Document

1775 Sherman Street, Suite 1200,

(Address of principal executive offices)

(Zip Code)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☑Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2019

☐Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)



Delaware		41-0518430
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

(303) 861-8140

(Registrant’s telephone number, including area code)

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, $.01 par value	SM	New York Stock Exchange

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(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 emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



	Large accelerated filer	☑	Accelerated filer	☐

	Non-accelerated filer	☐	Smaller reporting company	☐

			Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

The aggregate market value of the 111,242,033 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, of $12.52 per share, as reported on the New York Stock Exchange, was $1,392,750,253. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 6, 2020, the registrant had 112,988,364 shares of common stock outstanding.

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 within 120 days after December 31, 2019.



TABLE OF CONTENTS
Item		Page
	Cautionary Information about Forward-Looking Statements	4
	Glossary of Oil and Gas Terms	4
	Part I	7
Items 1. and 2.	Business and Properties	7
	General	7
	Strategy	7
	Significant Developments in 2019	7
	Outlook for 2020	8
	Areas of Operation	8
	Reserves	9
	Production	13
	Productive Wells	13
	Drilling and Completion Activity	14
	Acreage	15
	Delivery Commitments	15
	Major Customers	15
	Employees and Office Space	16
	Title to Properties	16
	Seasonality	16
	Competition	17
	Government Regulations	17
	Available Information	20
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	36
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36
	Part II	37
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Overview of the Company	41
	Financial Results of Operations and Additional Comparative Data	45
	Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017	48
	Overview of Liquidity and Capital Resources	52
	Critical Accounting Policies and Estimates	56
	Accounting Matters	59
	Environmental	59
	Non-GAAP Financial Measures	60



TABLE OF CONTENTS
(Continued)
Item		Page
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 7)	62
Item 8.	Consolidated Financial Statements and Supplementary Data	63
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	107
Item 9A.	Controls and Procedures	107
Item 9B.	Other Information	111
	Part III	111
Item 10.	Directors, Executive Officers, and Corporate Governance	111
Item 11.	Executive Compensation	111
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	112
Item 13.	Certain Relationships and Related Transactions, and Director Independence	113
Item 14.	Principal Accountant Fees and Services	113
	Part IV	114
Item 15.	Exhibits and Consolidated Financial Statement Schedules	114
Item 16.	Form 10-K Summary	117

Cautionary Information about Forward-Looking Statements

This Annual Report on Form 10-K (“Form 10-K”) contains “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”). All statements, other than statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:


•	the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;


•	any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”);


•	our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document) prices, well costs, service costs, lease operating costs, and general and administrative costs;


•	the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;


•	possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;


•	oil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;


•	future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;


•	cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;


•	business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;


•	plans, objectives, expectations and intentions; and


•	other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in Part I, Item 1A, Risk Factors - Risks Related to Our Business below and elsewhere in this report. The forward-looking statements in this report speak as of the filing of this report. Although, we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.

Glossary of Oil and Gas Terms

The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the Securities and Exchange Commission’s (“SEC”) website at www.sec.gov.

Ad valorem tax. A tax based on the value of real estate or personal property.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

BBtu. One billion British thermal units.

Bcf. One billion cubic feet, used in reference to gas.

BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas to one Bbl of oil or NGLs.

Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

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

Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

Dry hole. A well found to be incapable of producing either oil, gas, and/or NGLs in commercial quantities.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Gross acre. An acre in which a working interest is owned.

Gross well. A well in which a working interest is owned.

Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.

Lease operating expenses. The expenses incurred in the lifting of oil, gas, and/or NGLs from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.

MBbl. One thousand barrels of oil, NGLs, water, or other liquid hydrocarbons.

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet, used in reference to gas.

MMBbl. One million barrels of oil, NGLs, water, or other liquid hydrocarbons.

MMBOE. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet, used in reference to gas.

Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.

NGLs. The combination of ethane, propane, isobutane, normal butane, and natural gasoline that when removed from gas become liquid under various levels of higher pressure and lower temperature.

NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for oil.

NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.

OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.

PV-10 (Non-GAAP). PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.

Productive well. A well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products.

Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.

Reserve life index. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil, gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resource play. A term used to describe an accumulation of oil, gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.

Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil, gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.

Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil, gas, and NGL production free of costs of exploration, development, and production operations.

Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized measure of discounted future net cash flows. The discounted future net cash flows related to estimated proved reserves based on prices used in estimating the reserves, year end costs, and statutory tax rates, at a 10 percent annual discount rate. The information for this calculation is included in Supplemental Oil and Gas Information (unaudited) located in Part II, Item 8 of this report.

Track record. Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped reserves.

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, gas, and NGLs regardless of whether such acreage contains estimated net proved reserves.

Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The applicable SEC definition of undeveloped reserves provides that 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.

Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.

PART I

When we use the terms “SM Energy,” the “Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business in the Glossary of Oil and Gas Terms section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or events, all of which may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this report for an explanation of these types of statements and the associated risks and uncertainties.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas. SM Energy was founded in 1908, incorporated in Delaware in 1915, and our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”

Our principal office is located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.

Strategy

At SM Energy, our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision for the Company is to sustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top tier assets. Our current energy project development portfolio is focused on oil and gas producing properties in the state of Texas.

Significant Developments in 2019

Strategic Transformation. During 2019, we completed our strategic transformation, which commenced in 2016 through a series of asset acquisitions and divestitures. For the fourth quarter of 2019, we passed an important milestone by achieving a positive difference between our net cash provided by operating activities and our net cash used in investing activities. Our operational execution in 2019 was outstanding, achieving our objectives in important industry metrics, including key top-quartile benchmarks for environmental, health, and safety performance. We were also successful in proving up additional investment opportunities on our existing acreage positions.

Production. Our average daily production in 2019 consisted of 59.9 MBbl of oil, 300.8 MMcf of gas, and 22.2 MBbl of NGLs, for an average net daily equivalent production rate of 132.3 MBOE, which represented a 10 percent increase compared with 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets as a result of strong well performance, increased drilling and completion efficiencies, improved completion designs, and longer laterals. We completed more lateral feet in 2019 compared with 2018, driving continued increases in volumes at a lower average drilling and completion cost. On a retained asset basis, our production volumes increased 13 percent in 2019. As a result of the above, oil production revenue was approximately 75 percent of total production revenue for the year ended December 31, 2019, compared with 65 percent and 52 percent for the years ended December 31, 2018 and 2017, respectively. Please refer to Areas of Operation below for additional discussion.

