Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
þ    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2018
or
o    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
(State or other jurisdiction of incorporation or organization)
41-0518430
(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
80203
(Zip Code)
(303) 861-8140
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common stock, $.01 par value
 
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 þ No o

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 o No þ

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 þ No o

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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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 þ
 
Accelerated filer o
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
 
 
 
 
 
Emerging growth company o

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. o

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

The aggregate market value of the 110,740,087 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 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, of $25.69 per share, as reported on the New York Stock Exchange, was $2,844,912,835. 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 7, 2019, the registrant had 112,243,245 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 2019 annual meeting of stockholders to be filed within 120 days after December 31, 2018.

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TABLE OF CONTENTS
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2

TABLE OF CONTENTS
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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 under Glossary of Oil and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation of these types of statements.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are an independent energy company engaged in the development, production, exploration, and acquisition of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout the document) in onshore North America. We were founded in 1908 and incorporated in Delaware in 1915. 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
Our strategic objective is to be a premier operator of top tier assets. We pursue growth opportunities through both acquisitions and exploration, and we seek to maximize the value of our assets through industry leading technology and outstanding operational execution. We are focused on generating strong full-cycle economic returns on our investments and maintaining a strong balance sheet.
Significant Developments in 2018
Reserves and Capital Investment. Our estimated proved reserves increased eight percent to 503.4 MMBOE at December 31, 2018, from 468.1 MMBOE at December 31, 2017. Reserve additions from discoveries, extensions, and infills were 188.0 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. These positive results for 2018 were partially offset by the divestiture of 40.3 MMBOE of estimated proved reserves, and net downward revisions of 68.8 MMBOE, which resulted primarily from changes in our development plans in our Eagle Ford shale program. On a retained asset basis, estimated proved reserves increased 18 percent year-over-year. Our proved reserve life index increased to 11.5 years as of December 31, 2018, compared with 10.5 years as of December 31, 2017. Costs incurred for development and exploration activities, excluding acquisitions, increased 41 percent from the prior year to $1.3 billion in 2018. Please refer to Areas of Operation and Reserves below, and to the caption Oil and Gas Reserve Quantities in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report for additional discussion.
Production. Our average daily production in 2018 consisted of 51.4 MBbl of oil, 282.7 MMcf of gas, and 21.8 MBbl of NGLs, for an average net daily equivalent production rate of 120.3 MBOE, which represents a one percent decrease compared with 2017. Our Permian region realized a 91 percent increase in production volumes during 2018, compared with 2017, as a result of ramping up development activities and realizing stronger than expected well results. Increased production volumes from our Permian region were offset by the divestiture of our remaining producing assets in the Rocky Mountain region in the first half of 2018 and decreased production volumes from our Eagle Ford shale assets as a result of reduced capital investment in this area. On a retained asset basis, our production volumes increased 11 percent in 2018. Please refer to Areas of Operation below for additional discussion.
Net Cash Provided by Operating Activities. Net cash provided by operating activities was $720.6 million for the year ended December 31, 2018, compared with $515.4 million for the year ended December 31, 2017, which was an increase of 40 percent year-over-year. The increase in net cash provided by operating activities for 2018, compared with 2017, was primarily the result of 37 percent growth in higher margin oil production, which, combined with increased benchmark pricing for oil and NGLs, drove a 32 percent increase in our realized price per BOE before the effects of derivative settlements, and led to a 31 percent increase in oil, gas, and NGL production revenue. Partially offsetting the increase from oil, gas, and NGL production revenue was a cash settlement loss on derivatives of $135.8 million for the year ended December 31, 2018, compared to a cash settlement gain on derivatives of $21.2 million for 2017. Please refer to Analysis of Cash Flow Changes Between 2018 and 2017 and Between 2017 and 2016 in Part II, Item 7 and Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Divestiture Activity. During the first quarter of 2018, we successfully completed the divestiture of our Powder River Basin assets (the “PRB Divestiture”) for total cash consideration, net of costs (referred to throughout this report as “net divestiture proceeds”) of $492.2 million and recorded a final net gain of $410.6 million. During the second quarter of 2018, we completed divestitures of our remaining assets in the Williston Basin located in Divide County, North Dakota (the “Divide County Divestiture”) and our non-operated Halff East assets in the Midland Basin (the “Halff East Divestiture”), for combined net divestiture proceeds of $252.2 million, and a final

4

net gain of $15.4 million. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Long-Term Debt Reduction. During 2018 we completed multiple transactions that resulted in overall long-term debt reduction and extension of the average maturity date for our remaining long-term debt. Total principal outstanding for long-term debt decreased from $3.0 billion at year end 2017, to $2.6 billion at year end 2018, and was accomplished through the redemption of our 6.50% Senior Notes due 2021 (“2021 Senior Notes”) using cash proceeds from divestitures. We also successfully extended the average maturity of our remaining long-term debt obligations by issuing 6.625% Senior Notes due 2027 (“2027 Senior Notes”) and using the net proceeds from this issuance to repurchase our 6.50% Senior Notes due 2023 (“2023 Senior Notes”) and a portion of our 6.125% Senior Notes due 2022 (“2022 Senior Notes”). Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Outlook
We remain focused on maximizing the returns and increasing the value of our top tier capital project inventory in the Midland Basin and Eagle Ford shale.  We expect to do this through exploration, acquisitions, and further development optimization.  These assets will allow for production growth while maximizing internally generated cash flows, which will also support our priorities for improving our credit metrics and maintaining strong financial flexibility.
Our capital program for 2019, excluding acquisitions, is expected to range from $1.00 billion to $1.07 billion. We expect our program to concentrate on developing our top tier assets in the Midland Basin and Eagle Ford shale, with the majority of our 2019 capital being allocated to our Midland Basin program. Planned drilling and completion activity in the Eagle Ford shale will continue to be partially funded by a third-party as part of our joint venture agreement, which was extended into 2019 to include 12 additional wells that we expect to be completed in 2019. Please refer to the caption Outlook in the Overview of the Company section and Overview of Liquidity and Capital Resources, under Part II, Item 7 of this report for additional discussion of our financing and capital plans for 2019.

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Areas of Operation
Our 2018 operations were concentrated in our onshore Permian and South Texas & Gulf Coast regions in the United States. We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. The following table summarizes estimated proved reserves, production, and costs incurred in oil and gas activities for the year ended December 31, 2018, for these regions:

Permian
 
South Texas & Gulf Coast
 
Rocky
Mountain
 
Total (1)
Proved reserves
 
 
 
 
 
 
 
Oil (MMBbl)
159.4

 
16.3

 
—

 
175.7

Gas (Bcf)
328.4

 
993.4

 
—

 
1,321.8

NGLs (MMBbl)
0.2

 
107.2

 
—

 
107.4

MMBOE (1)
214.3

 
289.1

 
—

 
503.4

Relative percentage
43
%
 
57
%
 
—
%
 
100
%
Proved developed %
40
%
 
55
%
 
N/A

 
49
%
Production
 
 
 
 
 
 
 
Oil (MMBbl)
16.6

 
1.3

 
0.9

 
18.8

Gas (Bcf)
25.8

 
76.2

 
1.2

 
103.2

NGLs (MMBbl)
—

 
7.9

 
—

 
7.9

MMBOE (1)
20.9

 
21.8

 
1.1

 
43.9

Avg. daily equivalents (MBOE/d) (1)
57.4

 
59.9

 
3.1

 
120.3

Relative percentage
48
%
 
50
%
 
2
%
 
100
%
Costs incurred (in millions) (2) (3)
$
1,180.9

 
$
185.3

 
$
2.7

 
$
1,389.5

____________________________________________
(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 the caption Costs Incurred in Oil and Gas Producing Activities in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report.
(3) 
Costs incurred for 2018 included $57.0 million relating to acquisitions of primarily unproved oil and gas properties in our Permian region. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information in Part II, Item 8 of this report.
Excluding acquisition activity, costs incurred increased in 2018 by 41 percent compared with the prior year as we continued to accelerate development activities in our Permian region. Total estimated proved reserves at year end 2018 increased eight percent from the prior year and increased 18 percent on a retained asset basis. Production decreased one percent on an equivalent basis for the year ended December 31, 2018, compared with 2017, but increased 11 percent on a retained asset basis.
Permian Region. Operations in our Permian region are managed from our regional office in Midland, Texas. In 2018, we focused on continuing to delineate, develop, and expand our Midland Basin position in western Texas. Our approximately 79,800 net acre position as of December 31, 2018, excludes approximately 1,885 net acres associated with drill-to-earn opportunities we plan to pursue, and is lower than our year end 2017 net acreage position as a result of the Halff East Divestiture, which reduced our Midland Basin position by approximately 5,400 net acres year-over-year. Our current Midland Basin position provides for substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
We incurred approximately $1.2 billion of costs and added approximately 78.3 MMBOE of estimated proved reserves, net of price and performance revisions, through our drilling and completion activities in 2018. 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. Capital was also invested in our water transportation and handling facilities, which began operations in mid-2018 and now serve a significant portion of our disposal needs on our RockStar acreage. During 2018, we operated an average of seven drilling rigs and four completion crews. As of December 31, 2018, we had six drilling rigs and three completion crews running in the Midland Basin, primarily focused on developing our RockStar acreage. Estimated proved reserves increased 34 percent to 214.3 MMBOE at year end 2018, from 159.9 MMBOE at year end 2017. We completed 114 gross (104 net) wells during 2018, and full-year production increased 91 percent year-over-year to 20.9 MMBOE for 2018.
As of December 31, 2018, there were 61 gross (55 net) wells that had been drilled but not completed in our Midland Basin program.

