictions included in the 2015 management plans. It is also possible that the ongoing litigation could result in the sage grouse being re-listed under the ESA in the future. If endangered or otherwise protected species are located in areas where we wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive

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mitigation may be required. For example, certain of our operations in Colorado are in proximity to sage grouse habitat and we are prohibited from performing operations in those areas during certain hours from March to mid-July of each year. Further, in February 2016, the USFWS published a final policy which alters how it identifies critical habitats for endangered and threatened species. In August 2019, the USFWS issued three final rules revising its ESA regulations, consisting of changes to the procedures and criteria for listing or delisting species and designating critical habitat, removal of the automatic take prohibition for species listed as threatened, and regulations for protection of threatened species, (ii) criteria for listing and delisting of species and designation of critical habitat, and new procedures and time frames for required consultations by other federal agencies. In general these rules were designed to alleviate some of the burdens of the ESA and streamline its implementation, but the prospect of new species listings and critical habitat designations remains. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, a settlement approved by the U.S. District Court for the District of Columbia in 2011 required the USFWS to consider listing numerous species as endangered under the ESA by the end of its 2017 fiscal year; however, the agency has not yet completed this process.

The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

We are an active participant on various agency and industry committees that are developing or addressing various USFWS and other federal and state agency programs to minimize potential impacts to business activity relating to the protection of any endangered or threatened species.

Employee Health and Safety

Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires us to maintain information concerning hazardous materials used or produced in our operations and to provide this information to employees. Pursuant to the Federal Emergency Planning and Community Right-to-Know Act, facilities that store threshold amounts of chemicals that are subject to OSHA’s Hazard Communication Standard above certain threshold quantities must submit information regarding those chemicals by March 1 of each year to state and local authorities in order to facilitate emergency planning and response. That information is generally available to employees, state and local governmental authorities, and the public. We do not believe that compliance with applicable laws and regulations relating to worker health and safety will have a material adverse effect on our business and results of operations.

State Regulation

The states in which we operate, along with some municipalities and Native American tribal areas, regulate some or all of the following activities: the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. These regulations may affect the number and location of our wells and the amounts of oil and natural gas that may be produced from our wells, and increase the costs of our operations. Moreover, obtaining or renewing permits and other approvals for operating on Native American lands can take substantial amounts of time, and could result in increased costs or delays to our operations.

Hydraulic Fracturing

Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in

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2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; and in June 2016 issued final effluent limitations guidelines under the CWA that waste water from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant. The EPA also issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act (“TSCA”) in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing but, to date, has taken no further action. Separately, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, the U.S. District Court of Wyoming struck down this rule in June 2016. The June 2016 decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, following issuance of a presidential executive order to review rules related to the energy industry, in July 2017, the BLM published a proposed rule to rescind the 2015 final rule. In September 2017, the Tenth Circuit issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking. The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears unlikely. At the state level, some states, including Oklahoma and Colorado, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, operational or well construction requirements on hydraulic fracturing activities, or that prohibit hydraulic fracturing altogether. Local government may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions, and associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable, and could cause us to incur substantial compliance costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

In addition to asserting regulatory authority, certain government agencies have conducted reviews focusing on environmental issues associated with hydraulic fracturing practices. For example, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources in December 2016. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water sources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

We diligently review best practices and industry standards, serve on industry association committees and comply with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. There have not been any incidents, citations or suits related to our hydraulic fracturing activities involving environmental concerns.


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


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The price of oil, natural gas and NGLs is not currently regulated and are made at market prices. Although oil, natural gas and NGL prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil, natural gas and NGL prices might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.

Drilling and Production

Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where we operate also regulate one or more of the following activities:
the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities;
the rates of production, or “allowables”;
the use of surface or subsurface waters;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
the notice to surface owners and other third parties.

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

State agencies in Colorado, Kansas, Oklahoma and Texas impose financial assurance requirements on operators. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

Natural Gas Sales and Transportation

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005 (the “EPAct 2005”), FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of up to $1,269,500 per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress

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may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties of up to $1,212,866 per day per violation.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Currently, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the less stringent regulatory approach currently pursued by FERC and Congress might not continue indefinitely into the future. The Company is unable to determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Although its policy is still in flux, in the past FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our cost of transporting gas to point-of-sale locations.
Oil Price Controls and Transportation Rates
Sales prices of oil and NGLs are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (the “FTC”) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of up to $1,231,690 per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.
The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Some of our transportation of oil, natural gas and NGLs is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC’s regulation of crude oil and natural gas liquids transportation rates may tend to increase the cost of transporting crude oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.