Reserves and Capital Investment. Our estimated proved reserves decreased eight percent to 462.0 MMBOE at December 31, 2019, from 503.4 MMBOE at December 31, 2018. Reserve additions from discoveries, extensions, and infills totaled 98.4 MMBOE and were a result of our successful development programs, completion optimizations that resulted in improved well performance, and development plan improvements that we believe will enhance inventory value. The 2019 reserve additions were offset by 2019 production volumes of 48.3 MMBOE and by downward revisions of 94.7 MMBOE, which resulted primarily from the impact of lower commodity prices. Our proved reserve life index decreased to 9.6 years as of December 31, 2019, compared with 11.5 years as of December 31, 2018. Costs incurred for development and exploration activities, excluding acquisitions, decreased 23 percent from the prior year to $1.0 billion in 2019. Please refer to Areas of Operation and Reserves below, and to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Net Cash Provided by Operating Activities. Net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million for the year ended December 31, 2018, which was an increase of 14 percent year-over-year. Oil, gas, and NGL production revenues decreased for the year ended December 31, 2019, compared with 2018, as the impact from higher production volumes was offset by lower commodity prices. However, the impact of lower commodity prices in 2019 was offset by a net derivative cash settlement gain of $39.2 million for the year ended December 31, 2019, compared to a net derivative cash settlement loss of $135.8 million for 2018. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between

2018 and 2017 in Overview of Liquidity and Capital Resources in Part II, Item 7, and to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

Outlook

Our business outlook for the next several years is a continuation of our trajectory of improving operating margins and cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics. Our total capital program in 2020, is budgeted to be between $825.0 million and $850.0 million, and is expected to be approximately 20% lower compared with 2019, in large part due to significant cost reductions and efficiencies that were achieved in 2019. Our 2020 program will be focused on highly economic oil development projects in both our Midland Basin and South Texas assets. We expect total production volumes in 2020 to decrease slightly compared with 2019 as expected continued growth in our oil production volumes will not completely offset expected decreases in gas and NGL production volumes.

Sustainability is a key focus of our plans, in terms of positioning ourselves financially to participate in future energy investment opportunities, and executing our strategy of being a premier operator with high standards for corporate responsibility. We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas.

Please refer to Overview of Liquidity and Capital Resources in Part II, Item 7 of this report for discussion of how we expect to fund our 2020 capital program.

Areas of Operation

Our 2019 operations were concentrated in the Midland Basin and South Texas, as further described below. The following table summarizes estimated proved reserves, production, and costs incurred in oil and gas producing activities (“costs incurred”) for the year ended December 31, 2019, for these areas:



	Midland Basin			South Texas			Total ⁽¹⁾
Proved reserves
Oil (MMBbl)	167.5			16.6			184.1
Gas (Bcf)	398.8			824.4			1,223.2
NGLs (MMBbl)	0.1			73.9			74.0
MMBOE ⁽¹⁾	234.1			227.8			462.0
Relative percentage	51		%	49		%	100		%
Proved developed %	49		%	58		%	53		%
Production
Oil (MMBbl)	20.5			1.3			21.9
Gas (Bcf)	34.4			75.4			109.8
NGLs (MMBbl)	—			8.1			8.1
MMBOE ⁽¹⁾	26.3			22.0			48.3
Avg. daily equivalents (MBOE/d) ⁽¹⁾	72.0			60.3			132.3
Relative percentage	54		%	46		%	100		%
Costs incurred (in millions) ^{(2) (3)}	$	859.6		$	160.9		$	1,040.2

____________________________________________


⁽¹⁾	Amounts may not calculate due to rounding.


⁽²⁾	Regional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activities that are excluded from this regional table. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.


⁽³⁾	Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Excluding acquisition activity, costs incurred decreased in 2019 by 23 percent compared with 2018 primarily due to increased operational efficiencies and decreased drilling, completion crew, and sand costs incurred in developing our Midland Basin assets. Total estimated proved reserves at year end 2019 decreased eight percent from 2018. Production increased 10 percent on an equivalent basis for the year ended December 31, 2019, compared with 2018, and increased 13 percent on a retained assets basis.

Midland Basin. Our Midland Basin assets are located within the Permian Basin in Western Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In 2019, we focused on continuing to delineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.

In 2019, we incurred $859.6 million of costs and averaged six drilling rigs and three completion crews. The majority of our Midland Basin capital was deployed on projects targeting the Lower Spraberry and Wolfcamp A and B intervals on our RockStar assets in Howard and Martin Counties, Texas and Sweetie Peck assets in Upton and Midland Counties, Texas. We completed 123 gross (111 net) wells and full-year production increased 25 percent year-over-year to 26.3 MMBOE for 2019. As of December 31, 2019, there were 51 gross (48 net) wells that had been drilled but not completed in our Midland Basin program. Estimated proved reserves increased nine percent to 234.1 MMBOE at year end 2019, from 214.3 MMBOE at year end 2018. This increase was driven by additions of 58.9 MMBOE from discoveries, extensions and infill, and acquisitions, partially offset by 12.6 MMBOE of downward revisions from price, performance, and aged proved undeveloped reserves.

South Texas. Our South Texas assets are comprised of approximately 158,900 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the Eagle Ford shale formation and delineating the Austin Chalk formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations covers a significant portion of the western Eagle Ford shale and Maverick Basin Austin Chalk (“Eagle Ford shale”) and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

In 2019, we incurred $160.9 million of costs and averaged one drilling rig and one completion crew. We completed 31 gross (20 net) wells during 2019, and full-year regional production increased one percent year-over-year to 22.0 MMBOE for 2019. As of December 31, 2019, there were 21 gross (21 net) wells that had been drilled but not completed in our South Texas program.

Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. The agreement provided that the third party carried substantially all drilling and completion costs and receives a majority of the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove up the value of our Eagle Ford North area, while also allowing us to test cutting edge technology, capture additional technical data, satisfy certain lease obligations, and potentially expand economic drilling inventory in the future. All wells subject to this agreement were drilled and completed as of December 31, 2019.

During 2019, we added 43.0 MMBOE of estimated proved reserves, offset by downward revisions of 82.1 MMBOE, of which 68.5 MMBOE resulted from decreased commodity pricing and 10.3 MMBOE resulted from performance revisions. As a result, estimated proved reserves decreased 21 percent to 227.8 MMBOE at year end 2019, from 289.1 MMBOE at year end 2018.