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South Texas & Gulf Coast Region. Operations in our South Texas & Gulf Coast region are managed from our regional office in Houston, Texas. This region is primarily comprised of our Eagle Ford shale position, which includes approximately 163,000 contiguous net acres. Our acreage position in the Eagle Ford shale covers a significant portion of the western Eagle Ford shale play and includes acreage across the gas-condensate and dry gas windows of the play with gas composition amenable to processing for NGL extraction.
In 2018, we incurred $185.3 million of costs and added approximately 40.8 MMBOE of estimated proved reserves, net of revisions, primarily as a result of a net increase in proved undeveloped reserves resulting from changes to our future development plans, and positive price revisions. During 2018, we averaged one drilling rig and one completion crew on our Eagle Ford shale acreage. Estimated proved reserves increased five percent to 289.1 MMBOE at year end 2018, from 275.2 MMBOE at year end 2017. We completed 40 gross (26 net) wells during 2018 on our operated acreage, and full-year regional production decreased 26 percent year-over-year to 21.8 MMBOE for 2018. The decrease in production from our Eagle Ford shale program was primarily driven by the sale of our outside-operated assets in the first quarter of 2017, reduced capital investment on our retained operated acreage, and reduced working and revenue interests associated with certain Eagle Ford shale wells as a result of the joint venture agreement discussed below.
In September 2017, we entered into a joint venture agreement with a third-party to drill 16 wells and complete 23 wells in a focused portion of our Eagle Ford North area (“Phase 1 JV”). In December 2018, we extended this agreement and added an additional 12 wells to be drilled and completed (“Phase 2 JV”). The agreement provides that the third-party carries 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 allows 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 Phase 1 JV wells were drilled and completed as of December 31, 2018. Six of the 12 Phase 2 JV wells were drilled during 2018, and we expect the remaining six wells to be drilled and all 12 wells to be completed during 2019.
As of December 31, 2018, there were 29 gross (23 net) wells that had been drilled but not completed in our South Texas & Gulf Coast region.
Rocky Mountain Region. We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Reserves
The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year period ended December 31, 2018. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit at least 80 percent of our total calculated estimated proved reserve PV-10 for each year presented. 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 Securities and Exchange Commission (“SEC”) rules, and were $65.56 per Bbl for oil, $3.10 per MMBtu for gas, and $33.45 per Bbl for NGLs for the year ended December 31, 2018. We then adjusted these prices to reflect appropriate quality and location differentials over the period in estimating our proved 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. PV-10 shown in the following table 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 PV-10 nor the standardized measure of discounted future net cash flows 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 our production is critical to us. 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.

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The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows, PV-10, and reserve life index as of December 31, 2018, 2017, and 2016:
 
As of December 31,
 
2018
 
2017
 
2016
Reserve data:
 
 
 
 
 
Proved developed
 
 
 
 
 
Oil (MMBbl)
68.2

 
58.6

 
48.5

Gas (Bcf)
699.1

 
642.9

 
609.1

NGLs (MMBbl)
60.1

 
49.0

 
58.6

MMBOE (1)
244.8

 
214.7

 
208.7

Proved undeveloped
 
 
 
 
 
Oil (MMBbl)
107.6

 
99.6

 
56.4

Gas (Bcf)
622.7

 
637.2

 
502.0

NGLs (MMBbl)
47.2

 
47.6

 
47.1

MMBOE (1)
258.6

 
253.4

 
187.1

Total proved (1)
 
 
 
 
 
Oil (MMBbl)
175.7

 
158.2

 
104.9

Gas (Bcf) (2)
1,321.8

 
1,280.1

 
1,111.1

NGLs (MMBbl)
107.4

 
96.5

 
105.7

MMBOE
503.4

 
468.1

 
395.8

Proved developed reserves %
49
%
 
46
%
 
53
%
Proved undeveloped reserves %
51
%
 
54
%
 
47
%
 
 
 
 
 
 
Reserve data (in millions):
 
 
 
 
 
Standardized measure of discounted future net cash flows (GAAP)
$
4,654.4

 
$
3,024.1

 
$
1,152.1

PV-10 (non-GAAP):
 
 
 
 
 
Proved developed PV-10
$
3,084.2

 
$
1,984.2

 
$
1,051.1

Proved undeveloped PV-10
2,020.1

 
1,072.3

 
101.0

Total proved PV-10 (non-GAAP)
$
5,104.3

 
$
3,056.5

 
$
1,152.1

 
 
 
 
 
 
Reserve life index (years)
11.5

 
10.5

 
7.2

____________________________________________
(1) 
Amounts may not calculate due to rounding.
(2) 
For the years ended December 31, 2018, 2017, and 2016, proved gas reserves contained 59.1 Bcf, 48.1 Bcf, and 43.7 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily to power compressors).
The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the pre-tax PV-10 (non-GAAP) of total estimated proved reserves. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 in the Glossary of Oil and Gas Terms section of this report.
 
As of December 31,
 
2018
 
2017
 
2016
 
(in millions)
Standardized measure of discounted future net cash flows (GAAP)
$
4,654.4

 
$
3,024.1

 
$
1,152.1

Add: 10 percent annual discount, net of income taxes
3,847.1

 
2,573.2

 
937.1

Add: future undiscounted income taxes
1,012.2

 
205.7

 
—

Undiscounted future net cash flows
9,513.7

 
5,803.0

 
2,089.2

Less: 10 percent annual discount without tax effect
(4,409.4
)
 
(2,746.5
)
 
(937.1
)
PV-10 (non-GAAP)
$
5,104.3

 
$
3,056.5

 
$
1,152.1




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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, 2018, 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 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 258.6 MMBOE of total proved undeveloped reserves as of December 31, 2018, approximately 81.4 MMBOE of proved undeveloped reserves in our Wolfcamp and Lower Spraberry shale positions in the Midland Basin and 71.4 MMBOE of proved undeveloped reserves in our Eagle Ford shale 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, 2018, estimated proved undeveloped reserves totaled 258.6 MMBOE, which was an increase of 5.2 MMBOE, or two percent, from 253.4 MMBOE at December 31, 2017.  The following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2018:
 
Total
(MMBOE)
Total proved undeveloped reserves:
 
Beginning of year
253.4

Revisions of previous estimates
(54.4
)
Additions from discoveries, extensions, and infill
151.7

Sales of reserves
(22.0
)
Purchases of minerals in place
0.1

Removed for five-year rule
(22.6
)
Conversions to proved developed
(47.6
)
End of year
258.6

Revisions of previous estimates. Revisions of previous estimates includes a downward performance revision of 37.8 MMBOE from our Eagle Ford shale program as a result of optimizing our development plan. Offsetting these downward reserve revisions are proved undeveloped reserves in our Eagle Ford shale program that are engineered with wider spacing and longer lateral completions, which are reflected as additions from discoveries, extensions, and infill. In addition, we had downward performance revisions of 17.2 MMBOE in our Midland Basin program as we updated certain of our previous assumptions based on actual well results observed during the year.
Additions from discoveries, extensions, and infill. We added 67.6 MMBOE and 78.8 MMBOE of infill estimated proved undeveloped reserves in our Midland Basin and Eagle Ford shale programs, respectively, in 2018. We added an additional 5.3 MMBOE of estimated proved undeveloped reserves in the Midland Basin through various extensions and discoveries. The majority of additions in our Midland Basin program were the result of future development projects identified by our on-going development activities, while the majority of additions in our Eagle Ford shale program were from newly identified locations based on an optimized development plan that includes wider well spacing and longer lateral completions.
Sales of reserves. Proved undeveloped reserves sold during the year primarily related to our PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. There was also a reduction in proved undeveloped reserves as a result of the joint venture we executed in December 2018 for the development of certain Eagle Ford shale wells in which our working interest was reduced.

