UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the transition period from ___________ to _________

Commission File Number 001‑36302

Sundance Energy Inc.

(Exact name of Registrant as specified in its Charter)

Registrant’s telephone number, including area code: (303) 543‑5700

Securities Registered Pursuant to Section 12(b) of the Act:

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). 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 definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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 the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter, was $131,992,965. The number of outstanding shares of the registrant’s common stock as of April 24, 2020 was 6,875,672.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2020 annual meeting of stockholders to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended.

Table of Contents

Glossary of Selected Oil and Natural Gas Terms

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this annual report on Form 10-K (this “annual report”). As used in this document:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d. Barrels of oil equivalent per day.

Completion. A process of treating a drilled well, including hydraulic fracturing among other stimulation processes, followed by the installation of permanent equipment for the production of oil or gas.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Held-by-production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Hydraulic fracturing or fracking. The technique of pumping a mixture of fluids into a well to rupture the rock, creating artificial channels. As part of this technique, sand or other material may also be injected into the formation to keep the channels open, so that fluids or natural gases may more easily flow through the formation.

MBoe. Thousand barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

MMBoe. Million barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Mcf. Thousand cubic feet of natural gas.

MMBtu. Million British Thermal Units.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be. An owner who has 50% interest in 100 acres owns 50 net acres.

NYMEX. New York Mercantile Exchange.

Proved reserves. Those reserves 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 regulation 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.

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be 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. Undrilled locations can be 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. Under no circumstances shall estimates for proved 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.

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

Working interest. A cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

WTI. means the West Texas Intermediate spot price.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this annual report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements are identified by the use of the words “project,” “believe,” “estimate,” “expect,” “anticipate,” “intend,” “contemplate,” “foresee,” “would,” “could,” “plan,” and similar expressions that are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that are anticipated. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

Known material factors that could cause actual results to differ materially from those in our expectations as it relates to our recent redomiciliation to the U.S. include, amongst other factors, changes in U.S. or non-U.S. laws that could reduce or eliminate the benefits expected to be achieved from our redomiciliation, an inability to realize expected benefits from the redomiciliation or the occurrence of difficulties that arise as a result, or in connection with, the redomiciliation. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors” of this annual report.

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described in this annual report as anticipated, believed, estimated or expected. Accordingly, you should not place undue reliance on these forward-looking statements. These statements speak only as of the date of this annual report and will not be revised or updated to reflect events after the date of this annual report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Presentation of Information

On November 26, 2019, Sundance Energy Inc., a newly formed Delaware corporation, acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited, a public company incorporated under the laws of the State of South Australia (“SEAL”), and former parent company of the Sundance group of companies, pursuant to a Scheme of Arrangement under Australian law, which was approved by the Federal Court of Australia on November 14, 2019, and by SEAL shareholders at a meeting of shareholders, which approval was obtained on November 8, 2019 (the “Redomiciliation”). All of the issued and outstanding shares of SEAL were exchanged for newly issued shares of common stock of Sundance Energy Inc., on the basis of one share of common stock for every 100 ordinary shares of SEAL issued and outstanding. Holders of SEAL’s American Depository Shares (“ADSs”) (each of which represented 10 ordinary shares) received one share of common stock for every 10 ADSs held. Thereafter, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL.

The purpose of the Redomiciliation was to reorganize the operations of SEAL into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the Australian Securities Exchange, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s ADSs were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation.

Sundance Energy, Inc., a Colorado corporation (“SEI”), a subsidiary of SEAL prior to the Redomiciliation, has historically been the U.S. operating company for the Sundance group of companies. Following the Redomiciliation, SEI will continue in the role of U.S. operating company as a subsidiary of Sundance Energy Inc.

Unless the context otherwise requires, references to “Sundance,” “we,” “us,” “our,” and the “Company” refer to (i) SEAL and its subsidiaries prior to the Redomiciliation and (ii) Sundance Energy Inc. and its subsidiaries upon completion of the Redomiciliation, as applicable. 

PART I

Item 1. Business.

General

We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations consist primarily of drilling and production from unconventional horizontal wells targeting the Eagle Ford formation in South Texas. 

Strategy

Our strategy is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes.  We plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory.  We continue to realize cost improvement by reducing our operating costs and per well drilling and completion costs.  We intend to manage our liquidity by scaling our 2020 capital program to remain within our operating cash flow. We believe execution of each of these focus areas should increase long-term shareholder value. 

Oil and Natural Gas Properties

Description of Properties

All of our operations and assets are located in the Eagle Ford formation in South Texas. Since entering the Eagle Ford play in 2014, we have built a strong assets base that includes over 41,000 net acres targeting the Eagle Ford, through a combination of property acquisitions and development of proved reserves.  Our 2018 acquisition of approximately 21,900 net acres in the Eagle Ford in McMullen, Live Oak, Atascosa and La Salle counties, Texas has positioned us to compete more effectively in this market by offering economies of scale and positioning us to compete for further acquisition opportunities in this area. As of December 31, 2019, we operated 97% of our net producing wells and our average working interest in our operated wells was approximately 95%. 

Estimated Proved Reserves

The following table presents summary information regarding our estimated net proved oil, natural gas and NGL reserves as of the dates indicated. The estimates of our net proved reserves as of December 31, 2019 and 2018 are based on the reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of December 31, 2019 and 2018, please see the reports to management prepared by Ryder Scott, which have been filed or incorporated by reference, as exhibits to this annual report.  All of reserves were located in the Eagle Ford.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil, natural gas and NGLs that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers may vary and are subject to change with additional data. Furthermore, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, operational changes, regulatory changes, environmental protection, prices and costs, and reservoir performance. Please read Part I, Item IA. “Risk Factors” of this annual report.

Additional information regarding our proved reserves can be found in our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report.

PV‑10

Certain of our oil and natural gas reserve disclosures included in this annual report are presented on a PV‑10 basis. PV‑10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV‑10 may be considered a non-GAAP financial measure as defined by the SEC because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that PV‑10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies.  Investors should be cautioned that neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.

The following table provides a reconciliation of Standardized Measure to PV-10 (in thousands):

Proved Undeveloped Reserves

Annually, management develops a five-year development plan based on our best available data at the time the plan is developed. Our five-year plan incorporates a development plan for converting PUD reserves to proved developed. The development plan includes only PUD reserves that we are reasonably certain will be spud within five years of initial booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns, commodity prices and cost forecasts and recent drilling and well performance.   Our five-year development plan generally does not contemplate a uniform conversion of our PUD reserves to proved developed.  At December 31, 2019, our short-term strategy was to slow the pace of development in 2020 and 2021, which would allow cash flow to accumulate.  The accumulated cash flow would be used to fund an increased pace of development in later years, such that all remaining proved undeveloped locations would be developed within the five-year period.