Reserves

Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The following table presents the standardized measure of discounted future net cash flows and pre-tax PV-10 (“PV-10”). PV-10 is a non-GAAP financial measure, and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held without regard to the specific tax characteristics of such entities. Please refer to the Glossary of Oil and Gas Terms section of this report for additional information regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Business below.

Our ability to replace production with new oil and gas reserves is critical to the future success of our business. Please refer to the reserve life index term in the Glossary of Oil and Gas Terms section of this report for information describing how this metric is calculated.

The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of proved reserves estimates, and reserve life index as of December 31, 2019, 2018, and 2017:



	As of December 31,
	2019			2018			2017
Reserve data:
Proved developed
Oil (MMBbl)	85.0			68.2			58.6
Gas (Bcf)	712.1			699.1			642.9
NGLs (MMBbl)	43.4			60.1			49.0
MMBOE ⁽¹⁾	247.0			244.8			214.7
Proved undeveloped
Oil (MMBbl)	99.1			107.6			99.6
Gas (Bcf)	511.1			622.7			637.2
NGLs (MMBbl)	30.6			47.2			47.6
MMBOE ⁽¹⁾	214.9			258.6			253.4
Total proved ⁽¹⁾
Oil (MMBbl)	184.1			175.7			158.2
Gas (Bcf) ⁽²⁾	1,223.2			1,321.8			1,280.1
NGLs (MMBbl)	74.0			107.4			96.5
MMBOE	462.0			503.4			468.1
Proved developed reserves %	53		%	49		%	46		%
Proved undeveloped reserves %	47		%	51		%	54		%

Reserve data (in millions):
Standardized measure of discounted future net cash flows (GAAP)	$	4,104.0		$	4,654.4		$	3,024.1
PV-10 (non-GAAP):
Proved developed PV-10	$	2,830.4		$	3,084.2		$	1,984.2
Proved undeveloped PV-10	1,532.4			2,020.1			1,072.3
Total proved PV-10 (non-GAAP)	$	4,362.8		$	5,104.3		$	3,056.5

12-month trailing average prices ⁽³⁾
Oil (per Bbl)	$	55.69		$	65.56		$	51.34
Gas (per MMBtu)	$	2.58		$	3.10		$	3.00
NGLs (per Bbl)	$	22.68		$	33.45		$	27.69

Reserve life index (years)	9.6			11.5			10.5

____________________________________________


⁽¹⁾	Amounts may not calculate due to rounding.


⁽²⁾	For the years ended December 31, 2019, 2018, and 2017, proved gas reserves contained 44.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily to power compressors).


⁽³⁾	The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.

The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated proved reserves. Please refer to the Glossary of Oil and Gas Terms section of this report for the definitions of standardized measure of discounted future net cash flows and PV-10.



	As of December 31,
	2019			2018			2017
	(in millions)
Standardized measure of discounted future net cash flows (GAAP)	$	4,104.0		$	4,654.4		$	3,024.1
Add: 10 percent annual discount, net of income taxes	2,955.3			3,847.1			2,573.2
Add: future undiscounted income taxes	579.8			1,012.2			205.7
Pre-tax undiscounted future net cash flows	7,639.1			9,513.7			5,803.0
Less: 10 percent annual discount without tax effect	(3,276.3		)	(4,409.4		)	(2,746.5		)
PV-10 (non-GAAP)	$	4,362.8		$	5,104.3		$	3,056.5

Proved Undeveloped Reserves

Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2019, we did not have any proved undeveloped reserves that had been on our books in excess of five years, and none of our proved undeveloped reserves were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.

For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking estimated proved undeveloped reserves. Of the 214.9 MMBOE of total proved undeveloped reserves as of December 31, 2019, approximately 60.1 MMBOE of proved undeveloped reserves in the Midland Basin and 68.7 MMBOE of proved undeveloped reserves in our South Texas position were offset by more than one development spacing area from the nearest developed producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.

As of December 31, 2019, estimated proved undeveloped reserves decreased 43.7 MMBOE, or 17 percent compared with December 31, 2018. The following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2019:



	Total (MMBOE)
Total proved undeveloped reserves:
Beginning of year	258.6
Revisions of previous estimates	(47.6	)
Additions from discoveries, extensions, and infill	78.5
Purchases of minerals in place	1.9
Removed for five-year rule	(9.8	)
Conversions to proved developed	(66.7	)
End of year	214.9

Revisions of previous estimates. Revisions of previous estimates includes a downward pricing revision of 42.3 MMBOE from our South Texas program as a result of decreased gas and NGL prices. In addition, we had downward performance revisions of 6.0 MMBOE in our Midland Basin program as we updated certain assumptions based on future well spacing.

Additions from discoveries, extensions, and infill. We added 40.8 MMBOE and 30.4 MMBOE of infill estimated proved undeveloped reserves in our Midland Basin and South Texas assets, respectively, in 2019. We added an additional 3.1 MMBOE and 4.1 MMBOE of estimated proved undeveloped reserves in the Midland Basin and South Texas, respectively, through various extensions and discoveries. The majority of additions in our Midland Basin and South Texas programs resulted from future development projects identified by our on-going development and portfolio optimization activities.

Removed for five-year rule. As a result of our testing and delineation efforts in 2019, we revised certain aspects of our future development plans to focus on maximizing returns and the value of our assets. As a result, we removed 9.8 MMBOE of estimated proved undeveloped reserves and reclassified these locations to unproved reserve categories. The reclassified locations were generally replaced by locations with higher quality proved undeveloped reserves, which are reflected as additions from discoveries, extensions, and infill.

Conversions to proved developed. Our 2019 conversion rate was 26 percent. During 2019, we incurred $686.3 million on projects with reserves booked as proved undeveloped at the end of 2018, of which $611.1 million was spent on converting proved undeveloped reserves to proved developed reserves by December 31, 2019. At December 31, 2019, drilled but not completed wells represented 26.8 MMBOE of total estimated proved undeveloped reserves. We expect to incur $182.0 million of capital expenditures in completing these drilled but not completed wells, and we expect all estimated proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.

As of December 31, 2019, estimated future development costs relating to our proved undeveloped reserves were $591.5 million, $615.6 million, and $458.1 million in 2020, 2021, and 2022, respectively.