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Removed for five-year rule. As a result of our testing and delineation efforts in 2018, we removed 22.6 MMBOE of estimated proved undeveloped reserves due to changes in our future development activities. Our development plans continue to be focused on maximizing returns and the value of our assets, and changes to these plans in 2018 caused these locations to be reclassified to unproved reserve categories and were replaced by higher quality proved undeveloped reserves, which are reflected as additions from discoveries, extensions, and infill.
Conversions to proved developed. Conversions of proved undeveloped reserves to proved developed reserves were in our Midland Basin and Eagle Ford shale programs. Our 2018 conversion track record was 19 percent. We expect our conversion track record to increase in 2019 as a result of increased capital expenditures related to converting proved undeveloped reserves. During 2018, we incurred $490.4 million on projects with reserves booked as proved undeveloped at the end of 2017, of which $442.4 million was spent on proved undeveloped reserves that converted to proved developed reserves by December 31, 2018. At December 31, 2018, drilled but not completed wells represented 40.1 MMBOE of total estimated proved undeveloped reserves. We expect to incur $254.3 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, 2018, estimated future development costs relating to our proved undeveloped reserves were $661.7 million, $457.7 million, and $599.1 million in 2019, 2020, and 2021, 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 10 years of experience in the energy industry and has been employed by the Company for nine 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. This data, 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 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 to be within 10 percent of our proved reserve amounts for the total company, as well as for each respective region.  Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 70 years.  The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is a Managing Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers. The Ryder Scott 2018 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 - Operations, 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.

10

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,
 
2018
 
2017
 
2016
Net production volumes
 
 
 
 
 
Oil (MMBbl)
18.8

 
13.7

 
16.6

Gas (Bcf)
103.2

 
123.0

 
146.9

NGLs (MMBbl)
7.9

 
10.3

 
14.2

Equivalent (MMBOE) (1)
43.9

 
44.5

 
55.3

Midland Basin net production volumes (2)
 
 
 
 
 
Oil (MMBbl)
16.6

 
8.5

 
2.6

Gas (Bcf)
25.8

 
14.7

 
5.6

NGLs (MMBbl)
—

 
—

 
—

Equivalent (MMBOE) (1)
20.9

 
11.0

 
3.5

Eagle Ford shale net production volumes (2)(3)
 
 
 
 
 
Oil (MMBbl)
1.2

 
1.9

 
5.4

Gas (Bcf)
76.1

 
104.0

 
129.9

NGLs (MMBbl)
7.9

 
10.1

 
13.8

Equivalent (MMBOE) (1)
21.8

 
29.3

 
40.9

Realized price, before the effect of derivative settlements
 
 
 
 
 
Oil (per Bbl)
$
56.80

 
$
47.88

 
$
36.85

Gas (per Mcf)
$
3.43

 
$
3.00

 
$
2.30

NGLs (per Bbl)
$
27.22

 
$
22.35

 
$
16.16

Per BOE
$
37.27

 
$
28.20

 
$
21.32

Production expense per BOE
 
 
 
 
 
Lease operating expense
$
4.74

 
$
4.43

 
$
3.51

Transportation costs
$
4.36

 
$
5.48

 
$
6.16

Production taxes
$
1.52

 
$
1.18

 
$
0.94

Ad valorem tax expense
$
0.48

 
$
0.34

 
$
0.21

____________________________________________
(1) 
Amounts may not calculate due to rounding.
(2) 
For each of the years ended December 31, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin properties exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis. For each of the annual periods presented, total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis.
(3) 
During the first quarter of 2017, we completed a divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE and 9.7 MMBOE of net production on an equivalent basis for the years ended December 31, 2017, and 2016, respectively.
Productive Wells
As of December 31, 2018, we had working interests in 715 gross (671 net) productive oil wells and 504 gross (485 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells mechanically capable of commercial production, but are temporarily shut-in. Multiple completions in the same wellbore are counted as one well. As of December 31, 2018, 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 production composition.

11

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 2018, 2017, and 2016, 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,
 
2018
 
2017
 
2016
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development wells
 
 
 
 
 
 
 
 
 
 
 
Oil
103

 
92

 
56

 
46

 
100

 
73

Gas
39

 
24

 
38

 
35

 
114

 
56

Non-productive
—

 
—

 
4

 
3

 
2

 
1

 
142

 
116

 
98

 
84

 
216

 
130

Exploratory wells
 
 
 
 
 
 
 
 
 
 
 
Oil
18

 
14

 
32

 
29

 
7

 
7

Gas
1

 
1

 
—

 
—

 
—

 
—

Non-productive
—

 
—

 
1

 
—

 
—

 
—

 
19

 
15

 
33

 
29

 
7

 
7

Total
161

 
131

 
131

 
113

 
223

 
137

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 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 plugged and abandoned.
In addition to the wells drilled and completed in 2018 (included in the table above), we were actively participating in the drilling of 21 gross (19 net) wells and had 104 gross (91 net) drilled but not completed wells as of January 31, 2019. These drilled but not completed wells represent wells that were being completed or were waiting on completion as of January 31, 2019.

12

Acreage
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2018. 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
55,632

 
49,552

 
20,451

 
15,321

 
76,083

 
64,873

Sweetie Peck
15,176

 
14,189

 
3,736

 
772

 
18,912

 
14,961

Midland Basin Total (4)
70,808

 
63,741

 
24,187

 
16,093

 
94,995

 
79,834

Eagle Ford
73,926

 
73,549

 
92,379

 
89,443

 
166,305

 
162,992

Other (5)
16,278

 
11,368

 
262,059

 
188,994

 
278,337

 
200,362

Total
161,012

 
148,658

 
378,625

 
294,530

 
539,637

 
443,188

____________________________________________
(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 7, 2019, approximately 1,406, 2,016, and 244 net acres of undeveloped acreage are scheduled to expire by December 31, 2019, 2020, and 2021, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.
(4) 
As of December 31, 2018, total Midland Basin acreage excludes approximately 1,885 net acres associated with drill-to-earn opportunities 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, 2018, we had gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum quantity of 29 MMBbl of oil, 595 Bcf of gas, and 21 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: a) our existing productive wells, b) future development of our proved undeveloped reserves, and c) 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.
In the event that no more product is delivered in accordance with these agreements, the aggregate undiscounted future deficiency payments as of December 31, 2018, would total $287.8 million. This amount does not include deficiency payment estimates associated with approximately 18.6 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 oil, gas, or NGLs would materially impact our operating results, as these are products with well-established markets and other viable purchaser options are available in our operating regions.

13

We had the following major customers and sales to entities under common ownership, which 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,
 
2018
 
2017
 
2016
Major customer #1 (1) 
18
%
 
6
%
 
—
%
Major customer #2 (1) 
10
%
 
10
%
 
5
%
Group #1 of entities under common ownership (2)
18
%
 
17
%
 
15
%
Group #2 of entities under common ownership (2)
12
%
 
8
%
 
8
%
____________________________________________
(1) 
These major customers are purchasers of a portion of our production from our Permian region.
(2) 
In the aggregate, these groups of entities under common ownership represented 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 represented more than 10 percent of our total oil, gas, and NGL production revenue.
Employees and Office Space
As of February 7, 2019, we had 611 full-time employees. This is a four percent decrease from the 635 reported full-time employees as of February 14, 2018. 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, 2018, including our corporate headquarters and regional offices:
 
 
Approximate Square Footage Leased
Corporate
 
107,000

Permian
 
59,000

South Texas & Gulf Coast
 
62,000

Mid-Continent (1)
 
50,000

Total
 
278,000

____________________________________________
(1) 
During the third quarter of 2015, we closed our office in Tulsa, Oklahoma. We have subleased this space through the expiration of the lease, which will occur in September 2019.
In addition to the leased office space summarized in the table above, as of December 31, 2018, we owned a total of 79,000 square feet of office space in our South Texas & Gulf Coast and Rocky Mountain regions.
Title to Properties
Substantially all of our interests are held pursuant to oil and gas leases from third parties. We usually obtain title opinions prior to commencing our initial drilling operations on our properties. 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 Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), royalty and overriding royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of such properties. We typically perform title investigation in accordance with standards generally accepted in the oil and gas industry before acquiring undeveloped leasehold acreage.
Seasonality
Generally, but not always, the demand and price levels for gas increase during winter months and decrease during summer months. To lessen the impact of seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users 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 traditionally is placed into storage. This could reduce the typical seasonal price differential. Demand for energy is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. 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. See Risk Factors - Risks Related to Our Business below for additional discussion.

14

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, own drilling rigs or other 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, and NGLs. 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 other fossil fuels such as coal and imported liquefied natural gas. 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 the competition for quality people, and we must compete effectively in order to be successful.
Government Regulations
Our business is extensively controlled by numerous federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time 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
Many of the states in which we conduct our operations or own assets have 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 various state 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, state conservation laws sometimes 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.
Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders that are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and must comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federal leases.
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.