Management reviews and revises the development plan throughout the year and may modify the development plan after evaluating the factors noted above, as well as realized commodity prices, cost and availability of services and equipment, acquisition and divestiture activity; and our current and projected financial condition and liquidity. If there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, we reclassify those PUD reserve locations to unproved reserve categories. In addition, PUD locations and reserves may be removed from the development plan prior to their five-year expiration as a result of changes in our development plan related to factors discussed above.

The following table summarizes our changes in PUDs during the years ended December 31, 2019:

During the year ended December 31, 2019, we incurred capital expenditures of approximately $69.5 million to convert proved undeveloped reserves to proved developed reserves. The remainder of capital expenditures for our proved properties for the period were related to wells in process, development of reserve locations that were not previously classified as proved, infrastructure and installation of artificial lift on proved developed producing reserves.

As of December 31, 2019, our proved undeveloped reserves were approximately 76,461 MBoe, an increase of 10,417 MBoe over our December 31, 2018 proved undeveloped reserves estimate of approximately 66,044 MBoe.  The change primarily resulted from proved undeveloped locations added in 2019 as result of our technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018 (total extensions of 36,535 MBoe).  As of December 31, 2018, we were still in the process of evaluating many of the undeveloped locations acquired in 2018, and at that time approximately half of the undeveloped locations in our development plan were on acreage acquired in the 2018 Eagle Ford acquisition.  The remainder of the December 31, 2018 proved undeveloped locations were on properties that we owned prior to the 2018 acquisition.  As a result of our additional technical evaluation of the acquired properties during 2019, the focus of our development plan shifted to properties acquired in 2018 with higher projected returns, and we had revisions of 19,881 MBoe primarily associated with approximately 50 proved undeveloped locations on legacy properties that were removed because we expect them to be drilled outside the 5-year window. 

Independent Reserve Engineers

Our reserve estimates are calculated by Ryder Scott as of December 31, 2019 in accordance with SEC guidelines. The reserve estimates are based on, and fairly represent, information and supporting documentation prepared by, or under supervision of Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado (Colorado No. 44720) and Texas (Texas No. 100578) with over 14 years of practical experience in estimation and evaluation of petroleum reserves. Mr. Gardner meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We believe that he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Mr. Gardner consents to the inclusion in this report of the information and context in which it appears.

Internal Controls over Reserves Estimation Process 

The primary inputs into the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. Our technical team consists of an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates.

Our board of directors has also established a Reserves Committee to assist with monitoring (i) the integrity of our oil, natural gas, and NGL reserves, (ii) the independence, qualifications and performance of our independent reservoir engineers, and (iii) our compliance with legal and regulatory requirements. Prior to release of the reserve report prepared by our independent reserve engineers, the draft of the report is reviewed by the Reserves Committee, our internal petroleum engineers and management. 

Our senior reservoir engineer is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates and year-end third-party report of our reserves estimates. He received his Masters of Science and Ph.D. in Petroleum Engineering from the Colorado School of Mines.  He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.  The senior reservoir engineer currently reports directly to our Chief Executive Officer.

Technology Used to Establish Estimates of Proved Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott employed or reviewed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data, well test data, simulation, and statistical methods. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using both volumetric estimates and performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Acreage

We had the following developed, undeveloped and total acres as of December 31, 2019:

Production and Pricing

The following tables set forth information regarding our total production and average daily production for the periods indicated from our operating areas: 

Producing Wells

We had the following producing wells as of December 31, 2019:

Drilling Activity

The following table summarizes our drilling activity for the fiscal years ended December 31, 2019, 2018 and 2017:

We did not drill any exploratory wells during the years ended December 31, 2019, 2018 and 2017.  As of December 31, 2019, we had 2 gross (2.0 net) wells waiting on completion and 3 gross (0.3 net) non-operated wells were being drilled.

Operations

General

We operated 97% of our production for the year ended December 31, 2019.  As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis.

Marketing and Customers

For the year ended December 31, 2019, purchases by two customers each accounted for over 10% of our total sales revenues. Our largest customer, a large midstream company and production purchaser accounted for approximately 60% of our 2019 revenue. We have a long-term contract in place with this customer, under which we are subject to minimum revenue commitments (“MRCs”) for gathering, processing, transportation and marketing services, with $54.3 million remaining through 2022 (described more below in Part I, Item 1. “Business” under “Delivery Commitments”). Our second largest customer, a large physical trading and logistics company, accounted for approximately 21% of our 2019 revenue. Our agreement with this purchaser ended in September 2019, and was replaced by a marketing agreement with another large physical trading company.  

The oil and natural gas that we sell are commodities for which there are a large number of potential buyers. Because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include global economic and political conditions, the level of demand for oil and natural gas, the price and quantity of imports of foreign oil and natural gas, the level of global oil and natural gas exploration and production, global oil and gas inventories, weather conditions and natural disasters, the outbreak of pandemic or contagious disease, governmental regulations, oil and natural gas speculation, actions of the Organization of Petroleum Exporting Companies (“OPEC”), technological advances and the price and availability of alternative fuels. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months.

Delivery Commitments

In conjunction with our 2018 acquisition, we entered into contracts with a large midstream company to provide gathering, processing, transportation and marketing of hydrocarbon production for the acquired properties.  The contracts contain MRCs that requires us to pay minimum annual fees related to gathering, processing, transportation and marketing.  Volumetric fixed fees are expensed as incurred and settled with the midstream company on a monthly basis.  The following table summarizes the remaining MRC (in thousands) by year:

If, at the end of any calendar year during the term of the contract, we fail to satisfy our MRC with the monthly settlements paid during the year, we are required to pay a deficiency payment equal to the shortfall.  If the volumes and associated fees exceed the MRC in any contractual year, the overage can be applied to reduce the future shortfalls, if any.  

The MRC for the years ended December 31, 2019 and 2018 totaled $15.8 million and $11.1 million, respectively, and we realized a shortfall of $2.3 million and $2.8 million, respectively.  Based on our 2019 development plan, we had anticipated an immaterial MRC shortfall, however, midstream constraints reduced our sales volumes, and increased the amount of the 2019 shortfall.  The 2018 commitment was measured on a calendar year basis; however, we did not own and operate the acquired assets until April 23, 2018.  Due to the timing of the acquisition, our development program was back-loaded in 2018, and we were unable to meet the 2018 MRC.   