Internal Controls Over Proved Reserves Estimates

Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our corporate reserves group and is coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Our Corporate Engineering Manager has approximately 12 years of experience in the energy industry and has been employed by the Company for 10 years. He holds a Bachelor of Science Degree in Petroleum Engineering from Montana Tech of the University of Montana and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming and Montana. He is also a member of the Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our regional staff. Data, obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff do not report directly to our Corporate Engineering Manager; they report to either their respective regional technical managers or directly to the regional manager. This design is intended to promote objective and independent analysis within our regions in the proved reserves estimation process.

Third-party Reserves Audit

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 70 years. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for each respective region. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. The 2019 Ryder Scott report concerning our reserves is included as Exhibit 99.1.

In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee of our Board of Directors. Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President and Chief Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, apart from our management, from time to time to discuss processes and findings.

Production

The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest during the periods presented. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related production expense on a per BOE basis.



	For the Years Ended December 31,
	2019		2018		2017
Net production volumes
Oil (MMBbl)	21.9		18.8		13.7
Gas (Bcf)	109.8		103.2		123.0
NGLs (MMBbl)	8.1		7.9		10.3
Equivalent (MMBOE) ⁽¹⁾	48.3		43.9		44.5
Midland Basin net production volumes ⁽²⁾
Oil (MMBbl)	20.5		16.6		8.5
Gas (Bcf)	34.4		25.8		14.7
NGLs (MMBbl)	—		—		—
Equivalent (MMBOE) ⁽¹⁾	26.3		20.9		11.0
Eagle Ford shale net production volumes ⁽²⁾⁽³⁾
Oil (MMBbl)	1.3		1.2		1.9
Gas (Bcf)	75.4		76.1		104.0
NGLs (MMBbl)	8.1		7.9		10.1
Equivalent (MMBOE) ⁽¹⁾	21.9		21.8		29.3
Realized price, before the effect of derivative settlements
Oil (per Bbl)	$	54.10	$	56.80	$	47.88
Gas (per Mcf)	$	2.39	$	3.43	$	3.00
NGLs (per Bbl)	$	17.26	$	27.22	$	22.35
Per BOE	$	32.84	$	37.27	$	28.20
Production expense per BOE
Lease operating expense	$	4.67	$	4.74	$	4.43
Transportation costs	$	3.88	$	4.36	$	5.48
Production taxes	$	1.35	$	1.52	$	1.18
Ad valorem tax expense	$	0.48	$	0.48	$	0.34

____________________________________________


⁽¹⁾	Amounts may not calculate due to rounding.


⁽²⁾	For each of the years ended December 31, 2019, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle Ford shale assets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis.


⁽³⁾	During the first quarter of 2017, we completed the divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE of net production on an equivalent basis for the year ended December 31, 2017.

Productive Wells

As of December 31, 2019, we had working interests in 807 gross (758 net) productive oil wells and 519 gross (487 net) productive gas wells. Productive wells are exploratory, development, or extension wells that are producing, or are capable of commercial production of oil, gas, and/or NGLs. Productive wells may be temporarily shut-in. Multiple completions in the same wellbore are counted as one well. As of December 31, 2019, two of these wells had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but such designation may not be indicative of current or future production composition.

Drilling and Completion Activity

All of our drilling and completion activities are conducted by independent contractors. We do not own any drilling or completion equipment. The following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2019, 2018, and 2017, excluding non-consented projects, active injector wells, salt water disposal wells, or wells in which we own only a royalty interest:



	For the Years Ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Development wells
Oil	119	107	103	92	56	46
Gas	27	16	39	24	38	35
Non-productive	1	1	—	—	4	3
	147	124	142	116	98	84
Exploratory wells
Oil	4	4	18	14	32	29
Gas	4	4	1	1	—	—
Non-productive	1	1	—	—	1	—
	9	9	19	15	33	29
Total	156	133	161	131	131	113

A productive well is an exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well.

As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.

In addition to the wells drilled and completed in 2019 (included in the table above), we were actively participating in the drilling of 22 gross (20 net) wells and had 66 gross (63 net) drilled but not completed wells as of January 31, 2020. These drilled but not completed wells represent wells that were being completed or were waiting on completion as of January 31, 2020.

Acreage

The following table sets forth the number of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2019. Undeveloped acreage includes leasehold interests containing proved undeveloped reserves.



	Developed Acres ⁽¹⁾		Undeveloped Acres ⁽²⁾⁽³⁾		Total
	Gross	Net	Gross	Net	Gross	Net
Midland Basin:
RockStar	67,113	59,589	4,966	4,217	72,079	63,806
Sweetie Peck	17,007	15,782	2,835	251	19,842	16,033
Midland Basin Total ⁽⁴⁾	84,120	75,371	7,801	4,468	91,921	79,839
Eagle Ford shale	74,247	71,296	88,058	87,631	162,305	158,927
Other⁽⁵⁾	16,259	11,363	90,415	25,599	106,674	36,962
Total	174,626	158,030	186,274	117,698	360,900	275,728

____________________________________________


⁽¹⁾	Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above.


⁽²⁾	Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

⁽³⁾

As of February 6, 2020, approximately 1,354, 184, and 155 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021, and 2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale acreage is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met.


⁽⁴⁾	As of December 31, 2019, total Midland Basin acreage excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to pursue.


⁽⁵⁾	Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.

Delivery Commitments

As of December 31, 2019, we had gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum quantity of 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced water through 2027. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We expect to fulfill our delivery commitments from a combination of production from our existing productive wells, future development of our proved undeveloped reserves, and future development of resources not yet characterized as proved reserves. Under certain of our commitments, if we are unable to deliver the minimum quantity from our production, we may deliver production acquired from third-parties to satisfy our minimum volume commitments.

As of December 31, 2019, in the event that no additional volumes are delivered in accordance with these agreements, the aggregate undiscounted future deficiency payments would total $218.5 million. This amount does not include deficiency payment estimates associated with approximately 16.5 MMBbl of future oil delivery commitments where we cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement.

As of the filing of this report, we do not expect to incur any material shortfalls with regard to these commitments.

Major Customers

We do not believe the loss of any single purchaser of our production would materially impact our operating results, as oil, gas, and NGLs are products with well-established markets and other viable purchaser options are available in our operating regions.