15

Environmental, Health and Safety Matters
General.  Our operations are subject to stringent and complex federal, state, tribal, 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

16

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” 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 greenhouse gases 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. See 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. 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.

17

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 conducting our business in a manner that protects the environment and the health and safety of our employees, contractors and the public.  We set annual goals for our environmental, health and safety program focused on reducing the number of safety related incidents that occur and the number and impact of spills of produced fluids. We also periodically conduct regulatory compliance audits of our operations to ensure compliance with all regulations and 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, releases of gas into the environment and flaring is an economic waste and reducing these volumes is a priority for us. To avoid flaring where possible, we restrict testing periods and make every effort to ensure that our production is connected 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.
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, 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,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “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:
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the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
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any changes to the borrowing base or aggregate lender commitments under our Credit Agreement;
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our outlook on future oil, gas, and NGL prices, well costs, service costs, and general and administrative costs;
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the drilling of wells and other exploration and development activities and plans by us, our joint venture partners, and/or other third-party operators, as well as possible or expected acquisitions or divestitures;
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the possible divestiture or farm-down of, or joint venture relating to, certain properties;
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proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
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future oil, gas, and NGL production estimates;
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cash flows, anticipated liquidity, interest and related debt service expenses, and the future repayment of debt;
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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;
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the possible divestiture or farm-down of, or joint venture relating to, certain properties; and
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other similar matters, such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section 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 a number of 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. Some of these risks are described in the Risk Factors section of this report, and include without limitation such factors as:
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domestic and foreign supply of oil, natural gas, and NGLs;
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the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
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weakness in economic conditions, consumer demand, and uncertainty in financial markets;

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•
our ability to replace reserves in order to sustain production;
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our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
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our ability to compete against competitors that have greater financial, technical, and human resources;
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our ability to attract and retain key personnel;
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the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves, and that development of our proved undeveloped reserves may take longer and may require greater capital expenditures than we anticipate;
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the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
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the possibility that exploration and development drilling may not result in commercially producible reserves;
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our limited control over activities on outside-operated properties;
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our reliance on the skill, expertise and availability of third-party service providers and equipment for our operated activities;
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the possibility that title to properties in which we claim an interest may be defective;
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our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
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the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including our success in integrating new assets, and whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
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the uncertainties associated with enhanced recovery methods;
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our commodity derivative contracts expose us to counterparty credit risk and may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;
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the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
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our ability to deliver required quantities of oil, gas, NGL, or water to contractual counterparties;
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price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
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the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
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the possibility our amount of 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;
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the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”) may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt;
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operating and environmental risks and hazards that could result in substantial losses;
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the impact of extreme weather conditions, laws and regulations, and lease stipulations on our ability to conduct drilling activities;
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our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
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complex laws and regulations, including environmental regulations, that result in substantial costs, delays, and other risks;
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the availability and capacity of gathering, transportation, processing, and/or refining facilities;
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our ability to sell and/or receive market prices for our oil, gas, and NGLs;
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new technologies may cause our current exploration and drilling methods to become obsolete;
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the possibility of security threats, including terrorist attacks and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and systems; and
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litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.
We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in the forward-looking statements. 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 securities laws.

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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.
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 SEC’s 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. 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,

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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.

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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 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.

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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 2018 and Reserves within Part I, Items 1 and 2, Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016 within Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies, Note 11 – Fair Value Measurements, and Supplemental Oil and Gas Information 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:
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global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;
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the level of consumer demand for oil, gas, and NGLs;
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overall global and domestic economic conditions;
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weather conditions;
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the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;
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liquefied natural gas deliveries to and from the United States;
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the price and availability of alternative fuels;
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technological advances and regulations affecting energy consumption and conservation;
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the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and production controls;
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political instability or armed conflict in oil or gas producing regions;
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strengthening and weakening of the United States dollar relative to other currencies; and
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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, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government and other governments. Although the United States economy appears to have stabilized, future uncertainty is possible. Renewed weakness in the United States or other large economies could materially adversely affect our business and financial condition. For example:
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the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
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the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;
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our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for the exploration and/or development of reserves;

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•
our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and
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variable interest rate spread levels, including for LIBOR 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, or 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 and develop or 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 recent acquisitions, or any future acquisitions we may complete, a successful impact on 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 property acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential problems and deficiencies with the 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 special 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 obtain funding through 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

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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.
In February 2016, Moody’s Investors Service and Standard & Poor’s downgraded our credit ratings (“Debt Rating”). Our Debt Rating levels could have materially adverse consequences on our business and future prospects and could:
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limit our ability to access debt markets, including for the purpose of refinancing our existing debt;
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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;
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negatively impact current and prospective customers’ willingness to transact business with us;
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impose additional insurance, guarantee and collateral requirements;
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limit our access to bank and third-party guarantees, surety bonds and letters of credit; and
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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.

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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, 2018, 51%, or 258.6 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our proved undeveloped reserves, as of December 31, 2018, we estimate approximately $2.6 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 PV-10 or the standardized measure of discounted future net cash flows 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, 2018, was estimated using 12-month average sales prices of $65.56 per Bbl of oil (NYMEX WTI spot price), $3.10 per MMBtu of gas (NYMEX Henry Hub spot price), and $33.45 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 2018, our monthly average realized oil prices before the effect of derivative settlements were as high as $64.02 per Bbl and as low as $41.87 per Bbl, were as high as $34.56 per Bbl and as low as $19.59 per Bbl for NGLs, and were as high as $4.04 per Mcf and as low as $2.70 per Mcf for gas.  Many other factors will affect actual future net cash flows, including:
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amount and timing of actual production;
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supply and demand for oil, gas, and NGLs;
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curtailments or increases in consumption by oil purchasers and gas pipelines;
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changes in government regulations or taxes, including severance and excise taxes; and
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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.

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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 and obtain title opinions only on significant properties that we drill. 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:
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unexpected adverse drilling or completion conditions;
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title problems;
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disputes with owners or holders of surface interests on or near areas where we operate;
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pressure or geologic irregularities in formations;
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engineering and construction delays;
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equipment failures or accidents;
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hurricanes, tornadoes, flooding, or other adverse weather conditions;

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•
governmental permitting delays;
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compliance with environmental and other governmental requirements; and
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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 our newer resource plays, including those plays where we have recently acquired acreage, 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 7, 2019, that is scheduled to expire over the ensuing three years, represents approximately one percent of our total net undeveloped acreage as of December 31, 2018. 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

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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 gas, and swap arrangements for 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, 2018, we were in a net accrued asset position of $158.3 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:
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our production is less than expected;
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one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
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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 regions for our oil, gas, and NGL production. Please refer to Note 1 – Summary of Significant Accounting Policies, under the heading Concentration of Credit Risk and Major Customers 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, 2018, we were contractually committed to deliver 29 MMBbl of oil, 595 Bcf of gas, and 21 MMBbl of produced water. These contracts expire at various dates 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.

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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, and other inherent acreage risks. For the year ended December 31, 2018, we incurred abandonment and impairment of unproved properties expense totaling $49.9 million. We incurred impairment of proved properties expense and abandonment and impairment of unproved properties expense totaling $3.8 million and $12.3 million, respectively, during 2017, and $354.6 million and $80.4 million, respectively, during 2016. 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 $1.0 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 $1.5 billion, up from $925.0 million at December 31, 2017. The next semi-annual redetermination date is scheduled for April 1, 2019. We do not expect a material change to the borrowing base or the aggregate lender commitments as a result of this redetermination. 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, 2018, we had the following outstanding long-term debt:
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$172.5 million in aggregate principal amount of long-term senior unsecured convertible debt outstanding relating to our 1.50% Senior Convertible Notes due July 1, 2021 that we issued on August 12, 2016;
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$476.8 million of long-term senior unsecured debt outstanding relating to our 6.125% Senior Notes due 2022 that we issued on November 17, 2014;
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$500.0 million of long-term senior unsecured debt outstanding relating to our 5.0% Senior Notes due 2024 that we issued on May 20, 2013;
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$500.0 million of long-term senior unsecured debt outstanding relating to our 5.625% Senior Notes due 2025 that we issued on May 21, 2015;
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$500.0 million of long-term senior unsecured debt outstanding relating to our 6.75% Senior Notes due 2026 that we issued on September 12, 2016; and,
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$500.0 million of long-term senior unsecured debt outstanding relating to our 6.625% Senior Notes due 2027 that we issued on August 20, 2018.
Additionally, we had no outstanding borrowings under our Credit Agreement as of December 31, 2018. We had one outstanding letter of credit in the aggregate amount of $200,000 (which reduces the amount available for borrowing under the facility on a dollar-for-dollar basis), resulting in $999.8 million of available borrowing capacity under our secured credit facility. Our long-term debt represented 47 percent of our total book capitalization as of December 31, 2018.
Our indebtedness could have important consequences for our operations, including:
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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;
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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;

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•
limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;
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placing us at a competitive disadvantage compared to our competitors with less debt; and
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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 the Credit Agreement and the indentures governing our Senior Convertible Notes and our Senior 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 renewals of 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 the Credit Agreement and the indentures governing our Senior Convertible Notes and our Senior 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 the Company’s (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. The Company was in compliance with all financial and non-financial covenants as of December 31, 2018, and through the filing of this report.
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:
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incur additional debt;
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make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire common stock;
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sell assets, including common stock of our subsidiaries;
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restrict dividends or other payments of our subsidiaries;
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create liens that secure debt;
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enter into transactions with affiliates; and
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merge or consolidate with 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.