Current production from the producing wells dedicated under these agreements is not sufficient to meet the MRC for the hydrocarbon gathering and handling agreement.  Based on our current 2020 development plan, we expect we will have a shortfall under the hydrocarbon gathering and handling agreement for the year ending December 31, 2020.  Our ability to meet our commitments in future periods will depend on our pace of development through the term of the contract.  Our development plan is subject to a number of risks, many of which are not within our control.

Competition

The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that have greater resources than we do. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties and obtaining drilling rigs, completion crews and other services.  Our competitors may be able to pay more for productive crude oil and natural gas properties and undeveloped prospects, or bid for and purchase a greater number of properties and prospects than our financial resources permit.

There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by state, local and the U.S. government agencies. However, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to better absorb the burden of existing and changing federal, state or local laws and regulations than we can, which would adversely impact our competitive position.

Seasonality of Business

We do not believe that the pricing of our crude oil and NGL production is subject to any meaningful seasonal effects. Historically, the pricing of natural gas is seasonal, typically with higher pricing in the winter months.

Title to Properties

Title to our properties are subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of our business.

As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Government Regulations

Nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of doing business and consequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Regulation of Production

The State of Texas, the state where we conduct operations and own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or operate wells, governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to Texas conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce.  FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.

Environmental, Health and Safety Matters

Oil, natural gas and NGL exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, including requirements to:

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on our properties are subject.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the Environmental Protection Agency (“EPA”) interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance. Comparable state statutes may include petroleum in the definition of hazardous substance.

Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes under RCRA. RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. No such effort has been successful to date.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.

Air Emissions

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants, including greenhouse gases, from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, report emissions, or utilize specific equipment or technologies to control emissions. CAA rules may require us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment and implementing additional emissions testing and monitoring. These requirements have the potential to delay or increase the cost of the development of oil and natural gas projects. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs or negatively impact our production and operations. For example, in 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion (“ppb”) to 70 ppb. If areas in which we operate are designated as nonattainment or if the EPA were to further reduce ozone standards, bringing areas in which we operate into nonattainment, states that contain any areas designated nonattainment, and any tribes that choose to do so, are required to develop state implementation plans demonstrating how the area will attain the standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. Similar initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels.

Additionally, the EPA has established new air emission control requirements for oil, natural gas and NGLs production, processing and transportation activities, including New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012, if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves.

In 2016, the EPA published updates to new source performance standard requirements that would impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. Many of these requirements were rescinded in a proposed rule published by the EPA in August 2019, which has not yet been finalized. However, the 2016 rule currently remains in effect. Similarly in November 2016, the Bureau of Land Management (“BLM”) issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands, though many of these regulations were later rescinded by a final rule published by the BLM in September 2018. Compliance with these or other future changes to regulations regarding air emission may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Climate Change

The U.S. is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas (“GHG”) concentrations in the atmosphere at a level that would prevent serious damage to the climate system. In December 2015, the international community agreed upon a new climate change treaty, known as the Paris Agreement. The U.S. committed to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline. This new agreement, which was legally effective in November 2016, incorporates actions taken by individual countries to reduce GHG on the national level. U.S. involvement in developing the new agreement creates significant international pressure for the U.S. to take responsive action to reduce GHG emissions. President Trump stated in June 2017 that he intends to withdraw the U.S. from the Paris Agreement and in November 2019, the U.S. submitted formal notification of its withdrawal from the Paris Agreement to the United Nations. Under the terms of the Paris Agreement, the earliest the U.S. could withdraw from the treaty is November 2020. The Trump administration may allow the U.S. to remain in the Paris Agreement, but soften the emission reductions that the U.S. implements to comply with the Paris Agreement. In general, implementation of the Paris Agreement would encourage a shift away from higher GHG emitting power sources like coal-fired power plants.

In the absence of comprehensive climate change legislation, regulatory action to regulate GHG emissions under the federal Clean Air Act occurred under the Obama administration. The Trump administration is in the process of narrowing, revising or attempting to repeal nearly all of the Obama-era climate regulations. Thus, no new federal climate regulations that impose additional requirements are likely in the near term in the U.S. and the focus will be on the state level with certain states like California taking significant actions to reduce GHG emissions.

The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including GHG from petroleum and natural gas systems that emit more than 25,000 tons of GHG per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage.

In 2015, the EPA released the final Clean Power Plan, which is a regulation designed to reduce carbon pollution from existing fossil fuel-fired power plants, including natural gas power plants. Upon finalization of the Clean Power Plan, over twenty states and industry groups challenged the rule in the D.C. Circuit court and requested a stay of the rule. In 2019, the EPA replaced the Clean Power Plan with the more narrowly-scoped Affordable Clean Energy rule. The rule is currently being litigated by public health groups, certain states and environmental groups.

In 2016, the EPA issued a suite of proposed regulations that would reduce methane emissions from the oil and gas industry, including proposed updates to the NSPS for new and modified sources in the oil and gas industry, a clarification of the source determination rule as applied to the oil and natural gas industry and a proposed Federal Implementation Plan for new oil and gas sources in Indian Country. These regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result. In 2019, the EPA proposed to replace existing NSPS methane limits with a narrower rule and to amend the Federal Implementation Plan for oil and gas production activities in Indian Country. The EPA is currently reviewing public comments on the proposed rules.

In 2017, President Trump signed an executive order to rescind President Obama’s climate-related executive orders and climate action plans and to direct the EPA to review and revise the Clean Power Plan, the standards for new power plants and other climate regulations. The executive order sets in motion a process that will take several years to fully implement. Because the EPA climate regulations are final regulations, the EPA will have to go through a notice and comment rulemaking process to modify or revoke them and such actions are expected to be litigated by environmental groups and states supportive of the regulations. Even if the carbon regulations are ultimately revoked or weakened under the Trump administration, we may continue to incur compliance costs and we may incur new costs associated with transitioning to the new requirements.

 The EPA’s GHG rules are being reviewed pursuant to President Trump’s executive order and many are being challenged in court proceedings. Depending on the outcome of such proceedings, the rules may be modified or rescinded or the EPA could develop new rules. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations or could adversely affect demand for the oil and natural gas we produce.