The following major customers and entities under common control accounted for 10 percent or more of our total oil, gas, and NGL production revenue for at least one of the periods presented:



	For the Years Ended December 31,
	2019		2018		2017
Major customer #1⁽¹⁾	18	%	18	%	6	%
Major customer #2⁽¹⁾	14	%	5	%	1	%
Major customer #3 ⁽¹⁾	13	%	7	%	—	%
Major customer #4 ⁽¹⁾	9	%	10	%	10	%
Group #1 of entities under common control⁽²⁾	13	%	18	%	17	%
Group #2 of entities under common control ⁽²⁾	11	%	12	%	8	%

____________________________________________


⁽¹⁾	These major customers are purchasers of a portion of our production from our Midland Basin assets.


⁽²⁾	In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of our total oil, gas, and NGL production revenue.

Employees and Office Space

As of February 6, 2020, we had 530 full-time employees. This is a 13 percent decrease from the 611 full-time employees that we reported as of February 7, 2019. None of our employees are subject to a collective bargaining agreement.

The following table summarizes the approximate square footage of office space leased by us, as of December 31, 2019, including our corporate headquarters and regional offices:



		Approximate Square Footage Leased
Corporate		107,000
Midland Basin		59,000
South Texas		62,000
Total		228,000

In addition to the leased office space summarized in the table above, as of December 31, 2019, we owned approximately 12,000 square feet of office space in South Texas.

Title to Properties

Substantially all of our oil and gas producing assets are held pursuant to oil and gas leases from third-party mineral owners. We obtain title opinions prior to commencing initial drilling operations on the properties we operate. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe we have satisfactory title to such properties. Most of our producing properties are subject to mortgages securing indebtedness under our Credit Agreement, royalty and overriding royalty interests, liens for current taxes, and other ordinary course burdens that we believe do not materially interfere with the development of such properties. We typically perform title investigation in accordance with standards generally accepted in the oil and gas industry before acquiring developed and undeveloped leasehold acreage.

Seasonality

The price of crude oil is primarily driven by global socioeconomic factors and is less affected by seasonal fluctuations; however, demand for energy is generally higher in the winter and the summer driving season. The demand and price for gas frequently increases during winter months and decreases during summer months. To lessen the impact of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.

Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions, government regulations, and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. Please refer to Risk Factors - Risks Related to Our Business below for additional discussion.

Competition

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and gas properties. We believe our acreage positions provide a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical teams and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and gas reserves, but also have gathering, processing or refining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity.

We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells, as well as for the gathering, transporting, and processing of oil, gas, NGLs and water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may be affected by future energy, climate-related, financial, or other policies, legislation, and regulations.

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from competition for quality people, and we must compete effectively in order to be successful.

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.

Energy Regulations

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

General. Our operations are subject to stringent and complex federal, state, and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things:


•	require the acquisition of various permits before drilling commences;


•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;


•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and


•	require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.

These laws, rules, and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may result in more stringent, or different permitting, waste handling, disposal, and cleanup requirements for the oil and gas industry and could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules, and regulations to which our business is subject.

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release or threatened release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to 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. In addition, it is not uncommon for third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third-parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.

Water discharges. The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. The Clean Water Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers, or a state if the state has assumed authority to issue such permits. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.

Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing a comprehensive suite of regulations to restrict emissions of GHGs under existing provisions of the CAA. The Trump administration has taken steps to rescind or review many of these regulations. Legislative and regulatory initiatives related to climate

change could have an adverse effect on our operations and the demand for oil and gas. Please refer to Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs. In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products.

Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.

National Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment to determine the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. The Trump administration has taken steps to modify NEPA’s implementing regulations intended to streamline the NEPA process. No new regulations have yet been finalized. Judicial and regulatory challenges are expected, and we cannot predict the outcome of any such challenges. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and gas projects.

OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe we are in substantial compliance with the applicable requirements of OSHA and comparable laws.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells, an increase in compliance costs, and delays, all of which could adversely affect our financial position, results of operations and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local levels, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.

We believe it is reasonably likely that the trend in local and state environmental legislation and regulation will continue toward stricter standards, while the trend in federal environmental legislation and regulation faces an uncertain future under the Trump administration. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future.

Environmental, Health and Safety Initiatives. We are committed to exceptional safety, health, and environmental stewardship; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas. We set annual goals for our environmental, health and safety program focused on reducing the number of safety related incidents and the number and impact of spills of produced fluids. In addition, we set annual goals for GHG emissions intensity and methane emissions as a percentage of total methane produced. We also periodically conduct audits of our operations to ensure regulatory compliance and we strive to provide appropriate training for our employees. Reducing air emissions as a result of leaks, venting, or

flaring of gas during operations has become a major focus area for regulatory efforts and for our compliance efforts. While flaring is sometimes necessary, reducing these volumes is a priority for us. To avoid flaring when possible, we restrict testing periods and connect our production to gas pipeline infrastructure as quickly as possible after well completions. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.

Available Information

Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC, and can be located at www.sec.gov. We also make available through our website our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document.

ITEM 1A. RISK FACTORS

In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us.

Risks Related to Our Business

Oil, gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.

Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and gas properties depend heavily on the prices we receive for oil, gas, and NGL sales. Oil, gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the volume and value of our oil, gas, and NGL reserves. For example, the amount of our borrowing base under our Credit Agreement is subject to periodic redetermination based on oil, gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have oil and gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. Please refer to Significant Developments in 2019 and Reserves in Part I, Items 1 and 2 Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 in Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies, Note 11 – Fair Value Measurements, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 for specific discussion.

Historically, the markets for oil, gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, gas, and NGL prices may result from relatively minor changes in the supply of and demand for oil, gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:


•	global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;


•	the level of consumer demand for oil, gas, and NGLs;


•	overall global and domestic economic conditions;


•	weather conditions;


•	the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;


•	liquefied natural gas deliveries to and from the United States;


•	the price and availability of alternative fuels;


•	technological advances and regulations affecting energy consumption and conservation;


•	the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and production controls;


•	political instability or armed conflict in oil or gas producing regions;


•	actual or perceived epidemic risks, such as the Coronavirus outbreak in early 2020;


•	strengthening and weakening of the United States dollar relative to other currencies;


•	stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and


•	governmental regulations and taxes.

Declines in oil, gas, and NGL prices would reduce our revenues and could also reduce the amount of oil, gas, and NGLs that we can produce economically, which could have a materially adverse effect on us.

Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

In the last decade, the United States and global economies and financial systems have experienced turmoil and upheaval characterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, and an unprecedented level of intervention by the United States federal government and other governments. Weakness or uncertainty in the United States economy or other large economies could materially adversely affect our business and financial condition. For example:


•	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;


•	the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;


•	our ability or the ability of our suppliers or contractors to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;


•	our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and


•	variable interest rate spread levels, including for LIBOR (or any applicable replacement rate) and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.

If we are unable to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find, develop, and acquire oil, gas, and NGL reserves that are economically producible. Our properties produce oil, gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate, develop and acquire new oil, gas, and NGL reserves to replace those being depleted by production. Competition for oil and gas properties is intense, and many of our competitors have financial, technical, human, and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us.

For our prior acquisitions, as well as any future acquisitions we may complete, a successful outcome for our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price and transaction costs for the acquisition, future oil, gas, and NGL prices, the ability to reasonably estimate the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation, and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. Our customary review in connection with acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential problems and deficiencies with such properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. We often acquire interests in properties on an “as-is” basis with limited remedies for breaches of representations and warranties.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of unique risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Substantial capital is required to develop and replace our reserves.

We must make substantial capital expenditures to find, acquire, develop, and produce oil, gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for oil, gas, and NGL sales, our success in locating, developing and acquiring new reserves, and the orderly functioning of

credit and capital markets. If our cash flows from operations are less than expected, we may reduce our planned capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be acceptable to us. Any downgrades to our credit ratings may make it more difficult or expensive for us to borrow additional funds.

If our revenues decrease in the future due to lower oil, gas, or NGL prices, decreased production, or other reasons, and if we cannot access sufficient liquidity under our Credit Agreement, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.

Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.

The marketability of our oil, gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, and other transportation systems, which are generally owned or operated by third-parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay, or discontinuance of development plans for our properties, or lower price realizations. Although we have some influence over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil, gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, transport, or market oil, gas, and NGLs.

In particular, if production from the Midland Basin continues to grow, the amount of oil, gas, and NGLs being produced by us and others could exceed the capacity of, and result in constraints on, available gathering and transportation systems, pipelines, processing facilities, and other infrastructure. In such circumstances, it will be necessary for pipelines, gathering and transportation systems, processing facilities, and additional infrastructure to be expanded, built, or developed to accommodate anticipated production. Certain processing, pipeline, and other gathering, transportation, and infrastructure projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints, including regulatory constraints. Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows. In addition, the operations of the third-parties on whom we rely for gathering, processing, and transportation services are subject to complex and stringent laws and regulations, which require obtaining and maintaining numerous permits, approvals, and certifications from various federal, state, and local government authorities. These third-parties may incur substantial costs in order to comply with existing and future laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the availability and costs of such services. Similarly, a failure to comply with such laws and regulations by the third-parties on whom we rely could have a material adverse effect on our business, financial condition, and results of operations.

A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.

Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and materially adversely affect our business and financial condition.

Our debt rating levels could have materially adverse consequences on our business and future prospects and could:


•	limit our ability to access debt markets, including for the purpose of refinancing our existing debt;


•	cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any dividend distributions or repurchase shares;


•	negatively impact current and prospective customers’ willingness to transact business with us;


•	impose additional insurance, guarantee and collateral requirements;


•	limit our access to bank and third-party guarantees, surety bonds and letters of credit; and


•	cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.

We cannot provide assurance that any of our current Debt Ratings will remain in effect for any given period of time or that a Debt Rating will not be further lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.

Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.

We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, and institutional and individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate oil and gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. We may not be successful in acquiring and developing profitable properties in the face of this competition. In addition, other companies may have a greater ability to continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities, financial condition, and results of operations.

The loss of key personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of their services could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals can be intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated.

This report and certain of our other SEC filings contain estimates of our proved oil, gas, and NGL reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil, gas, and NGL prices, drilling and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations, and availability of funds. The process of estimating oil, gas, and NGL reserves is complex and involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates depend on many variables, and changes often occur as our knowledge of these variables evolves. Therefore, these estimates are inherently imprecise. In addition, our reserve estimates for properties that do not have a significant production history may be less reliable than estimates for properties with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing and/or amount of development expenditures.

Actual future production; prices for oil, gas, and NGLs; revenues; production taxes; development expenditures; operating expenses; and quantities of producible oil, gas, and NGL reserves will most likely vary from those estimated. Any significant variance of any nature could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than what we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of operations, results of exploration and development activity, prevailing oil, gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control.

As of December 31, 2019, 47 percent, or 214.9 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our proved undeveloped reserves, as of December 31, 2019, we estimate approximately $2.0 billion of capital expenditures would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated.

You should not assume that the standardized measure of discounted future net cash flows or PV-10 included in this report represent the current market value of our estimated proved oil, gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, the present value of our proved reserves as of December 31, 2019, was estimated using 12-month average sales prices of $55.69 per Bbl of oil (NYMEX WTI spot price), $2.58 per MMBtu of gas (NYMEX Henry Hub spot price), and $22.68 per Bbl of NGL (OPIS spot price). We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves. During 2019, our monthly average realized oil prices before the

effect of derivative settlements were as high as $61.66 per Bbl and as low as $42.28 per Bbl for oil, were as high as $3.33 per Mcf and as low as $2.05 per Mcf for gas, and were as high as $20.06 per Bbl and as low as $13.84 per Bbl for NGLs. Many other factors will affect actual future net cash flows, including:


•	amount and timing of actual production;


•	supply and demand for oil, gas, and NGLs;


•	curtailments or increases in consumption by oil purchasers and gas pipelines;


•	changes in government regulations or taxes, including severance and excise taxes; and


•	escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.

The timing of production from oil and gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In addition, the 10 percent discount factor required by the SEC to be used to calculate PV-10 for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and gas industry in general are subject.

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

We regularly sell non-core assets in order to increase capital resources available for core assets and other purposes and to create organizational and operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in other core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third-parties, the availability of purchasers willing to acquire the assets on terms we deem acceptable, or other matters or uncertainties that could impact such dispositions, including whether transactions could be consummated or completed in the form or timing and for the value that we anticipate. We at times may be required to retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liabilities or of the indemnification obligations may be difficult to quantify at the time of the transaction and ultimately could be material.

We have limited control over the activities on properties we do not operate.

Some of our properties are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the operator and other working interest owners in these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations.

We rely on third-party service providers to conduct drilling and completion and other related operations on properties we operate.

Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion and other related operations. The ability of third-party service providers to perform such operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, gas, and NGLs, prevailing economic conditions and financial, business, and other factors. In addition, sustained low commodity prices could cause third-party service providers to consolidate or declare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.

Title to the properties in which we have an interest may be impaired by title defects.

We generally rely on title reports in acquiring oil and gas leasehold interests. We obtain title opinions prior to commencing initial drilling operations on the properties we operate. Undeveloped acreage has greater risk of title defects than developed acreage and title insurance is not generally available for oil and gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title abstract facilities before acquiring a specific mineral interest and/or undertaking drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title. Generally, under the terms of the operating agreements affecting our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A material title defect can reduce the value of a property or render it worthless, thus adversely affecting our financial condition, results of operations, and operating cash flow if such property is of sufficient value.

Exploration and development drilling may not result in commercially producible reserves.

Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or NGLs will be found. The cost of drilling and completing wells is often uncertain, and oil, gas, or NGLs drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors may include, but are not limited to:


•	unexpected adverse drilling or completion conditions;


•	title problems;


•	disputes with owners or holders of surface interests on or near areas where we operate;


•	pressure or geologic irregularities in formations;


•	engineering and construction delays;


•	equipment failures or accidents;


•	hurricanes, tornadoes, flooding, or other adverse weather conditions;


•	governmental permitting delays;


•	compliance with environmental and other governmental requirements; and


•	shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

The prevailing prices for oil, gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the available rigs in that region.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore or develop our properties.

The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if oil, gas, or NGLs are present, or whether they can be produced economically. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of oil, gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to repair the well, and/or the loss and abandonment of the well.

Results in newer resource plays may be more uncertain than results in resource plays that are more developed and have longer established production histories. We and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the early development of new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.

In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so for locations booked as proved undeveloped locations, or if we will be able to produce oil, gas, or NGLs from these potential drilling locations.

We may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we will lose our right to develop the related properties. Our total net acreage as of February 6, 2020, that is scheduled to expire over the next three years, represents approximately one percent of our total net undeveloped acreage as of December 31, 2019. Although we have identified numerous potential drilling locations, we may not be able to economically drill for and produce oil, gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow.

Part of our strategy involves drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by us, other operators and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the desired drilling zone while drilling horizontally through the formation, the inability to run our casing the entire length of the well bore, and the inability to run tools and recover equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation.

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

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, result in increased lease operating expenses and adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.

To mitigate a portion of the exposure to potentially adverse market changes in oil, gas, and NGL prices and the associated impact on cash flows, we have entered into various derivative contracts. Our derivative contracts in place include swap and collar arrangements for oil, and swap arrangements for gas and NGLs. We have also entered into basis swap arrangements for a portion of our expected Midland Basin oil production to reduce volatility associated with location differentials between where these volumes are sold and NYMEX WTI. As of December 31, 2019, we were in a net accrued asset position of $21.5 million with respect to our oil, gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:


•	our production is less than expected;


•	one or more counterparties to our commodity derivative contracts default on their contractual obligations; or


•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

In addition, commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract.

The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil, gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other market conditions, including declines in oil, gas, and NGL prices. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating results, as we have numerous options for purchasers in each of our operating areas for our oil, gas, and NGL production. Please refer to Concentration of Credit Risk and Major Customers in Note 1 – Summary of Significant Accounting Policies, in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers. Additionally, the inability of our co-owners to pay joint interest billings could negatively impact our cash flows and financial ability to drill and complete current and future wells.

We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.

As of December 31, 2019, we were contractually committed to deliver 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced water through 2027. We may enter into additional firm transportation agreements as we expand the development of our resource plays. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we expect to develop reserves that will meet or exceed the commitments and therefore do not expect any material shortfalls. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, or if we further limit our capital expenditures due to future commodity price declines or for other reasons, the requirements to pay for quantities not delivered could have a material impact on our results of operations, financial position, and liquidity.

Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed.

The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net cash flows, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Write downs for unproved properties are also evaluated for carrying costs in excess of fair value. This evaluation considers the potential for abandonment due to lease expirations, losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. For the years ended December 31, 2019, 2018, and 2017, we incurred impairment of oil and gas properties expense totaling $33.8 million, $49.9 million, and $16.1 million, respectively. If the prices of oil, gas, or NGLs decline, or we have unsuccessful exploration efforts, it could cause additional proved and/or unproved property impairments in the future.

We review the carrying values of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and gas properties held for use cannot be reversed at a later date, even if oil, gas, or NGL prices increase.

Lower oil, gas, or NGL prices could limit our ability to borrow under our Credit Agreement.

Our Credit Agreement has a current commitment amount of $1.2 billion, subject to a borrowing base that the lenders redetermine semi-annually based on the bank group’s assessment of the value of our proved reserves, which in turn is impacted by oil, gas, and NGL prices. The borrowing base under our Credit Agreement is $1.6 billion, up from $1.5 billion at December 31, 2018. The next semi-annual redetermination date is scheduled for April 1, 2020. Divestitures of additional properties, incurrence of additional debt, or declines in commodity prices could limit our borrowing base and reduce the amount we can borrow under our Credit Agreement.

The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.

As of December 31, 2019, we had the following outstanding long-term debt:


•	$476.8 million of long-term senior unsecured debt relating to our 6.125% Senior Notes due 2022 (“2022 Senior Notes”) that we issued on November 17, 2014;


•	$500.0 million of long-term senior unsecured debt relating to our 5.0% Senior Notes due 2024 (“2024 Senior Notes”) that we issued on May 20, 2013;


•	$500.0 million of long-term senior unsecured debt relating to our 5.625% Senior Notes due 2025 (“2025 Senior Notes”) that we issued on May 21, 2015;


•	$500.0 million of long-term senior unsecured debt relating to our 6.75% Senior Notes due 2026 (“2026 Senior Notes”) that we issued on September 12, 2016;


•	$500.0 million of long-term senior unsecured debt relating to our 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes collectively referred to as the “Senior Notes”) that we issued on August 20, 2018; and,


•	$172.5 million in aggregate principal amount of long-term senior unsecured convertible debt relating to our 1.50% Senior Convertible Notes due July 1, 2021 (“Senior Convertible Notes”) that we issued on August 12, 2016.