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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, 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. Our insurance 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.
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

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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 the CERCLA or the Superfund law, the 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 in our Permian and South Texas & Gulf Coast regions 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

33

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, 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 Permian and South Texas & Gulf Coast regions. 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 will decide by March 2019 whether to initiate rulemaking governing the disposal of wastewater from oil and gas development. 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 focus on environmental aspects and impacts of hydraulic fracturing practices. For example, in December 2016, the EPA issued a final assessment of potential impacts to drinking water resources from hydraulic fracturing. On March 28, 2017, President Trump issued Executive Order 13783 entitled “Promoting Energy Independence and Economic Growth” (“Executive Order 13783”). Executive Order 13783 directed executive departments and agencies to review regulations that potentially burden the development or use of domestically produced energy resources and, as appropriate, suspend, revise, or rescind those that unduly burden domestic energy resources development.
On March 26, 2015, the BLM published a final rule requiring, among other things, disclosure of chemicals used in hydraulic fracturing on federal and tribal lands, including private surface lands with underlying federal minerals. The rule was never implemented due to court challenges. On December 29, 2017, the BLM rescinded the rule. We will continue to be subject to uncertainty associated with new regulatory suspensions, revisions or rescissions and inconsistent state and federal regulatory mandates that could adversely affect our production.
Further, as to air quality and greenhouse gas (“GHG”) regulation of oil and gas sources, the overall trend has been toward increased regulation and requirements for reduced emissions. The Trump administration has taken steps toward rescinding or reviewing many of those regulations, but any deregulation will likely face immediate judicial challenges. The Obama administration took several actions to regulate air quality and GHGs, many of which remain in effect. For example, on August 16, 2012, the EPA issued final rules subjecting all new and modified oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and all existing and new operations to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards require the use of reduced emission completion (“REC”) techniques developed in the EPA’s Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAP include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and certain storage vessels at major sources of hazardous air pollutants not previously subject to MACT standards. These rules require additional control equipment, changes to procedure, and extensive monitoring and reporting. In September 2013 and December 2014, the EPA published technical fixes to the 2012 NSPS, including standards for storage tanks subject to the NSPS. The amendments clarified stages for flowback and the point at which green completion equipment is required and updated requirements for storage tanks and

34

leak detection requirements for processing plants. As part of the EPA’s strategy during the Obama administration to reduce methane and ozone-forming volatile organic compound (“VOC”) emissions from the oil and gas industry, on May 12, 2016, the EPA issued final regulations that amend and expand the 2012 regulations. The 2016 NSPS requires reduction of greenhouse gases in the form of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The final regulation requires, among other things, GHG and VOC standards for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and natural gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. Both the 2012 and 2016 rules are the subjects of Petitions for Review before the U.S. Circuit Court of Appeals for the District of Columbia, though the litigation of both rules has been stayed. In June 2017, the EPA proposed a 2-year stay of the compliance requirements in the 2016 NSPS. In a related action in March 2017, the EPA withdrew the final information request it had issued in 2016 as part of an effort to develop standards under the CAA NSPS provisions for methane and other emissions from existing sources in the oil and natural gas industry. In September 2018, the EPA proposed changes to the 2016 NSPS amending specific provisions related to, among other things, fugitive emissions requirements.
In October 2015, the EPA revised and lowered the ambient air quality standard for ozone in the U.S. under the CAA, from 75 parts per billion to 70 parts per billion, which is likely to result in more, and expanded, ozone non-attainment areas, which in turn will require states to adopt implementation plans to reduce emissions of ozone-forming pollutants, like VOCs and nitrogen oxides, that are emitted from, among others, the oil and gas industry. A decision in the judicial challenge to the ozone standard is expected in 2019. In October 2016, the EPA finalized Control Techniques Guidelines for VOC emissions from existing oil and natural gas equipment and processes in moderate ozone non-attainment areas. These Control Techniques Guidelines provide recommendations for states and local air agencies to consider when determining what emissions requirements apply to sources in the non-attainment areas. The EPA has proposed to completely withdraw the rules. On May 12, 2016, the EPA also issued a final rule named the “Source Determination Rule” that was issued to clarify when multiple pieces of oil and gas equipment and activities must be aggregated as a single source for determining whether major source permitting programs apply. This action can expand the permitting and related control requirements to sources that were not previously subject to permitting requirements. However, more recently, the EPA has issued several guidance documents and memorandums related to aggregation of facilities that may narrow the effect of the Source Determination Rule.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third-parties opposing such activities to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In 2013, a court in California held that the BLM did not comply with NEPA because it did not adequately consider the impact of hydraulic fracturing and horizontal drilling before issuing leases. Courts in New York and Colorado reduced the level of evidence required before a court will agree to consider alleged damage claims from hydraulic fracturing by property owners. Litigation resulting in financial compensation for damages linked to hydraulic fracturing, including damages from induced seismicity, could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or restrictions or increased costs in the exploration for, and production of, oil, gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional state or local laws, or the implementation of new regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows.
Requirements to reduce gas flaring could have an adverse effect on our operations.
Wells in the Midland Basin in Texas, where we have significant operations, produce natural gas, as well as oil and NGLs. Constraints in the gas gathering and processing network in certain areas of the Midland Basin have resulted in some of that gas being flared instead of gathered, processed, and sold. Further, we are subject to laws established by state and other regulatory agencies that restrict the duration and amount of natural gas that can be legally flared. These laws and regulations, including potential future regulations that may impose further restrictions on flaring, could limit the amount of oil and gas the Company can produce from the Company’s wells or may limit the number of wells or the locations that the Company can drill.
In November 2016, the BLM finalized regulations to address methane emissions from oil and gas operations on federal and tribal lands. The regulations prohibit venting gas except in limited situations and limit the flaring of gas. After continuous court challenges, the BLM issued a final rule in September 2018 that rescinded most of the 2016 rule, including most of the methane control requirements. Any future regulations requiring similar capture standards may increase our operational costs, or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

35

Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.
The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of oil, gas, and NGLs requires the use and disposal of significant quantities of water.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water produced from our wells, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of oil, gas, and NGLs.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.
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 December 2009, the EPA made a finding that emissions of carbon dioxide, methane, and other “greenhouse gases” endanger public health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on this finding, the EPA adopted and implemented a comprehensive suite of regulations to restrict and otherwise regulate emissions of greenhouse gases under existing provisions of the CAA. In particular, the EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA. One rule requires a reduction in greenhouse gas emissions from motor vehicles, and the other regulates permitting and greenhouse gas emissions from certain large stationary sources. These EPA regulatory actions have been challenged by various industry groups, initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, in June 2014, the United States Supreme Court reversed the D.C. Circuit and struck down the EPA’s greenhouse gas permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of greenhouse gases. The EPA proposed a rule in 2016 to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits addressing emissions of greenhouse gases to large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). If finalized, large sources of air pollutants other than greenhouse gases will be required to implement the best available capture technology for greenhouse gases. However, the EPA has not taken action on the proposed rule and is unlikely to do so under the Trump administration. The EPA has also adopted reporting rules for greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as well as certain onshore oil and gas extraction and production facilities.
Several other cases regarding greenhouse gases have been heard by the courts in recent years. While courts have generally declined to assign direct liability for climate change to large sources of greenhouse gas emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities. There is a continuing risk of claims being filed against companies that have significant greenhouse gas emissions, and new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue.  Such cases often seek to challenge air emissions permits that greenhouse gas emitters apply for, seek to force emitters to reduce their emissions, or seek damages for alleged climate change impacts to the environment, people, and property. Any court rulings, laws, or regulations that restrict or require reduced emissions of greenhouse gases could lead to increased operating and compliance costs and could have an adverse effect on demand for the oil and gas that we produce.
The United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas “cap and trade” programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. In 2013, the Congressional Budget Office provided Congress with a study on the potential effects on the United States economy of a tax on greenhouse gas emissions and recently summarized the impact of imposition of a tax on greenhouse gas emissions for reducing the deficit. While “carbon tax” legislation has been introduced in Congress, the prospects for passage of such legislation are uncertain at this time.
On June 25, 2013, President Obama issued a Climate Action Plan to address climate change through a variety of executive actions, including reduction of methane emissions from oil and gas production and processing operations as well as pipelines and coal mines (the “Climate Action Plan”). Please refer to Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays for more information on EPA actions to implement the Climate Action Plan. The focus on legislating and/or regulating methane could eventually result in:

36

•
requirements for methane emission reductions from existing oil and gas equipment;
•
increased scrutiny for sources emitting high levels of methane, including during permitting processes;
•
analysis, regulation and reduction of methane emissions as a requirement for project approval; and
•
actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors.
In relation to the Climate Action Plan, both assumed global warming potential (“GWP”) and assumed social costs associated with methane and other greenhouse gas emissions have been finalized, including a 20% increase in the GWP of methane. Changes to these measurement tools could adversely impact permitting requirements, application of agencies’ existing regulations for source categories with high methane emissions, and determinations of whether a source qualifies for regulation under the CAA. However, in Executive Order 13783, President Trump ordered a review of the use of social cost of carbon for regulatory impact analysis. Therefore, the continued use of the social cost of carbon under the Trump administration is uncertain.
Finally, it should be noted that scientists have predicted that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such events. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our costs and planning requirements.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services that use new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies we currently use or implement in the future may become obsolete. We cannot be certain we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations, and financial condition may be adversely affected.
Risks Related to Our Common Stock
The price of our common stock may fluctuate significantly, which may result in losses for investors.
From January 1, 2018, to February 7, 2019, the intraday trading prices per share of our common stock as reported by the New York Stock Exchange ranged from a low of $13.15 per share in December 2018 to a high of $33.76 per share in October 2018. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include, in addition to the other Risk Factors set forth herein, the following:
•
changes in oil, gas, or NGL prices;
•
changes in the outlook for regional, national, or global commodity supply and demand;
•
variations in drilling, recompletion, and operating activity;
•
changes in financial estimates by securities analysts;
•
changes in market valuations of comparable companies;
•
additions or departures of key personnel;
•
increased volatility due to the impacts of algorithmic trading practices;
•
future sales of our common stock; and
•
changes in the national and global economic outlook, including potential impacts from trade agreements.
We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.

37

Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.
Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, these provisions could make it more difficult for a third-party to acquire us, even if doing so would benefit our stockholders, which may limit the price investors are willing to pay in the future for shares of our common stock.
We may not always pay dividends on our common stock.
Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our Credit Agreement limiting our annual cash dividends to no more than $50.0 million, and to covenants in the indentures for our Senior Notes and Senior Convertible Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share or discontinue the payment of dividends altogether.

38

ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.
ITEM 3.     LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a materially adverse effect upon our financial condition, results of operations or cash flows.
Chieftain Royalty Company v. SM Energy Company, Case No. CIV-11-D, In the United States District Court, Western District of Oklahoma. On January 27, 2011, Chieftain Royalty Company (“Plaintiff”) commenced a putative class action lawsuit against the Company by filing a Petition in the District Court of Beaver County, Oklahoma, in the matter originally styled Chieftain Royalty Company v. SM Energy Company (including predecessors, successors and affiliates), Case No. CJ-201104, alleging that the Company had improperly deducted post-production costs from royalty payments due on production from wells located throughout Oklahoma, and asserting claims against the Company for breach of contract, tortious breach of contract, breach of fiduciary or quasi-fiduciary duty, fraud (actual and constructive), deceit, conversion and conspiracy.
The Company removed the case to the United States District Court for the Western District of Oklahoma. Thereafter, the Court stayed this matter pending the outcome of two appeals involving XTO Energy, Inc (“XTO”), before the Tenth Circuit Court of Appeals. After resolution of the XTO appeals, the stay was lifted in 2013.
The Company was originally the only named defendant, but, as a result of the Company’s 2013 disposition of approximately 75% of its Oklahoma properties to various entities, with those entities agreeing to assume any liability for any past or present royalty claims, Plaintiff filed a Second Amended Complaint in 2014 joining such entities as defendants. Those defendants subsequently settled all claims with Plaintiff; however, that settlement was effectively stayed during extended appellate proceedings concerning disputed attorneys’ fees in the matter. The Chieftain matter concerning the remaining Oklahoma properties was stayed during the fee dispute proceedings.
On August 2, 2018, the Court in this matter required that Plaintiff file any motion to certify a class by February 8, 2019. Plaintiff filed such motion but only with respect to royalty owners in wells attached to the Coal County, Oklahoma pipeline system, which was owned by the Company’s affiliate, Four Winds Marketing, LLC, until 2015, when the subject wells and pipeline system were sold to a third party.
This case involves complex legal and factual issues and uncertainties as to Oklahoma law and federal law concerning class certification under the circumstances of this case, and has resulted in a significant amount of discovery. The Company believes that it has properly paid royalties under Oklahoma law and that the class as proposed by Plaintiff should not be certified. The Company has and will continue to vigorously defend this case.
ITEM 4.     MINE SAFETY DISCLOSURES
These disclosures are not applicable to us.

39

PART II

ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM.”
PERFORMANCE GRAPH
The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2013, and ending on December 31, 2018, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Index, and the Standard & Poor’s 500 Stock Index.
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS
item52018relativeperfor02.jpg
The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC.
Holders. As of February 7, 2019, the number of record holders of our common stock was 65. Based upon inquiry, management believes that the number of beneficial owners of our common stock is approximately 21,337.
Purchases of Equity Securities by Issuer and Affiliated Purchasers. The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2018, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act.

40

PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Period
 
Total Number of Shares Purchased (1)
 
Weighted Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Program
 
Maximum Number of Shares that May Yet be Purchased Under the Program (2)
01/01/2018 -
     03/31/2018
 
—

 
$
—

 
—

 
3,072,184

04/01/2018 -
     06/30/2018
 
355

 
$
26.64

 
—

 
3,072,184

07/01/2018 -
     09/30/2018
 
115,429

 
$
25.69

 
—

 
3,072,184

10/01/2018 -
     12/31/2018
 
—

 
$
—

 
—

 
3,072,184

Total
 
115,784

 
$
25.69

 
—

 
3,072,184

____________________________________________
(1) 
All shares purchased by us in 2018 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying Restricted Stock Units (“RSUs”) issued under the terms of award agreements granted under the SM Energy Equity Incentive Compensation Plan, as amended and restated effective as of May 22, 2018 (the “Equity Plan”).
(2) 
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.

41

ITEM 6.     SELECTED FINANCIAL DATA
The following table sets forth selected supplemental financial and operating data as of the dates or for the years indicated. The financial data for each of the five years presented was derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.
 
As of or for the Years Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in millions, except per share data)
Statement of operations data:
 
 
 
 
 
 
 
 
 
Total operating revenues and other income
$
2,067.1

 
$
1,129.4

 
$
1,217.5

 
$
1,557.0

 
$
2,522.3

Net income (loss)
$
508.4

 
$
(160.8
)
 
$
(757.7
)
 
$
(447.7
)
 
$
666.1

Net income (loss) per share:
 
 
 
 
 
 
 
 
 
Basic
$
4.54

 
$
(1.44
)
 
$
(9.90
)
 
$
(6.61
)
 
$
9.91

Diluted
$
4.48

 
$
(1.44
)
 
$
(9.90
)
 
$
(6.61
)
 
$
9.79

Cash dividends declared and paid per common share
$
0.10

 
$
0.10

 
$
0.10

 
$
0.10

 
$
0.10

Balance sheet data:
 
 
 
 
 
 
 
 
Total assets
$
6,352.9

 
$
6,176.8

 
$
6,393.5

 
$
5,621.6

 
$
6,483.1

Long-term debt:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$
—

 
$
—

 
$
—

 
$
202.0

 
$
166.0

Senior Notes, net of unamortized deferred financing costs
$
2,448.4

 
$
2,769.7

 
$
2,766.7

 
$
2,316.0

 
$
2,166.4

Senior Convertible Notes, net of unamortized discount and deferred financing costs
$
147.9

 
$
139.1

 
$
130.9

 
$
—

 
$
—


42

Supplemental Selected Financial and Operations Data
 
 
 
As of or for the Years Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
Balance sheet data (in millions):
 
 
 
 
 
 
 
 
Total working capital (deficit)
$
(36.8
)
 
$
(10.1
)
 
$
(190.5
)
 
$
216.5

 
$
(39.6
)
Total stockholders’ equity
$
2,920.3

 
$
2,394.6

 
$
2,497.1

 
$
1,852.4

 
$
2,286.7

Weighted-average common shares outstanding (in thousands):
 
 
 
 
 
 
Basic
111,912

 
111,428

 
76,568

 
67,723

 
67,230

Diluted
113,502

 
111,428

 
76,568

 
67,723

 
68,044

Reserves:
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
175.7

 
158.2

 
104.9

 
145.3

 
169.7

Gas (Bcf)
1,321.8

 
1,280.1

 
1,111.1

 
1,264.0

 
1,466.5

 NGLs (MMBbl)
107.4

 
96.5

 
105.7

 
115.4

 
133.5

MMBOE (1)
503.4

 
468.1

 
395.8

 
471.3

 
547.7

 
 
 
 
 
 
 
 
 
 
Production and operations (in millions):
 
 
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
1,636.4

 
$
1,253.8

 
$
1,178.4

 
$
1,499.9

 
$
2,481.5

Oil, gas, and NGL production expense
$
487.4

 
$
507.9

 
$
597.6

 
$
723.6

 
$
715.9

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
665.3

 
$
557.0

 
$
790.7

 
$
921.0

 
$
767.5

General and administrative (2)
$
116.5

 
$
117.3

 
$
124.8

 
$
156.1

 
$
166.5

Production volumes:
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
18.8

 
13.7

 
16.6

 
19.2

 
16.7

Gas (Bcf)
103.2

 
123.0

 
146.9

 
173.6

 
152.9

NGLs (MMBbl)
7.9

 
10.3

 
14.2

 
16.1

 
13.0

MMBOE (1)
43.9

 
44.5

 
55.3

 
64.2

 
55.1

 
 
 
 
 
 
 
 
 
 
Realized price, before the effect of derivative settlements:
 
 
 
 
 
 
Oil (per Bbl)
$
56.80

 
$
47.88

 
$
36.85

 
$
41.49

 
$
80.97

Gas (per Mcf)
$
3.43

 
$
3.00

 
$
2.30

 
$
2.57

 
$
4.58

NGLs (per Bbl)
$
27.22

 
$
22.35

 
$
16.16

 
$
15.92

 
$
33.34

Per BOE
$
37.27

 
$
28.20

 
$
21.32

 
$
23.36

 
$
45.01

Expense per BOE:
 
 
 
 
 
 
 
 
 
Lease operating expense
$
4.74

 
$
4.43

 
$
3.51

 
$
3.73

 
$
4.28

Transportation costs
$
4.36

 
$
5.48

 
$
6.16

 
$
6.02

 
$
6.11

Production taxes
$
1.52

 
$
1.18

 
$
0.94

 
$
1.13

 
$
2.13

Ad valorem tax expense
$
0.48

 
$
0.34

 
$
0.21

 
$
0.39

 
$
0.46

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
15.15

 
$
12.53

 
$
14.30

 
$
14.34

 
$
13.92

General and administrative (2)
$
2.65

 
$
2.64

 
$
2.26

 
$
2.43

 
$
3.02

Statement of cash flows data (in millions):
 
 
 
 
 
 
 
 
 
Provided by operating activities (2)
$
720.6

 
$
515.4

 
$
552.8

 
$
990.8

 
$
1,456.6

Used in investing activities (2)
$
(587.9
)
 
$
(201.5
)
 
$
(1,867.6
)
 
$
(1,144.6
)
 
$
(2,575.5
)
Provided by (used in) financing activities (2)
$
(368.7
)
 
$
(12.3
)
 
$
1,327.2

 
$
153.7

 
$
740.0

____________________________________________
(1) 
Amounts may not calculate due to rounding.
(2) 
Certain prior period amounts have been reclassified to conform to the current period presentation on the consolidated financial statements. Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 for additional discussion of the change in presentation as a result of adopting new accounting standards.

43

ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in Part I, Items 1 and 2 of this report for important information about these types of statements.
Overview of the Company
General Overview
We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. We currently have producing assets and significant acreage positions in the Midland Basin and Eagle Ford shale in Texas. Our strategic objective is to be a premier operator of top tier assets. We seek to maximize the value of our assets by applying industry leading technology and outstanding operational execution. Our portfolio is comprised of unconventional resource prospects with expanding prospective drilling opportunities, which we believe provides for long-term production and reserves growth. We are focused on generating strong full-cycle economic returns on our investments and maintaining a strong balance sheet.
2018 Financial and Operational Highlights
Our objective to be a premier operator of top tier assets led to our multi-year portfolio transformation, which now allows us to focus solely on maximizing the value of our core acreage positions located in the Midland Basin and Eagle Ford shale. As part of our transformation strategy, we completed divestitures of substantially all remaining non-core assets in the first half of 2018. We used proceeds from these divestitures, along with operating cash flows, to fully fund our 2018 capital program and to meaningfully reduce our long-term debt. Additionally, we completed financial transactions during the year that extended the average maturity on our remaining long-term debt, and we had no outstanding borrowings against our credit facility as of December 31, 2018. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions and Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Financial and Operational Results. During the year ended December 31, 2018, we achieved the following financial and operational results:
•
Total estimated proved reserves increased eight percent from the prior year to 503.4 MMBOE as of December 31, 2018, of which 56 percent were liquids (oil and NGLs) and 49 percent were characterized as proved developed. During 2018, we added 188.0 MMBOE through our Midland Basin and Eagle Ford shale drilling programs as well as from changes to our future development strategy in the Eagle Ford shale, which includes wider spacing and longer lateral completions. These positive results for 2018 were partially offset by the divestiture of 40.3 MMBOE of estimated proved reserves, and net downward revisions of 68.8 MMBOE, which resulted primarily from changes in our development plans in our Eagle Ford shale program. On a retained asset basis, estimated proved reserves increased 18 percent year-over-year. Further, our estimated proved reserve life index increased to 11.5 years at December 31, 2018, compared to 10.5 years at December 31, 2017. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion.
•
The standardized measure of discounted future net cash flows was $4.7 billion as of December 31, 2018, compared with $3.0 billion as of December 31, 2017, which was an increase of 54 percent year-over-year. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report for additional discussion.
•
Average net daily production for the year ended December 31, 2018, was 120.3 MBOE, compared with 121.8 MBOE for the same period in 2017. This decrease was driven largely by producing property divestitures in 2017 and in the first half of 2018. On a retained asset basis, production increased 11 percent year-over-year, which was due to a 91 percent increase in production volumes in our Permian region for the year ended December 31, 2018, compared with 2017. Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends below for additional discussion on production.
•
We recorded net income of $508.4 million, or $4.48 per diluted share, for the year ended December 31, 2018. This compares with a net loss of $160.8 million, or $1.44 per diluted share, for the year ended December 31, 2017. Please refer to Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016 below for additional discussion regarding the components of net income (loss) for each period presented.
•
Net cash provided by operating activities was $720.6 million for the year ended December 31, 2018, compared with $515.4 million for the year ended December 31, 2017, which was an increase of 40 percent year-over-year. The increase in net cash provided by operating activities for 2018, compared with 2017, was primarily the result of 37 percent growth in higher margin oil production, which, combined with increased benchmark pricing for oil and NGLs, drove a 32 percent increase in our realized price per BOE before the effects of derivative settlements, and led to a 31 percent increase in oil, gas, and NGL production revenue. Partially offsetting the increase from oil, gas, and NGL production revenue was a cash settlement loss on derivatives of $135.8 million for the year ended December 31, 2018, compared to a cash settlement

44

gain on derivatives of $21.2 million during 2017. Please refer to Analysis of Cash Flow Changes Between 2018 and 2017 and Between 2017 and 2016 below for additional discussion.
•
Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2018, was $900.4 million, compared with $663.2 million for the same period in 2017. The increase in adjusted EBITDAX for 2018 was largely driven by the growth in higher margin oil production and improved benchmark pricing for oil and NGLs. This increase was partially offset by increased losses on derivative settlements. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to our net income (loss) and net cash provided by operating activities.
Long-Term Debt. During the year ended December 31, 2018, we executed certain long-term debt transactions and agreements, which are summarized below:
•
2021 Senior Notes Redemption. On July 16, 2018, we redeemed the $344.6 million principal outstanding of our 2021 Senior Notes using cash on hand resulting from property divestitures. Redemption of the 2021 Senior Notes resulted in a loss on extinguishment of debt of $9.8 million for the year ended December 31, 2018. This loss included $7.5 million associated with the premium paid and $2.3 million due to the acceleration of previously unamortized deferred financing costs.
•
2027 Senior Notes Issuance. On August 20, 2018, we issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027 and received net proceeds of $492.1 million. This offering was made in order to fund the tender offer and notes redemption discussed below.
•
Tender Offer and Redemption of our 2023 Senior Notes and a Portion of our 2022 Senior Notes. Concurrently with our 2027 Senior Notes offering, we announced a cash tender offer (the “Tender Offer”), which included plans to redeem our 2023 Senior Notes and a portion of our 2022 Senior Notes. Upon completion of these transactions, we retired the $395.0 million principal outstanding of our 2023 Senior Notes and $85.0 million principal outstanding of our 2022 Senior Notes. We paid total consideration, including accrued interest, of $497.8 million to complete these transactions, which resulted in a loss on extinguishment of debt of $16.9 million for the year ended December 31, 2018. This amount included $12.9 million associated with premiums paid and $4.0 million due to the acceleration of previously unamortized deferred financing costs.
•
Credit Agreement. On September 28, 2018, we entered into the Credit Agreement with our lenders which provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, an initial borrowing base of $1.5 billion, and initial aggregate lender commitments totaling $1.0 billion. The Credit Agreement is scheduled to mature on September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, to the extent we have not completed certain repurchase, redemption, or refinancing activities associated with our 2022 Senior Notes as outlined in the Credit Agreement.
Please refer to Overview of Liquidity and Capital Resources below and Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Operational Activities. The value of the RockStar area of our Midland Basin position continues to exceed our pre-acquisition expectations and was key to driving significant growth in our operating margin and cash flows from operations in 2018 due to the high percentage of oil these wells produce. Our operational execution and development strategy in this region has resulted in stronger well performance due to enhanced completion design and our ability to drill longer laterals given the increasingly contiguous nature of our acreage position as a result of successful infill leasing and acreage trades. Efficiency in completions and operations also increased in 2018, as a large portion of our water transportation and disposal needs are being satisfied by the water facilities we constructed in a core area of our RockStar acreage. We also continued to increase our use of locally sourced sand in our well completions, which has resulted in further cost savings and improved returns for our program.
In our Midland Basin program, we averaged seven drilling rigs and four completion crews during 2018, focusing on the development of the Lower Spraberry and Wolfcamp A and B shale intervals on our RockStar acreage in Howard and Martin Counties, Texas, as well as our Sweetie Peck acreage in Upton and Midland Counties, Texas. We completed 114 gross (104 net) operated wells during 2018 and increased production volumes year-over-year by 91 percent to 20.9 MMBOE, 79 percent of which was oil. 84 percent of our total 2018 drilling and completion capital was allocated to our Midland Basin program.
During 2018 in our operated Eagle Ford shale program, we were focused on increasing overall inventory value through optimizing our completion designs and by evaluating our development strategy and electing to revise our development plans to include wider spaced locations and longer lateral well completions that we believe will yield greater returns. We have also been active in assessing new intervals outside of the core Eagle Ford shale formation to further expand our future drilling inventory.
In September 2017, we entered into a joint venture agreement with a third-party to drill 16 wells and complete 23 wells in a focused portion of our Eagle Ford North area (“Phase 1 JV”). In December 2018, we extended this agreement and added an additional 12 wells to be drilled and completed (“Phase 2 JV”). The agreement provides that the third-party carries 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.

45

This arrangement allows 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 Phase 1 JV wells were drilled and completed as of December 31, 2018. Six of the 12 Phase 2 JV wells were drilled during 2018, and we expect the remaining six wells to be drilled and all 12 wells to be completed during 2019.
Our Eagle Ford shale program averaged one drilling rig and one completion crew during 2018. We completed 40 gross (26 net) wells during 2018. Total production for 2018 was 21.8 MMBOE, a 26 percent decrease from 2017. The decrease in production from our Eagle Ford shale program was primarily driven by the sale of our outside-operated assets in the first quarter of 2017 and reduced capital investment on our retained operated acreage. 14 percent of our total 2018 drilling and completion capital was allocated to our Eagle Ford shale program.

The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the year ended December 31, 2018.
 
Permian
 
South Texas & Gulf Coast
 
Bakken/Three Forks (1)
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled but not completed at December 31, 2017
49

 
41

 
33

 
30

 
18

 
15

 
100

 
86

Wells drilled
126

 
117

 
36

 
20

 
—

 
—

 
162

 
137

Wells completed
(114
)
 
(104
)
 
(40
)
 
(26
)
 
—

 
—

 
(154
)
 
(130
)
Wells sold (1)
—

 
—

 
—

 
—

 
(18
)
 
(15
)
 
(18
)
 
(15
)
Other (2)
—

 
1

 
—

 
(1
)
 
—

 
—

 
—

 
—

Wells drilled but not completed at December 31, 2018
61

 
55

 
29

 
23

 
—

 
—

 
90

 
78

_____________________________________
(1) 
Drilled but not completed wells in this table relating to the Bakken/Three Forks operated program were included as part of the Divide County Divestiture, which was completed in the second quarter of 2018.
(2)
Reflects net working interest changes resulting from normal business operations.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Year Ended
 
December 31, 2018
 
(in millions)
Development costs
$
1,147.6

Exploration costs
184.9

Acquisitions
 
Proved properties
1.3

Unproved properties
55.7

Total, including asset retirement obligations (1)
$
1,389.5

____________________________________________
(1)
Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information in Part II, Item 8 of this report.

All of our development and exploration costs were incurred in our Midland Basin and Eagle Ford shale programs for the year ended December 31, 2018, with 84 percent of these costs being directed towards activities on our Midland Basin assets. Costs incurred for acquisitions during the year related to transactions in the Midland Basin, as well as payments made to extend certain lease terms, to acquire new leases, and to acquire certain surface rights associated with our Midland Basin water handling and transportation facilities. Please refer to Operational Activities above and Acquisition Activity below for additional information on our regional activities.

46

Production Results. The table below presents the disaggregation of our production by product type for each of our operating regions for the year ended December 31, 2018:
 
Permian
 
South Texas & Gulf Coast
 
Rocky
Mountain (1)
 
Total
Production:
 
 
 
 
 
 
 
Oil (MMBbl)
16.6

 
1.3

 
0.9

 
18.8

Gas (Bcf)
25.8

 
76.2

 
1.2

 
103.2

NGLs (MMBbl)
—

 
7.9

 
—

 
7.9

Equivalent (MMBOE)
20.9

 
21.8

 
1.1

 
43.9

Avg. Daily Equivalents (MBOE/d)
57.4

 
59.9

 
3.1

 
120.3

Relative percentage
48
%
 
50
%
 
2
%
 
100
%
____________________________________________
Note: Amounts may not calculate due to rounding.
(1)  
We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.
We experienced a one percent decrease in production on an equivalent basis for the year ended December 31, 2018, compared with 2017. The decrease in overall production volumes was primarily a result of the divestiture of our outside-operated Eagle Ford shale assets in the first quarter of 2017, decreased production from our operated Eagle Ford shale assets as a result of reduced capital investment, and the divestiture of our remaining producing assets in the Rocky Mountain region in the first half of 2018. Production decreases from the Eagle Ford shale and Rocky Mountain region were mostly offset by the Permian region, which had an increase in production volumes of 91 percent for the year ended December 31, 2018, compared with 2017. Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016 below for additional discussion on production.
Divestiture Activity. On March 26, 2018, we divested approximately 112,000 net acres of our Powder River Basin assets for net divestiture proceeds of $492.2 million and recorded a final net gain of $410.6 million for the year ended December 31, 2018. During the second quarter of 2018, we divested our remaining assets in the Williston Basin, and our non-operated Halff East assets in the Midland Basin for combined net divestiture proceeds of $252.2 million. We recorded a combined final net gain of $15.4 million for the year ended December 31, 2018.
Acquisition Activity. During 2018, we acquired approximately 1,030 net acres of unproved properties in Howard and Martin Counties, Texas, in two separate transactions totaling $33.3 million. We also completed two non-monetary acreage trades of primarily unproved properties located in Howard and Martin Counties, Texas, resulting in the exchange of approximately 2,650 net acres, with $95.1 million of carrying value attributed to the properties we surrendered. These trades were recorded at carryover basis with no gain or loss recognized.
Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.

47

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the years ended December 31, 2018, 2017, and 2016:
 
For the Years Ended December 31,
 
2018
 
2017
 
2016
Oil (per Bbl):
 
 
 
 
 
Average NYMEX contract monthly price
$
64.77

 
$
50.95

 
$
43.32

Realized price, before the effect of derivative settlements
$
56.80

 
$
47.88

 
$
36.85

Effect of oil derivative settlements
$
(3.67
)
 
$
(2.28
)
 
$
14.63

 
 
 
 
 
 
Gas:
 
 
 
 
 
Average NYMEX monthly settle price (per MMBtu)
$
3.09

 
$
3.11

 
$
2.46

Realized price, before the effect of derivative settlements (per Mcf)
$
3.43