While new legislation requiring GHG controls is not expected at the national level in the near term, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHG, including obligations on utilities to purchase renewable energy and participate in GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

Climate change regulatory and legislative initiatives could have a material adverse effect on our business, results of operations and financial condition. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products could become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, increasing concentrations of GHG 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 effects could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Water Discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. Pursuant to the CWA and analogous state laws, permits must be obtained from the EPA or analogous state agency to discharge pollutants into state waters or waters of the U.S. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Endangered Species Act

The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Employee Health and Safety

We are subject to a number of federal and state laws and regulations regulating employee health and safety, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes. In addition, the OSH Act’s hazard communication standard, the EPA’s “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and the public. OSH Act regulates worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The key provisions of the rule: (i) reduce the permissible exposure limit (PEL) for respirable crystalline silica to 50 micrograms per cubic meter of air, averaged over an 8‑hour shift; (ii) require employers to: use engineering controls (such as water or ventilation) to limit worker exposure to the PEL; provide respirators when engineering controls cannot adequately limit exposure; limit worker access to high exposure areas; develop a written exposure control plan, offer medical exams to highly exposed workers, and train workers on silica risks and how to limit exposures; (iii) provide medical exams to monitor highly exposed workers and gives them information about their lung health; and (iv) provide flexibility to help employers protect workers from silica exposure. Workers at well sites may be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at well sites may lead to increased regulation and enforcement or related tort claims by our employees. Implementation of engineering and workplace controls to comply with the rule may require significant investment.

Hydraulic Fracturing

The Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for oil and gas activities under U.S. environmental laws. The Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”), first introduced in 2011, would amend the SDWA to repeal the exemption from regulation under the UIC program for hydraulic fracturing. This bill has been reintroduced in each congressional session since it was initially proposed but has not yet garnered enough support to be put to a vote. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, to adhere to certain construction specifications, to fulfill monitoring, reporting and recordkeeping obligations and to meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. Note that each of the above components of the FRAC Act have become increasingly common in state laws since the FRAC Act was first introduced. Other bills that have been introduced in recent years in the U.S. House of Representatives would end certain exemptions for oil and natural gas operations related to permitting requirements for multiple commonly owned and adjacent sources of hazardous air pollutants under the CAA and permitting requirements for stormwater discharges under the CWA. If the exemptions for hydraulic fracturing are removed from U.S. environmental laws, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has promulgated pretreatment standards for oil and gas extraction category under the CWA that prohibit the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA also has been conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA collected data and information related to the extent to which such wastewater is accepted, available treatment technologies, discharge characteristics and other information. The EPA is currently reviewing comments on the draft study report. The use of surface impoundments (i.e., pits or surface storage tanks) for the temporary storage of hydraulic fracturing fluids for re-use or prior to disposal may also be regulated. The EPA also completed a multi-year study about the effects of hydraulic fracturing on drinking water. Although the regulations for hydraulic fracturing on federal land that were promulgated by the U.S. Department of the Interior in 2015 were rescinded in 2017, that 2017 rulemaking is the subject of ongoing litigation. These regulatory developments have the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business. However, under the Trump administration, we expect no new significant requirements on hydraulic fracking.

Several state governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. For example, several states have implemented rules requiring hydraulic fracturing operators to sample ground and surface waters near proposed well sites before operations can begin, and to sample the same sites again after fracturing operations are complete. A majority of states around the country, including Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study potential seismic risks related to underground injection of fracturing fluids. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

Insurance Matters

As is common in the oil and gas industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Employees

As of December 31, 2019, we had 79 employees (all employed full-time). None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting and other disciplines as needed.

Available Information

Our website address is www.sundanceenergy.net. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Nominating and Corporate Governance Committee, Compensation Committee and Reserves Committee, and our Code of Ethics and Business Conduct are available through our website, and we also intend to disclose any amendments to our Code of Ethics, or waivers to such code on behalf of our Chief Executive Officer or Chief Financial Officer, on our website. The contents of our website are not intended to be incorporated by reference into this annual report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.  Information is also available on the SEC website at www.sec.gov.

Item 1A. Risk Factors.

We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this annual report.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, results of operations or financial condition and our ability to meet our capital expenditure obligations and financial commitments. 

Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. For example, average daily prices for NYMEX-WTI crude oil ranged from a high of $66.24 per barrel to a low of $46.31 per barrel during 2019.  In March 2020, oil prices dropped sharply to under $20 per barrel, and in April 2020, oil prices dropped further and, for a short period of time, were negative. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 62% and 18% of our estimated proved reserves as of December 31, 2019 were attributed to oil and NGLs, respectively, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under contracts at market-based prices.

Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil, natural gas and NGL sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. We currently have oil derivatives in place covering the expected 2020 production from our proved developed producing reserves as of January 1, 2020.  To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil, natural gas and NGLs that could materially and adversely affect our business and results of operations.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We might also elect during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, we could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, we may abandon any well if we reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

There can be no assurance that we will be able to comply with the terms of our credit facilities.

Our credit facilities require us to maintain compliance with certain financial and other covenants.  Our ability to comply with these covenants is uncertain and will be affected by our results of operations and financial condition, and events or circumstances beyond our control, including sustained low commodity prices. Absent a waiver or amendment, a breach of any of these covenants contained in our credit facilities could result in an event of default under these facilities. 

Specifically, due to the recent sharp decline in commodity prices and expectations for commodity prices in 2020, there is uncertainty as to our ability to remain in compliance with certain of the financial covenants and ratios throughout 2020 and early 2021. If we violate these financial covenants and ratios, or any other covenant in our credit facilities, our indebtedness may become immediately due and payable, the interest rates under our credit facilities may increase and the lenders’ commitment, if any, to make further loans to us may terminate. In the event that some or all of the amounts outstanding under our credit facilities are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts and our lenders could foreclose upon critical assets. Any of these outcomes would have an adverse effect on our business and financial condition.