Additionally, we had $122.5 million of outstanding borrowings under our Credit Agreement as of December 31, 2019, resulting in $1.1 billion of available borrowing capacity under our secured credit facility. Our long-term debt represented 50 percent of our total book capitalization as of December 31, 2019.

Our indebtedness could have important consequences for our operations, including:


•	making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;


•	requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;


•	limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;


•	placing us at a competitive disadvantage compared to our competitors with less debt; and


•	making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing.

Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes and our Senior Convertible Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition.

As discussed above, our Credit Agreement is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate adjustments to our borrowing base or arrange new financing, we may be forced to sell significant assets.

The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.

Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes and our Senior Convertible Notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our Credit Agreement is subject to compliance with certain financial covenants. Financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. Our Credit Agreement also requires us to comply with certain additional financial covenants, including a requirement that we limit our annual cash dividends to no more than $50.0 million. These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities. We were in compliance with all financial and non-financial covenants as of December 31, 2019, and through the filing of this report. Please refer to Non-GAAP Financial Measures in Part II, Item 7 of this report for our definition of adjusted EBITDAX.

The respective indentures governing the Senior Notes and Senior Convertible Notes also contain covenants that, among other things, limit our ability and the ability of our subsidiaries to:


•	incur additional debt;


•	make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire common stock;


•	sell assets, including common stock of our subsidiaries;


•	restrict dividends or other payments of our subsidiaries;


•	create liens that secure debt;


•	enter into transactions with affiliates; and


•	merge or consolidate with, or transfer or lease all or substantially all of our assets to another company.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.

We are subject to cybersecurity risks. The oil and gas industry is increasingly dependent on digital technology in all aspects of our business. We use digital technology to conduct certain of our drilling development, production and gathering activities, manage drilling rigs and completion equipment, gather and interpret seismic data, conduct reservoir modeling, record financial and operating data, and maintain employee and other databases. Our service providers, including those who gather, process and market our oil, gas and NGLs, are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts us at risk for technology system failures, data or network disruptions, cyberattacks and other breaches in cybersecurity. Power failures, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, flood, human error or other means could significantly impair our ability to conduct our business.

Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. Deliberate attacks on, or security breaches in our systems, infrastructure, the systems and infrastructure of third-parties, or cloud-based applications could lead to disclosure of confidential information, a corruption or loss of our proprietary data, delays in production or exploration activities, difficulty in completing or settling transactions, challenges in maintaining our books and records, environmental damage, communication or other operational disruptions, and liability to third parties. Any insurance we might obtain in the future may not provide adequate protection from these risks. Any such events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. As these cyber risks continue to evolve and our dependence on digital technologies grows, we may be required to expend significant additional resources to continue to modify or enhance our protective measures and remediate cyber vulnerabilities.

Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.

As an oil, gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

The threat of terrorism and the impact of military and other actions have caused instability in world financial markets and could lead to increased volatility in prices for oil, gas, and NGLs, all of which could adversely affect the markets for our production. Energy assets might be specific targets of terrorist attacks. While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms we consider reasonable, or at all. In addition, this insurance may not cover all of our losses for a terrorist attack. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business, financial condition, or results of operations.

Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations and our ability to attract capital.

Certain segments of the public as a whole, and the investment community in particular, have developed negative sentiment towards our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment management firms, sovereign wealth and pension funds, university endowments and other investment advisors, have adopted policies to discontinue or reduce their investments in the oil and gas sector based on social and environmental considerations. Furthermore, other influential stakeholders have pressured commercial and investment banks to reduce or cease financing of oil and gas companies and related infrastructure projects.

Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.

We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.

Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death, property damage, well blowouts, craterings, explosions, uncontrollable flows of oil, gas and NGLs, or well fluids, releases or spills of completion fluids, spills or releases from facilities and equipment used to deliver or store these materials, spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned number of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from the wellbore to allow production to begin, fires, adverse weather such as hurricanes or tornadoes, freezing conditions, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, seismic events, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.

Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, our ability to explore for and produce oil, gas, or NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of the need to shut down, abandon, or relocate drilling operations, the need to modify drill sites to lessen the risk of spills or releases, the need to investigate and/or remediate any spills, releases or ground water contamination that might have occurred, and the need to suspend our operations.

There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling, and disposal of materials, including produced water, solid and hazardous wastes, and petroleum hydrocarbons. We may incur joint and several, and/or strict liability under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for oil and gas exploration and production activities for a number of years, often by third-parties not under our control. For our outside-operated properties, we are dependent on the operator for operational and regulatory compliance and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including CERCLA or the Superfund law, RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under various implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into the environment. As a result, we may incur substantial liabilities to third-parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by environmental damage that occurs gradually over time is appropriate for us at this time given the nature of our operations and the nature and cost of such coverage. Further, we may elect not to obtain insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss.

Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.

Federal, state, and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing, or marketing of oil, gas, and NGL production. Non-compliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of oil, gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in oil and gas properties, rights-of-way and easements, disposal of produced water, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, restoration standards, and oil and gas operations. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate in, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and local environmental laws for emissions and for discharges of oil, gas, and NGLs or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or personal property and other damages and civil and criminal liabilities. The listing of additional wildlife or plant species as federally endangered or threatened could result in limitations on exploration and production activities in certain locations. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us.

The impact of extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Our operations on our Midland Basin and South Texas assets are adversely affected by the impact of extreme weather conditions and lease stipulations designed to protect various wildlife or plant species. In certain areas, drilling and other oil and gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs and completion equipment, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, gas, and NGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and gas properties, including our unconventional resource plays within our Midland Basin and South Texas assets. Hydraulic fracturing involves injecting water, sand, and certain chemicals under pressure to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and gas commissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.

The EPA has authority to regulate underground injections that contain diesel in the fluid system under the Safe Drinking Water Act. The EPA has published an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority. In June 2016, the EPA issued regulations under the Federal Clean Water Act establishing federal pre-treatment standards for wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process. Under a recent settlement, the EPA had until March 2019 to decide whether to initiate rulemaking governing the disposal of wastewater from oil and gas development under RCRA Subtitle D. In April 2019, the EPA released its review, concluding that no new regulations were needed for managing wastewater based on the EPA’s conclusion that existing state regulations and best management practices are sufficiently protective of human health and the environment. If the EPA implements further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

Certain states, including Texas, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict, or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event that state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

In the recent past, several federal governmental agencies were actively involved in studies or reviews that f