As of December 31, 2019, the Company had 270 full-time employees, including 43 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of our 270 employees, 130 were located at the Company’s headquarters in Oklahoma City, Oklahoma at December 31, 2019, and the remaining employees worked in our various field offices and drilling sites.


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Item 1A. Risk Factors

An investment in our common stock involves certain risks. If any of the following key risks were to develop into actual events, it could have a material adverse effect on our financial position, results of operations and cash flows. In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control. Declines in oil, natural gas or NGL prices significantly affect our financial condition and results of operations.
Our revenues, profitability and cash flow are highly dependent upon the prices we realize from the sale of oil, natural gas and NGLs. Historically, the markets for these commodities are very volatile. Prices for oil, natural gas and NGLs can move quickly and fluctuate widely in response to a variety of factors that are beyond our control. These factors include, among others:
changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally;
the price and quantity of foreign imports;
the ability of other companies to complete and commission liquefied natural gas export facilities in the U.S.;
U.S. and worldwide political and economic conditions;
the level of global and U.S. inventories;
weather conditions and seasonal trends;
anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities;
technological advances affecting energy consumption and energy supply;
the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;
natural disasters and other extraordinary events;
domestic and foreign governmental regulations and taxation;
energy conservation and environmental measures; and
the price and availability of alternative fuels.
These factors and the volatility of the energy markets, which we expect will continue, make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For oil, from January 2015 through December 2019, the NYMEX settled price fluctuated between a high of $76.41 per Bbl and a low of $26.21 per Bbl. For natural gas, from January 2015 through December 2019, the month-end NYMEX settled price fluctuated between a high of $4.72 per MMBtu and a low of $1.71 per MMBtu. In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season.

A buildup in inventories, lower sustained global demand, or other unexpected factors could cause prices for U.S. oil, natural gas and NGLs to further weaken, which could negatively affect our cash flows and results of operations. For instance, crude oil prices have experienced downward pressure in the first quarter of 2020 as a result of decreasing demand from the growing impact of the cornonavirus epidemic. Under such conditions, revenues may be negatively affected, and the amount of oil, natural gas and NGLs we can produce economically may be reduced, causing us to make substantial downward adjustments to our estimated proved reserves and having a material adverse effect on our financial condition and results of operations.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. Furthermore, even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. Decisions to develop properties depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies,

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the results of which are often inconclusive or subject to varying interpretations. The estimated cost of drilling, completing and operating wells is uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including the following:
reductions in oil, natural gas and NGL prices;
delays imposed by or resulting from compliance with regulatory requirements including permitting;
unusual or unexpected geological formations and miscalculations;
shortages of or delays in obtaining equipment and qualified personnel;
shortages of or delays in obtaining water and sand for hydraulic fracturing operations;
equipment malfunctions, failures or accidents;
lack of available gathering or midstream facilities or delays in construction of gathering or midstream facilities;
lack of available capacity on interconnecting transmission pipelines;
lack of adequate electrical infrastructure and water disposal capacity;
unexpected operational events and drilling conditions;
pipe or cement failures and casing collapses;
pressures, fires, blowouts and explosions;
lost or damaged drilling and service tools;
loss of drilling fluid circulation;
uncontrollable flows of oil, natural gas, brine, water or drilling fluids;
natural disasters;
environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing;
compliance with environmental and other governmental requirements;
adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes;
oil and natural gas property title problems; and
market and midstream limitations for oil, natural gas and NGLs.
Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.

Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production of oil, natural gas and NGLs.
Market conditions or a lack of satisfactory oil and natural gas transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production of oil, natural gas and NGLs. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and treating facilities for oil, natural gas and NGLs as well as gathering systems, treating facilities and disposal wells for water produced alongside the hydrocarbons. Our failure to obtain such services on acceptable terms in the future or to expand our midstream assets could have a material adverse effect on our business. We may be required to shut in wells for a lack of a market or because access to natural gas pipelines, gathering system capacity, treating facilities or disposal wells may be limited or unavailable. We would be unable to realize revenue from any shut-in wells until production arrangements were made to deliver the production to market.


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Our North Park Basin acreage may require the construction of significant gathering systems and pipelines as we increase drilling and development activity. Failure to obtain these services or expanding our midstream assets with acceptable commercial terms could adversely affect our ability to develop this acreage in a timely manner.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital necessary to drill such locations or construct the midstream infrastructure required to make such development profitable.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering and midstream system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals (including renewal of annual permits that allow for the combustion of produced gas until such time as midstream takeaway infrastructure or other gas disposition options are available) and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. We may not be able to raise the substantial amount of capital necessary to fully realize our North Park Basin assets. For example, our North Park Basin assets are in the delineation phase of the development cycle and may require significant investment over the next several years, including the construction of midstream and pipeline takeaway infrastructure, as we progress toward full field development with more activity and an expanded development footprint. Additionally, lack of midstream takeaway infrastructure for produced gas could impact our ability to continue producing currently existing wells for extended periods under current operating conditions if regulatory approval for gas combustion is not renewed.

In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Our acreage not contained within federal units must be drilled before lease expiration, generally within three to five years of the original date of the lease, in order to hold the acreage by production, and our acreage committed to federal units must be drilled pursuant to the federal unit timelines provided within the unit agreements. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on our oil and natural gas properties that are not federal units typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres, or the leases are renewed. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Acreage committed to federal units must be drilled pursuant to the federal unit timelines provided within the unit agreements, typically requiring two unit wells within the first five years and two more wells within the next five years. At the end of the second five-year term the unit begins to reduce in size to designated participating areas within the Federal Units. Unless we increase our current drilling program, we could lose undeveloped acreage through lease expirations. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage.

Our development and exploration operations require substantial capital. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil, natural gas and NGL reserves, which would adversely affect our business, financial condition and results of operations.

The oil and natural gas industry is capital intensive. Our future oil, natural gas and NGL reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current estimated proved reserves and finding or acquiring additional economically recoverable reserves. We make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil, natural gas and NGL reserves. Historically, we have financed capital expenditures primarily with cash generated by operations, borrowings on

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our credit facility and proceeds from asset sales. In particular, cash flow from operations was $121.3 million, $145.5 million and $181.2 million for the years ended December 31, 2019, 2018, and 2017, respectively.

The capital markets that we have historically accessed have recently been and may continue to be constrained to such an extent that debt or equity capital raises are practically unfeasible. If the debt and equity capital markets are not accessible or if our ability to draw on our credit facility is compromised, we may be unable to implement our drilling and development plans or otherwise carry out our business strategy as expected. Our cash flow from operations and access to capital are subject to a number of variables, including:
the prices at which oil, natural gas and NGLs are sold;
our proved reserves;
the level of oil, natural gas and NGLs we are able to produce from existing wells;
our ability to acquire, locate and produce new reserves; and
our capital and operating costs.

Declining cash flows from operations, as a result of lower commodity prices, could require us to reduce expenditures to develop and acquire additional reserves, which could lead to rapid declines in the reserve base supporting our credit facility. Based on our 2020 capital spending plans, we estimate that our production will experience a 25%- 30% decline. This decline in production as well as other factors such as lower oil, natural gas and NGL prices, declines in reserves, or for any other reason may lead to reductions in our revenues and cash flow from operations and may limit our ability to obtain the capital necessary, or maintain a sufficient borrowing base on our credit facility, to sustain our operations at desired levels. In order to fund capital expenditures, we may seek alternative sources of financing.

Further, we may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which could adversely affect our business, financial condition and results of operations.

Disruptions in the global financial and capital markets could also adversely affect our ability to obtain debt or equity financing on favorable terms, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of its prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGL reserves.

We may not be able to refinance or replace our maturing debt on favorable terms, or at all, which will materially adversely affect our financial condition and our ability to develop our oil and gas assets.
Our credit facility, which consists of all of our funded debt, matures on April 1, 2021. In November 2019, the borrowing base was reduced to $225.0 million, and as of December 31, 2019, we had $57.5 million outstanding under our credit facility. We have been involved in discussions with our current lenders and other financing sources regarding alternatives that would include the replacement or refinancing of the credit facility, prior to its maturity date on April 1, 2021. There is no assurance, however, that such discussions will result in a refinancing of the credit facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. Alternative sources of capital could involve the issuance of debt or equity on unfavorable terms or that would result in significant dilution. While we review such liquidity-enhancing alternative sources of capital, we intend to continue to minimize our drilling program capital expenditures, which could limit our ability to develop our properties. If we are unable to refinance or replace our debt on favorable terms, we may not be able to maintain adequate liquidity, and may have to limit our drilling program, sell core and non-core assets, and further reduce general and administrative expenses in order to pay down outstanding debt under the credit facility, or a combination of the foregoing. These actions could have a material adverse effect on our financial condition and results of operations and the trading price of our common stock.