In addition, our credit facilities contain reporting covenants that requires delivery of audited consolidated financial statements and related reports and certificates on or before certain deadlines provided for in our credit facilities.  Additionally, our financial statements must be delivered without a going concern or like qualification or exception.  Failure to comply with these covenants would constitute a default under our credit facilities.  On May 8, 2020 and May 11, 2020, we entered into waivers with our lenders to waive any potential default arising from the failure to deliver audited consolidated financial statements and related reports and certificates by the applicable deadlines, and with respect to inclusion of the going concern explanatory paragraph included in our audit report for the fiscal year ended December 31, 2019.  These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers, which included delivery of our audited consolidated financial statements for the fiscal year ended December 31, 2019 and related reports and certificates, and payment of the fees and expenses of the administrative agent incurred in connection with such waivers.  In consideration for the waiver under our senior secured revolving credit facility (“Revolving Facility”), we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the second quarter 2020 borrowing base redetermination has been completed.   In addition, in consideration for waiver with respect to our second lien term loan facility (“Term Loan”), we agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under our credit facilities, in which case the amounts outstanding under our credit facilities could be accelerated and become immediately due and payable. If this occurs, we may not have the funds to repay or ability to refinance such outstanding amounts and our lenders could foreclose upon critical assets.  Although we have entered into these waivers, there is no guarantee that our lenders will agree to waive events of default or potential events of default in the future.  Failure to obtain such waivers in the future would have an adverse effect on our business and financial condition.  For more information on the covenants under our credit facilities and the potential impact of the explanatory paragraph in the audit report, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.  

Our future revenues are dependent on our ability to successfully replace our proved producing reserves. 

Our business strategy is to generate profit through the acquisition, exploration, development and production of oil and natural gas reserves. Proved reserves generally decline as they are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.

Development and exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could materially and adversely affect our business, results of operations or financial condition. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

Even if our exploration, development and drilling efforts are successful, our wells, once completed, may not produce reserves of oil, natural gas or NGLs that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results described elsewhere in this annual report.

Development of our PUDs may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced. 

As of December 31, 2019, approximately 76% of our total proved reserves were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves. Based on our December 31, 2019 reserve report, it will require an estimated $1.2 billion of capital to develop approximately 76.5 MMBoe of our estimated proved undeveloped reserves over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves to unproved reserves.

Further, our reserve estimates assume that we can and will make these expenditures and that these operations will be conducted successfully. However, these assumptions may not prove correct. If our plans change and we choose not to spend the capital (or are unable to generate adequate cash flow or obtain the necessary capital under our credit facilities or from other sources) to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove these reserves from future reserve estimates.  Any such removal of our existing reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity. 

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGL reserves. We expect our 2020 capital program to be in the range of $40 - $45 million.  However, we plan to respond flexibly to market conditions to protect our balance sheet and retain liquidity.  

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, regulatory, and technological and competitive developments. We intend to finance our development plan in 2020 primarily with cash flows from operations, but we may also finance our future capital expenditures through a variety of other sources, including available borrowings under our Revolving Facility, through additional asset sales, or through the issuance of debt and/or equity, which may alter or increase our capitalization substantially.

Our cash flows from operations and access to capital are subject to a number of variables, including:

If our revenues or the amounts we can borrow under available credit facilities decrease as a result of lower oil, natural gas or NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, or at all. If cash generated by operations or cash available under our credit facilities is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our locations, which in turn could lead to a decline in our oil, natural gas and NGL reserves and production levels, and could materially and adversely affect our business, results of operations and financial condition.

Any significant reduction in our borrowing base under our Revolving Facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our Revolving Facility generally limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on May 1 and November 1 of each year. Our Revolving Facility has a borrowing base of $210.0 million ($190 million elected commitment), of which $115.0 million was outstanding as of December 31, 2019. Our next borrowing base redetermination is the second quarter of 2020. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of the debt owed under our Revolving Facility to the extent our outstanding borrowings at such time exceeds the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of our Revolving Facility and an acceleration of the loans outstanding under our Revolving Facility and our other credit facilities. Failure to timely pay these debt obligations when due could cause us to lose our assets through mortgage foreclosure, which would materially and adversely affect our business, results of operations and financial condition.

Additionally, in the future we may not have access to adequate funding under our Revolving Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans or make required repayments under the Revolving Facility or our other credit facilities, which would materially and adversely affect our business, results of operations and financial condition.

Effective April 29, 2020, we entered into a waiver with respect to any potential default arising from the reporting covenant under our Revolving Facility that requires delivery of audited consolidated financial statements on or before the deadline provided for in the Revolving Facility, and to deliver such financial statements without a going concern or like qualification or exception for the year ended December 31, 2019.  In consideration for the waiver, we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the second quarter 2020 borrowing base redetermination has been completed.   See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.

The current outbreak of COVID-19 has adversely impacted our business, financial condition and results of operations and is likely to have a continuing adverse impact for a significant period of time.

The COVID-19 pandemic has caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position.  Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil, which is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.

The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow could affect our borrowing capacity and may require us to shut-in production that has become uneconomic. These conditions may also increase the difficulty in repaying, refinancing or restructuring our long-term debt.

The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand.

Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition. 

The reference or regional index prices that we will use to price our oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.

Our level of indebtedness may reduce our financial flexibility. 

We intend to fund our capital expenditures primarily through cash flow from operations and, if necessary borrowings under available credit facilities and alternative debt or equity financings. If we obtain alternative debt or equity financing for these or other purposes, the related risks that we now face could intensify. Our level of debt could materially and adversely affect our business, results of operations and financial condition in several important ways, including the following:

The interest rates under our credit facilities may be impacted by the phase-out of LIBOR.

The London Interbank Offered Rate (“LIBOR”) is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rates on loans globally. We generally use LIBOR as a reference rate to calculate interest rates under our credit facilities. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR ceases to exist or replaced with an alternative reference rate, we may need to renegotiate our credit agreements to replace LIBOR with an agreed upon replacement index, and certain of the interest rates under our credit agreements may change. The new rates may not be as favorable to us as those in effect prior to any LIBOR phase-out. We may also find it desirable to engage in more frequent interest rate hedging transactions.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance. 

The oil and natural gas business involves operating hazards such as:

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims, regulatory investigation, penalties and suspension of operation and other damage to our properties and the property of others.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.

In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We depend upon several significant customers for the sale of most of our oil, natural gas and NGL production.

For the year ended December 31, 2019, purchases by two customers each accounted for over 10% of our total sales revenues. The loss of one or more of these customers or the inability or failure of either of these customers to meet their obligations to us or their insolvency or liquidation could adversely affect our revenues in the short term. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The availability of a ready market for any oil, natural gas or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGL in interstate commerce.

SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame, or if oil and natural gas prices decrease, making the PUDs uneconomic. Lower PV‑10 value, resulting from fewer PUDs, may negatively impact our investor perception.

Our planned drilling involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production. 

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to:

Risks that we face while completing our wells include, but are not limited to:

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise and/or oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. 

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

Although we have identified or budgeted for numerous drilling locations, we may not be able to lease or drill those locations within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a location rather than on analysis of seismic or other data in the location area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties, and our ability to produce oil, natural gas and NGLs may be significantly affected by the availability and prices of equipment and personnel.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing properties. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude 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 system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals 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 oil, natural gas or NGLs from these or any other potential locations. 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. Therefore, our actual drilling activities may materially differ from those presently identified.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis. 

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. We cannot predict the future availability or costs of these items. However, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities, could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

Certain of our undeveloped leasehold acreage is subject to leases expiring over the next several years unless production is established on units containing the acreage. 

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established. For these properties, if production in commercial quantities has not been established on the leased property or units that include the leased property containing these leases, our leases will expire and we will lose our right to develop the related properties. As of December 31, 2019, 2,118 net acres of our total acreage position were not held by production.  For the acreage underlying such properties, if production in paying quantities is not established on units containing these leases, or extensions are not successfully obtained, 1,927 net acres will expire in 2020, and approximately 191 net acres will expire in 2021 and 2022. In addition, approximately 4,500 net acres is currently held by production, but is subject to future drilling obligations. 

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult. 

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

Our producing properties are located primarily in the Eagle Ford, making us vulnerable to risks associated with operating in a limited number of geographic areas. 

All of our producing properties are geographically concentrated in the Eagle Ford area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation (including any proration and production restrictions in light of the COVID-19 pandemic or otherwise), processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs, any of which could materially and adversely affect our business, results of operations and financial condition.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves. 

The reserve data in this annual report represent only estimates. There are uncertainties inherent in estimating oil and natural gas reserves and their estimated value, including many factors beyond our control. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, oil and natural gas prices, revenue, taxes, operating expenses, expenditures and quantities of recoverable oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report, which could materially and adversely affect our business, results of operations and financial condition.

Our derivative activities could result in financial losses or could reduce our income. 

Because oil and natural gas prices are subject to volatility, we regularly enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in oil and natural gas prices.

These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and natural gas or a sudden, unexpected event that materially impacts oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

If the recent decline in oil and natural gas prices is sustained or prices decline further, we may be required to write-down the carrying values of our oil and natural gas properties. 

Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, natural gas and NGL prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors), we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. For example, we incurred impairment of oil and gas properties held for sale of $10.0 million and $43.0 million during 2019 and 2018, respectively.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. 

The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and natural gas reserves. In accordance with SEC regulations, the estimated discounted future net cash flows from proved reserves are based on the average of the historical sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Our inability to market our oil and natural gas could adversely affect our business. 

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on favorable terms could materially and adversely affect our business, results of operations and financial condition.

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we are unable to market and sustain production from a particular lease for an extended period of time, possibly resulting in the loss of a lease due to the lack of commercially established production.

We generally deliver our oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of adverse weather conditions or natural disasters, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.

Our credit facilities have substantial restrictions and financial covenants that restrict our business and financing activities. 

Our credit facilities contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to:

As a result, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.

Increased costs of capital could adversely affect our business. 

Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.

Competition in the oil and natural gas industry is intense and many of our competitors have resources that are greater than ours. 

The oil and natural gas industry is highly competitive. Public integrated and independent oil and natural gas

companies, private equity backed and private operators are all active bidders for desirable oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.

We may not be able to keep pace with technological developments in our industry. 

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

The loss of any of our key personnel could adversely affect our business the results of operations, financial condition and future growth.

We are reliant on a number of key members of our executive management team. Loss of such personnel may have an adverse effect on our performance. We operate in a highly competitive environment and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to sustain current operations or manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow or operate our business profitably.

Our ability to manage growth will have an impact on our business, results of operations and financial condition. 

Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. Our inability to achieve or manage growth may materially and adversely affect our business, results of operations and financial condition.

We may incur losses as a result of title deficiencies. 

We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if insufficient funds are available to meet the commitments.

The existence of title deficiencies with respect to our oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities. 

Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, well testing, plug and abandonment requirements and bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance. Federal and state regulators are increasingly targeting GHG emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to foreign ownership, access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing.

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially harmful working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. In March 2016, the Occupational Safety and Health Administration issued a final rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. Compliance with the rule may require significant investment in engineering and workplace controls. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

We have entered into physical delivery contracts that will require further development in order to deliver all the oil required under such contracts. 

We entered into midstream contracts with a large pipeline company and production purchaser to provide gathering, processing, transport and marketing of production for the Eagle Ford assets acquired in 2018. The contracts contain minimum revenue commitments, a portion of which is secured by letters of credit and performance bonds. If the planned development program is not executed to the extent projected, we may not produce sufficient quantities of hydrocarbons to meet the minimum revenue commitments and may be required to make cash deficiency payments. The deficiency payments would reduce liquidity to invest in growing the business and profitability. If we are unable to make the deficiency payments, the letters of credit and performance bonds may be drawn causing an increase in our level of indebtedness and potentially result in a default under our loan covenants.

Hydraulic fracturing, which is the process used for releasing hydrocarbons from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development. 

Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the U.S. at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the U.S., including states in which we operate, have begun adopting more restrictive regulations, including measures such as:

In addition, the federal government has the authority to regulate hydraulic fracturing on federal and tribal lands. Under the Obama administration, the Bureau of Land Management (“BLM”) issued its final regulations for hydraulic fracturing on federal and tribal lands that require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The regulations are the subject of litigation, which is still pending. At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the U.S. Congress (“Congress”) has considered and may continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. On June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on-shore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA’s regulation of hydraulic fracturing may result in our incurring additional costs to comply with such requirements that may be significant in nature. Such regulation may result in our experiencing delays or curtailment in the pursuit of exploration, development, or production activities, and we could even be prohibited from drilling and/or completing certain wells.

Despite the existing regulatory exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the U.S. Department of the Interior has proposed comprehensive regulations governing the use of hydraulic fracturing on federally managed lands. Under the current administration, many of these regulations are under review and may be repealed or revised.

These efforts by Congress, federal regulators, states and local governments could result in additional costs, delay and operational uncertainty that could limit, preclude or add costs to use of hydraulic fracturing in our drilling operations.

Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs. 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Increasing trends of opposition to oil and gas development activity and negative public perception regarding us and/or our industry could have an adverse effect on our operations.

In recent years, we have seen significant growth in anti-oil and gas development activity both in the U.S. and globally. Companies in our industry can be the target of opposition to hydrocarbon development. This opposition is focused on attempting to limit or stop hydrocarbon development in certain areas. Examples of such opposition include efforts to reduce access to public and private lands, restriction of exploration and production activities within government-owned and other lands, delaying or canceling permits for drilling or pipeline construction, limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal, imposition of set-backs on oil and gas sites, delaying or denying air-quality or siting permits, advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity, and the use of social media channels to cause reputational harm.

Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, results of operations or financial condition.

Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner. 

Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions.

Our inability to timely secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. 

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other

“greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the U.S., including companies in the energy industry, to annually report those emissions. New major sources or significant modifications of existing sources of traditional air pollutants are required to obtain permits and to use best available control technology to control those emissions pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. In addition, sources subject to best available control technology for traditional air pollutants are now also required to use best available control technology to control significant greenhouse gas emissions. While these regulations have not to date materially affected us, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

In May 2016, the EPA issued final regulations intended to reduce methane emissions from the oil and gas sector by 40% to 45% from 2012 levels by 2025. On October 20, 2016, the EPA issued final Control Techniques Guidelines for reducing smog-forming VOC emissions from existing oil and natural gas equipment and processes in certain states and areas with smog problems. The Obama-era methane regulations are currently under review by the Trump administration and a rule proposing to significantly revise and rescind these requirements was published by the EPA in August 2019. The methane regulations could affect us indirectly by affecting our customer base or by directly regulating our operations.

In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. While comprehensive climate legislation will likely not be passed by either house of Congress in the near future, energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Terrorist attacks aimed at energy operations could adversely affect our business. 

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack (in the form of physical attacks or cyber-attacks) on our facilities, customer facilities, and the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

General economic conditions could adversely affect our business and future growth. 

Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, it could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.

Also, market conditions could have an impact on our oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.

Federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business. 

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the OTC derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter or the ability and willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. At this time, the impact of such regulations is not clear.

Our business could be adversely impacted by security threats, including cyber-security threats, and other disruptions. 

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.

Our ability to use our net operating loss carryforwards could be limited.

As of December 31, 2019, we had approximately $292.4 million NOLs that we are allowed to carryforward for U.S. federal income tax purposes. Our NOLs begin to expire in 2033. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Code generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). Generally, a change in more than 50% of the ownership of a corporation’s stock, by value, over a three-year period constitutes an ownership change for U.S. federal income tax purposes. Any unused limitation may be carried forward to future taxable years. We believe that $206.2 million of our NOLs will expire unused as a result of the Section 382 limitation that resulted from a change in ownership occurring in conjunction with to our 2018 equity issuance. In addition, future ownership changes or regulatory changes could further limit our ability to utilize any NOLs. To the extent we are not able to offset our future income with NOLs, this could adversely affect our operating results and cash flows.

Ineffective internal controls could impact our business and financial results.

We are subject to Section 404(a) of the Sarbanes-Oxley Act, which requires that our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Although Section 404(b) of the Sarbanes-Oxley Act requires our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting, we have opted to rely on the exemptions provided in the Jumpstart Our Business Startups Act (the “JOBS Act”), and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

In connection with the preparation of this annual report, management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2019 and concluded that there was a material weakness related to deferred tax assets and the related valuation allowance, specifically related to the conversion of our historical financial statements from International Financial Reporting Standards (“IFRS”) to U.S. GAAP as a result of our Redomiciliation to the U.S.  For additional information regarding the material weakness identified please see “Part II, Item 9A — Controls and Procedures” of this annual report. 

If additional material weaknesses in internal control over financial reporting are discovered or occur in the future, it could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results and investors may lose confidence in our operating results, the price of our shares could decline and we may be subject to litigation or regulatory enforcement actions.

We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

We are an emerging growth company, and we cannot be certain if the reduced reporting requirements applicable to emerging growth companies will make our common stock less attractive to investors. 

We are an emerging growth company, as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We expect to continue to take advantage of some or all of the available exemptions.

Risks Related with the Redomiciliation

The expected benefits of the Redomiciliation may not be realized.

We cannot be assured that the anticipated benefits of the Redomiciliation will be achieved, particularly those subject to factors beyond our control. These factors include such things as the reactions of third parties with whom we do business and the reactions of investors, analysts and Australian and U.S. taxing authorities. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to continue to realize the expected logistical and operational benefits of the Redomiciliation.

We have incurred additional costs as a result of the Redomiciliation and we expect to continue to do so.

The Redomiciliation has resulted in an increase in some of our ongoing expenses and may require us to incur some new expenses, including professional fees, to comply with applicable U.S. corporate and tax laws.

Risks Related to Our Common Stock

The price of our common stock has been and may continue to be highly volatile, which may make it difficult for stockholders to sell our common stock when desired or at attractive prices.

Following our Redomiciliation, the trading price of our common stock has been volatile, and could be subject to fluctuations in response to various factors, some of which are beyond our control. Factors such as announcements of variations in our quarterly financial results and fluctuations in revenue could also cause the market price of our common stock to fluctuate. Additionally, the stock markets have at times experienced price and volume fluctuations that have affected and might in the future affect the market prices of equity securities of many companies. These fluctuations have, in some cases, been unrelated or disproportionate to the operating performance of these companies. Further, the trading prices of publicly traded shares of companies in our industry have been particularly volatile and may be very volatile in the future. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions, interest rate changes, international currency fluctuations or political unrest, may negatively impact the market price of our common stock. If the price of our common stock declines, our ability to raise funds through the issuance of equity or otherwise use our common stock as consideration will be reduced. A low price for our equity may negatively impact our ability to access additional debt capital. These factors may limit our ability to implement our operating and growth plans.

We have never declared or paid dividends on our common stock and we do not anticipate paying dividends in the foreseeable future. 

We have never declared or paid cash dividends on our common stock. For the foreseeable future, we currently intend to retain all available funds and any future earnings to support our operations and to finance the growth and development of our business. Any future determination to declare cash dividends will be made at the discretion of our board of directors, subject to compliance with applicable laws and covenants under current or future credit facilities, which may restrict or limit our ability to pay dividends, and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our board of directors may deem relevant. We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As a result, a return on your investment will only occur if the price of our common stock appreciates.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Information regarding our oil and gas properties is included in Part I, Item 1. “Business” under “Oil and Natural Gas Properties”.  We also lease approximately 19,000 square feet of office space at 1050 17th Street, Suite 700, Denver, Colorado 80265, where our principal offices are located. We also have various operating leases for rental of field office space, office and field equipment, and vehicles. See Note 6 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” for the future minimum rental payments. Such information is incorporated herein by reference.

Item 3. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position, cash flows or results of operations. 

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market

Our common stock is traded on the Nasdaq Global Market under the symbol “SNDE”. As of April 24, 2020, there were 4,169 holders of record of our common stock.

Dividend Policy

We currently intend to retain any earnings to fund the operation and expansion of our business and do not anticipate paying any cash dividends on our common stock for the foreseeable future. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend on common stock in the future, there can be no assurance that we will continue to pay such dividends. In addition, under our debt agreements, we are not permitted to pay cash dividends on our common stock without the prior written consent of our lenders.

Item 6. Selected Financial Data.

Not applicable.

Item  7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Part I, Item 1A. “Risk Factors” along with “Cautionary Statement Regarding Forward-Looking Statements” on page 2 of this annual report for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.

Overview and Executive Summary

We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations are located in the Eagle Ford formation in south Texas.  Our strategy is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes.  In 2019, we continued to focus on developing high-return assets from our portfolio while reducing our operating costs and per well drilling and completion costs. 

We took the following actions during 2019 in support of our corporate strategy:

Business and Industry Outlook

Market prices for crude oil, natural gas and NGLs are inherently volatile. In 2019, WTI oil prices averaged approximately $56.98 per Bbl versus $65.23 per Bbl in 2018. Despite price support in the first half of 2019 driven by supply tightness, geopolitical tensions, 2019 WTI oil prices overall were negatively impacted by trade concerns and economic slowdown fears. In March 2020, NYMEX WTI oil prices declined sharply to less than $20 per Bbl and in April 2020, for a short period of time were negative, primarily due to drastic price cutting and increased production by Saudi Arabia coupled with an expected demand reduction caused by the global COVID-19 outbreak. The U.S. domestic natural gas market remains oversupplied as production has continued to grow due to drilling efficiencies, higher incremental volumes of associated gas from oil wells and de-bottlenecking of transportation infrastructure. Henry Hub gas prices averaged approximately $2.56 per MMBtu in 2019 versus $3.15 per MMBtu in 2018. Natural gas and NGL prices faced strong headwinds in 2019 due to U.S. supply growth far outpacing demand for both commodities domestically and internationally. These factors continue to weigh on natural gas and NGL prices. To mitigate our exposure to commodity price volatility and ensure our financial strength, we continue to execute a hedging program.

We expect capital expenditures to be in the range of $40 - $45 million for 2020. However, we intend to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions to protect our balance sheet and retain liquidity.  We expect to be able to fund our planned capital program for 2020 with cash flow generated from operating activities (which includes proceeds from settlements of hedging contracts) and cash on hand.  As of the date of this annual report, we also had $58.6 million available under our Revolving Facility. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Cash flows used in investing activities” for further discussion of our capital expenditures.

Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Revenues and Sales Volume. The following table provides the components of our revenues for the years ended December 31, 2019 and 2018, as well as each period’s respective sales volumes:

Boe and average net daily production. Sales volumes increased by 1,327,395 Boe (3,636 Boe/d) to 4,835,663 Boe (13,248 Boe/d) for the year ended December 31, 2019 compared to 3,508,268 Boe (9,612 Boe/d) for the prior year primarily due to our 2019 and 2018 drilling programs, which was back-loaded in the second half of 2018, partially offset by normal field production declines and downtime resulting from midstream capacity constraints, well equipment failure and simultaneous operations.  We had initial production from 22 net operated wells in 2019 and 20 net operated wells in the second half of 2018.

Beginning in the fourth quarter of 2018 through May 2019, we experienced capacity constraints at a midstream facility.  We and our midstream partner completed the first phase of a capacity expansion of the gas processing plant through the installation of two additional compressors in May 2019.  In the fourth quarter of 2019, our midstream partner commenced an additional expansion project to ensure capacity for future development.  The second phase of the expansion project was completed in the first quarter of 2020. 

Our sales volume is oil‐weighted, with oil representing 64% of total sales volume for both the years ended December 31, 2019 and 2018, and liquids (oil and NGLs) representing 80% and 78% of total sales volumes for the years ended December 31, 2019 and 2018, respectively.  Our oil sales and liquid sales volumes as a percentage of total sales volumes was lower in 2019 than what we expect it to be prospectively primarily due to the gassier sales volumes produced from our Dimmit County assets, which were divested in October 2019.  

Oil sales. Oil sales increased by $37.6 million (27%) to $177.9 million for the year ended December 31, 2019 from $140.2 million for the prior year. The increase in oil revenue was driven by higher sales volumes ($51.0 million), offset by lower product pricing ($13.4 million).  The average realized price on the sale of our oil decreased by 7% to $57.81 per Bbl for the year ended December 31, 2019 (a $0.83 premium to the average WTI price for the same period) from $62.16 per Bbl for the prior year. We are able to sell oil at a premium to WTI due to our proximity to Gulf Coast refining and export markets.  Oil sales volumes increased 36% to 3,076,582 Bbls for the year ended December 31, 2019 compared to 2,256,043 Bbls for the prior year.

Natural gas sales. Natural gas sales increased by $0.5 million (4%) to $12.6 million for the year ended December 31, 2019 from $12.0 million for the prior year. The increase in natural gas revenues was the result of higher sales volumes ($3.2 million), partially offset by lower product pricing ($2.7 million). Natural gas sales volumes increased 27% to 5,767,779 Mcf for the year ended December 31, 2019 compared to 4,533,604 Mcf for the prior year. The average realized price on the sale of our natural gas decreased by 18% to $2.18 per Mcf (net of certain transportation and marketing costs) for the year ended December 31, 2019 from $2.65 per Mcf for the prior year.

NGL sales. NGL sales increased by $0.5 million (4%) to $13.2 million for the year ended December 31, 2019 from $12.7 million for the prior year. The increase in NGL revenues was the result of higher sales volumes ($7.7 million), offset by lower product pricing ($7.2 million). NGL sales volumes increased 301,160 Bbls (61%) to 797,784 Bbls for the year ended December 31, 2019 compared to 496,624 Bbls for the prior year. The average realized price on the sale of our NGLs decreased by 35% to $16.51 per Bbl for the year ended 31 December 2019 from $25.51 per Bbl for the prior year. 

The following table provides a summary of our operating expenses on a per BOE basis: