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
Common stock, $.01 par value
Name of each exchange on which registered
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
Non-accelerated filer o
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 .
1
ITEM
ITEMS 1. AND 2.
BUSINESS AND PROPERTIES
TABLE OF CONTENTS
PART I
General
Strategy
Significant Developments in 2018
Outlook for 2019
Areas of Operation
Reserves
Production
Productive Wells
Drilling and Completion Activity
Acreage
Delivery Commitments
Major Customers
Employees and Office Space
Title to Properties
Seasonality
Competition
Government Regulations
ITEM 1A.
ITEM 1B.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
ITEM 7.
Cautionary Information about Forward-Looking Statements
Available Information
Glossary of Oil and Gas Terms
RISK FACTORS
UNRESOLVED STAFF COMMENTS
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES
PART II
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of the Company
Financial Results of Operations and Additional Comparative Data
Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016
Overview of Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Accounting Matters
Environmental
Non-GAAP Financial Measures
2
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TABLE OF CONTENTS
(Continued)
ITEM
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
ITEM 15.
ITEM 16.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included within the content of ITEM
7)
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
PART III
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
EXHIBITS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY
PAGE
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3
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.
PART I
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 .
5
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:
Proved reserves
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Relative percentage
Proved developed %
Production
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Avg. daily equivalents (MBOE/d) (1)
Permian
South Texas &
Gulf Coast
Rocky
Mountain
Total (1)
159.4
328.4
0.2
214.3
43%
40%
16.6
25.8
—
20.9
57.4
16.3
993.4
107.2
289.1
57%
55%
1.3
76.2
7.9
21.8
59.9
—
—
—
—
—%
N/A
0.9
1.2
—
1.1
3.1
175.7
1,321.8
107.4
503.4
100%
49%
18.8
103.2
7.9
43.9
120.3
Relative percentage
48%
50%
2%
100%
Costs incurred (in millions) (2) (3)
____________________________________________
(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.
1,180.9
1,389.5
185.3
2.7
$
$
$
$
(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.
6
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.
7
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 :
Reserve data:
Proved developed
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Proved undeveloped
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Total proved (1)
Oil (MMBbl)
Gas (Bcf) (2)
NGLs (MMBbl)
MMBOE
Proved developed reserves %
Proved undeveloped reserves %
Reserve data (in millions):
Standardized measure of discounted future net cash flows (GAAP)
PV-10 (non-GAAP):
Proved developed PV-10
Proved undeveloped PV-10
Total proved PV-10 (non-GAAP)
As of December 31,
2018
2017
2016
68.2
699.1
60.1
244.8
107.6
622.7
47.2
258.6
175.7
1,321.8
107.4
503.4
58.6
642.9
49.0
214.7
99.6
637.2
47.6
253.4
158.2
1,280.1
96.5
468.1
49%
51%
46%
54%
48.5
609.1
58.6
208.7
56.4
502.0
47.1
187.1
104.9
1,111.1
105.7
395.8
53%
47%
$
$
$
4,654.4
$
3,024.1
$
1,152.1
3,084.2
$
1,984.2
$
2,020.1
1,072.3
5,104.3
$
3,056.5
$
1,051.1
101.0
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 $
Add: 10 percent annual discount, net of income taxes
Add: future undiscounted income taxes
Undiscounted future net cash flows
Less: 10 percent annual discount without tax effect
3,847.1
1,012.2
9,513.7
(4,409.4)
2,573.2
205.7
5,803.0
(2,746.5)
PV-10 (non-GAAP)
$
5,104.3 $
3,056.5 $
1,152.1
937.1
—
2,089.2
(937.1)
1,152.1
8
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 proved undeveloped reserves:
Beginning of year
Revisions of previous estimates
Additions from discoveries, extensions, and infill
Sales of reserves
Purchases of minerals in place
Removed for five-year rule
Conversions to proved developed
End of year
Total
(MMBOE)
253.4
(54.4)
151.7
(22.0)
0.1
(22.6)
(47.6)
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.
9
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.
Net production volumes
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE) (1)
Midland Basin net production volumes (2)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE) (1)
Eagle Ford shale net production volumes (2)(3)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE) (1)
Realized price, before the effect of derivative settlements
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per BOE
Production expense per BOE
Lease operating expense
Transportation costs
Production taxes
For the Years Ended December 31,
2018
2017
2016
18.8
103.2
7.9
43.9
16.6
25.8
—
20.9
1.2
76.1
7.9
21.8
56.80 $
3.43 $
27.22 $
37.27 $
4.74 $
4.36 $
1.52 $
13.7
123.0
10.3
44.5
8.5
14.7
—
11.0
1.9
104.0
10.1
29.3
47.88 $
3.00 $
22.35 $
28.20 $
4.43 $
5.48 $
1.18 $
16.6
146.9
14.2
55.3
2.6
5.6
—
3.5
5.4
129.9
13.8
40.9
36.85
2.30
16.16
21.32
3.51
6.16
0.94
$
$
$
$
$
$
$
Ad valorem tax expense
____________________________________________
(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
0.21
$
0.48 $
0.34 $
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:
Development wells
Oil
Gas
Non-productive
Exploratory wells
Oil
Gas
Non-productive
For the Years Ended December 31,
2018
2017
2016
Gross
Net
Gross
Net
Gross
Net
103
39
—
142
18
1
—
19
92
24
—
116
14
1
—
15
56
38
4
98
32
—
1
33
46
35
3
84
29
—
—
29
100
114
2
216
7
—
—
7
73
56
1
130
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.
Midland Basin:
RockStar
Sweetie Peck
Midland Basin Total (4)
Eagle Ford
Other (5)
Total
Developed Acres (1)
Undeveloped Acres (2)(3)
Total
Gross
Net
Gross
Net
Gross
Net
55,632
15,176
70,808
73,926
16,278
49,552
14,189
63,741
73,549
11,368
161,012
148,658
20,451
3,736
24,187
92,379
262,059
378,625
15,321
772
16,093
89,443
188,994
294,530
76,083
18,912
94,995
166,305
278,337
539,637
64,873
14,961
79,834
162,992
200,362
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.
Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.
(5)
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:
Major customer #1 (1)
Major customer #2 (1)
Group #1 of entities under common ownership (2)
For the Years Ended December 31,
2018
2017
2016
18%
10%
18%
6%
10%
17%
—%
5%
15%
Group #2 of entities under common ownership (2)
____________________________________________
(1) These major customers are purchasers of a portion of our production from our Permian region.
(2)
8%
12%
8%
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:
Corporate
Permian
South Texas & Gulf Coast
Mid-Continent (1)
Total
Approximate Square
Footage Leased
107,000
59,000
62,000
50,000
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.
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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;
any changes to the borrowing base or aggregate lender commitments under our Credit Agreement;
our outlook on future oil, gas, and NGL prices, well costs, service costs, and general and administrative costs;
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;
the possible divestiture or farm-down of, or joint venture relating to, certain properties;
proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve
estimates;
future oil, gas, and NGL production estimates;
cash flows, anticipated liquidity, interest and related debt service expenses, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital
investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
the possible divestiture or farm-down of, or joint venture relating to, certain properties; and
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;
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;
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;
our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
our ability to compete against competitors that have greater financial, technical, and human resources;
our ability to attract and retain key personnel;
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;
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
the possibility that exploration and development drilling may not result in commercially producible reserves;
our limited control over activities on outside-operated properties;
our reliance on the skill, expertise and availability of third-party service providers and equipment for our operated activities;
the possibility that title to properties in which we claim an interest may be defective;
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;
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;
the uncertainties associated with enhanced recovery methods;
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;
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
our ability to deliver required quantities of oil, gas, NGL, or water to contractual counterparties;
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
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;
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;
operating and environmental risks and hazards that could result in substantial losses;
the impact of extreme weather conditions, laws and regulations, and lease stipulations on our ability to conduct drilling activities;
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;
complex laws and regulations, including environmental regulations, that result in substantial costs, delays, and other risks;
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
new technologies may cause our current exploration and drilling methods to become obsolete;
the possibility of security threats, including terrorist attacks and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and
systems; and
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;
the level of consumer demand for oil, gas, and NGLs;
overall global and domestic economic conditions;
weather conditions;
the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;
liquefied natural gas deliveries to and from the United States;
the price and availability of alternative fuels;
technological advances and regulations affecting energy consumption and conservation;
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and
production controls;
political instability or armed conflict in oil or gas producing regions;
strengthening and weakening of the United States dollar relative to other currencies; and
governmental regulations and taxes.
Declines in oil, gas, and NGL prices would reduce our revenues and could also reduce the amount of oil, gas, and NGLs that we can produce
economically, which could have a materially adverse effect on us.
Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.
In the last decade, the United States and global economies and financial systems have experienced turmoil and upheaval characterized by extreme
volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure,
collapse, or sale of financial institutions, 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;
the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;
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
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;
cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any
dividend distributions or repurchase shares;
negatively impact current and prospective customers’ willingness to transact business with us;
impose additional insurance, guarantee and collateral requirements;
limit our access to bank and third-party guarantees, surety bonds and letters of credit; and
cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when
dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding
indebtedness.
We cannot provide assurance that any of our current Debt Ratings will remain in effect for any given period of time or that a Debt Rating will not be
further lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.
Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.
We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, and institutional and
individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate oil and
gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many oil and gas properties are sold
in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive
properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. We
may not be successful in acquiring and developing profitable properties in the face of this competition. In addition, other companies may have a greater ability to
continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation. In
addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as
needed. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities,
financial condition, and results of operations.
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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;
supply and demand for oil, gas, and NGLs;
curtailments or increases in consumption by oil purchasers and gas pipelines;
changes in government regulations or taxes, including severance and excise taxes; and
escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.
The timing of production from oil and gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves,
and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In
addition, the 10 percent discount factor required by the SEC to be used to calculate PV-10 for reporting purposes is not necessarily the most appropriate
discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and gas industry in general are subject.
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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;
title problems;
disputes with owners or holders of surface interests on or near areas where we operate;
pressure or geologic irregularities in formations;
engineering and construction delays;
equipment failures or accidents;
hurricanes, tornadoes, flooding, or other adverse weather conditions;
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governmental permitting delays;
compliance with environmental and other governmental requirements; and
shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe,
chemicals, water, sand, and other supplies.
The prevailing prices for oil, gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related
services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary
significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of
demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the available rigs in that region.
Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in
obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the
applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially
adverse effect on our ability to explore or develop our properties.
The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other
technologies we use do not allow us to know conclusively prior to drilling a well if oil, gas, or NGLs are present, or whether they can be produced economically.
Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling
and completion costs. Even if sufficient amounts of oil, gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or
experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to
repair the well, and/or the loss and abandonment of the well.
Results in 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;
one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative
contract arrangement.
In addition, commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially
over the price established by the commodity derivative contract.
The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil, gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we
operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various
economic and other market conditions, including declines in oil, gas, and NGL prices. The loss of one or more of these customers could reduce competition for
our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating
results, as we have numerous options for purchasers in each of our operating 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 ;
$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 ;
$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;
$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 ;
$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,
$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:
• 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;
placing us at a competitive disadvantage compared to our competitors with less debt; and
• making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.
If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement
or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we
are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity
securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on
a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future
credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost,
terms, conditions, and availability of future financing.
Our debt agreements, including 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;
• 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;
restrict dividends or other payments of our subsidiaries;
create liens that secure debt;
enter into transactions with affiliates; and
• 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 CO 2 (or modifications of these sources that result in an emissions increase of
75,000 tons per year or more of CO 2 e). 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.
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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.”
PART II
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
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
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)
— $
355 $
115,429 $
— $
115,784 $
—
26.64
25.69
—
25.69
—
—
—
—
—
3,072,184
3,072,184
3,072,184
3,072,184
3,072,184
Period
01/01/2018 -
03/31/2018
04/01/2018 -
06/30/2018
07/01/2018 -
09/30/2018
10/01/2018 -
12/31/2018
Total
(2)
____________________________________________
(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”).
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.
Statement of operations data:
Total operating revenues and other
income
Net income (loss)
Net income (loss) per share:
Basic
Diluted
Cash dividends declared and paid
per common share
Balance sheet data:
Total assets
Long-term debt:
Revolving credit facility
Senior Notes, net of
unamortized deferred financing
costs
Senior Convertible Notes, net of
unamortized discount and
deferred financing costs
$
$
$
$
$
$
$
$
$
As of or for the Years Ended December 31,
2018
2017
2016
2015
2014
(in millions, except per share data)
2,067.1 $
1,129.4 $
1,217.5 $
1,557.0 $
508.4 $
(160.8) $
(757.7) $
(447.7) $
4.54 $
4.48 $
(1.44) $
(1.44) $
(9.90) $
(9.90) $
(6.61) $
(6.61) $
0.10 $
0.10 $
0.10 $
0.10 $
2,522.3
666.1
9.91
9.79
0.10
6,352.9 $
6,176.8 $
6,393.5 $
5,621.6 $
6,483.1
— $
— $
— $
202.0 $
166.0
2,448.4 $
2,769.7 $
2,766.7 $
2,316.0 $
2,166.4
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)
Total stockholders’ equity
$
$
(36.8) $
(10.1) $
(190.5) $
216.5 $
(39.6)
2,920.3 $
2,394.6 $
2,497.1 $
1,852.4 $
2,286.7
Weighted-average common shares outstanding (in thousands):
Basic
Diluted
Reserves:
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Production and operations (in millions):
Oil, gas, and NGL production revenue
Oil, gas, and NGL production expense
Depletion, depreciation, amortization, and
asset retirement obligation liability
accretion
General and administrative (2)
Production volumes:
$
$
$
$
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per BOE
Expense per BOE:
Lease operating expense
Transportation costs
Production taxes
Ad valorem tax expense
Depletion, depreciation, amortization, and
asset retirement obligation liability
accretion
General and administrative (2)
Statement of cash flows data (in millions):
Provided by operating activities (2)
Used in investing activities (2)
$
$
$
$
$
$
$
$
$
$
$
$
111,912
113,502
111,428
111,428
76,568
76,568
67,723
67,723
175.7
158.2
104.9
145.3
1,321.8
1,280.1
1,111.1
1,264.0
107.4
503.4
96.5
468.1
105.7
395.8
115.4
471.3
67,230
68,044
169.7
1,466.5
133.5
547.7
1,636.4 $
1,253.8 $
1,178.4 $
1,499.9 $
2,481.5
487.4 $
507.9 $
597.6 $
723.6 $
715.9
665.3 $
116.5 $
557.0 $
117.3 $
790.7 $
124.8 $
921.0 $
156.1 $
18.8
103.2
7.9
43.9
13.7
123.0
10.3
44.5
16.6
146.9
14.2
55.3
19.2
173.6
16.1
64.2
56.80 $
47.88 $
36.85 $
41.49 $
3.43 $
27.22 $
37.27 $
3.00 $
22.35 $
28.20 $
2.30 $
16.16 $
21.32 $
2.57 $
15.92 $
23.36 $
4.74 $
4.36 $
1.52 $
0.48 $
4.43 $
5.48 $
1.18 $
0.34 $
3.51 $
6.16 $
0.94 $
0.21 $
3.73 $
6.02 $
1.13 $
0.39 $
15.15 $
12.53 $
14.30 $
14.34 $
2.65 $
2.64 $
2.26 $
2.43 $
767.5
166.5
16.7
152.9
13.0
55.1
80.97
4.58
33.34
45.01
4.28
6.11
2.13
0.46
13.92
3.02
720.6 $
515.4 $
552.8 $
990.8 $
1,456.6
(587.9) $
(201.5) $
(1,867.6) $
(1,144.6) $
(2,575.5)
Realized price, before the effect of derivative settlements:
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 .
Wells drilled but not completed at December 31,
2017
Wells drilled
Wells completed
Wells sold (1)
Other (2)
Wells drilled but not completed at December 31,
2018
_____________________________________
Permian
South Texas &
Gulf Coast
Bakken/Three
Forks (1)
Total
Gross Net
Gross Net
Gross Net
Gross Net
49
126
41
117
33
36
30
20
(114)
(104)
(40)
(26)
—
—
—
1
—
—
—
(1)
18
—
—
(18)
—
15
—
—
(15)
—
100
162
86
137
(154)
(130)
(18)
—
(15)
—
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:
Development costs
Exploration costs
Acquisitions
Proved properties
Unproved properties
For the Year Ended
December 31, 2018
(in millions)
$
1,147.6
184.9
1.3
55.7
Total, including asset retirement obligations (1) $
____________________________________________
(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.
1,389.5
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 :
Production:
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE)
Avg. Daily Equivalents (MBOE/d)
Relative percentage
____________________________________________
Permian
South Texas &
Gulf Coast
Rocky
Mountain (1)
Total
16.6
25.8
—
20.9
57.4
1.3
76.2
7.9
21.8
59.9
0.9
1.2
—
1.1
3.1
18.8
103.2
7.9
43.9
120.3
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 :
Oil (per Bbl):
Average NYMEX contract monthly price
Realized price, before the effect of derivative settlements
Effect of oil derivative settlements
Gas:
Average NYMEX monthly settle price (per MMBtu)
Realized price, before the effect of derivative settlements (per Mcf)
Effect of gas derivative settlements (per Mcf)
NGLs (per Bbl):
Average OPIS price (1)
Realized price, before the effect of derivative settlements
Effect of NGL derivative settlements
For the Years Ended December 31,
2018
2017
2016
$
$
$
$
$
$
$
$
$
64.77 $
56.80 $
(3.67) $
50.95 $
47.88 $
(2.28) $
3.09 $
3.43 $
(0.12) $
3.11 $
3.00 $
0.72 $
32.96 $
27.22 $
(6.78) $
27.63 $
22.35 $
(3.44) $
43.32
36.85
14.63
2.46
2.30
0.64
19.98
16.16
(0.60)
____________________________________________
(1) Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane,
and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent
our product mix for NGL production. Realized prices reflect our actual product mix.
We expect future prices for oil and NGLs to continue to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of
oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other
currencies. We expect oil prices to remain volatile due to uncertainty in global supply and demand.
We expect gas prices to remain near current levels in the near term due to the abundance of supply relative to demand. Demand from increased
liquefied natural gas (“LNG”) exports and gas exports to Mexico are expected to help balance supply.
We expect NGL prices to continue to benefit from increased demand from export and petrochemical markets while being offset by increased drilling
activity.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed
under the table above) as of February 7, 2019 , and December 31, 2018 :
NYMEX WTI oil (per Bbl)
NYMEX Henry Hub gas (per MMBtu)
OPIS NGLs (per Bbl)
$
$
$
54.48 $
2.75 $
25.11 $
46.96
2.85
24.04
As of February 7, 2019
As of December 31, 2018
We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our
use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet, the level of capital commitments
and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts. With our current derivative contracts, we
believe we have partially reduced our exposure to volatility in commodity prices and location differentials in the near term. Our use of costless collars for a
portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil
and gas production.
Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Risk in Overview of Liquidity and
Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
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
48
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 capital program to
concentrate on developing our top tier assets in the Midland Basin and Eagle Ford shale. We expect to allocate approximately 80% of our 2019 capital to our
Midland Basin program, which generates the highest margins in our portfolio. Planned drilling and completion activity in the Eagle Ford shale will be partially
funded by a third-party as part of our joint venture agreement. By concentrating our capital on high return investments and operating at strong performance
levels, we believe we will generate higher company-wide margins, cash flow growth, and value creation for our stockholders.
In our Permian region, we entered 2019 with six drilling rigs and three completion crews and anticipate maintaining this level of activity on average
throughout the remainder of the year. On our operated acreage, we plan to drill and complete approximately 100 net wells in 2019. Our focus will continue to be
on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals on our RockStar acreage in Howard and Martin Counties, Texas, and
our Sweetie Peck acreage in Upton and Midland Counties, Texas.
In our South Texas & Gulf Coast region, we entered 2019 with one drilling rig and added one completion crew in January. We anticipate averaging one
to two drilling rigs and one completion crew throughout 2019. We plan to drill approximately 28 net wells and plan to complete approximately 18 net wells in
2019. We expect our joint venture in a portion of our Eagle Ford North area will allow for an increase in our capital efficiency. This joint venture will continue to
test new technologies and completion designs at varied well spacing, potentially enhancing the asset’s value while reducing the required capital outlay that is
necessary to meet certain lease obligations.
Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our 2019 capital program.
49
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended December 31, 2018 , and the
immediately preceding three quarters.
For the Three Months Ended
December 31,
September 30,
June 30,
March 31,
2018
2018
2018
2018
11.3
392.5 $
121.5 $
182.0 $
14.3 $
30.4 $
309.7 $
$
$
$
$
$
$
(in millions)
12.0
458.4 $
127.6 $
201.1 $
13.1 $
29.5 $
(135.9) $
10.5
402.6 $
117.4 $
151.8 $
14.1 $
28.9 $
17.2 $
10.1
382.9
120.9
130.5
13.7
27.7
317.4
Production (MMBOE)
Oil, gas, and NGL production revenue
Oil, gas, and NGL production expense
Depletion, depreciation, amortization, and asset
retirement obligation liability accretion
Exploration
General and administrative
Net income (loss)
____________________________________________
Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
Average net daily production equivalent (MBOE per
day)
Lease operating expense (per BOE)
Transportation costs (per BOE)
Production taxes as a percent of oil, gas, and NGL
production revenue
Ad valorem tax expense (per BOE)
Depletion, depreciation, amortization, and asset
retirement obligation liability accretion (per BOE)
General and administrative (per BOE)
____________________________________________
Note: Amounts may not calculate due to rounding.
$
$
$
$
$
For the Three Months Ended
December 31,
September 30,
June 30,
March 31,
2018
2018
2018
2018
122.8
4.98
4.19
$
$
3.4%
0.39
$
16.10
2.69
$
$
130.2
4.41
4.20
$
$
4.1%
0.45
$
16.78
2.46
$
$
115.2
4.66
4.47
$
$
4.3%
0.41
$
14.48
2.76
$
$
112.7
4.95
4.63
4.4%
0.67
12.87
2.73
50
A Year-to-Year Overview of Selected Production and Financial Information, Including Trends
For the Years Ended
December 31,
Amount Change Between Percent Change Between
2018
2017
2016
2018/2017 2017/2016 2018/2017 2017/2016
(2.9)
(23.9)
(3.9)
(10.8)
(7.9)
(64.5)
(10.6)
(29.2)
42.5
32.1
0.8
75.4
2.9
(96.7)
0.5
3.6
Net production volumes: (1)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE)
Average net daily production: (1)
Oil (MBbl per day)
Gas (MMcf per day)
NGLs (MBbl per day)
Equivalent (MBOE per day)
18.8
103.2
7.9
43.9
51.4
282.7
21.8
120.3
13.7
123.0
10.3
44.5
37.4
337.0
28.2
121.8
16.6
146.9
14.2
55.3
45.4
401.5
38.8
151.0
5.1
(19.8)
(2.4)
(0.6)
14.0
(54.3)
(6.4)
(1.5)
Oil, gas, and NGL production revenue (in millions):
(1)
Oil production revenue
$
Gas production revenue
NGL production revenue
Total oil, gas, and NGL
production revenue
1,065.7 $
354.5
216.2
654.3 $
369.4
230.1
611.8 $
337.3
229.3
411.4 $
(15.0)
(13.9)
$
1,636.4 $
1,253.8 $
1,178.4 $
382.6 $
Oil, gas, and NGL production expense (in millions):
(1)
Lease operating expense
$
Transportation costs
Production taxes
Ad valorem tax expense
Total oil, gas, and NGL
production expense
208.1 $
191.5
66.9
20.9
196.9 $
243.6
52.4
15.0
194.0 $
340.3
51.9
11.4
11.2 $
(52.1)
14.5
5.9
$
487.4 $
507.9 $
597.6 $
(20.5) $
(89.7)
Oil (per Bbl)
Realized price, before the effect of derivative settlements:
56.80 $
3.43 $
27.22 $
37.27 $
NGLs (per Bbl)
Gas (per Mcf)
Per BOE
$
$
$
$
47.88 $
3.00 $
22.35 $
28.20 $
36.85 $
2.30 $
16.16 $
21.32 $
8.92 $
0.43 $
4.87 $
9.07 $
11.03
0.70
6.19
6.88
Per BOE data:
Production costs:
Lease operating expense
Transportation costs
Production taxes
Ad valorem tax expense
Depletion, depreciation,
amortization, and asset retirement
obligation liability accretion
General and administrative (2)
$
$
$
$
$
$
Derivative settlement gain (loss) (3) $
Earnings per share information:
Basic weighted-average common
shares outstanding (in thousands)
Diluted weighted-average common
shares outstanding (in thousands)
Basic net income (loss) per
common share
Diluted net income (loss) per
common share
$
$
4.74 $
4.36 $
1.52 $
0.48 $
4.43 $
5.48 $
1.18 $
0.34 $
3.51 $
6.16 $
0.94 $
0.21 $
15.15 $
2.65 $
(3.09) $
12.53 $
2.64 $
0.48 $
14.30 $
2.26 $
5.96 $
0.31 $
(1.12) $
0.34 $
0.14 $
2.62 $
0.01 $
(3.57) $
0.92
(0.68)
0.24
0.13
(1.77)
0.38
(5.48)
111,912
111,428
76,568
484
34,860
113,502
111,428
76,568
2,074
34,860
4.54 $
(1.44) $
(9.90) $
5.98 $
4.48 $
(1.44) $
(9.90) $
5.92 $
8.46
8.46
51
37 %
(16)%
(23)%
(1)%
37 %
(16)%
(23)%
(1)%
63 %
(4)%
(6)%
31 %
6 %
(21)%
28 %
39 %
(4)%
19 %
14 %
22 %
32 %
7 %
(20)%
29 %
41 %
21 %
— %
(744)%
— %
2 %
415 %
411 %
(18)%
(16)%
(27)%
(20)%
(17)%
(16)%
(27)%
(19)%
7 %
10 %
— %
6 %
1 %
(28)%
1 %
32 %
(15)%
30 %
30 %
38 %
32 %
26 %
(11)%
26 %
62 %
(12)%
17 %
(92)%
46 %
46 %
85 %
85 %
____________________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Prior periods have been adjusted 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 in Part II, Item 8 of this report for additional discussion.
(3) Derivative settlements for the years ended December 31, 2018 , 2017 , and 2016 , are included within the net derivative (gain) loss line item in the
accompanying statements of operations.
Average net equivalent daily production for the year ended December 31, 2018 , decreased one percent compared with 2017 . This decrease is
primarily due to the divestiture of our outside-operated Eagle Ford shale assets in the first quarter of 2017, the divestiture of our remaining producing assets in
the Rocky Mountain region in the first half of 2018, and decreasing production due to reduced capital investment in our operated Eagle Ford shale assets.
Production decreases in the Eagle Ford shale and Rocky Mountain region were substantially offset by our Permian region, which had a 91 percent increase in
production volumes for the year ended December 31, 2018 , compared with 2017 . We anticipate 2019 total production to be higher than 2018 total production,
driven by continued development of our Permian assets in the Midland Basin. Please refer to Comparison of Financial Results and Trends Between 2018 and
2017 and Between 2017 and 2016 below for additional discussion.
We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we
believe may require additional analysis and discussion.
Changes in production volumes, revenues, and costs are directly influenced by the volatility of commodity prices for the products we produce,
fluctuations in costs necessary to develop and operate our properties, our ability to increase efficiencies in operations, and changes in our overall asset portfolio.
Our realized price before the effect of derivative settlements on a per BOE basis for the year ended December 31, 2018 , increased 32 percent compared with
2017 , which was driven primarily by a 37 percent growth in higher margin oil production and improved benchmark pricing for oil and NGLs. For the year ended
December 31, 2018 , we realized a loss of $3.09 per BOE on the settlement of our derivative contracts, which was primarily driven by improving oil and NGL
prices in 2018, compared to a gain of $0.48 per BOE in 2017 . Settlement losses due to strengthening commodity prices in 2018 were partially offset by cash
settlement gains on our Midland Basin oil basis swaps that settled during 2018. Overall, there was a 19 percent increase in our realized price after the effect of
derivative settlements for the year ended December 31, 2018 , compared with 2017 .
Lease operating expense (“LOE”) increased seven percent on a per BOE basis for the year ended December 31, 2018 , compared with 2017 . This
increase was primarily driven by the increased percentage of oil in our total product mix, which has higher lifting costs per BOE. We expect LOE on a per BOE
basis to be flat or slightly higher in 2019 compared with 2018 as our product mix continues to shift towards more oil production. We anticipate volatility in LOE on
a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and changes in industry activity
and the effects this has on service provider costs.
Transportation costs decreased 20 percent on a per BOE basis for the year ended December 31, 2018 , compared with 2017 . The decrease in
transportation costs per BOE continues to be driven by production decreases from our Eagle Ford shale assets, which have higher average transportation costs.
Our Permian region production is primarily sold at the wellhead and therefore is subject to minimal transportation costs. We expect total transportation costs to
fluctuate in line with changes in production from our operated Eagle Ford shale program as these assets incur the majority of our transportation costs. On a per
BOE basis, we expect transportation costs to decrease in 2019, as compared with 2018, as production from our Midland Basin assets continues to become a
larger portion of our total production.
Production taxes on a per BOE basis for the year ended December 31, 2018 , increased 29 percent compared with 2017 , primarily due to a 32 percent
increase in our realized price on a per BOE basis before the effect of derivative settlements for the year ended December 31, 2018 , compared with 2017 . Our
overall production tax rate for the years ended December 31, 2018 , and 2017 was 4.1 percent and 4.2 percent , respectively. The slight decrease in our
production tax rate was primarily a result of divesting our remaining producing assets in the Rocky Mountain region, which were taxed at higher rates than our
Texas properties. We generally expect production tax expense to trend with oil, gas, and NGL production revenue on an absolute and per BOE basis. We
expect our overall production tax expense to remain consistent in 2019 compared to 2018, as the impacts of expected higher production volumes are expected
to be offset by lower commodity prices, assuming such prices are consistent with the 12-month strip pricing as of February 7, 2019 , as presented above within
the Oil, Gas, and NGL Prices section. We expect our overall production tax rate to remain consistent in 2019 compared to 2018. Product mix, the location of
production, and incentives to encourage oil and gas development can also impact the amount of production tax we recognize.
Ad valorem tax expense on a per BOE basis for the year ended December 31, 2018 , increased 41 percent compared with 2017 , due to changes in
our asset and production base and increased commodity price assumptions used in 2018 property tax valuations. The majority of ad valorem tax expense is
related to our Texas properties. We expect an overall increase in the value attributed to our reserves volumes in 2019, which would increase ad valorem tax on
an absolute basis compared with 2018. On a per BOE basis, we expect 2019 ad valorem expense to also increase compared to 2018, but this increase could be
partially offset by expected increases in production volumes in 2019 compared with the prior year.
52
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased 21 percent for
the year ended December 31, 2018 , compared with 2017 . The increase was primarily driven by the increase in production volumes from our Midland Basin
assets, which have higher depletion rates than our Eagle Ford shale assets. DD&A was also higher as a result of the capital we invested in 2018 to construct our
water transportation facilities in the Midland Basin. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing
arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. In general, we expect DD&A
expense on a per BOE basis in 2019 to increase compared with 2018 as production from our Midland Basin program continues to increase as a percentage of
our total production.
General and administrative (“G&A”) expense remained flat on a per BOE basis for the year ended December 31, 2018 , compared with 2017 . We
expect G&A expense on a per BOE basis in 2019 to decrease slightly compared with 2018 , as total production in 2019 is expected to increase from total 2018
production.
Please refer to Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016 for additional discussion.
Please refer to Note 9 - Earnings Per Share in Part II, Item 8 of this report for additional discussion on the types of shares included in our basic and
diluted net income (loss) per common share calculations. For the year ended December 31, 2018 , we recorded net income and thus considered dilutive shares
in the calculation of diluted net income per common share as of December 31, 2018 . We recorded a net loss for the years ended December 31, 2017 , and
2016 . Consequently, all potentially dilutive shares were anti-dilutive and were excluded from the calculation of diluted net loss per common share for the years
ended December 31, 2017 , and 2016 .
Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016
Net equivalent production, production revenue, and production expense
The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the years
ended December 31, 2018 , and 2017 :
Net Equivalent Production
Increase (Decrease)
Production Revenue
Increase (Decrease)
Production Expense
Increase (Decrease)
(MBOE per day)
(in millions)
(in millions)
Permian
South Texas & Gulf Coast
Rocky Mountain (1)
Total
27.4 $
(20.8)
(8.1)
(1.5) $
582.5 $
(95.9)
(104.0)
382.6 $
89.5
(64.5)
(45.5)
(20.5)
__________________________________________
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 net equivalent production in 2018 compared with 2017 . The decrease in overall production volumes was a
result of decreased production from our operated Eagle Ford shale assets as a result of reduced capital investment, the divestiture of our outside-operated
Eagle Ford shale assets, which occurred in the first quarter of 2017, and the divestiture of our remaining producing assets in the Rocky Mountain region in the
first half of 2018. Production decreases in the Eagle Ford shale and Rocky Mountain region were predominately offset by the 91 percent production volume
increase in our Permian region for the year ended December 31, 2018 , compared with 2017 . Increased production in the Permian region also drove oil
production as a percentage of our overall product mix to increase from 31 percent in 2017 , to 43 percent in 2018 . The increase in higher margin oil production
also increased realized prices, before the effects of derivative settlements, on a per BOE basis by 32 percent in 2018 , resulting in a 31 percent increase in oil,
gas, and NGL production revenue for the year ended 2018 compared to the prior year. Production expense in 2018 , compared with 2017 , decreased four
percent , and was primarily driven by the divestiture of the remaining assets in our Rocky Mountain region in the first half of 2018, which had the highest average
production costs in our portfolio.
53
The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the years
ended December 31, 2017 , and 2016 :
Net Equivalent Production
Increase (Decrease)
Production Revenue
Increase (Decrease)
Production Expense
Increase (Decrease)
(MBOE per day)
(in millions)
(in millions)
Permian
South Texas & Gulf Coast
Rocky Mountain
Total
19.8 $
(31.9)
(17.1)
(29.2) $
347.3 $
(113.5)
(158.4)
75.4 $
76.5
(92.5)
(73.7)
(89.7)
__________________________________________
Note: Amounts may not calculate due to rounding.
Oil, gas, and NGL production revenue increased six percent in 2017 compared with 2016 as the 32 percent increase in realized price, before the
effects of derivative settlements, on a per BOE basis was mostly offset by the 20 percent decrease in net equivalent production volumes as a result of divestiture
activity. 2017 production expense decreased $89.7 million when compared with 2016 due to a 20 percent decrease in net equivalent production volumes. The
15 percent decrease in production expense was less than the 20 percent decrease in net equivalent production volumes, which resulted in increased production
expense per BOE. On a per BOE basis, production expense increased slightly in 2017 compared with 2016 primarily due to the sale of our outside-operated
Eagle Ford shale assets in the first quarter of 2017, which had lower average lifting costs per BOE than our retained assets.
Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for discussion of trends on a per
BOE basis for the years ended December 31, 2018 , 2017 , and 2016 .
Net gain (loss) on divestiture activity
For the Years Ended December 31,
2018
2017
2016
(in millions)
Net gain (loss) on divestiture activity
$
426.9 $
(131.0) $
37.1
The $426.9 million net gain on divestiture activity recorded for the year ended December 31, 2018 , was the result of a total net gain of $410.6 million
recorded for the PRB Divestiture, which closed in the first quarter of 2018, and a combined total net gain of $15.4 million recorded for the Divide County
Divestiture and the Halff East Divestiture, both of which closed in the second quarter of 2018.
The net loss on divestiture activity recorded for the year ended December 31, 2017 , was primarily the result of $526.5 million of write-downs recorded
on certain retained North Dakota assets previously held for sale. These assets were divested in the second quarter of 2018, as discussed above. Partially
offsetting these write-downs recorded during 2017, was a $396.8 million total net gain recorded on the sale of our outside-operated Eagle Ford shale assets.
The net gain on divestiture activity recorded for the year ended December 31, 2016 , was primarily the result of the $29.5 million net gain recorded on
our Raven/Bear Den assets sold in the fourth quarter of 2016, as well as a $6.3 million total net gain recorded on the non-core Williston Basin, Powder River
Basin, and southeast New Mexico asset divestitures in the third quarter of 2016.
Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
For the Years Ended December 31,
2018
2017
2016
(in millions)
Depletion, depreciation, amortization, and asset retirement
obligation liability accretion
$
665.3 $
557.0 $
790.7
DD&A expense for the year ended December 31, 2018 , increased 19 percent compared with 2017. The increase is directly related to the 91 percent
increase in production volumes from our Midland Basin assets in the Permian region, which have higher depletion rates than our Eagle Ford shale assets in the
South Texas & Gulf Coast region.
54
DD&A expense for the year ended December 31, 2017 , decreased 30 percent compared with 2016 due to a 20 percent decrease in production
volumes and the impact of assets sold or classified as held for sale throughout 2017.
Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on
a per BOE basis.
Exploration
Geological and geophysical expenses
$
Exploratory dry hole
Overhead and other expenses (1)
For the Years Ended December 31,
2018
2017
2016
(in millions)
5.6 $
—
49.6
4.0 $
2.4
48.3
11.0
—
54.0
Total (1)
___________________________________________
(1) Prior periods have been adjusted to conform to the current period presentation on the consolidated financial statements. Please refer to Recently Issued
55.2 $
54.7 $
65.0
$
Accounting Standards in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion.
Exploration expense increased one percent for the year ended December 31, 2018 , compared with 2017 . In 2019 , we expect to continue focusing on
testing and delineating our Midland Basin acreage, which may result in additional geological and geophysical expenses; however, we do not expect total
exploration activity and related expenses to differ significantly compared with 2018 . Our expectations for exploration expense could change significantly
depending on actual geological and geophysical studies we perform, the amount of allocated overhead, and the potential for exploratory dry hole expense.
Exploration expense for the year ended December 31, 2017 , decreased 16 percent compared with 2016 driven primarily by geological and geophysical
expenses incurred for a seismic study performed on our Midland Basin acreage in the fourth quarter of 2016, which were not incurred in 2017.
Impairment of proved properties and Abandonment and impairment of unproved properties
Impairment of proved properties
Abandonment and impairment of unproved properties
$
$
— $
49.9 $
3.8 $
12.3 $
354.6
80.4
For the Years Ended December 31,
2018
2017
2016
(in millions)
There was no impairment of proved properties expense recognized for the year ended December 31, 2018 . Unproved property abandonments and
impairments recorded for the year ended December 31, 2018 related to actual and anticipated lease expirations, as well as actual and anticipated losses on
acreage due to title defects, changes in development plans, and other inherent acreage risks. We expect proved property impairments to more likely occur in
periods of declining or depressed commodity prices, and unproved property impairments to fluctuate with the timing of lease expirations or defects, unsuccessful
exploration activities, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, downward engineering
revisions, or unsuccessful exploration efforts may result in proved and unproved property impairments. Future impairments of proved and unproved properties
are difficult to predict; however, based on our updated commodity price assumptions as of February 7, 2019 , we do not expect any material impairments in the
first quarter of 2019 resulting from commodity price impacts. Please refer to Critical Accounting Policies and Estimates below for additional discussion.
There was no material impairment of proved properties recognized for the year ended December 31, 2017 . Abandonment and impairment of unproved
properties expense recorded during the year ended December 31, 2017 , related primarily to lease expirations.
The majority of our proved property impairments during 2016 were recorded in the first quarter of 2016 in our outside-operated Eagle Ford shale
program as a result of commodity price declines. In the fourth quarter of 2016, we recorded proved and unproved property impairment expense on our Powder
River Basin assets as a result of negative performance reserve revisions at year end 2016 and lower market prices on third-party acreage transactions.
Additionally, we allowed certain leases to expire throughout the year ended December 31, 2016 .
55
General and administrative
For the Years Ended December 31,
2018
2017
2016
(in millions)
General and administrative (1)
___________________________________________
(1) Prior periods have been adjusted to conform to the current period presentation on the consolidated financial statements. Please refer to Recently Issued
124.8
$
116.5 $
117.3 $
Accounting Standards in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion.
G&A expense for the year ended December 31, 2018 , was flat compared with 2017 . We expect G&A expense in total to continue to remain relatively
flat in 2019 compared with 2018. Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for
discussion of G&A costs on a per BOE basis.
G&A expense for the year ended December 31, 2017 , decreased six percent from 2016 primarily due to decreased compensation expense resulting
from lower average headcount for the full year in 2017.
Net derivative (gain) loss
For the Years Ended December 31,
2018
2017
2016
(in millions)
Net derivative (gain) loss
$
(161.8) $
26.4 $
250.6
We recognized a net derivative gain of $161.8 million for the year ended December 31, 2018 . For contracts that settled during 2018 , the fair value was
a net liability of $108.3 million at December 31, 2017 , and net cash settlements paid totaled $135.8 million, resulting in a $27.5 million loss. Additionally, we
recorded a $189.3 million mark-to-market gain on remaining contracts as of December 31, 2018 , resulting from a decrease in commodity strip prices toward the
end of 2018.
We recognized a net derivative loss of $26.4 million for the year ended December 31, 2017 . For contracts that settled during 2017 , the fair value was
a net liability of $60.9 million at December 31, 2016 , and net cash settlements received totaled $21.2 million, resulting in an $82.1 million gain. Offsetting this
gain was a $108.5 million mark-to-market loss on remaining contracts as of December 31, 2017, resulting from an increase in commodity strip prices.
We recognized a net derivative loss of $250.6 million for the year ended December 31, 2016 . For contracts that settled during 2016 , the fair value was
a net asset of $367.7 million at December 31, 2015, and net cash settlements received totaled $329.5 million, resulting in a $38.2 million loss. Additionally, we
recorded a $212.4 million mark-to-market loss on remaining contracts as of December 31, 2016, resulting from an increase in commodity strip prices.
Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Interest expense
For the Years Ended December 31,
2018
2017
2016
(in millions)
Interest expense
$
(160.9) $
(179.3) $
(158.7)
The $18.4 million , or 10 percent , decrease in interest expense for the year ended December 31, 2018 , compared with the same period in 2017 , was
driven in part by the redemption of our 2021 Senior Notes, which reduced interest expense related to debt in 2018 by $9.4 million compared with 2017. In
addition to the overall reduction in debt, interest expense was also reduced as the amount of interest we capitalized increased given our higher level of
development activity in 2018 compared with 2017. As a result of our overall reduction in long-term debt, we expect interest expense related to our Senior Notes
to be lower in 2019 compared with 2018; however, total interest expense can vary based on the timing and amount of any borrowings against our credit facility.
The $20.6 million , or 13 percent , increase in interest expense for the year ended December 31, 2017 , compared with 2016 , was driven by an
increase in total debt outstanding for full year 2017 due to additional debt issuances in the second half of 2016. Offsetting a portion of the increase was
additional interest expense of $10.0 million recognized in 2016 as a result of terminating an unused second lien facility that was no longer necessary to fund a
portion of our Midland Basin acquisitions.
56
Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report and Overview of Liquidity and Capital Resources below for additional
discussion.
Gain (loss) on extinguishment of debt
Gain (loss) on extinguishment of debt
$
(26.7) $
— $
15.7
For the Years Ended December 31,
2018
2017
2016
(in millions)
For the year ended December 31, 2018 , we recorded a $26.7 million net loss on the early extinguishment of our 2021 Senior Notes, 2023 Senior
Notes, and a portion of our 2022 Senior Notes. The net loss on extinguishment of debt included $20.4 million associated with the premiums paid upon
redemption and repurchase, and $6.3 million related to the acceleration of unamortized deferred financing costs.
For the year ended December 31, 2016 , we recorded a $15.7 million net gain on the early extinguishment of a portion of our Senior Notes, which
included $16.4 million associated with the discount realized upon repurchase, slightly offset by $700,000 related to the acceleration of unamortized deferred
financing costs.
Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Income tax (expense) benefit
Income tax (expense) benefit
Effective tax rate
For the Years Ended December 31,
2018
2017
2016
(in millions, except tax rate)
$
(143.4)
$
183.0
$
22.0%
53.2%
444.2
37.0%
The decrease in the effective tax rate for 2018 compared with 2017 is primarily due to the impacts of the Tax Cuts and Jobs Act (the “2017 Tax Act”).
The 18.5 percentage point increase in 2017 from a nonrecurring deferred tax adjustment was caused by the 14 percentage point decrease in the highest
marginal corporate rate from 35 percent to 21 percent beginning in 2018. The effect for 2017 was cumulatively added to a tax benefit calculated for that year.
The 14 percentage point decrease is reflected in the 2018 income tax expense rate. In addition, the year-over-year tax rate decreased due to effects related to
an excess tax deficiency from settlement of employee share-based payment awards, which had the effect of increasing the 2018 tax rate and partially offsetting
the year-over-year decrease. Other nominal 2018 tax rate decreases included effects from property sales, net apportionment changes, research credits, and
percentage depletion offset by the effects from limits to certain covered individual’s compensation.
The increase in the effective tax rate in 2017 compared with 2016 was primarily due to the enactment of the 2017 Tax Act into law on December 22,
2017, which decreased the highest marginal corporate tax rate and resulted in an 18.5 percentage point nonrecurring benefit adjustment increasing the effective
tax rate. This increase was partially offset by an excess tax deficiency from the settlement of employee share-based payment awards, state apportionment
changes due to the sale of our outside-operated Eagle Ford shale assets, and a net decrease in valuation allowances due to projected utilization of various state
net operating losses.
Please refer to Overview of Liquidity and Capital Resources and Critical Accounting Policies and Estimates below as well as Note 4 – Income Taxes in
in Part II, Item 8 of this report for further discussion.
57
Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the
foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments to maintain the flexibility to adjust our
activity and capital expenditures.
Sources of Cash
We currently expect our 2019 capital program to be funded by cash flows from operations, cash proceeds from prior divestiture activities, and with any
remaining cash needs being funded by borrowings under our credit facility. During the year ended December 31, 2018 , we generated $720.6 million of cash
flows from operating activities and we received $748.5 million of net proceeds from the sale of oil and gas properties. As of December 31, 2018 , the
combination of our cash balance of $78.0 million with our $1.0 billion of available borrowing capacity under our Credit Agreement provided $1.1 billion in liquidity.
Although we anticipate cash flows from these sources will be sufficient to fund our expected 2019 capital program, we may also elect to raise funds through debt
or equity financings or from other sources. Further, we may enter into additional carrying cost funding and sharing arrangements with third parties for particular
exploration and/or development programs. Our borrowing base could be reduced as a result of lower commodity prices, divestitures of proved properties, or the
issuance of debt securities. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current
stockholders could be diluted, and these newly-issued securities may have rights, preferences, or privileges senior to those of existing stockholders. Any future
downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be affected by the
general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our
industry.
We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil,
gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Please refer to Note 10 – Derivative
Financial Instruments in Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of
settlement of those contracts .
The enactment of the 2017 Tax Act reduced our highest marginal federal tax rate for 2018 and future years from 35 percent to 21 percent. It also
eliminated the domestic production activities deduction for all taxpayers, the alternative minimum tax (“AMT”) for corporate taxpayers, and may impact our ability
to deduct interest expense in future years. However, it did not impact current tax deductions for intangible drilling costs, percentage depletion, or amortization of
geological and geophysical expenses, and it will allow us the option to expense 100 percent of our equipment acquisition costs in future years. In general, we
believe the enactment of the 2017 Tax Act will have a positive impact on our future operating cash flows.
Credit Agreement
On September 28, 2018, we entered into the Sixth Amended and Restated Credit Agreement with our lenders. The Credit Agreement, which replaced
our Fifth Amended and Restated Credit Agreement, 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, if we have not completed certain repurchase, redemption, or refinancing activities
associated with our 2022 Senior Notes, as outlined in the Credit Agreement. We had no outstanding balance under our Credit Agreement as of December 31,
2018 , or 2017 . No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit
Agreement. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion as well as the presentation of the outstanding
balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of February 7, 2019 , December 31, 2018 , and
December 31, 2017 .
The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil
and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each
as determined by our lender group. We do not expect a material change to the borrowing base or the aggregate lender commitments during the next scheduled
redetermination on April 1, 2019 .
We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend
payments and requiring that we maintain certain financial ratios, as defined by the Credit Agreement. The financial covenants under the Credit Agreement
require that our (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters
(excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending
December 31, 2018 through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than
4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. We were in compliance with all financial and
non-financial covenants as of December 31, 2018 , and through the filing of this report. Please refer to the caption Non-GAAP Financial Measures below for the
calculation of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
58
We had no credit facility borrowing activity during 2018. This was a result of our cash balance entering 2018 and cash proceeds received during 2018
from the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. Our daily weighted-average credit facility debt balance was approximately $13.1
million and $183.8 million for the years ended December 31, 2017 , and 2016 , respectively. Cash flows provided by our operating activities, divestiture
proceeds, capital markets activities, and the amount of our capital expenditures, including acquisitions, all impact the amount we borrow under our credit facility.
Weighted-Average Interest Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the
Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discount related to the Senior
Convertible Notes. Our weighted-average borrowing rate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2018 ,
2017 , and 2016 .
Weighted-average interest rate
Weighted-average borrowing rate
For the Years Ended December 31,
2018
2017
2016
6.4%
5.8%
6.4%
5.8%
6.2%
5.7%
Our weighted-average interest rates and weighted average borrowing rates for the years ended December 31, 2018 , 2017 , and 2016 , have been
impacted by the timing of long-term debt issuances and redemptions, the average balance on our revolving credit facility under the Credit Agreement, and the
fees paid on the unused portion of our aggregate commitment. There was no change in our weighted-average interest rate or weighted-average borrowing rate
for the years ended December 31, 2018 , and 2017 . The increase in these rates for the year ended 2017, as compared with 2016 , was largely due to the
issuance of the Senior Convertible Notes and the 2026 Senior Notes in the third quarter of 2016. The rates disclosed in the above table do not reflect amounts
associated with the repurchase of Senior Notes, such as the discount realized or premium paid upon repurchase, or the acceleration of unamortized deferred
financing costs expensed upon repurchase. The rates also do not reflect the $10.0 million fee paid to terminate an unused second lien facility in the third quarter
of 2016. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Uses of Cash
We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating and general and
administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the acquisition, exploration, and development of oil and
gas properties are the primary use of our capital resources. During 2018 , we spent approximately $1.3 billion on capital expenditures and on acquisitions, which
were comprised primarily of unproved oil and gas properties. This amount differs from the costs incurred amount, which is accrual-based and includes asset
retirement obligations, geological and geophysical expenses, and exploration overhead amounts.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including the number and size of acquisitions, our
cash flows from operating, investing, and financing activities, and our ability to execute our drilling program. In addition, the impact of oil, gas, and NGL prices on
investment opportunities, the availability of capital, and the timing and results of our exploration and development activities may lead to changes in funding
requirements for future development. We periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition
and divestiture activities, debt requirements, and other factors.
We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such
repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will
depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts
involved in any such transaction may be material. Repurchases or exchanges are reviewed as part of the allocation of our capital. On July 16, 2018, we
completed the 2021 Senior Notes Redemption which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million . On
August 20, 2018, we issued $500.0 million in aggregate principal amount of 2027 Senior Notes which resulted in the receipt of net proceeds of $492.1 million
after deducting fees of $7.9 million , which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. The proceeds received from
the issuance of the 2027 Senior Notes were used to complete the Tender Offer and 2023 Senior Notes Redemption. As a result, we repurchased our 2023
Senior Notes and a portion of our 2022 Senior Notes during the third quarter of 2018, which resulted in the payment of total consideration, including accrued
interest, of $497.8 million. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion. As part of our strategy for 2019, we
will continue to focus on improving our debt metrics and potentially reducing outstanding debt.
59
As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the
approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market
conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes, the indenture governing our
Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically
reviews this program as part of the allocation of our capital. During 2018 , we did not repurchase any shares of our common stock, and we currently do not plan
to repurchase any outstanding shares of our common stock during 2019 .
During 2018 , we paid $11.2 million in dividends to our stockholders, reflecting a dividend of $0.10 per share. Our current intention is to continue to
make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, Credit Agreement, indentures governing our Senior
Convertible Notes and Senior Notes, other covenants, and other factors which could arise. The payment and amount of future dividends remains at the
discretion of our Board of Directors.
Analysis of Cash Flow Changes Between 2018 and 2017 and Between 2017 and 2016
The following tables present changes in cash flows between the years ended December 31, 2018 , 2017 , and 2016 , for our operating, investing, and
financing activities. The year ended December 31, 2016, has been adjusted 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 in Part II, Item 8 of this report for
additional discussion of adjustments made as a result of adopting new accounting standards. The analysis following each table should be read in conjunction
with our accompanying consolidated statements of cash flows (“accompanying statements of cash flows”) in Part II, Item 8 of this report.
Operating Activities
For the Years Ended December 31,
Amount Change Between Percent Change Between
2018
2017
2016
2018/2017 2017/2016 2018/2017 2017/2016
(in millions)
Net cash provided
by operating
activities
$
720.6 $
515.4 $
552.8 $
205.2 $
(37.4)
40%
(7)%
Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements,
increased $196.0 million , or 19 percent , to $1.2 billion for the year ended December 31, 2018 , compared with the same period in 2017 , primarily as a result of
an increase in our realized price, after the effect of derivative settlements. Interest paid decreased $13.4 million for the year ended December 31, 2018 ,
compared with the same period in 2017 , due to the redemption and repurchase of senior notes in the third quarter of 2018. Please refer to Note 5 – Long-Term
Debt in Part II, Item 8 of this report for additional discussion.
Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements,
decreased $91.6 million , or eight percent , to $1.0 billion for the year ended December 31, 2017 , compared with the same period in 2016 , as a result of a 20
percent decrease in production volumes partially offset by an increase in our realized price after the effect of derivative settlements. Interest paid increased
$34.3 million for the year ended December 31, 2017 , compared with the same period in 2016 , due to the issuance of our 2026 Senior Notes and Senior
Convertible Notes in the third quarter of 2016. Cash paid for LOE and ad valorem taxes in 2017 decreased $19.7 million , or nine percent , to $199.1 million
compared with 2016, as a result of a 20 percent decrease in production volumes partially offset by an increase in production costs on a per BOE basis,
specifically LOE, production taxes, and ad valorem taxes. Cash paid for G&A expense decreased $13.8 million , or 12 percent , to $98.6 million in 2017
compared with 2016, primarily as a result of the decrease in average headcount for 2017. During 2016, we paid $10.0 million to terminate a second lien facility
that was not needed to fund the Rock Oil Acquisition. Further, net cash provided by operating activities is affected by working capital changes.
Investing Activities
For the Years Ended December 31,
Amount Change Between Percent Change Between
2018
2017
2016
2018/2017 2017/2016 2018/2017 2017/2016
(in millions)
Net cash used in
investing
activities
$
(587.9) $
(201.5) $
(1,867.6) $
(386.4) $
1,666.1
192%
(89)%
Net cash used in investing activities increased for the year ended December 31, 2018 , compared with the same period in 2017 . Capital expenditures
in 2018 increased $414.8 million , or 47 percent , compared with 2017 as a result of increased drilling and
60
completion activities. During 2018, cash paid to acquire proved and unproved properties decreased $56.6 million , or 63 percent compared with 2017. Further,
net proceeds from the sale of oil and gas properties decreased $28.2 million for 2018 , compared with the same period in 2017 . During 2018 , net proceeds
were primarily from the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. During 2017 , net proceeds were primarily from the sale of our
outside-operated Eagle Ford shale assets.
Net cash used in investing activities decreased for the year ended December 31, 2017 , compared with the same period in 2016 . During 2017 , cash
paid to acquire proved and unproved properties in the Midland Basin totaled $89.9 million compared with $2.2 billion paid in 2016. Net proceeds from the sale of
oil and gas properties decreased $169.3 million for the year ended December 31, 2017 , compared with the same period in 2016 . During 2017 , net proceeds
were primarily from the sale of our outside-operated Eagle Ford shale assets, and during 2016 , net proceeds were primarily related to the divestitures of our
Raven/Bear Den and certain other non-core Permian and Rocky Mountain assets. Capital expenditures in 2017 increased $258.4 million , or 41 percent ,
compared with 2016 as a result of increased drilling and completion activities and slightly higher service provider costs.
In 2017, we adjusted year ended December 31, 2016, amounts to conform to the current period presentation on the consolidated financial statements.
As a result, we reclassified $3.0 million of restricted cash out of investing activities and combined it with cash and cash equivalents when reconciling the
beginning and end of period balances on the accompanying statements of cash flows, resulting in a decrease in net cash used in investing activities in 2016.
Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 for additional discussion of
adjustments made as a result of adopting new accounting standards.
Financing Activities
For the Years Ended December 31,
Amount Change Between Percent Change Between
2018
2017
2016
2018/2017 2017/2016 2018/2017 2017/2016
(in millions)
Net cash
provided by
(used in)
financing
activities
$
(368.7) $
(12.3) $
1,327.2 $
(356.4) $
(1,339.5)
2,898%
(101)%
Net cash used in financing activities increased for the year ended December 31, 2018 , compared with the same period in 2017 primarily as a result of
the redemption of $344.6 million principal outstanding of our 2021 Senior Notes. Cash flows related to financing activities during 2018 were also impacted by the
repurchase of $395.0 million principal outstanding of our 2023 Senior Notes and $85.0 million principal outstanding of our 2022 Senior Notes. Premiums totaling
$20.4 million were also paid in connection with these redemptions and repurchases during 2018. Offsetting these cash outflows, was cash provided by the
issuance of our 2027 Senior Notes in 2018 for net proceeds of $492.1 million . Dividend payments during the years ended December 31, 2018 and 2017 , were
$11.2 million and $11.1 million , respectively. We had a zero balance on our credit facility as of December 31, 2018 and 2017 , due to our cash balance resulting
from the proceeds received from the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture in the first half of 2018, proceeds received from the
sale of our outside-operated Eagle Ford shale assets during 2017, and proceeds received from the sale of our Raven/Bear Den assets in December 2016.
Consequently, there was no credit facility activity during 2018, and credit facility borrowings and repayments netted to zero in 2017.
During 2016 , we received $934.1 million of net proceeds from two public equity offerings, $491.6 million of net proceeds from our 2026 Senior Notes
issuance, and $166.6 million of net proceeds from our Senior Convertible Notes issuance. These proceeds were used to partially fund the Rock Oil Acquisition
and QStar Acquisition, as well as repay our credit facility balance of $202.0 million during the year ended December 31, 2016 . Additionally, in 2016, we paid
$24.2 million for capped call transactions related to our Senior Convertible Notes and paid $29.9 million for the repurchase of $46.3 million in aggregate principal
amount of a portion of our senior notes. Please refer to Note 5 – Long-Term Debt and Note 13 – Equity in Part II, Item 8 of this report for additional discussion.
Interest Rate Risk
We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of
December 31, 2018 , we had a zero balance on our credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal
balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the credit facility’s
fair market value, but will not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest
rate changes will not affect the fair market value, but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount
of interest we pay on our fixed-rate Senior Notes or fixed-rate Senior Convertible Notes, but can impact their fair market values. As of December 31, 2018 , our
outstanding principal amount of fixed-rate debt totaled $2.6 billion . Please refer to Note 11 – Fair Value Measurements in Part II, Item 8 of this report for
additional discussion on the fair values of our Senior Notes and Senior Convertible Notes.
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Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, overall profitability, access to capital, and future rate of growth.
Oil, gas, and NGL prices are subject to wide fluctuations in response to changes in supply and demand and other factors. The markets for oil, gas, and NGLs
have been volatile, especially over the last several years, and these markets will likely continue to be volatile in the future. The prices we receive for our
production depend on numerous factors beyond our control. Based on our 2018 production, a 10 percent decrease in our average realized oil, gas, and NGL
prices before the effects of derivative settlements would have reduced our oil, gas, and NGL production revenues by approximately $106.6 million , $35.4 million
, and $21.6 million , respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the year ended December 31, 2018 would
have offset the declines in oil, gas, and NGL production revenue by approximately $117.8 million.
We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative
contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2018 , a 10 percent increase or decrease in
the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net liability positions by approximately
$71.8 million , $23.9 million , and $12.9 million , respectively.
Schedule of Contractual Obligations
The following table summarizes our contractual obligations at December 31, 2018 , for the periods specified (in millions):
Contractual Obligations
Total
Less than 1
year
1-3 years
3-5 years
More than 5
years
Long-term debt (1)
Interest payments (2)
Delivery commitments (3)
Operating leases and contracts (3)
Asset retirement obligations (4)
Derivative liabilities (5)
Other (6)
Total
$
2,649.3 $
— $
172.5 $
970.4
287.8
169.7
116.9
75.8
36.4
155.5
40.3
92.2
2.3
63.1
4.0
309.8
150.8
41.2
36.9
12.7
17.5
476.8 $
272.1
2,000.0
233.0
88.2
19.9
1.0
—
14.9
8.5
16.4
76.7
—
—
$
4,306.3 $
357.4 $
741.4 $
872.9 $
2,334.6
____________________________________________
(1) Long-term debt consists of our Senior Notes and Senior Convertible Notes and assumes no principal repayment until the due dates of the instruments. The
(2)
actual payment dates may vary significantly. As of December 31, 2018 , we had a zero balance on our revolving credit facility.
Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the due dates of the instruments.
As our credit facility balance was zero at December 31, 2018 , the above table includes only the fee that would be paid on the unused credit facility’s
aggregate lender commitment amount through the maturity date of the Credit Agreement.
(3) Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts
and gathering, processing, transportation throughput, and delivery commitments. The amount relating to our gathering, processing, transportation
throughput, and delivery commitments reflects the aggregate undiscounted deficiency payments assuming we delivered no product. This amount does not
include any costs that may be incurred for certain contracts where we cannot predict with accuracy the amount and timing of any payments that may be
incurred for not meeting certain minimum commitments, as such payments are dependent upon the price of oil in effect at the time of settlement.
(4) Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our
accompanying consolidated balance sheets (“accompanying balance sheets”) as of December 31, 2018 . The timing and amount of the ultimate settlement
of these obligations is unknown and can be impacted by economic factors, a change in development plans, and federal and state regulations. Obligations
related to inactive wells or wells that are not economic at current commodity price levels as of December 31, 2018 , are shown as an obligation in 1-3 years,
however, there is substantial uncertainty on the timing of plugging or re-entering these wells. Please refer to Note 14 – Asset Retirement Obligations in Part
II, Item 8 of this report for additional discussion.
(5) Amounts shown represent only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices as of
December 31, 2018 , and exclude estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on
the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for
us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk
and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
(6) The majority of this amount is related to the unfunded portion of our estimated pension liability of $36.0 million , for which we have estimated the timing of
future payments based on historical annual contribution amounts.
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In December 2018, we entered into an agreement that included minimum drilling and completion requirements for certain existing leases. Based on our
expectation that we will meet these minimum requirements, this agreement is not reflected in the Schedule of Contractual Obligations table above. Please refer
to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion on this agreement.
Off-Balance Sheet Arrangements
As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial
partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of
facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest
entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during 2018 or
2017 , or through the filing of this report.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The
preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to
make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets
and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other
sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in circumstances,
global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant
Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and
results of operations and that require the application of significant management judgment.
Successful Efforts Method of Accounting . GAAP provides for two alternative methods for the oil and gas industry to use in accounting for oil and gas
producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely
used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a
given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note
1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report.
Oil and Gas Reserve Quantities . Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our
business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including
the calculations of depletion and impairment of proved and unproved oil and gas properties. Please refer to the Oil and Gas Producing Activities section of Note
1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve
quantities.
Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality
differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that
period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future
net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise, and estimates of new
discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in
estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit at least 80 percent of our total calculated proved
reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital
costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net
cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2018 , is the current market value of our estimated proved reserves. In accordance with SEC
requirements, we based these measures on a 12-month average of the first-day-of-the-month prices for the year ended December 31, 2018 . Actual future
prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Please refer to Risk Factors in Part I, Item 1A of this
report.
If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, which would reduce future net income.
Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact
the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.
63
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from
changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital
expenditures we incurred to develop other estimated proved reserves.
For the Years Ended December 31,
2018
MMBOE
Change
2017
MMBOE
Change
2016
MMBOE
Change
Revisions resulting from performance
Removal of proved undeveloped reserves no longer
in our five-year development plan
Revisions resulting from price changes
Total
(59.7)
(22.6)
13.5
(68.8)
7.4
(13.9)
23.1
16.6
(18.1)
(43.0)
(35.1)
(96.2)
As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue
experiencing these types of changes.
We cannot reasonably predict future commodity prices, although we believe that together, the below analyses provide reasonable information regarding
the impact of changes in pricing and trends on total estimated proved reserves. The following table reflects the estimated MMBOE change and percentage
change to our total reported estimated proved reserve volumes from the described hypothetical changes:
10 percent decrease in SEC pricing (1)
Average NYMEX strip pricing as of fiscal year end (2)
10 percent decrease in proved undeveloped reserves
(3)
For the year ended December 31, 2018
MMBOE
Change
Percentage
Change
(4.6)
(12.2)
(25.9)
(1)%
(2)%
(5)%
___________________________________________
(1) The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31,
2018 , and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future
service or equipment costs.
(2) The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2018 . SEC pricing of
$65.56 per Bbl for oil, $3.10 per MMBtu for gas, and $33.45 per Bbl for NGLs as of December 31, 2018 , compared to the five-year average NYMEX strip
pricing of $50.02 per Bbl for oil, $2.70 per MMBtu for gas, and $23.67 per Bbl for NGLs as of December 31, 2018 , would result in a two percent decrease to
our total reported estimated proved reserve volumes.
(3) The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2018 , and does not include any additional impacts
to our estimated proved reserves.
Additional reserve information can be found in the Reserves section in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information
in Part II, Item 8 of this report.
Impairment of Oil and Gas Properties . Proved properties are evaluated periodically for impairment on a pool-by-pool basis and when events or
changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of
our oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying
amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value (or discounted
future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors,
which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs,
development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows.
Unproved oil and gas properties are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be
recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive
prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other
information, including current drilling plans and our intent to renew leases. We estimate the fair value of unproved properties, using a market approach, which
takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated
reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by us or other market participants.
64
Proved and unproved oil and gas properties are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty
the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for
impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell.
We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any
amount of future impairment being difficult to predict, based on our commodity price assumptions as of February 7, 2019 , we do not expect any material
property impairments in the first quarter of 2019 resulting from commodity price impacts.
Please refer to Note 1 – Summary of Significant Accounting Policies and Note 11 – Fair Value Measurements in Part II, Item 8 of this report for
discussion of impairments of oil and gas properties recorded for the years ended December 31, 2018 , 2017 , and 2016 .
Purchase Price Allocation . Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities
acquired based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned to proved and
unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including
price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgment by
management at the time of the valuation.
Asset Retirement Obligations . We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas
properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells and our current understanding of federal and state
regulatory requirements. Our present value calculations require us to estimate the cost, the economic lives and timing of abandonment of our properties, future
inflation rates, and the appropriate credit-adjusted risk-free discount rate to use. The impact to the accompanying consolidated statements of operations
(“accompanying statements of operations”) from these estimates is reflected in our depletion, depreciation, and amortization calculations and occurs over the
remaining life of our respective oil and gas properties. Please refer to Note 14 – Asset Retirement Obligations in Part II, Item 8 of this report for additional
discussion.
Revenue Recognition . Effective January 1, 2018, our revenue recognition policy was updated to reflect the adoption of new accounting guidance. Our
revenue recognition policy is a critical accounting policy because revenue is a key component of our results of operations and our forward-looking statements
contained in our analysis of liquidity and capital resources. Our primary source of revenue is derived by the sale of produced oil, gas, and NGLs. Revenue is
recognized at the point in time when control of the product, as defined by contractual terms, transfers to the purchaser. Payment for these sales is typically
received between 30 and 90 days after the date of production. At the end of each month, we make estimates of the amount of production delivered to the
purchaser and the price we will receive. We use our knowledge of our properties, contractual arrangements, historical performance, NYMEX, local spot market,
OPIS prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month
payment is received. A 10 percent change in our revenue accrual at year end would have impacted total operating revenues by approximately $10.7 million in
2018 . Please refer to Note 1 – Summary of Significant Accounting Policies under the heading Recently Issued Accounting Standards and Note 2 - Revenue
from Contracts with Customers in Part II, Item 8 of this report for additional discussion.
Derivative Financial Instruments . We periodically enter into commodity derivative contracts to manage our exposure to oil, gas, and NGL price volatility
and location differentials. We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any
such amounts in accumulated other comprehensive income (loss). The estimated fair value of our derivative instruments requires substantial judgment. These
values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values we report in our
consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which
are beyond our control.
Income Taxes . We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our
consolidated financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is
recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely
than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we
estimate the tax basis of our assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital
loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods
in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our
results of operations. A one percent change in our effective tax rate would have changed our calculated income tax expense by approximately $6.5 million for
the year ended December 31, 2018 .
Accounting Matters
Please refer to Recently Issued Accounting Standards under Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for
information on new authoritative accounting guidance.
65
Environmental
We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures
will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to
predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital
expenditures, liquidity, and results of operations.
Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight
formations. For additional information about hydraulic fracturing and related environmental matters, please refer to Risk Factors – Risks Related to Our Business
– 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 .
Climate Change. In June 2013, President Obama announced a Climate Action Plan designed to further reduce greenhouse gas emissions and prepare
the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas
sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations that
amend and expand 2012 regulations for the oil and gas sector by setting emission limits for VOCs and methane, a greenhouse gas, or GHG, and added
requirements for previously unregulated sources. The 2016 NSPS requires reduction 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 regulation requires, among
other things, greenhouse gas and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak
detection and repair for well sites and quarterly boosting and garnering compressor stations and gas transmission compressor stations; control requirements
and emission limits for pneumatic pumps; and additional requirements for control of greenhouse gases and VOCs from well completions. Both the 2012 and
2016 rules are the subject of Petitions for Review before the U.S. Circuit Court of Appeals for the District of Columbia, although the litigation of both rules has
been stayed. In October 2018, the EPA proposed scaling back provisions of the 2016 NSPS directed toward cutting leaks of methane, including proposing
allowing only annual inspections for many sites. The rule does not extend to existing sources and the Trump EPA has rescinded the Information Collection
Request that was intended to gather information to develop existing source standards. On November 16, 2016, the BLM finalized regulations to address
methane emissions from oil and gas operations on federal and tribal lands, as part of President Obama’s Climate Action Plan. The regulations were intended to
reduce the waste of gas from flaring, venting, and leaks by oil and gas production. The rule included requirements that prohibits venting gas except in limited
circumstances and limits flaring of gas and includes requirements for leak detection and repair. The rule also increased royalty payments for “waste” gas that is
released in contravention of the rule requirements. 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.
In August of 2015, the EPA finalized existing source performance standards as stringent state emission “goals” for utilities to reduce greenhouse gas
emissions. The proposed standards focus on re-dispatching electricity from coal-fired units to gas combined cycle plants and renewables. In February 2016,
however, the Supreme Court stayed these rules pending judicial review. The EPA has proposed a repeal of the rule based on a new legal interpretation of the
EPA’s authority. The EPA proposed a replacement rule, the Affordable Clean Energy Rule, in August 2018.
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 legal 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 addition, there have
been international conventions and efforts to establish standards for the reduction of greenhouse gases globally, including the Paris accords in December 2015.
The conditions for entry into force of the Paris accords were met on October 5, 2016 and the Agreement went into force 30 days later on November 4, 2016.
However, in August 2017, the U.S. notified the United Nations Secretary-General that it intends to withdraw from the agreement as soon as it is able to do so, or
November 2019.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such
as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any
such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently,
legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition, and results of
operations. Finally, scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere produce climate changes that likely
have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an
adverse effect on our financial condition and results of operations.
66
In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such as enhanced oil recovery,
carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change
legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces
lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become
more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel
standards, gas may become a more attractive transportation fuel. Approximately 39 percent and 46 percent of our production on a BOE basis in 2018 and 2017
, respectively, was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs,
could also benefit us through the potential to obtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of
carbon dioxide.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and
asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based
compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and
certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are
generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present
because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally
generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on
adjusted EBITDAX ratios as further described in the Credit Agreement section in Overview of Liquidity and Capital Resources above. In addition, adjusted
EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil
and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions.
Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating
activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income
(loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our credit
facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum
permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from
borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are
unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes and
Senior Convertible Notes would be entitled to exercise all of their remedies for default.
67
The following table provides reconciliations of our net income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX
(non-GAAP) for the periods presented:
Net income (loss) (GAAP)
Interest expense
Interest income (1)
Income tax expense (benefit)
Depletion, depreciation, amortization, and asset retirement obligation
liability accretion
Exploration (2) (3)
Impairment of proved properties
Abandonment and impairment of unproved properties
Stock-based compensation expense
Net derivative (gain) loss
Derivative settlement gain (loss)
Net (gain) loss on divestiture activity
(Gain) loss on extinguishment of debt
Other, net
Adjusted EBITDAX (non-GAAP) (3)
Interest expense
Interest income (1)
Income tax (expense) benefit
Exploration (2) (3)
Amortization of debt discount and deferred financing costs
Deferred income taxes
Other, net (3)
Changes in current assets and liabilities
Net cash provided by operating activities (GAAP) (3)
____________________________________________
(1)
For the Years Ended December 31,
2018
2017
2016
(in thousands)
$
508,407 $
(160,843) $
(757,744)
160,906
(5,191)
143,370
665,313
49,627
—
49,889
23,908
(161,832)
(135,803)
(426,917)
26,740
1,977
900,394
(160,906)
5,191
(143,370)
(49,627)
15,258
141,708
(1,690)
13,671
179,257
(3,968)
(182,970)
557,036
48,413
3,806
12,272
22,700
26,414
21,234
131,028
35
8,820
663,234
(179,257)
3,968
182,970
(48,413)
16,276
158,685
(362)
(444,172)
790,745
58,523
354,614
80,367
26,897
250,633
329,478
(37,074)
(15,722)
(4,764)
790,104
(158,685)
362
444,172
(58,523)
9,938
(192,066)
(448,643)
(935)
69,613
(5,167)
(20,754)
$
720,629 $
515,390 $
552,804
Interest income is included within the other non-operating income (expense), net line item on the accompanying statements of operations in Part II, Item 8
of this report.
(2) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying
statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying
statements of operations for the component of stock-based compensation expense recorded to exploration expense.
(3) Certain prior period amounts have been adjusted to conform to the current period presentation on the consolidated financial statements. Please refer to
Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion.
68
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk in Item 7 above, as well as under the
section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place under Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and
is incorporated herein by reference.
69
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of SM Energy Company and subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the Company) as of December 31, 2018 and 2017 ,
the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period
ended December 31, 2018 , and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017 , and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 2018 , in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal
control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 21, 2019 expressed an unqualified opinion thereon.
Adoption of ASU No. 2016-09
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for share-based arrangements in the
December 31, 2017 consolidated financial statements due to the adoption of ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements
to Employee Share-Based Payment Accounting .
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial
statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to
assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating
the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We
believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2012.
Denver, Colorado
February 21, 2019
70
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
December 31,
2018
2017
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Derivative assets
Prepaid expenses and other
Total current assets
Property and equipment (successful efforts method):
Proved oil and gas properties
Accumulated depletion, depreciation, and amortization
Unproved oil and gas properties
Wells in progress
Properties held for sale, net
Other property and equipment, net of accumulated depreciation of $57,102 and $49,985, respectively
Total property and equipment, net
Noncurrent assets:
Derivative assets
Other noncurrent assets
Total noncurrent assets
Total assets
Current liabilities:
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued expenses
Derivative liabilities
Total current liabilities
Noncurrent liabilities:
Revolving credit facility
Senior Notes, net of unamortized deferred financing costs
Senior Convertible Notes, net of unamortized discount and deferred financing costs
Asset retirement obligations
Asset retirement obligations associated with oil and gas properties held for sale
Deferred income taxes
Derivative liabilities
Other noncurrent liabilities
Total noncurrent liabilities
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,241,966 and 111,687,016
shares, respectively
Additional paid-in capital
Retained earnings (1)
Accumulated other comprehensive loss (1)
Total stockholders’ equity
Total liabilities and stockholders’ equity
$
$
$
$
77,965 $
167,536
175,130
8,632
429,263
7,278,362
(3,417,953)
1,581,401
295,529
5,280
88,546
5,831,165
58,499
33,935
92,434
6,352,862 $
403,199 $
62,853
466,052
—
2,448,439
147,894
91,859
—
223,278
12,496
42,522
2,966,488
1,122
1,765,738
1,165,842
(12,380)
2,920,322
6,352,862 $
313,943
160,154
64,266
10,752
549,115
6,139,379
(3,171,575)
2,047,203
321,347
111,700
106,738
5,554,792
40,362
32,507
72,869
6,176,776
386,630
172,582
559,212
—
2,769,663
139,107
103,026
11,369
79,989
71,402
48,400
3,222,956
1,117
1,741,623
665,657
(13,789)
2,394,608
6,176,776
____________________________________________
(1) The Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. Please refer to Note 1
– Summary of Significant Accounting Policies for further detail.
The accompanying notes are an integral part of these consolidated financial statements.
71
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Operating revenues and other income:
Oil, gas, and NGL production revenue
Net gain (loss) on divestiture activity
Other operating revenues
Total operating revenues and other income
Operating expenses:
Oil, gas, and NGL production expense
Depletion, depreciation, amortization, and asset retirement obligation liability
accretion
Exploration
Impairment of proved properties
Abandonment and impairment of unproved properties
General and administrative
Net derivative (gain) loss
Other operating expenses, net
Total operating expenses
Income (loss) from operations
Interest expense
Gain (loss) on extinguishment of debt
Other non-operating income (expense), net
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Basic weighted-average common shares outstanding
Diluted weighted-average common shares outstanding
Basic net income (loss) per common share
Diluted net income (loss) per common share
For the Years Ended
December 31,
2018
2017
2016
(as adjusted)
(as adjusted)
$
1,636,357 $
1,253,783 $
1,178,426
426,917
3,798
2,067,072
(131,028)
6,621
1,129,376
487,367
507,906
665,313
55,166
—
49,889
116,504
(161,832)
18,328
1,230,735
836,337
(160,906)
(26,740)
3,086
651,777
(143,370)
557,036
54,713
3,806
12,272
117,283
26,414
13,667
1,293,097
(163,721)
(179,257)
(35)
(800)
(343,813)
182,970
$
$
$
508,407 $
(160,843) $
111,912
113,502
4.54 $
4.48 $
111,428
111,428
(1.44) $
(1.44) $
37,074
1,950
1,217,450
597,565
790,745
64,970
354,614
80,367
124,828
250,633
10,772
2,274,494
(1,057,044)
(158,685)
15,722
(1,909)
(1,201,916)
444,172
(757,744)
76,568
76,568
(9.90)
(9.90)
The accompanying notes are an integral part of these consolidated financial statements.
72
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Net income (loss)
Other comprehensive income (loss), net of tax:
Pension liability adjustment (1)
Total other comprehensive income (loss), net of tax
Total comprehensive income (loss)
$
$
For the Years Ended
December 31,
2018
2017
2016
508,407 $
(160,843) $
(757,744)
4,378
4,378
767
767
512,785 $
(160,076) $
(1,154)
(1,154)
(758,898)
____________________________________________
(1) Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.
The accompanying notes are an integral part of these consolidated financial statements.
73
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except share data and dividends per share)
Common Stock
Amount
Additional
Paid-in Capital
Retained
Earnings
Accumulated Other
Comprehensive Loss
42,710,949
427
1,382,666
Balances, January 1, 2016
Net loss
Other comprehensive loss
Cash dividends, $ 0.10 per share
Issuance of common stock under Employee Stock
Purchase Plan
Issuance of common stock upon vesting of RSUs
and settlement of PSUs, net of shares used for tax
withholdings
Stock-based compensation expense
Issuance of common stock from stock offerings,
net of tax
Equity component of 1.50% Senior Convertible
Notes due 2021 issuance, net of tax
Purchase of capped call transactions
Other
Shares
68,075,700 $
—
—
—
218,135
199,243
53,473
—
—
—
Balances, December 31, 2016
111,257,500 $
Net loss
Other comprehensive income
Cash dividends, $0.10 per share
Issuance of common stock under Employee Stock
Purchase Plan
Issuance of common stock upon vesting of RSUs,
net of shares used for tax withholdings
Stock-based compensation expense
Cumulative effect of accounting change (1)
Other
Balances, December 31, 2017
Net income
Other comprehensive income
Cash dividends, $0.10 per share
Issuance of common stock under Employee Stock
Purchase Plan
Issuance of common stock upon vesting of RSUs,
net of shares used for tax withholdings
Stock-based compensation expense
Cumulative effect of accounting change (1)
—
—
—
186,665
171,278
71,573
—
—
111,687,016 $
—
—
—
199,464
291,745
63,741
—
681 $
—
—
—
2
2
1
305,607 $
—
—
—
4,196
(2,356)
26,896
—
—
—
1,113 $
—
—
—
2
1
1
—
—
1,117 $
—
—
—
2
3
—
—
1,122 $
33,575
(24,195)
(9,833)
1,716,556 $
—
—
—
2,621
(1,241)
22,699
1,108
(120)
1,741,623 $
—
—
—
3,185
(2,978)
23,908
—
1,765,738 $
1,559,515 $
(757,744)
—
(7,751)
—
—
—
—
—
—
—
794,020 $
(160,843)
—
(11,144)
—
—
—
43,624
—
665,657 $
508,407
—
(11,191)
—
—
—
2,969
1,165,842 $
Balances, December 31, 2018
____________________________________________
(1) Refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.
112,241,966 $
The accompanying notes are an integral part of these consolidated financial statements.
74
Total
Stockholders’
Equity
1,852,401
(757,744)
(1,154)
(7,751)
4,198
(2,354)
26,897
1,383,093
33,575
(24,195)
(9,833)
2,497,133
(160,843)
767
(11,144)
2,623
(1,240)
22,700
44,732
(120)
(13,402)
$
—
(1,154)
—
—
—
—
—
—
—
—
(14,556)
$
—
767
—
—
—
—
—
—
(13,789)
$
2,394,608
—
4,378
—
—
—
—
(2,969)
508,407
4,378
(11,191)
3,187
(2,975)
23,908
—
(12,380)
$
2,920,322
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
Impairment of proved properties
Abandonment and impairment of unproved properties
Stock-based compensation expense
Net derivative (gain) loss
Derivative settlement gain (loss)
Amortization of debt discount and deferred financing costs
(Gain) loss on extinguishment of debt
Deferred income taxes
Other, net
Changes in current assets and liabilities:
Accounts receivable
Prepaid expenses and other
Accounts payable and accrued expenses
Accrued derivative settlements
Net cash provided by operating activities
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties
Capital expenditures
Acquisition of proved and unproved oil and gas properties
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from credit facility
Repayment of credit facility
Net proceeds from senior notes
Cash paid to repurchase senior notes, including premium
Net proceeds from Senior Convertible Notes
Cash paid for capped call transactions
Net proceeds from sale of common stock
Dividends paid
Other, net
Net cash provided by (used in) financing activities
Net change in cash, cash equivalents, and restricted cash (1)
Cash, cash equivalents, and restricted cash at beginning of period (1)
Cash, cash equivalents, and restricted cash at end of period (1)
For the Years Ended
December 31,
2018
2017
2016
$
508,407 $
(160,843) $
(757,744)
(426,917)
665,313
—
49,889
23,908
(161,832)
(135,803)
15,258
26,740
141,708
287
(30,152)
(729)
23,819
20,733
720,629
748,509
(1,303,188)
(33,255)
(587,934)
—
—
492,079
(845,002)
—
—
3,187
(11,191)
(7,746)
(368,673)
131,028
557,036
3,806
12,272
22,700
26,414
21,234
16,276
35
(192,066)
7,885
13,997
(1,953)
44,985
12,584
515,390
776,719
(888,353)
(89,896)
(201,530)
406,000
(406,000)
—
(2,357)
—
—
2,623
(11,144)
(1,411)
(12,289)
(235,978)
313,943
77,965 $
301,571
12,372
313,943 $
$
(37,074)
790,745
354,614
80,367
26,897
250,633
329,478
9,938
(15,722)
(448,643)
(9,931)
(10,562)
8,478
(53,210)
34,540
552,804
946,062
(629,911)
(2,183,790)
(1,867,639)
947,000
(1,149,000)
491,640
(29,904)
166,617
(24,195)
938,268
(7,751)
(5,486)
1,327,189
12,354
18
12,372
____________________________________________
(1) Cash, cash equivalents, and restricted cash for the year ended December 31, 2016, includes $3.0 million of restricted cash which is included in other noncurrent assets
on the accompanying balance sheets.
The accompanying notes are an integral part of these consolidated financial statements.
75
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(in thousands)
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest
Net cash paid (refunded) for income taxes
Investing activities:
Changes in capital expenditure accruals and other
Supplemental non-cash investing activities:
Carrying value of properties exchanged
Supplemental non-cash financing activities:
Issuance of common stock for an asset acquisition (1)
Non-cash (gain) loss on extinguishment of debt, net
For the Years Ended
December 31,
2018
2017
2016
(150,727) $
(164,097) $
2,995 $
5,986 $
(129,761)
(4,690)
(2,774) $
7,309 $
8,044
95,121 $
293,963 $
733
— $
6,334 $
— $
22 $
437,194
(15,722)
$
$
$
$
$
$
____________________________________________
(1) Refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions and Note 13 – Equity for additional discussion.
76
SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration,
development, and production of oil, gas, and NGLs in onshore North America.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the
instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the
consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2018 , through the filing of this report.
Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the consolidated financial statements.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas
reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset
retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash and Cash Equivalents and Restricted Cash
The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of
cash and cash equivalents approximates fair value due to the short-term nature of these instruments. Restricted cash includes cash that is contractually
restricted for its use through an agreement with a non-related party. The Company includes restricted cash in other noncurrent assets on the accompanying
balance sheets.
Accounts Receivable
The Company’s accounts receivable consists mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the
Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover
non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had
minimal bad debts.
Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by
the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 15 – Accounts Receivable and Accounts Payable and
Accrued Expenses for additional disclosure.
Concentration of Credit Risk and Major Customers
The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related
industries. The creditworthiness of customers and other counterparties is subject to regular review.
77
The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as oil, gas, and NGLs are
products with well-established markets and numerous purchasers in the Company’s operating regions. The Company had the following major customers and
sales to entities under common ownership, which accounted for 10 percent or more of its total oil, gas, and NGL production revenue for at least one of the
periods presented:
Major customer #1 (1)
Major customer #2 (1)
Group #1 of entities under common ownership (2)
For the Years Ended December 31,
2018
2017
2016
18%
10%
18%
6%
10%
17%
—%
5%
15%
Group #2 of entities under common ownership (2)
____________________________________________
(1) These major customers are purchasers of a portion of the Company’s production from its Permian region.
(2)
8%
12%
8%
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 the Company’s total oil, gas,
and NGL production revenue.
The Company’s policy is to use the commodity affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each
counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 derivative counterparties meet both of these requirements
as of the filing of this report.
The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The
Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the
amount of credit exposure to any single institution or investment. The Company maintains investments in highly rated, highly liquid investment products with
numerous banks that are party to its revolving credit facility.
Oil and Gas Producing Activities
Proved properties . The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of
development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well
equipment, intangible development costs, and operational support facilities in the field, are depleted on a group basis (properties aggregated with a common
geological structure) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are
depleted on the same group asset basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of
DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.
Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may
not be recoverable. The Company uses an income valuation technique, which converts future cash flow to a single present value amount, to measure the fair
value of proved properties through an application of discount rates and price forecasts, as selected by the Company’s management. The Company uses
discount rates that are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of
possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The discount rates typically range from 10 percent to
15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows. The prices for oil and gas are forecasted based on
NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for
NGLs are forecasted using OPIS pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also
adjusted as deemed appropriate for these estimates.
The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is
recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved
property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other
sales of proved properties.
Unproved properties . The unproved oil and gas properties line item on the accompanying balance sheets consists of costs incurred to acquire
unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved
properties and depleted on a units-of-production basis. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there
is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the
portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be
nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair
value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms,
future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for
similar, recent acreage transactions by the Company or other market participants.
78
For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on a group basis,
neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the
accompanying statements of operations in the amount of such excess.
Exploratory . Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage
are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically
recoverable reserves have been found. If economically recoverable reserves are found, exploratory wells costs will be capitalized as proved properties and will
be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well
costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper
designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is
drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are
included in cash flows from investing activities as part of capital expenditures within the accompanying statements of cash flows.
Other Property and Equipment
Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost.
The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes
software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are
capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful
lives of the assets, which range from 3 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the
capitalized costs and related accumulated depreciation are removed from the accounts.
Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be
recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on
the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and
unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the
assets.
Assets Held for Sale
Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the
accompanying balance sheets at the lower of carrying value or fair value less the estimated cost to sell. Properties classified as held for sale, including any
corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most
current bid prices received from third-parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques
discussed above. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions .
Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities
requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived
asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved oil and gas properties
in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with
the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement
obligations is included in the operating section of the Company’s accompanying statements of cash flows.
The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic
lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate
estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities
range from 5.5 percent to 12 percent . In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the
liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in
inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a
reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2018 , and 2017 .
Derivative Financial Instruments
The Company periodically enters into derivative commodity instruments to reduce its exposure to pricing volatility for a portion of its expected future oil,
natural gas, and NGL production. These instruments typically include commodity price swaps and costless
79
collars, as well as, basis differential swaps. Derivative instruments are measured at fair value and are included in the accompanying consolidated balance
sheets as assets and/or liabilities. The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company
reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives are
included within cash flows from operations in the accompanying consolidated statement of cash flows. For additional discussion on derivatives, please see Note
10 – Derivative Financial Instruments .
Revenue Recognition
The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when control of the
product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Revenue accruals are recorded
monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual
amounts received are recorded in the month payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.
Stock-Based Compensation
At December 31, 2018 , the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance
share units (“PSUs”) issued to employees and RSUs and restricted stock issued to non-employee directors, as well as an employee stock purchase plan
available to eligible employees. These are more fully described in Note 7 – Compensation Plans . The Company records expense associated with the fair value
of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at
the time of grant, and is included within general and administrative and exploration expense in the accompanying statements of operations. For stock-based
compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected
to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company
accounts for forfeitures of stock-based compensation awards as they occur.
Income Taxes
The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary
differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using current
enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are
recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more
likely than not to be realized based upon Company analysis. Please refer to Note 4 – Income Taxes for additional disclosure.
Earnings per Share
The Company uses the treasury stock method to determine the potential dilutive effect of non-vested restricted stock units, contingent Performance
Share Units, and Senior Convertible Notes. Please refer to Note 9 - Earnings Per Share for additional discussion.
Comprehensive Income (Loss)
Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is
comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income
(loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss). Please
refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income (loss).
Fair Value of Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which
approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it
bears interest at a floating rate that approximates a current market rate. The Company had a zero balance under its credit facility as of December 31, 2018 , and
2017 . The Company’s Senior Notes and Senior Convertible Notes are recorded at cost, net of any unamortized discount and deferred financing costs, and the
respective fair values are disclosed in Note 11 – Fair Value Measurements . The Company has derivative financial instruments that are recorded at fair value.
Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would
realize upon the sale or refinancing of such instruments.
80
Industry Segment and Geographic Information
The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a
single industry segment.
Off-Balance Sheet Arrangements
The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities
often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other
contractually narrow or limited purposes.
The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary
beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 2018 or 2017
.
Recently Issued Accounting Standards
Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting
Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU
2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for
forfeitures, and net share settlements. The Company adopted the various applicable amendments, which are summarized as follows:
•
•
•
On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was
recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Effective January 1, 2017, excess tax
benefits are presented in net cash provided by operating activities on the accompanying statements of cash flows.
On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than
applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in
additional paid-in capital of $1.1 million , a decrease in deferred tax assets of $400,000 , and a net $700,000 cumulative effect adjustment
decrease to retained earnings.
Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between
periods. Please refer to Note 4 – Income Taxes for additional discussion .
Effective December 31, 2017, the Company early adopted, on a retrospective basis, FASB ASU No. 2016-15, Statement of Cash Flows (Topic 230):
Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted
Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The
Company determined that of the eight issues addressed in ASU 2016-15, only the issue related to debt extinguishment costs impacted the Company’s
consolidated financial statements and disclosures. In accordance with ASU 2016-15, the Company reclassified certain debt extinguishment costs from operating
activities to financing activities. ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash
equivalents in the statement of cash flows. In accordance with ASU 2016-18, the Company reclassified $3.0 million of restricted cash out of investing activities
and combined it with cash and cash equivalents in the accompanying statements of cash flows for the year ended December 31, 2016.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) . Under the new standard,
revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive
in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from
contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the
effective date of ASU 2014-09. Effective January 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition
method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period
results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its
disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional
discussion.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , followed by other related ASUs that provided targeted improvements and
additional practical expedient options (collectively “ASU 2016-02”). ASU 2016-02 requires lessees to recognize right-of-use assets and lease payment liabilities
on the balance sheet for leases representing the Company’s right to use the underlying assets for the lease term. Each lease that is recognized in the balance
sheet will be classified as either finance or operating, with such classification affecting the pattern and classification of expense recognition in the consolidated
statements of operations and presentation within the statements of cash flows.
81
The Company leveraged a dedicated project team and external consultants to evaluate the impacts of ASU 2016-02, which included an analysis of
contracts for office leases, drilling rig agreements, well completion agreements, midstream agreements, water handling agreements, certain field equipment
rentals, land easements, and other arrangements that included potential lease components. The scope of ASU 2016-02 does not apply to leases used in the
exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. The Company has completed the process of reviewing and
determining contracts to which the new guidance applies, and has implemented policies, internal controls, and processes that are necessary to support the
additional accounting and disclosure requirements going forward. The lease administration system that will support the on-going maintenance and accounting
after adoption is operational and is currently being populated with the necessary lease data and relevant assumptions. Policy elections and practical expedients
the Company has implemented as part of adopting ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b)
for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the
package of practical expedients, which allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated
under legacy GAAP, (d) excluding land easements that existed or expired before adoption of ASU 2016-02, and (e) the policy election that eliminates the need
for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. The Company adopted ASU 2016-02 on January
1, 2019, using the modified retrospective approach, and has necessary staff and processes in place to ensure on-going compliance. Adoption of this guidance
will result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-
01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as
acquisitions (or disposals) of assets or businesses. The Company adopted ASU 2017-01 on the effective date of January 1, 2018, on a prospective basis.
In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost
and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other
compensation costs arising from services rendered by employees during the period, and presentation of the remaining components of net benefit cost in a
separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted
ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost
in the consolidated statements of operations, and prospective application for the capitalization of the service cost component of net benefit costs in assets. While
the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not
result in a material impact to the Company’s consolidated financial statements or disclosures.
The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the years ended
December 31, 2017 , and 2016 are summarized as follows:
Operating expenses:
Exploration
General and administrative
Total operating expenses
Income (loss) from operations
Other non-operating income (expense), net
For the Year Ended
December 31, 2017
For the Year Ended
December 31, 2016
As Reported As Adjusted As Reported As Adjusted
(in thousands)
$
$
$
$
$
56,179 $
54,713 $
65,641 $
120,585 $
117,283 $
126,428 $
64,970
124,828
1,297,865 $
1,293,097 $
2,276,765 $
2,274,494
(168,489) $
(163,721) $
(1,059,315) $
(1,057,044)
3,968 $
(800) $
362 $
(1,909)
In February 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain
Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated
other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. The Company early adopted ASU 2018-02 effective January 1, 2018
using a retrospective method. As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other
comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive
loss is an incremental, unit-of-account approach.
In August 2018, the FASB issued ASU No. 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure
Framework-Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU
82
2018-14 provides updated disclosure requirements related to retirement benefits and defined pension plans with the purpose of improving the effectiveness of
disclosures with regard to such topics. The guidance is to be applied using a retrospective method and is effective for fiscal years ending after December 15,
2020, with early adoption permitted. The Company early adopted ASU 2018-14 on December 31, 2018, and it did not result in a material impact to the
Company’s consolidated financial statements or disclosures.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting
for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for
capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred
to develop or obtain internal-use software. The Company expects to adopt ASU 2018-15 on January 1, 2020, with prospective application. The Company is
evaluating the impact of ASU 2018-15 on its consolidated financial statements.
There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related
disclosures that have been issued but not yet adopted by the Company as of December 31, 2018 , and through the filing of this report.
Note 2 - Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Permian, South Texas & Gulf Coast, and Rocky
Mountain regions. During the first quarter of 2018, the Company entered into two definitive agreements to sell all of its producing properties in its Rocky
Mountain region. One transaction closed in the first quarter of 2018, and the second transaction closed in the second quarter of 2018. As a result of these
divestitures, there has been no production revenue from the Rocky Mountain region after the second quarter of 2018. Please refer to Note 3 – Divestitures,
Assets Held for Sale, and Acquisitions for additional detail. Oil, gas, and NGL production revenue presented within the accompanying statements of operations
is reflective of the revenue generated from contracts with customers.
The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for
the years ended December 31, 2018 , 2017 , and 2016 :
For the year ended December 31, 2018
Permian
South Texas &
Gulf Coast
Rocky
Mountain
Total
(in thousands)
Oil, gas, and NGL production
revenue:
Oil production revenue
$
938,004
$
72,821
$
54,851
$
1,065,676
Gas production revenue
NGL production revenue
125,603
1,000
227,252
214,441
1,595
790
354,450
216,231
Total
Relative percentage
$
1,064,607
$
514,514
$
57,236
$
1,636,357
65%
32%
3%
100%
____________________________________________
Note: Amounts may not calculate due to rounding.
For the year ended December 31, 2017
Permian
South Texas &
Gulf Coast
Rocky
Mountain
Total
(in thousands)
$
$
419,732
$
82,674
$
151,844
$
61,781
547
301,780
226,031
5,849
3,545
654,250
369,410
230,123
482,060
$
610,485
$
161,238
$
1,253,783
38%
49%
13%
100%
Oil, gas, and NGL production
revenue:
Oil production revenue
Gas production revenue
NGL production revenue
Total
Relative percentage
____________________________________________
Note: Amounts may not calculate due to rounding.
83
For the year ended December 31, 2016
Permian
South Texas &
Gulf Coast
Rocky
Mountain
Total
(in thousands)
$
$
117,399
$
189,313
$
305,126
$
17,315
92
308,829
225,821
11,144
3,387
611,838
337,288
229,300
134,806
$
723,963
$
319,657
$
1,178,426
11%
62%
27%
100%
Oil, gas, and NGL production
revenue:
Oil production revenue
Gas production revenue
NGL production revenue
Total
Relative percentage
____________________________________________
Note: Amounts may not calculate due to rounding.
The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differs
depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing,
and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior
to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other
deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has four categories
under which oil, gas, and NGL production revenue is generated. Each of the Company’s operating regions generate production revenue from a combination of
some or all of the four different contract types summarized below:
1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and
transportation differentials. Under this arrangement, control transfers at or near the wellhead.
2) The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream
processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and
residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and
is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are
recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.
3) The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for
processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-
kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds it generates
from selling the NGLs to other third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at
points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately
recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL
production expense line item on the accompanying statements of operations.
4) The Company has certain midstream processing arrangements where unprocessed gas is delivered to the inlet of the midstream processor’s
facility for processing. Upon completion of processing, the midstream processor purchases the processed NGLs and residue gas and remits the
proceeds to the Company from the sale of the products to third-party customers. In these arrangements, control transfers at the tailgate of the
midstream processing facility for both products. Given the structure of these arrangements and where control transfers, the Company separately
recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL
production expense line item on the accompanying statements of operations.
Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers relate to the point in time when
control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are
required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level
of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company
does not consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership
interest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead, inlet, or tailgate of the midstream
processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is
generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
84
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of
hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount
of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is
recorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with
customers within the accompanying balance sheets as of December 31, 2018 and December 31, 2017 , were $107.2 million and $96.6 million , respectively. To
estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements,
index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts
received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the year ended December 31, 2018 ,
that related to performance obligations satisfied in prior reporting periods, was immaterial.
Note 3 – Divestitures, Assets Held for Sale, and Acquisitions
2018 Divestiture Activity
PRB Divestiture. On March 26, 2018 , the Company divested approximately 112,000 net acres of its 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 . These assets were recorded as properties
held for sale as of December 31, 2017.
Divide County Divestiture and Halff East Divestiture. During the second quarter of 2018, the Company completed the Divide County Divestiture and the
Halff East Divestiture, for combined net divestiture proceeds of $252.2 million , and recorded a combined final net gain of $15.4 million for the year ended
December 31, 2018 . A portion of these assets were recorded as properties held for sale as of December 31, 2017.
The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2018 , 2017
, and 2016 . The Divide County Divestiture was considered a disposal of a significant asset group.
For the Years Ended December 31,
2018
2017
2016
(in thousands)
Loss before income taxes (1)
$
(28,975) $
(468,786) $
(50,034)
____________________________________________
(1) Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization,
and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity. During the year ended December 31,
2017 , the Company recorded a write-down of $523.6 million on these assets previously held for sale.
2017 Divestiture Activity
Eagle Ford Divestiture. On March 10, 2017, the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in
related midstream assets, for final net divestiture proceeds of $744.1 million . The Company recorded a final net gain of $396.8 million related to these divested
assets for the year ended December 31, 2017.
The following table presents income (loss) before income taxes from the outside-operated Eagle Ford shale assets sold for the years ended
December 31, 2018 , 2017 , and 2016 . This divestiture was considered a disposal of a significant asset group.
For the Years Ended December 31,
2018
2017
2016
(in thousands)
$
— $
24,324 $
(218,506)
Income (loss) before income taxes (1)
____________________________________________
(1)
Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation,
amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes $269.6 million of impairment of
proved properties expense for the year ended December 31, 2016 .
Rocky Mountain and Permian Divestitures. During 2017, the Company divested certain non-core properties in its Rocky Mountain and Permian regions
for net divestiture proceeds of $36.2 million and recognized an insignificant final net gain.
85
2016 Divestiture Activity
Rocky Mountain Divestitures. During the third quarter of 2016, the Company divested certain non-core properties in the Williston Basin and Powder
River Basin in two separate transactions for combined net divestiture proceeds of $110.3 million and a final net gain of $16.4 million .
During the fourth quarter of 2016, the Company divested certain Williston Basin assets located outside of Divide County, North Dakota (referred to as
“Raven/Bear Den” throughout this report) for net divestiture proceeds of $755.7 million and a final net gain of $29.5 million . In conjunction with this divestiture,
the Company closed its Billings, Montana regional office.
Permian Divestiture. During the third quarter of 2016, the Company divested its non-core properties in southeast New Mexico for net divestiture
proceeds of $54.7 million and recorded a final net loss of $10.0 million .
The Company finalized these divestitures in 2017.
The Company determined that neither planned nor executed asset sales in 2018 , 2017 , and 2016 qualify for discontinued operations accounting
under financial statement presentation authoritative guidance.
Properties Held for Sale
Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year.
Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and
expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are
measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization
expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held
for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain (loss) on divestiture activity line item on the
accompanying statements of operations.
As of December 31, 2018 , and 2017 , there were $5.3 million and $111.7 million , respectively, of assets held for sale presented on the accompanying
balance sheets. The balance as of December 31, 2017, consisted primarily of approximately 112,000 net acres in the Powder River Basin, and is presented net
of accumulated depletion, depreciation, and amortization expense. As discussed above, the Company sold these assets in the first quarter of 2018.
2018 Acquisition Activity
During the year ended December 31, 2018 , the Company acquired approximately 1,030 net acres of primarily unproved properties located in Martin
and Howard Counties, Texas, in two separate transactions which closed in 2018. Combined total cash consideration paid by the Company was $33.3 million .
Under authoritative accounting guidance, these transactions were both individually considered to be asset acquisitions. Therefore, the properties were recorded
based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the
assets acquired.
During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily unproved properties, located in Howard and
Martin Counties, Texas, resulting in the Company exchanging approximately 2,650 net acres, with $95.1 million of carrying value attributed to the properties
surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized.
Subsequent to December 31, 2018 , the Company completed several non-monetary acreage trades of primarily unproved properties, located in
Howard, Martin, and Upton Counties, Texas, resulting in the Company receiving approximately 1,580 net acres in exchange for approximately 1,650 net acres.
2017 Acquisition Activity
During the year ended December 31, 2017 , the Company acquired approximately 3,600 net acres of primarily unproved properties in Howard and
Martin Counties, Texas, in multiple transactions for a total of $76.5 million of cash consideration. Under authoritative accounting guidance, these transactions
were considered asset acquisitions and the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and
transaction costs were capitalized as a component of the cost of the assets acquired.
Also, during the year ended December 31, 2017 , the Company completed several non-monetary acreage trades of primarily unproved properties in
Howard and Martin Counties, Texas, resulting in the Company acquiring approximately 8,125 net acres in
86
exchange for approximately 7,580 net acres with $294.0 million of carrying value attributed to the properties surrendered by the Company in such trades.
These trades were recorded at carryover basis with no gain or loss recognized.
2016 Acquisition Activity
Rock Oil Acquisition. During the fourth quarter of 2016, the Company acquired all membership interests of JPM EOC Opal, LLC, which owned proved
and unproved properties in the Midland Basin, from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”). The Company finalized the Rock Oil
Acquisition during 2017 by paying $7.7 million of cash consideration in addition to the initial adjusted purchase price of $991.0 million , resulting in total
consideration of $998.7 million paid after final closing adjustments. The Company funded the acquisition with proceeds from divestitures in 2016, the Senior
Convertible Notes and equity offerings in August 2016, and the 2026 Senior Notes offering in September 2016, as discussed in Note 5 – Long-Term Debt and
Note 13 – Equity , respectively.
The Company determined that the Rock Oil Acquisition met the criteria of a business combination under ASC Topic 805, Business Combinations . The
Company allocated the final adjusted purchase price to the acquired assets and liabilities based on fair value as of the acquisition date, as summarized in the
table below. This measurement resulted in no goodwill or bargain purchase gain being recognized. The acquisition costs were insignificant and were expensed
as incurred.
Cash consideration
Fair value of assets and liabilities acquired:
Wells in progress
Proved oil and gas properties
Unproved oil and gas properties
Other assets
Total fair value of oil and gas properties acquired
Working capital
Asset retirement obligations
Total fair value of net assets acquired
$
$
$
As of October 4, 2016
(in thousands)
998,691
5,672
82,584
913,819
5,338
1,007,413
(1,127)
(7,595)
998,691
QStar Acquisition. During the fourth quarter of 2016, the Company acquired additional proved and unproved properties in the Midland Basin from QStar
LLC and RRP-QStar, LLC (referred to as the “QStar Acquisition”). The Company finalized the QStar Acquisition during the third quarter of 2017 by paying $7.3
million of cash consideration in addition to the initial consideration of $1.2 billion in cash consideration and the issuance of approximately 13.4 million shares of
the Company’s common stock, resulting in total consideration of approximately $1.6 billion paid after final closing adjustments. The Company funded the
acquisition with proceeds from the 2016 divestitures and the December 2016 equity offering. Please refer to Note 13 – Equity for additional discussion.
87
Under authoritative accounting guidance, the transaction was considered an asset acquisition, and therefore, the properties were recorded based on
the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets
acquired. The Company allocated the final adjusted purchase price to the acquired assets and liabilities, as summarized in the table below.
As of December 21, 2016
(in thousands)
Cash consideration, including acquisition costs paid
Fair value of equity consideration (1)
Total consideration
Assets and liabilities acquired:
Wells in progress
Proved oil and gas properties
Unproved oil and gas properties
Total oil and gas properties acquired
Working capital
Asset retirement obligations
Total net assets acquired
$
$
$
$
1,174,628
437,194
1,611,822
21,812
61,239
1,538,264
1,621,315
(1,852)
(7,641)
1,611,822
____________________________________________
(1)
The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar
Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the
lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibited the sale of such stock until no
earlier than the 90th day after issuance.
Note 4 – Income Taxes
The provision for income taxes consists of the following:
For the Years Ended December 31,
2018
2017
2016
(in thousands)
Current portion of income tax expense (benefit)
Federal
State
Deferred portion of income tax expense (benefit)
Total income tax expense (benefit)
$
$
— $
5,698
$
1,662
141,708
3,398
(192,066)
143,370
$
(182,970)
$
2,932
1,539
(448,643)
(444,172)
Effective tax rate
22.0%
53.2%
37.0%
88
The components of the net deferred tax liabilities are as follows:
Deferred tax liabilities
Oil and gas properties
Derivative assets
Other
Total deferred tax liabilities
Deferred tax assets
Derivative liabilities
Credit carryover
Pension
Federal and state tax net operating loss
carryovers
Stock compensation
Other liabilities
Total deferred tax assets
Valuation allowance
Net deferred tax assets
Total net deferred tax liabilities
Current federal income tax refundable
Current state income tax payable
$
$
$
As of December 31,
2018
2017
(in thousands)
$
218,094 $
142,467
35,247
4,812
258,153
—
22,554
6,427
4,217
3,263
1,497
37,958
(3,083)
34,875
223,278 $
59 $
1,331 $
—
3,412
145,879
29,463
22,537
7,986
3,867
3,545
1,470
68,868
(2,978)
65,890
79,989
37
3,009
The enactment of the 2017 Tax Act on December 22, 2017 reduced the Company’s federal tax rate for 2018 and future years from 35 percent to 21
percent . With the conclusion of the one-year measurement period and considering subsequent guidance, the Company believes it has properly analyzed the
tax accounting impacts of the 2017 Tax Act, including the $1.0 million limitation on the compensation of certain covered individuals, which impacts the
Company’s tax rate. There are no new estimates or finalized income tax items associated with the 2017 Tax Act included in income tax (expense) benefit for the
year ended December 31, 2018 .
As of December 31, 2018 , the Company estimated its federal net operating loss (“NOL”) carryforward at $2.3 million , which reflects the planning
strategies to utilize NOLs for the 2017 and 2016 tax years. In 2017, the Company re-evaluated various factors affecting deferred tax assets related to net
operating losses and tax credits and determined utilization would be appropriate. The change in the current quarter portion of income tax (expense) benefit
between periods reflects the effect of this determination. The Company expects to receive the 2018 federal current portion of income tax expense as a credit
against tax in a future period. See the credit discussion below.
After the adoption of ASU 2016-09 in 2017, the Company no longer records a deferred tax amount for unrecognized excess income tax benefits
associated with employee share-based payment awards. A cumulative effect adjustment was recorded to the beginning deferred income tax balance and
retained earnings as of January 1, 2017. Please refer to Note 1 – Summary of Significant Accounting Policies above for additional information regarding the
adoption of ASU 2016-09.
The Company has federal research and development (“R&D”) and AMT credit carryforwards of $7.4 million and $15.6 million , respectively. The federal
R&D credit carryforwards expire between 2028 and 2034. The Company’s AMT credit carryforwards do not expire and are expected to be fully refunded by
2022. State NOL carryforwards were $79.7 million and state tax credits were $212,000 as of December 31, 2018 . Federal and state NOLs and state credits
expire between 2019 and 2038. The Company’s current valuation allowance relates to state NOL carryforwards and state tax credits, which are expected to
expire before they can be utilized. The change in the valuation allowance from 2017 to 2018 primarily relates to an allocable change to the Company’s mix of
state apportioned losses and anticipated utilization of state cumulative NOLs.
89
Federal income tax expense (benefit) differs from the amount that would be provided by applying the statutory United States federal income tax rate to
income before income taxes primarily due to the effect of state income taxes, excess tax benefits and deficiencies from share-based payment awards, changes
in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, and is reported as follows:
For the Years Ended December 31,
2018
2017
2016
(in thousands)
Federal statutory tax expense (benefit)
$
136,873 $
(120,335) $
(420,671)
Increase (decrease) in tax resulting from:
Federal tax reform changes - 2017 Tax Act
State tax expense (benefit) (net of federal benefit)
Change in valuation allowance
Employee share-based compensation
Other
—
2,771
105
2,508
1,113
(63,675)
(3,286)
(2,727)
8,190
(1,137)
—
(17,549)
(5,059)
—
(893)
$
(444,172)
Income tax expense (benefit)
$
143,370 $
(182,970)
Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of
taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This
change, when applied to the Company’s total temporary differences, impacts the total state income tax expense (benefit) reported in the current year. Items
affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are
significant changes in drilling activity, or if estimated state revenue changes occur during the year. As a result of the 2018 divestitures, the Company’s state
apportionment rate reflects its significant Texas presence.
The Company and its subsidiaries file federal income tax returns and various state income tax returns. The Company is generally no longer subject to
United States federal or state income tax examinations by tax authorities for years before 2015. During the third quarter of 2018, the IRS finalized its
examination of the net operating loss (“NOL”) claims back to tax years 2003 through 2005 with no changes to claimed amounts. The Company received $5.9
million and $5.5 million of cash refunds in 2018 and 2017, respectively, for NOL carryback claims. During 2016, the Company’s 2007 - 2011 IRS examination
was finalized, with no material adjustments to previously recorded amounts.
The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit
reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible
amount associated with income taxes. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2019 .
The total amount recorded for unrecognized tax benefits is presented below:
Beginning balance
Additions for tax positions of prior years
Settlements
Ending balance
For the Years Ended December 31,
2018
2017
2016
$
$
(in thousands)
446 $
446 $
—
—
—
—
446 $
446 $
2,782
9
(2,345)
446
90
Note 5 – Long-Term Debt
Credit Agreement
On September 28, 2018 , the Company and its lenders entered into the Sixth Amended and Restated Credit Agreement. The Credit Agreement, which
replaced the Company’s Fifth Amended and Restated Credit Agreement, 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 borrowing base is subject to regular,
semi-annual redetermination, and considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve
report; and (b) commodity derivative contracts, each as determined by the Company’s lender group. The Company does not expect a material change to the
borrowing base or the aggregate lender commitments during the next scheduled redetermination on April 1, 2019 .
The Credit Agreement is scheduled to mature on the earlier of September 28, 2023 , (the “Scheduled Maturity Date”), and August 16, 2022, to the
extent that, on or before such date, the Company’s outstanding 2022 Senior Notes are not repurchased, redeemed, or refinanced to have a maturity date at
least 91 days after the Scheduled Maturity Date unless, on August 16, 2022, both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not
more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate
amount of unrestricted cash and certain types of unrestricted investments held by the Company and its Consolidated Restricted Subsidiaries plus the amount of
unused availability under the Credit Agreement is at least $300.0 million .
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting
dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. The 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. The Company was in
compliance with all financial and non-financial covenants as of December 31, 2018 , and through the filing of this report.
Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. Eurodollar loans accrue
interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate (“ABR”) or Swingline Loans accrue
interest at a market based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the
aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of
operations. The borrowing base utilization grid as set forth in the Credit Agreement is as follows:
Borrowing Base Utilization Percentage
<25%
≥25% <50% ≥50% <75% ≥75% <90%
≥90%
Eurodollar Loans
ABR Loans or Swingline Loans
Commitment Fee Rate
1.500%
0.500%
0.375%
1.750%
0.750%
0.375%
2.000%
1.000%
0.500%
2.250%
1.250%
0.500%
2.500%
1.500%
0.500%
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit
Agreement as of February 7, 2019 , and December 31, 2018 , and under the Company’s Fifth Amended and Restated Credit Agreement as of December 31,
2017 :
As of February 7, 2019
As of December 31, 2018 As of December 31, 2017
(in thousands)
Credit facility balance (1)
Letters of credit (2)
Available borrowing capacity
$
— $
—
1,000,000
— $
200
999,800
—
200
924,800
Total aggregate lender commitment amount $
____________________________________________
(1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying
1,000,000 $
1,000,000 $
925,000
balance sheets and totaled $6.4 million and $3.1 million as of December 31, 2018 , and 2017 , respectively. These costs are being amortized over the term
of the credit facility on a straight-line basis.
(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of
December 31, 2018 , was released effective January 8, 2019.
91
Senior Notes
During the third quarter of 2018, the Company redeemed its 2021 Senior Notes, repurchased or redeemed all of its 2023 Senior Notes, repurchased a
portion of its 2022 Senior Notes, and issued its 2027 Senior Notes. As of December 31, 2018 , the Company’s Senior Notes consisted of 6.125% Senior Notes
due 2022, 5.0% Senior Notes due 2024 (“2024 Senior Notes”), 5.625% Senior Notes due 2025 (“2025 Senior Notes”), 6.75% Senior Notes due 2026 (“2026
Senior Notes”), and 6.625% Senior Notes due 2027 (collectively referred to as “Senior Notes”). Please refer to the discussion below for additional information.
The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of December 31, 2018 , and 2017 , consisted of the
following:
As of December 31,
2018
2017
Unamortized
Deferred
Financing
Costs
Principal
Amount
Principal
Amount, Net of
Unamortized
Deferred
Financing
Costs
Unamortized
Deferred
Financing
Costs
Principal
Amount
Principal
Amount, Net of
Unamortized
Deferred
Financing
Costs
(in thousands)
$
— $
— $
— $
344,611 $
2,656 $
341,955
476,796
3,921
472,875
561,796
5,800
555,996
6.50% Senior Notes due
2021
6.125% Senior Notes due
2022
6.50% Senior Notes due
2023
5.0% Senior Notes due 2024
500,000
—
—
4,688
—
495,312
394,985
500,000
3,707
5,610
391,278
494,390
5.625% Senior Notes due
2025
6.75% Senior Notes due
2026
6.625% Senior Notes due
2027
500,000
5,808
494,192
500,000
6,714
493,286
500,000
6,407
493,593
500,000
7,242
492,758
500,000
7,533
492,467
—
—
—
Total
$ 2,476,796 $
28,357 $
2,448,439 $ 2,801,392 $
31,729 $
2,769,663
The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured
senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject
to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock,
and make restricted payments, including dividends. The Company was in compliance with all such covenants under its Senior Notes as of December 31, 2018 ,
and through the filing of this report. All Senior Notes are registered under the Securities Act. The Company may redeem some or all of its Senior Notes prior to
their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.
During the third quarter of 2018, the Company used the proceeds from the issuance of its 2027 Senior Notes, as discussed below, and cash on hand to
retire $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes through the Tender Offer and subsequent redemption of the remaining
2023 Senior Notes not repurchased as part of the Tender Offer (“2023 Senior Notes Redemption”). Total consideration paid, including accrued interest, for the
retirement of the 2023 Senior Notes and the 2022 Senior Notes was $497.8 million . As a result of the Tender Offer and the 2023 Senior Notes Redemption, the
Company recorded a loss on extinguishment of debt of $16.9 million for the year ended December 31, 2018 . This amount included $12.9 million of premiums
paid for the Tender Offer and 2023 Senior Notes Redemption and $4.0 million of accelerated unamortized deferred financing costs.
During the first quarter of 2016, the Company repurchased in open market transactions a total of $46.3 million in aggregate principal amount of certain
of its 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023 for a settlement amount of $29.9 million , excluding
interest, which resulted in a net gain on extinguishment of debt of approximately $15.7 million . This amount includes a gain of $16.4 million associated with the
discount realized upon repurchase, which was partially offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs.
2021 Senior Notes. On June 15, 2018 , the Company called for redemption all of the $344.6 million principal outstanding on its 2021 Senior Notes at a
redemption price of 102.167% of the principal amount, plus accrued and unpaid interest on the principal amount of the 2021 Senior Notes redeemed (“2021
Senior Notes Redemption”). On July 16, 2018, the Company completed the 2021 Senior Notes Redemption, which resulted in the payment of total cash
consideration, including accrued interest, of $355.9 million . The Company recorded a loss on extinguishment of debt of $9.8 million for the year ended
December 31, 2018. This amount included $7.5 million associated with the premium paid for the 2021 Senior Notes Redemption and $2.3 million of accelerated
unamortized deferred financing costs.
92
2022 Senior Notes. On November 17, 2014 , the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022 at
par, which mature on November 15, 2022 . The Company received net proceeds of $590.0 million after deducting fees of $10.0 million , which are being
amortized as deferred financing costs over the life of the 2022 Notes. During the first quarter of 2016, the Company repurchased $38.2 million in aggregate
principal amount of its 2022 Notes for a settlement amount of $24.3 million , excluding interest. During the third quarter of 2018, through the Tender Offer
discussed above, the Company retired $85.0 million of its 2022 Senior Notes for total consideration, including accrued interest, of $89.5 million .
2023 Senior Notes. During the first quarter of 2016, the Company repurchased $5.0 million in aggregate principal amount of its 2023 Notes for a
settlement amount of $3.3 million . During the third quarter of 2018, through the Tender Offer and 2023 Senior Notes Redemption discussed above, the
Company redeemed the remaining outstanding $395.0 million in aggregate principal amount of its 2023 Senior Notes for total consideration, including accrued
interest, of $408.3 million .
2024 Senior Notes. On May 20, 2013 , the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 at par, which
mature on January 15, 2024 . The Company received net proceeds of $490.2 million after deducting fees of $9.8 million , which are being amortized as deferred
financing costs over the life of the 2024 Notes.
2025 Senior Notes. On May 21, 2015 , the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 at par,
which mature on June 1, 2025 . The Company received net proceeds of $491.0 million after deducting fees of $9.0 million , which are being amortized as
deferred financing costs over the life of the 2025 Notes.
2026 Senior Notes. On September 12, 2016 , the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026 , at
par, which mature on September 15, 2026 . The Company received net proceeds of $491.6 million after deducting fees of $8.4 million , which are being
amortized as deferred financing costs over the life of the 2026 Notes. The net proceeds were used to partially fund the Rock Oil Acquisition that closed during
the fourth quarter of 2016.
2027 Senior Notes. On August 20, 2018 , the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027. The
2027 Senior Notes were issued at par and mature on January 15, 2027 . The Company received net proceeds of $492.1 million after deducting fees of $7.9
million , which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. The net proceeds were used to fund the Tender Offer and
2023 Senior Notes Redemption discussed above.
Senior Convertible Notes
On August 12, 2016 , the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 , unless
earlier converted. The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any
future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company received net proceeds of $166.6 million after
deducting fees of $5.9 million , of which a portion is being amortized over the life of the Senior Convertible Notes.
Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under the following circumstances: (1)
during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2016, if the last reported
sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on
the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (2)
during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price (as defined in the
indenture) per $1,000 principal amount of Notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price
of the Company’s common stock and the conversion rate on each such trading day; or (3) upon the occurrence of specified corporate events. On or after
January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible
Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common
stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s
common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share,
subject to adjustment.
The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal
amount in cash with any excess conversion in shares of the Company’s common stock. The Senior Convertible Notes were not convertible at the option of
holders as of December 31, 2018 , or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible
Notes as of December 31, 2018 , did not exceed the principal amount.
Upon the issuance of the Senior Convertible Notes, the Company recorded $132.3 million as the initial carrying amount of the debt component, which
approximated its fair value at issuance, and, was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes.
The effective interest rate used was 7.25% . The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt
component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The Company incurred transaction costs of $5.9 million
relating to the issuance of
93
the Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair value amounts. The debt
discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of
July 1, 2021 . Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $10.5
million , $9.9 million , and $3.7 million for the years ended December 31, 2018 , 2017 , and 2016, respectively.
The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets, consisted of the
following as of December 31, 2018 and 2017 :
Principal amount of Senior Convertible Notes
Unamortized debt discount
Unamortized deferred financing costs
Net carrying amount
As of December 31,
2018
2017
(in thousands)
$
$
172,500 $
(22,313)
(2,293)
147,894 $
172,500
(30,183)
(3,210)
139,107
The net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance
sheets consisted of the following as of December 31, 2018 and 2017 :
Equity component due to allocation of proceeds to equity
Related issuance costs
Deferred tax liability
Net carrying amount
As of December 31,
2018
2017
(in thousands)
$
$
40,217 $
(1,375)
(5,267)
33,575 $
40,217
(1,375)
(5,267)
33,575
If the Company undergoes a fundamental change, as defined by the governing indenture, holders of the Senior Convertible Notes may require the
Company to repurchase for cash all or any portion of their notes at a fundamental change repurchase price equal to 100% of the principal amount of the Senior
Convertible Notes to be repurchased, plus accrued and unpaid interest. The indenture governing the Senior Convertible Notes contains customary events of
default with respect to the Senior Convertible Notes, including that upon certain events of default, the trustee by notice to the Company, or the holders of at least
25% in principal amount of the outstanding Senior Convertible Notes by notice to the Company, may declare 100% of the principal and accrued and unpaid
interest, if any, due and payable immediately. In case of certain events of bankruptcy, insolvency or reorganization involving the Company or a significant
subsidiary, 100% of the principal and accrued and unpaid interest on the Senior Convertible Notes will automatically become due and payable.
The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as
of December 31, 2018 , and through the filing of this report.
Capped Call Transactions
In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of
such issuance. The aggregate cost of the capped call transactions was approximately $24.2 million . The capped call transactions are generally expected to
reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in
excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock is greater
than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible
Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call
transactions, there could be dilution or there would not be an offset of such potential cash payments.
The Company evaluated the capped call transactions under authoritative accounting guidance and determined that they should be accounted for as
separate transactions and classified as equity instruments with no recurring fair value measurement recorded.
Capitalized Interest
Capitalized interest costs for the Company for the years ended December 31, 2018 , 2017 , and 2016 , were $20.6 million , $12.6 million , and $17.0
million , respectively.
94
Note 6 – Commitments and Contingencies
Commitments
The Company has entered into various agreements, which include drilling rig and completion service contracts of $86.9 million , gathering, processing,
transportation throughput, and delivery commitments of $287.8 million , office leases, including maintenance, of $35.5 million , fixed price contracts to purchase
electricity of $29.0 million , and other miscellaneous contracts and leases of $18.3 million . The annual minimum payments for the next five years and total
minimum payments thereafter are presented below:
Years Ending December 31,
Amount
(in thousands)
2019
2020
2021
2022
2023
Thereafter
Total
$
$
132,502
103,169
88,785
70,741
37,334
24,931
457,462
Drilling Rig and Completion Service Contracts
The Company has several drilling rig and completion service contracts in place to facilitate drilling and completion plans. Early termination of these
contracts as of December 31, 2018 , would have resulted in termination penalties of $45.9 million , which would be in lieu of paying the remaining commitments
of $86.9 million included in the table above. For the year ended December 31, 2016 , the Company incurred $8.7 million of expenses related to the early
termination of drilling rig contracts or fees incurred for rigs placed on standby, which are recorded in the other operating expenses line item in the accompanying
statements of operations. No material expenses related to early termination or standby fees were recorded by the Company for the years ended December 31,
2018 , or 2017.
Pipeline Transportation Commitments
The Company has gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a
minimum amount of oil, gas, and produced water. As of December 31, 2018 , the Company has commitments to deliver a minimum of 29 MMBbl of oil, 595 Bcf
of gas, and 21 MMBbl of produced water through 2027 . The Company will be required to make periodic deficiency payments for any shortfalls in delivering the
minimum volume commitments under certain agreements. As of December 31, 2018 , if the Company fails to deliver any product, as applicable, the aggregate
undiscounted deficiency payments total approximately $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. Under certain of the Company’s commitments, if the Company is unable to
deliver the minimum quantity from its production, it may deliver production acquired from third-parties to satisfy its minimum volume commitments. As of the filing
of this report, the Company does not expect to incur any material shortfalls with regard to these commitments.
Drilling and Completion Commitments
In December 2018, the Company entered into an agreement that included minimum drilling and completion requirements for certain existing leases. If
these minimum requirements are not satisfied by March 31, 2020, the Company would be required to pay penalties based on the difference between actual
development progress and the minimum development requirements. The penalties could range from zero to a maximum of $60.0 million , with the maximum
exposure assuming no development activity occurred prior to March 31, 2020. As of the filing of this report, the Company is committed to and expects to meet
the minimum development requirements set forth in the agreement.
Office Leases
The Company leases office space under various operating leases with terms extending as far as 2026 . Rent expense, net of sublease income, for the
years ended December 31, 2018 , 2017 , and 2016 , was $4.5 million , $4.8 million , and $5.2 million , respectively. During the third quarter of 2015, the
Company closed its office in Tulsa, Oklahoma and has subleased the space through the expiration of the lease. In the fourth quarter of 2018, the Company paid
$1.3 million to the lessor to terminate the lease effective September 2019. The Company closed its office in Billings, Montana in November 2016 and paid $3.2
million to the lessor to terminate the lease. These lease termination fees are not reflected in the rent expense amounts above.
95
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both
probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not
expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.
Note 7 – Compensation Plans
Equity Incentive Compensation Plan
There are several components to the Company’s Equity Plan that are described in this section. Various types of equity awards have been granted by
the Company in different periods.
As of December 31, 2018 , approximately 5.9 million shares of common stock were available for grant under the Equity Plan. The issuance of a direct
share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one share against the number of shares
available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under
the Equity Plan based on the final performance multiplier.
Performance Share Units
The Company grants PSUs to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle
PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three -year performance
period. PSUs generally vest on the third anniversary of the date of the grant.
The fair value of PSUs is measured at the grant date with a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). A
stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which
means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company
cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three -year performance period. By using a stochastic
simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the
path the stock price may take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method,
specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation
include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a
three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers.
PSUs issued in 2017 and 2016, which the Company has determined to be equity awards, are subject to a combination of market and service vesting
criteria. These awards are based on annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s
TSR compared with the annualized TSR of the Company’s peer group for the performance period. The fair value of these PSUs is measured at the grant date
using the GBM Model. Compensation expense for these market-based PSUs is recognized on a straight-line basis within general and administrative expense
and exploration expense over the vesting periods of the respective awards.
Beginning in 2018, PSUs awarded to employees include both a market criteria component and a performance criteria component. For the performance
criteria component, the grant-date fair value is equal to the Company's stock price on the grant date, and compensation expense for the performance-based
PSUs will be recorded over the vesting period of the award. The value being recorded will be evaluated on a quarterly basis and may be adjusted as the number
of units expected to vest increases or decreases. For awards granted in 2018, the Company uses relative debt adjusted per share cash flow growth (“DACFG”)
compared with the DACFG, as calculated by the Company, of its peer group as the performance criteria that is evaluated over the three-year performance
period for these PSUs.
The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total
compensation expense recorded for PSUs was $10.3 million , $9.7 million , and $11.0 million for the years ended December 31, 2018 , 2017 , and 2016 ,
respectively. As of December 31, 2018 , there was $19.0 million of total unrecognized expense related to PSUs, which is being amortized through 2021 .
96
A summary of the status and activity of non-vested PSUs is presented in the following table:
For the Years Ended December 31,
2018
2017
2016
Non-vested at beginning of
year
Granted
Vested
Forfeited
PSUs (1)
1,533,491
572,924
(233,102)
(162,054)
Non-vested at end of year
1,711,259
Weighted-
Average
Grant-Date
Fair Value
Weighted-
Average
Grant-Date
Fair Value
Weighted-
Average
Grant-Date
Fair Value
PSUs (1)
PSUs (1)
$
$
$
$
$
22.97
24.45
44.25
21.79
828,923
977,731
(94,338)
(178,825)
20.68
1,533,491
$
$
$
$
$
43.25
15.86
85.85
44.99
22.97
626,328 $
447,971 $
(130,353) $
(115,023) $
828,923 $
61.81
26.56
64.17
55.59
43.25
____________________________________________
(1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year
performance multiplier, which ranges from zero to two .
The fair value of the PSUs granted in 2018 , 2017 , and 2016 was $14.0 million , $15.5 million , and $11.9 million , respectively. The PSUs fully vest on
the third anniversary of the date of the grant; however, employees who are retirement eligible at the time a PSU award was granted, vest in each portion of that
award equally in six -month increments over a three -year period beginning at grant date. Retirement eligible employees must stay with the Company through
the entire six -month vesting period to receive that increment of vesting and any non-vested portions of a PSU award will be forfeited when the employee leaves
the Company.
During the year ended December 31, 2018 , the Company granted 572,924 PSUs to eligible employees (“2018 PSU Grant”). As outlined in the award
agreement for the 2018 PSU Grant, performance measurements affecting vesting are based on a combination of relative performance of the Company’s
annualized TSR compared with the annualized TSR of the Company’s peer group over the three-year performance period, and relative performance of the
Company’s DACFG compared with its peer group DACFG over the three-year performance period. In addition to these performance measures, the award
agreement for the 2018 PSU Grant also stipulates that if the Company’s absolute TSR is negative over the three -year performance period, the maximum
number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date,
regardless of the Company’s TSR and DACFG performance relative to its peer group.
During the years ended December 31, 2018 and 2017, PSUs that were granted in 2015 and 2014, respectively did not satisfy the minimum
performance requirements. This resulted in a multiplier of zero times and therefore no shares of common stock were issued upon settlement. A summary of the
shares of common stock issued to settle PSUs for the year ended December 31, 2016 , is presented in the table below:
Shares of common stock issued to settle PSUs (1)
Less: shares of common stock withheld for income and payroll taxes
Net shares of common stock issued
For the Year Ended
December 31, 2016
44,870
(14,809)
30,061
Multiplier earned
____________________________________________
(1) During the year ended December 31, 2016 , the Company issued shares of common stock to settle PSUs that related to awards granted in 2013. The
Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in
accordance with the Company’s Equity Plan and individual award agreements.
0.2
The total fair value of PSUs that vested during the years ended December 31, 2018 , 2017 , and 2016 was $10.3 million , $8.1 million , and $8.4 million
, respectively.
Employee Restricted Stock Units
The Company grants RSUs to eligible persons as part of its long-term Equity Plan. Each RSU represents a right to receive one share of the Company’s
common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and
administrative expense and exploration expense over the vesting periods of the respective awards.
Total compensation expense recorded for employee RSUs for the years ended December 31, 2018 , 2017 , and 2016 , was $10.8 million , $10.3 million
, and $11.9 million , respectively. As of December 31, 2018 , there was $20.0 million of total unrecognized
97
compensation expense related to non-vested RSU awards, which is being amortized through 2021 . The Company records compensation expense associated
with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s
common stock on the day of the grant.
A summary of the status and activity of non-vested RSUs granted to employees is presented in the following table:
For the Years Ended December 31,
2018
2017
2016
Weighted-
Average
Grant-Date
Fair Value
RSUs
Weighted-
Average
Grant-Date
Fair Value
RSUs
Weighted-
Average
Grant-Date
Fair Value
RSUs
Non-vested at beginning of year
1,244,262 $
20.25
604,116 $
Granted
Vested
Forfeited
583,552 $
25.77
1,020,780 $
(407,529) $
(177,122) $
24.30
17.26
(246,025) $
(134,609) $
Non-vested at end of year
1,243,163 $
21.50
1,244,262 $
37.39
16.64
43.99
26.38
20.25
543,737 $
417,065 $
(241,363) $
(115,323) $
604,116 $
55.01
28.08
58.06
43.52
37.39
The fair value of RSUs granted to eligible employees in 2018 , 2017 , and 2016 was $15.0 million , $17.0 million , and $11.7 million , respectively. The
RSUs granted generally vest one-third of the total grant on each anniversary of the grant dates, unless the employee is retirement eligible, in which case the
RSUs generally vest in each portion of that award equally in six -month increments over a three -year period beginning at grant date. Retirement eligible
employees must stay with the Company through the entire six -month vesting period to receive that increment of vesting and any non-vested portions of an RSU
award will be forfeited when the employee leaves the Company.
A summary of the shares of common stock issued to settle employee RSUs is presented in the table below:
Shares of common stock issued to settle RSUs (1)
Less: shares of common stock withheld for income and payroll taxes
Net shares of common stock issued
____________________________________________
For the Years Ended December 31,
2018
2017
2016
407,529
(115,784)
291,745
246,025
(74,747)
171,278
241,363
(72,181)
169,182
(1) During the years ended December 31, 2018 , 2017 , and 2016 , the Company issued shares of common stock to settle RSUs that related to awards granted
in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll
tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
The total fair value of employee RSUs that vested during the years ended December 31, 2018 , 2017 , and 2016 was $9.9 million , $10.8 million , and
$14.0 million , respectively.
Director Shares
In 2018 , 2017 , and 2016 , the Company issued 63,741 , 71,573 , and 53,473 shares, respectively, of its common stock to its non-employee directors
under the Equity Plan. In 2017, the Company issued 8,794 RSUs to a non-employee director. For the years ended December 31, 2018 , 2017 , and 2016 , the
Company recorded $1.7 million , $1.6 million , and $2.0 million , respectively, of compensation expense related to director shares and RSUs issued.
All shares issued to non-employee directors fully vest on December 31 of the year granted. The RSUs issued to a non-employee director in 2017 fully
vested on December 31, 2017, and will settle upon the earlier to occur of May 25, 2027, or the director resigning from the Board of Directors.
Employee Stock Purchase Plan
Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through
payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The
purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is
intended to qualify under Section 423 of the Internal Revenue Code (the “IRC”). The Company had approximately 1.6 million shares of its common stock
available for issuance under the ESPP as of December 31, 2018 . There were 199,464 , 186,665 , and 218,135 shares issued under the ESPP in 2018 , 2017 ,
and 2016 , respectively.
98
Total proceeds to the Company for the issuance of these shares were $3.2 million , $2.6 million , and $4.2 million for the years ended December 31, 2018 , 2017
, and 2016 , respectively.
The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model. Expected volatility is calculated based on
the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a
six-month vesting period.
The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions:
Risk free interest rate
Dividend yield
Volatility factor of the expected market
price of the Company’s common stock
Expected life (in years)
For the Years Ended December 31,
2018
2017
2016
1.8%
0.4%
55.9%
0.5
0.9%
0.5%
62.5%
0.5
0.4%
0.4%
95.0%
0.5
The Company expensed $1.1 million , $1.0 million , and $2.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively, based on
the estimated fair value of the ESPP grants.
401(k) Plan
The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k)
Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. For
employees hired before December 31, 2014, the Company matches 100 percent of each employee’s contribution in cash on a dollar for dollar basis, up to six
percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches 150 percent of
contributions made by employees hired after December 31, 2014, up to six percent of the employee’s base salary and performance bonus in lieu of pension plan
benefits, and may make additional contributions at its discretion. Please refer to Note 8 – Pension Benefits for additional discussion of pension benefits. The
Company’s matching contributions to the 401(k) Plan were $4.9 million , $4.5 million , and $5.4 million for the years ended December 31, 2018 , 2017 , and
2016 , respectively.
Net Profits Plan
Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during each year were designated within a specific pool
with key employees designated as participants that became entitled to payments under the Net Profits Plan after the Company has received net cash flows
returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the
participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the
Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December
2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool
established by the Company.
The following table presents cash payments made or accrued under the Net Profits Plan related to periodic operations, of which the majority is
recorded as general and administrative expense, and cash payments made or accrued as a result of divestitures of properties subject to the Net Profits Plan,
which are recorded as a reduction to the net gain (loss) on divestiture activity line item in the accompanying statements of operations.
Cash payments made or accrued related to operations
Cash payments made or accrued related to divestitures
Total net settlements
For the Years Ended December 31,
2018
2017
2016
(in thousands)
63 $
—
63 $
(54) $
2,753
2,699 $
6,608
24,349
30,957
$
$
99
Note 8 – Pension Benefits
The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began
employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan
covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company
froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to it being frozen will continue to
earn benefits.
Obligations and Funded Status for the Pension Plans
The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the
Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to other
comprehensive income (loss), net of tax, in the accompanying statements of comprehensive income. The projected benefit obligation is the actuarial present
value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases.
The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The
Company’s measurement date for plan assets and obligations is December 31.
For the Years Ended December 31,
2018
2017
(in thousands)
Change in benefit obligation:
Projected benefit obligation at beginning of year
$
71,937 $
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Projected benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contribution
Benefits paid
Fair value of plan assets at end of year
6,730
2,622
(7,155)
(8,048)
66,086
30,978
(964)
8,134
(8,048)
30,100
Funded status at end of year
$
(35,986) $
69,659
6,638
2,689
3,708
(10,757)
71,937
31,731
2,956
7,048
(10,757)
30,978
(40,959)
The Company’s underfunded status for the Pension Plans as of December 31, 2018 , and 2017 , was $36.0 million and $41.0 million , respectively, and
is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. There are no plan assets in the Nonqualified Pension Plan.
Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans
Projected benefit obligation
Accumulated benefit obligation
Less: fair value of plan assets
Underfunded accumulated benefit obligation
As of December 31,
2018
2017
(in thousands)
66,086 $
71,937
52,368 $
(30,100)
22,268 $
56,045
(30,978)
25,067
$
$
$
Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest
cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan
assets that recognizes changes in fair value over a five-year period. This practice is
100
intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets
and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different
from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of
net periodic benefit cost for the year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected
benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of
participating employees expected to receive benefits under the plan.
The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of
December 31, 2018 , and 2017 , were as follows:
As of December 31,
2018
2017
(in thousands)
Unrecognized actuarial losses
Unrecognized prior service costs
Accumulated other comprehensive loss
$
$
15,741 $
48
15,789 $
21,397
66
21,463
The pension liability adjustments recognized in other comprehensive income (loss) during 2018 , 2017 , and 2016 , were as follows:
Net actuarial gain (loss)
Amortization of prior service cost
Amortization of net actuarial loss
Settlements
Total pension liability adjustment, pre-tax
Tax (expense) benefit
Cumulative effect of accounting change (1)
Total pension liability adjustment, net
$
$
For the Years Ended December 31,
2018
2017
2016
(in thousands)
4,329 $
(2,995) $
18
1,327
—
5,674
(4,265)
2,969
17
1,297
3,009
1,328
(561)
—
4,378 $
767 $
(3,322)
16
1,582
—
(1,724)
570
—
(1,154)
_________________________________________
(1) Refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information.
Components of Net Periodic Benefit Cost for the Pension Plans
Components of net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets that reduces
periodic pension benefit cost
Amortization of prior service cost
Amortization of net actuarial loss
Settlements
Net periodic benefit cost
$
$
For the Years Ended December 31,
2018
2017
2016
(in thousands)
6,730 $
2,622
(1,862)
18
1,327
—
6,638 $
2,689
(2,244)
17
1,297
3,009
8,835 $
11,406 $
101
8,200
2,908
(2,235)
16
1,582
—
10,471
Pension Plan Assumptions
The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows:
Projected benefit obligation:
Discount rate
Rate of compensation increase
As of December 31,
2018
4.4%
6.2%
2017
3.8%
6.2%
The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows:
Net periodic benefit cost:
Discount rate
Expected return on plan assets (1)
For the Years Ended December 31,
2018
3.8%
5.5%
2017
4.2%
6.5%
2016
4.7%
7.5%
Rate of compensation increase
____________________________________________
(1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.
6.2%
6.2%
6.2%
The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a
manner necessary to meet the future benefit obligation of the Pension Plans. The policy prohibits the direct investment of plan assets in the Company’s
securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term
perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification,
assessment of risk, and targeting the optimal expected returns for given levels of risk are applied.
The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The
investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities
having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to
maintain the target allocations.
The weighted-average asset allocation of the Qualified Pension Plan is as follows:
Asset Category
Equity securities
Fixed income securities
Other securities
Total
Target
2019
As of December 31,
2018
2017
35.0%
43.0%
22.0%
31.8%
41.3%
26.9%
100.0%
100.0%
38.4%
39.8%
21.8%
100.0%
There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in the plan. An expected return on plan assets of 5.5
percent , 6.5 percent , and 7.5 percent was used to calculate the Company’s net periodic pension cost under the Qualified Pension Plan for the years ended
December 31, 2018 , 2017 , and 2016 respectively. The expected long-term rate of return assumption of the Qualified Pension Plan is based upon the target
asset allocation and is determined using forward-looking assumptions in the context of historical returns and volatilities for each asset class, as well as
correlations among asset classes. We evaluate the expected rate of return on plan assets assumption on an annual basis.
102
Pension Plan Assets
The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2018 , and 2017 , utilizing the fair value hierarchy discussed in
Note 11 – Fair Value Measurements are as follows:
Actual Asset
Allocation (1)
Total
Level 1 Inputs Level 2 Inputs Level 3 Inputs
Fair Value Measurements Using:
(in thousands)
As of December 31, 2018
Cash
Equity securities:
Domestic (2)
International (3)
Total equity securities
Fixed income securities:
High-yield bonds (4)
Core fixed income (5)
Floating rate corporate loans (6)
Total fixed income securities
Other securities:
Commodities (7)
Real estate (8)
Collective investment trusts (9)
Hedge fund (10)
Total other securities
Total investments
As of December 31, 2017
Cash
Equity securities:
Domestic (2)
International (3)
Total equity securities
Fixed income securities:
High-yield bonds (4)
Core fixed income (5)
Floating rate corporate loans (6)
Total fixed income securities
Other securities:
Commodities (7)
Real estate (8)
Collective investment trusts (9)
Hedge fund (10)
Total other securities
Total investments
—% $
— $
— $
— $
15.4%
16.4%
31.8%
—%
34.4%
6.9%
41.3%
—%
6.0%
3.1%
17.8%
26.9%
4,639
4,941
9,580
—
10,342
2,078
12,420
—
1,820
934
5,346
8,100
3,197
3,642
6,839
—
10,342
2,078
12,420
—
—
—
—
—
1,442
1,299
2,741
—
—
—
—
—
—
934
1,659
2,593
100.0% $
30,100 $
19,259 $
5,334 $
—% $
— $
— $
— $
22.2%
16.2%
38.4%
2.8%
28.6%
8.4%
39.8%
1.9%
5.6%
3.1%
11.2%
21.8%
6,865
5,032
11,897
876
8,842
2,607
12,325
588
1,735
959
3,474
6,756
4,805
3,806
8,611
876
8,842
2,607
12,325
588
—
—
—
588
2,060
1,226
3,286
—
—
—
—
—
—
959
—
959
100.0% $
30,978 $
21,524 $
4,245 $
—
—
—
—
—
—
—
—
—
1,820
—
3,687
5,507
5,507
—
—
—
—
—
—
—
—
—
1,735
—
3,474
5,209
5,209
____________________________________________
(1) Percentages may not calculate due to rounding.
(2) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon
demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying
investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective
investment funds.
103
(3)
International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets,
commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at
attractive valuations.
(4) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased
level of default risk, security selection focuses on credit-risk analysis.
(5) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment
(6)
results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index.
Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of
interest rates.
Investments with exposure to commodity price movements, primarily through the use of futures, swaps, and other commodity-linked securities.
(7)
(8) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate
entails a long-term time horizon, periodic valuations, and potentially low liquidity.
(9) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as
provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments
held by the fund less its liabilities.
(10) The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that
invests both long and short using a variety of investment strategies.
Included below is a summary of the changes in Level 3 plan assets (in thousands):
Balance at January 1, 2017
Purchases
Realized gain on assets
Unrealized gain on assets
Disposition
Balance at December 31, 2017
Purchases
Realized gain on assets
Unrealized gain on assets
Disposition
Balance at December 31, 2018
Contributions
$
$
$
5,214
300
130
120
(555)
5,209
—
191
152
(45)
5,507
The Company contributed $8.1 million , $7.0 million , and $11.0 million to the Pension Plans for the years ended December 31, 2018 , 2017 , and 2016
, respectively. The Company expects to make a $4.0 million contribution to the Pension Plans in 2019 .
Benefit Payments
The Pension Plans made actual benefit payments of $8.0 million , $10.8 million , and $6.7 million in the years ended December 31, 2018 , 2017 , and
2016 , respectively. Expected benefit payments over the next 10 years are as follows:
Years Ending December 31,
(in thousands)
2019
2020
2021
2022
2023
2024 through 2028
$
$
$
$
$
$
5,429
5,066
4,913
5,715
7,693
30,400
104
Note 9 - Earnings Per Share
Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-
average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing adjusted net
income or loss by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially
dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible,
which are measured using the treasury stock method.
PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three -year performance period, a number of shares of the
Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares
related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end
of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading
Performance Share Units .
On August 12, 2016 , the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021 . Upon conversion, the
Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common
stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal
amount of the Senior Convertible Notes in cash and the excess conversion value in shares. However, the Company has not made an irrevocable election and
thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business circumstances warrant. Shares of the
Company’s common stock traded at an average closing price below the $40.50 conversion price for the years ended December 31, 2018 , and 2017 , and for
the portion of the year ended December 31, 2016 , during which the Senior Convertible Notes were outstanding; therefore, the Senior Convertible Notes had no
dilutive impact. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the
underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions will always be anti-dilutive and
therefore will never be reflected in diluted net income or loss per share. Please refer to Note 5 – Long-Term Debt for additional discussion.
When the Company recognizes a net loss from continuing operations, as was the case for the years ended December 31, 2017 , and 2016 , all
potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share.
The following table details the weighted-average dilutive and anti-dilutive securities for the years presented:
Dilutive
Anti-dilutive
For the Years Ended December 31,
2018
2017
2016
(in thousands)
1,590
—
—
264
—
280
The following table sets forth the calculations of basic and diluted net income (loss) per common share:
For the Years Ended December 31,
2018
2017
2016
(in thousands, except per share data)
Net income (loss)
$
508,407 $
(160,843) $
(757,744)
Basic weighted-average common shares outstanding
Dilutive effect of non-vested RSUs and contingent PSUs
Dilutive effect of Senior Convertible Notes
Diluted weighted-average common shares outstanding
111,912
1,590
—
113,502
111,428
76,568
—
—
—
—
111,428
76,568
Basic net income (loss) per common share
Diluted net income (loss) per common share
$
$
4.54 $
4.48 $
(1.44) $
(1.44) $
(9.90)
(9.90)
105
Note 10 – Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in
commodity prices and the associated impact on cash flows. As of December 31, 2018 , all derivative counterparties were members of the Company’s Credit
Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap
and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon
published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed
upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives
the difference between an agreed upon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed
upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and
ceiling prices.
The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry
benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts
with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland
prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a
portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.
As of December 31, 2018 , the Company had commodity derivative contracts outstanding through the fourth quarter of 2022 , as summarized in the
tables below.
Oil Swaps
Contract Period
NYMEX WTI Volumes
Weighted-Average
Contract Price
(MBbl)
(per Bbl)
First quarter 2019
Second quarter 2019
Third quarter 2019
Fourth quarter 2019
2020
Total
Oil Collars
826 $
575 $
1,217 $
1,115 $
2,491 $
6,224
60.16
55.52
61.41
59.97
65.68
Contract Period
NYMEX WTI Volumes
Weighted-Average
Floor Price
Weighted-Average
Ceiling Price
(MBbl)
(per Bbl)
(per Bbl)
First quarter 2019
Second quarter 2019
Third quarter 2019
Fourth quarter 2019
2020
Total
2,503 $
2,802 $
2,364 $
2,386 $
1,165 $
11,220
64.32
64.61
62.67
62.65
66.47
51.66 $
52.18 $
49.07 $
49.08 $
55.00 $
106
Oil Basis Swaps
Contract Period
WTI Midland-NYMEX
WTI Volumes
Weighted-Average
Contract Price (1)
NYMEX WTI-ICE
Brent Volumes
Weighted-Average
Contract Price (2)
(MBbl)
(per Bbl)
(MBbl)
(per Bbl)
First quarter 2019
Second quarter 2019
Third quarter 2019
Fourth quarter 2019
2020
2021
2022
Total
2,433 $
2,571 $
3,291 $
3,338 $
11,601 $
— $
— $
23,234
(4.44)
(4.49)
(2.86)
(2.87)
(1.03)
—
—
— $
— $
— $
— $
2,750 $
3,650 $
3,650 $
10,050
—
—
—
—
(8.03)
(7.86)
(7.78)
____________________________________________
(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
Gas Swaps
Contract Period
IF HSC Volumes
Weighted-
Average
Contract Price
WAHA Volumes
Weighted-
Average
Contract Price
First quarter 2019
Second quarter 2019
Third quarter 2019
Fourth quarter 2019
2020
(BBtu)
(per MMBtu)
(BBtu)
(per MMBtu)
19,805 $
10,439 $
12,531 $
14,433 $
9,123 $
2.99
2.82
2.82
2.88
2.98
— $
2,803 $
2,984 $
2,962 $
2,060 $
—
0.69
1.28
1.75
2.20
Total (1)
____________________________________________
(1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”),
10,809
66,331
and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2018, total volumes for gas swaps are comprised of 86 percent IF HSC , four percent
IF Waha , and 10 percent GD Waha .
Gas Collars
Contract Period
IF HSC Volumes
Weighted-
Average Floor
Price
Weighted-
Average Ceiling
Price
(BBtu)
(per MMBtu)
(per MMBtu)
First quarter 2019
Second quarter 2019
Third quarter 2019
Fourth quarter 2019
Total
— $
4,358 $
5,066 $
4,818 $
14,242
— $
2.50 $
2.50 $
2.50 $
—
2.83
2.83
2.83
107
NGL Swaps
OPIS Ethane Purity
Mont Belvieu
OPIS Propane Mont
Belvieu Non-TET
OPIS Normal Butane
Mont Belvieu Non-
TET
OPIS Isobutane Mont
Belvieu
Non-TET
OPIS Natural
Gasoline Mont
Belvieu Non-TET
Contract Period
Volumes
Weighted-
Average
Contract
Price
Volumes
Weighted-
Average
Contract
Price
Volumes
Weighted-
Average
Contract
Price
Volumes
Weighted-
Average
Contract
Price
Volumes
Weighted-
Average
Contract
Price
(MBbl)
(per Bbl)
(MBbl)
(per Bbl)
(MBbl)
(per Bbl)
(MBbl)
(per Bbl)
(MBbl)
(per Bbl)
First quarter 2019
Second quarter
2019
Third quarter 2019
Fourth quarter 2019
2020
Total
853 $
12.25
540 $
28.72
877 $
907 $
896 $
539 $
4,072
12.29
12.34
12.36
11.13
561 $
637 $
651 $
— $
2,389
31.32
31.29
31.64
—
35.64
35.64
35.64
35.64
—
38 $
38 $
39 $
39 $
— $
154
35.70
35.70
35.70
35.70
—
29 $
29 $
30 $
29 $
— $
117
48 $
50.93
50.93
50.93
50.93
—
49 $
50 $
50 $
— $
197
Derivative Assets and Liabilities Fair Value
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and
liabilities. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the derivative commodity contracts was
a net asset of $158.3 million at December 31, 2018 , and net liability of $139.4 million at December 31, 2017 .
The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:
Commodity contracts
Commodity contracts
Total commodity contracts
As of December 31, 2018
Derivative Assets
Derivative Liabilities
Balance Sheet
Classification
Fair Value
Balance Sheet
Classification
Fair Value
(in thousands)
Current assets
$
175,130 Current liabilities
Noncurrent assets
58,499 Noncurrent liabilities
$
233,629
$
$
62,853
12,496
75,349
As of December 31, 2017
Derivative Assets
Derivative Liabilities
Balance Sheet
Classification
Fair Value
Balance Sheet
Classification
Fair Value
(in thousands)
Commodity contracts
Commodity contracts
Total commodity contracts
Current assets
$
64,266 Current liabilities
$
172,582
Noncurrent assets
40,362 Noncurrent liabilities
71,402
$
104,628
$
243,984
Offsetting of Derivative Assets and Liabilities
As of December 31, 2018 , and 2017 , all derivative instruments held by the Company were subject to master netting arrangements with various
financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty,
at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event
of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The
Company’s accounting policy is to not offset these positions in its accompanying balance sheets.
108
The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential
effects of master netting arrangements on the fair value of the Company’s derivative contracts:
Derivative Assets
Derivative Liabilities
As of December 31,
As of December 31,
Offsetting of Derivative Assets and Liabilities
2018
2017
2018
2017
Gross amounts presented in the accompanying balance
sheets
$
233,629 $
104,628 $
(75,349) $
(243,984)
Amounts not offset in the accompanying balance sheets
(56,041)
(100,035)
56,041
100,035
Net amounts
$
177,588 $
4,593 $
(19,308) $
(143,949)
(in thousands)
The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such
amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the years ended
December 31, 2018 , 2017 , and 2016 . Please refer to Note 11 – Fair Value Measurements for more information regarding the Company’s derivative
instruments, including its valuation techniques.
The following table summarizes the components of the net derivative (gain) loss line item presented in the accompanying statements of operations:
Derivative settlement (gain) loss:
Oil contracts
Gas contracts
NGL contracts
Total derivative settlement (gain) loss
Net derivative (gain) loss:
Oil contracts
Gas contracts
NGL contracts
Total net derivative (gain) loss
Credit Related Contingent Features
For the Years Ended December 31,
2018
2017
2016
(in thousands)
$
$
$
$
68,860 $
13,029
53,914
31,176 $
(87,857)
35,447
135,803 $
(21,234) $
(192,002) $
35,411
(5,241)
(161,832) $
71,502 $
(76,315)
31,227
26,414 $
(243,102)
(94,936)
8,560
(329,478)
85,370
81,060
84,203
250,633
As of December 31, 2018 , and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit
Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent
of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit
Agreement also secures the Company’s derivative agreement obligations.
Note 11 – Fair Value Measurements
The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the
measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence
of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
•
•
Level 1 – quoted prices in active markets for identical assets or liabilities
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not
active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
109
•
Level 3 – significant inputs to the valuation model are unobservable
Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on the Company’s policies for determining fair value for
the categories discussed below.
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where
they are classified within the fair value hierarchy as of December 31, 2018 :
Assets:
Derivatives (1)
Liabilities:
Derivatives (1)
Level 1
Level 2
Level 3
(in thousands)
$
$
— $
— $
233,629 $
75,349 $
—
—
____________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where
they are classified within the fair value hierarchy as of December 31, 2017 :
Assets:
Derivatives (1)
Liabilities:
Derivatives (1)
Level 1
Level 2
Level 3
(in thousands)
$
$
— $
— $
104,628 $
243,984 $
—
—
____________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is
significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general
classification of such instruments pursuant to the above fair value hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data.
The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit
rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors
result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity
derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity
derivative markets are highly active.
Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment
may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of
its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to
a more stable counterparty.
Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position.
This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any
letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk,
taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.
The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair
values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance
and other marketplace participants, the Company recognizes that third-parties may use different methodologies or assumptions to determine the fair value of
certain financial instruments that could result in a different estimate of fair value at the reporting date.
Refer to Note 10 – Derivative Financial Instruments for more information regarding the Company’s derivative instruments.
110
Proved and Unproved Oil and Gas Properties
Proved oil and gas properties . Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication
that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique to measure the fair value of
proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the
Company’s management. There were no material proved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31,
2018 , or December 31, 2017 . The Company recorded impairment of proved properties expense of $354.6 million for the year ended December 31, 2016 ,
related primarily to the decline in expected reserve cash flows from the Company’s outside-operated Eagle Ford shale assets driven by commodity price
declines during the first quarter of 2016, and downward performance reserve revisions in the fourth quarter of 2016 for the Company’s Powder River Basin
assets.
Unproved oil and gas properties . Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an
indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes
into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated
reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.
The following table presents abandonment and impairment of unproved properties expense recorded for the periods presented:
For the Years Ended December 31,
2018
2017
2016
(in millions)
Abandonment and impairment of unproved properties
$
49.9 $
12.3 $
80.4
Abandonment and impairment of unproved properties expense recorded during the years ended December 31, 2018 , and 2017 , related primarily to
actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other
inherent acreage risks. During the year ended December 31, 2016 , abandonment and impairment expense related primarily to a decrease in the fair value of
the Company’s unproved Powder River Basin properties due to downward performance reserve revisions and lower market prices based on third-party acreage
transactions.
Long-Term Debt
The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted
secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2018 , or 2017 , as
they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional
discussion.
As of December 31,
2018
2017
Principal Amount
Fair Value
Principal Amount
Fair Value
6.50% Senior Notes due 2021
6.125% Senior Notes due 2022
6.50% Senior Notes due 2023
5.0% Senior Notes due 2024
5.625% Senior Notes due 2025
6.75% Senior Notes due 2026
6.625% Senior Notes due 2027
1.50% Senior Convertible Notes due 2021
$
$
$
$
$
$
$
$
(in thousands)
— $
— $
476,796 $
452,336 $
— $
500,000 $
500,000 $
500,000 $
500,000 $
172,500 $
— $
439,265 $
436,460 $
448,305 $
442,500 $
158,614 $
344,611 $
561,796 $
394,985 $
500,000 $
500,000 $
500,000 $
— $
172,500 $
351,682
571,627
403,434
483,440
494,355
516,350
—
168,291
The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market
rates.
111
Note 12 – Suspended Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2018 , 2017 , and 2016 . The table does not include amounts
that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year:
For the Years Ended December 31,
2018
2017
2016
(in thousands)
Beginning balance
$
49,446 $
19,846 $
11,952
Additions to capitalized exploratory well costs pending the
determination of proved reserves
Divestitures
Reclassifications to wells, facilities, and equipment based on the
determination of proved reserves
Capitalized exploratory well costs charged to expense
11,197
(109)
(49,337)
—
49,446
—
(19,846)
—
Ending balance
$
11,197 $
49,446 $
19,846
—
(11,952)
—
19,846
As of December 31, 2018 , there were no exploratory well costs that were capitalized for more than one year.
Note 13 – Equity
On August 12, 2016 , the Company completed an underwritten public offering of approximately 18.4 million shares of its common stock at an offering
price of $30.00 per share. Net proceeds from the offering totaled $530.9 million , after deducting underwriting discounts and commissions and offering
expenses, which the Company used to partially fund the Rock Oil Acquisition that closed during the fourth quarter of 2016.
On December 7, 2016 , the Company completed an underwritten public offering of approximately 10.9 million shares of its common stock at an offering
price of $38.25 per share. Net proceeds from the offering totaled $403.2 million , after deducting underwriting discounts and commissions and offering
expenses, which the Company used to partially fund the QStar Acquisition that also closed during the fourth quarter of 2016.
The Company’s 2016 public equity offerings were made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC.
On December 21, 2016, and as part of the QStar Acquisition, the Company issued approximately 13.4 million shares of its common stock valued at
approximately $437.2 million in a private placement to the sellers as partial consideration for the acquired properties. Please refer to Note 3 – Divestitures,
Assets Held for Sale, and Acquisitions for additional discussion.
The Company did not conduct any equity offerings during 2018 or 2017.
112
Note 14 – Asset Retirement Obligations
Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policies for a discussion of the initial and subsequent
measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates.
A reconciliation of the Company’s total asset retirement obligation liability is as follows:
Beginning asset retirement obligations
Liabilities incurred (1)
Liabilities settled (2)
Accretion expense
Revision to estimated cash flows
Ending asset retirement obligations (3)(4)
$
$
As of December 31,
2018
2017
(in thousands)
114,470 $
4,054
(33,024)
4,438
4,256
94,194 $
123,307
7,588
(30,432)
5,988
8,019
114,470
____________________________________________
(1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.
(2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.
(3) Balance as of December 31, 2017 , included $11.4 million of asset retirement obligations associated with oil and gas properties held for sale.
(4) Balances as of December 31, 2018 , and 2017 , included $2.3 million and $75,000 , respectively, related to the Company’s current asset retirement
obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.
Note 15 – Accounts Receivable and Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following accruals:
Oil, gas, and NGL production revenue
Amounts due from joint interest owners
State severance tax refunds
Derivative settlements
Other
Total accounts receivable
As of December 31,
2018
2017
(in thousands)
107,230 $
31,497
4,415
9,475
14,919
167,536 $
96,610
56,929
2,276
99
4,240
160,154
$
$
Accounts payable and accrued expenses are comprised of the following accruals:
As of December 31,
2018
2017
(in thousands)
Drilling and lease operating cost accruals
$
139,711 $
126,500
Trade accounts payable
Revenue and severance tax payable
Property taxes
Compensation
Derivative settlements
Interest
Other
56,047
94,806
18,694
31,486
1,287
40,840
20,328
77,573
60,328
13,222
39,471
12,644
45,057
11,835
Total accounts payable and accrued expenses
$
403,199 $
386,630
113
Supplemental Oil and Gas Information (unaudited)
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:
Development costs (1)
Exploration costs
Acquisitions (2)
Proved properties
Unproved properties (3)
For the Years Ended December 31,
2018
2017
2016
(in thousands)
$
1,147,574 $
184,930
1,312
55,688
675,523 $
271,502
1,602
91,420
595,331
118,224
201,672
2,458,667
Total, including asset retirement obligations (4)(5)
____________________________________________
(1)
(2) Balances at December 31, 2016, include $437.2 million of value attributed to the equity consideration given to the sellers of the assets acquired in the QStar
Includes facility costs of $72.6 million , $43.8 million , and $25.9 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively.
1,040,047 $
1,389,504 $
3,373,894
$
Acquisition. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion.
Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $23.4 million ,
$12.8 million , and $7.5 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively.
Includes amounts relating to estimated asset retirement obligations of $7.1 million , $13.6 million , and $32.1 million for the years ended December 31, 2018
, 2017 , and 2016 , respectively.
Includes capitalized interest of $20.6 million , $12.6 million , and $17.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively.
(3)
(4)
(5)
Oil and Gas Reserve Quantities
The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and
SEC rules for oil and gas reporting of reserve estimation and disclosure.
Proved reserves are the estimated 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. All of the Company’s estimated proved
reserves are located in the United States.
114
The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended
December 31, 2018 . The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the Company’s total calculated
proved reserve PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries
and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to
change as future information becomes available.
For the Years Ended December 31,
2018 (1)
2017 (2)
2016 (3)
Oil
Gas
NGLs
Oil
Gas
NGLs
Oil
Gas
NGLs
(MMBbl)
(Bcf)
(MMBbl)
(MMBbl)
(Bcf)
(MMBbl)
(MMBbl)
(Bcf)
(MMBbl)
Total proved reserves:
Beginning of year
158.2 1,280.1
96.5
104.9 1,111.1
105.7
145.3 1,264.0
115.4
Revisions of
previous
estimate
Discoveries and
extensions
Infill reserves in
an existing
proved field
Sales of
reserves (4)
Purchases of
minerals in
place (4)
Production
(24.0)
(219.5)
(8.0)
1.0
63.8
4.9
(36.0)
(249.8)
(18.6)
9.3
20.3
0.5
11.5
21.9
—
7.8
42.5
4.1
80.4
391.5
29.0
79.0
347.4
22.9
32.3
228.1
18.9
(29.6)
(48.1)
(2.7)
(25.3)
(143.8)
(26.7)
(40.0)
(46.7)
—
0.2
0.7
(18.8)
(103.2)
—
(7.9)
0.8
2.7
(13.7)
(123.0)
End of year
175.7 1,321.8
107.4
158.2 1,280.1
—
(10.3)
96.5
12.1
19.9
(16.6)
(146.9)
104.9 1,111.1
0.1
(14.2)
105.7
Proved developed reserves:
Beginning of year
End of year
58.6
68.2
642.9
699.1
Proved undeveloped reserves:
Beginning of year
99.6
637.2
End of year
____________________________________________
Note: Amounts may not calculate due to rounding.
622.7
107.6
49.0
60.1
47.6
47.2
48.5
609.1
58.6
642.9
56.4
99.6
502.0
637.2
58.6
49.0
47.1
47.6
75.6
644.4
48.5
609.1
69.6
56.4
619.7
502.0
61.5
58.6
53.9
47.1
(1) For the year ended December 31, 2018 , the Company added 188.0 MMBOE from its drilling program and through development plan optimization. The
Company divested 40.3 MMBOE during 2018, primarily as a result of the PRB Divestiture, Divide County Divestiture, and Half East Divestiture. The
Company also had net downward revisions of 68.8 MMBOE, which resulted primarily from changes in development plans in its Eagle Ford shale program.
(2) For the year ended December 31, 2017 , the Company added 175.0 MMBOE from its drilling program. The Company divested 76.0 MMBOE during 2017,
including 72.5 MMBOE related to its outside-operated Eagle Ford shale assets.
(3) For the year ended December 31, 2016 , the Company added 108.2 MMBOE from its drilling program and acquired 15.5 MMBOE. These additions were
offset by net downward revisions of 96.2 MMBOE, consisting of 18.1 MMBOE of performance revisions, a 35.1 MMBOE price revision, and the removal of
43.0 MMBOE of proved undeveloped reserves to reflect the Company’s shift to develop its predominately unproven Midland Basin properties. Additionally,
the Company divested 47.7 MMBOE during 2016.
(4) Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information.
Standardized Measure of Discounted Future Net Cash Flows
The Company computes a standardized measure of future net cash flows (“Standardized Measure”) and changes therein relating to estimated proved
reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices
and costs, including transportation, quality, and basis differentials, to the year end estimated future reserve quantities. Each property the Company operates is
also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax
rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10
percent annual discount factor.
115
Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves
in place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the
central administrative office attributable to operating activities.
The assumptions used to compute the Standardized Measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily
reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve
quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations since these reserve quantity estimates
are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the
Standardized Measure:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
For the Years Ended December 31,
2018
2017
2016
$
$
$
57.76 $
3.49 $
26.23 $
48.57 $
3.20 $
23.33 $
37.22
2.45
16.38
The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the Standardized
Measure.
Future cash inflows
Future production costs
Future development costs
Future income taxes (1)
Future net cash flows
10 percent annual discount
As of December 31,
2018
2017
2016
(in thousands)
$
17,579,432 $
14,035,704 $
8,359,938
(5,386,264)
(2,679,488)
(1,012,209)
8,501,471
(3,847,088)
(5,594,226)
(2,638,459)
(205,694)
5,597,325
(2,573,183)
(4,634,649)
(1,636,077)
—
2,089,212
(937,099)
1,152,113
Standardized measure of discounted future net cash flows
$
4,654,383 $
3,024,142 $
___________________________________________
(1) Regarding the calculations as of December 31, 2016, after evaluating all factors and giving effect to tax basis, future tax deductions, and available tax
credits, the Company determined that at price levels for each respective period, future net cash flows would not be subject to federal or state income tax for
the projected life of the reserves under authoritative tax legislation.
The principle sources of changes in the Standardized Measure were:
For the Years Ended December 31,
2018
2017
2016
(in thousands)
Standardized Measure, beginning of year
$
3,024,142 $
1,152,113 $
1,790,526
Sales of oil, gas, and NGLs produced, net of production costs
Net changes in prices and production costs
Extensions, discoveries and other including infill reserves in an
existing proved field, net of related costs
Sales of reserves in place
Purchase of reserves in place
Previously estimated development costs incurred during the period
Changes in estimated future development costs
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Changes in timing and other
(1,148,991)
1,010,335
2,218,475
(147,887)
1,818
445,638
(34,871)
(611,168)
305,657
(449,884)
41,119
(745,877)
1,181,447
1,638,734
(226,528)
12,032
121,879
(116,609)
103,916
115,211
(32,426)
(179,750)
(580,861)
(315,725)
242,556
(377,607)
115,270
290,837
27,961
(124,845)
179,050
—
(95,049)
Standardized Measure, end of year
$
4,654,383 $
3,024,142 $
1,152,113
116
Quarterly Financial Information (unaudited)
The Company’s quarterly financial information for fiscal years 2018 and 2017 is as follows (in thousands, except per share data):
Year Ended December 31, 2018 (2)
Total operating revenues and other income
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
Basic net income (loss) per common share (1)
Diluted net income (loss) per common share (1)
Dividends declared per common share
Year Ended December 31, 2017 (3)
Total operating revenues and other income
Total operating expenses (4)
Income (loss) from operations (4)
Income (loss) before income taxes
Net income (loss)
Basic net income (loss) per common share (1)
Diluted net income (loss) per common share (1)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
769,595 $
443,916 $
459,369 $
310,527
459,068 $
416,392 $
317,401 $
2.84 $
2.81 $
0.05 $
387,768
568,013
56,148 $
16,296 $
17,197 $
0.15 $
0.15 $
— $
(108,644) $
(172,671) $
(135,923) $
(1.21) $
(1.21) $
0.05 $
394,192
(35,573)
429,765
391,760
309,732
2.76
2.73
—
372,738 $
120,721 $
295,379 $
206,577
268,047
380,531
166,161 $
(147,326) $
(85,152) $
340,538
437,942
(97,404)
118,940 $
(190,968) $
(128,382) $
(143,403)
74,434 $
(119,907) $
(89,112) $
(26,258)
0.67 $
0.67 $
(1.08) $
(1.08) $
(0.80) $
(0.80) $
(0.24)
(0.24)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Dividends declared per common share
____________________________________________
(1) Amounts may not calculate due to rounding.
(2) For the first quarter of 2018, the Company recorded an estimated $409.2 million net pre-tax gain on divestiture activity related to the PRB Divestiture, which
was partially offset by a $24.1 million write-down on certain assets previously held for sale. During the second quarter of 2018, the Company recorded an
estimated $15.7 million net pre-tax gain on divestiture activity related to the Divide County Divestiture and Halff East Divestiture (see Note 3 – Divestitures,
Assets Held for Sale, and Acquisitions ). During the third quarter of 2018, the Company recorded a $26.7 million loss on the early extinguishment of its 2021
Senior Notes, 2023 Senior Notes, and a portion of its 2022 Senior Notes (see Note 5 – Long-Term Debt ). For the first, second, third, and fourth quarters of
2018, the Company recorded net derivative losses of $7.5 million , $63.7 million , $178.0 million , and a net derivative gain of $411.1 million , respectively
(see Note 10 – Derivative Financial Instruments ).
—
0.05 $
0.05 $
— $
(3) During the first quarter of 2017, the Company recorded an estimated $37.5 million net pre-tax gain on divestiture activity related to the sale of the
Company’s outside-operated Eagle Ford shale assets partially offset by a write-down of the Company’s Divide County, North Dakota assets, which were
previously classified as held for sale. During the second quarter of 2017, the Company recorded a $167.1 million net pre-tax loss on divestiture activity
related primarily to an additional write-down of the Company’s retained Divide County, North Dakota assets upon reclassification as assets held for use. For
the first, second, third, and fourth quarters of 2017, the Company recorded a $114.8 million net derivative gain, a $55.2 million net derivative gain, an $80.6
million net derivative loss, and a $115.8 million net derivative loss, respectively (see Note 10 – Derivative Financial Instruments ).
(4) Amounts have been adjusted 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 for additional discussion.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
117
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our
SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that
such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to
allow for timely decisions regarding required disclosure.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control
system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the
company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur
because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by
management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events,
and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations
in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make
modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report.
This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial
Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a
reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
118
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-
15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
The Company’s internal control over financial reporting includes those policies and procedures that:
(i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
Company;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with
authorizations of management and directors of the Company; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets
that have a material effect on the financial statements.
Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined
to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of
compliance with the policies and procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018 . In making this
assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated
Framework (2013 framework) .
Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of
December 31, 2018 .
The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal control over financial
reporting. That report immediately follows this report.
119
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of SM Energy Company and subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2018 , based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO
criteria). In our opinion, SM Energy Company and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2018 , based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance
sheets of the Company as of December 31, 2018 and 2017 , the related consolidated statements of operations, comprehensive income (loss), stockholders’
equity, and cash flows for each of the three years in the period ended December 31, 2018 , and the related notes and our report dated February 21, 2019
expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to
express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of
the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Denver, Colorado
February 21, 2019
120
ITEM 9B. OTHER INFORMATION
None.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
PART III
The information required by this Item concerning the Company’s Directors, Executive Officers, and corporate governance is incorporated by reference
to the information provided under the captions “Proposal 1 - Election of Directors,” “Information about Executive Officers,” and “Corporate Governance” in the
Company’s definitive proxy statement for the 2019 annual meeting of stockholders to be filed within 120 days from December 31, 2018 .
The information required by this Item concerning compliance with Section 16(a) of the Exchange Act is incorporated by reference to the information
provided under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement for the 2019 annual meeting
of stockholders to be filed within 120 days from December 31, 2018 .
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the captions “Executive Compensation” and
“Director Compensation” in the Company’s definitive proxy statement for the 2019 annual meeting of stockholders to be filed within 120 days from December 31,
2018 .
121
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the
information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in the Company’s definitive proxy statement for the
2019 annual meeting of stockholders to be filed within 120 days from December 31, 2018 .
Securities Authorized for Issuance Under Equity Compensation Plans. The Company has equity compensation plans under which options and shares
of the Company’s common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of
Directors. The Company’s stockholders have approved these plans. See Note 7 – Compensation Plans included in Part II, Item 8 of this report for further
information about the material terms of the Company’s equity compensation plans. The following table is a summary of the shares of common stock authorized
for issuance under equity compensation plans as of December 31, 2018 :
(a)
(b)
(c)
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants,
and rights
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
— $
1,251,957
1,725,044
2,977,001 $
—
—
2,977,001 $
—
N/A
N/A
—
—
—
—
5,877,607
1,613,871
—
7,491,478
Plan category
Equity compensation plans approved by security holders:
Equity Incentive Compensation Plan
Stock options and incentive stock options (1)
Restricted stock units (1)(2)
Performance share units (1)(2)(3)
Total for Equity Incentive Compensation Plan
Employee Stock Purchase Plan (4)
Equity compensation plans not approved by security holders
Total for all plans
____________________________________________
(1)
In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options,
incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and
members of the Board of Directors of the Company or any affiliate of the Company. The Company’s Board of Directors approved amendments to the Equity
Plan in 2009, 2010, 2013, 2016, and 2018 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The
number of shares of the Company’s common stock underlying awards granted in 2018 , 2017 , and 2016 under the Equity Plan were 1,220,217 , 2,078,878
, and 918,509 , respectively.
(2) RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide
additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and
PSUs was $21.49 and $20.68, respectively. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for additional discussion.
(3) The number of awards vested assumes a one multiplier. The final number of shares of the Company’s common stock issued upon settlement may vary
depending on the three -year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two .
(4) Under the ESPP, eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible
compensation. The purchase price of the common stock is 85 percent of the lower of the fair market value of the common stock on the first or last day of the
six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to
qualify under Section 423 of the IRC. The number of shares of the Company’s common stock issued in 2018 , 2017 , and 2016 under the ESPP were
199,464 , 186,665 , and 218,135 , respectively.
122
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the information provided under the captions “ Certain Relationships and Related
Transactions ” and “ Corporate Governance ” in the Company’s definitive proxy statement for the 2019 annual meeting of stockholders to be filed within 120
days from December 31, 2018 .
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the information provided under the captions “ Independent Registered Public
Accounting Firm ” and “ Audit Committee Preapproval Policy and Procedures ” in the Company’s definitive proxy statement for the 2019 annual meeting of
stockholders to be filed within 120 days from December 31, 2018 .
123
ITEM 15. EXHIBITS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Consolidated Financial Statements and Financial Statement Schedules:
PART IV
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
70
71
72
73
74
75
77
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.
(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:
Exhibit
Number Description
2.1
2.2
2.3
2.4
2.5
2.6
2.7
3.1
3.2
4.1
4.2
4.3
Membership Interest Purchase Agreement dated August 8, 2016 between SM Energy Company and Rock Oil Holdings
LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on August 8, 2016, and incorporated herein by
reference)
Purchase and Sale Agreement, dated October 17, 2016, by and between SM Energy Company and QStar LLC (filed as
Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference)
Letter Agreement dated October 17, 2016, by and among SM Energy Company, QStar LLC, and RRP-QStar, LLC (filed as
Exhibit 2.2 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference)
Purchase and Sale Agreement dated October 17, 2016, by and between SM Energy Company and Oasis Petroleum North
America LLC (filed as Exhibit 2.3 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and
incorporated herein by reference)
Membership Interest Purchase Agreement dated January 1, 2017 between SM Energy Company and Venado EF LLC
(filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, and
incorporated herein by reference)
Second Amendment to Membership Interest Purchase Agreement dated March 4, 2017 between SM Energy and Venado
EF L.P. (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, and
incorporated herein by reference)
Purchase and Sale Agreement dated January 8, 2018 by and between SM Energy Company and Converse Energy
Acquisitions, LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on January 11, 2018 and
incorporated herein by reference)
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the
registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
Indenture related to the 5.0% Senior Notes due 2024, dated May 20, 2013, by and between SM Energy Company, as
issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K
filed on May 20, 2013, and incorporated herein by reference)
Indenture related to the 6.125% Senior Notes due 2022, dated November 17, 2014, by and between SM Energy Company,
as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-
K filed on November 18, 2014, and incorporated herein by reference)
Indenture related to senior debt securities of SM Energy Company by and between SM Energy Company and U.S. Bank
National Association, as trustee (filed as Exhibit 4.1 to the registrant’s Registration Statement on Form S-3 filed on May 7,
2015 (Registration No. 333-203936) and incorporated herein by reference)
124
4.4
4.5
4.6
4.7
4.8
4.9
4.10†
4.11
10.1
10.2
10.3†
10.4***
10.5††
10.6†
10.7+
10.8
10.9
10.10
10.11†
10.12†
2025 Notes Supplemental Indenture (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on May 21,
2015, and incorporated herein by reference)
Base Indenture, dated as of May 21, 2015, by and between SM Energy Company and U.S. Bank National Association, as
trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated
herein by reference)
Second Supplemental Indenture, dated August 12, 2016, by and between SM Energy Company and U.S. Bank, National
Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and
incorporated herein by reference)
Third Supplemental Indenture, dated September 12, 2016 by and between SM Energy Company and U.S. Bank National
Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on September 12, 2016,
and incorporated herein by reference)
Fourth Supplemental Indenture, dated as of August 20, 2018, by and between SM Energy Company and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on August 20,
2018, and incorporated herein by reference)
Supplemental Indenture, dated as of August 20, 2018, by and between SM Energy Company and U.S. Bank National
Association, as trustee (filed as Exhibit 4.3 to the registrant’s Current Report on Form 8-K filed on August 20, 2018, and
incorporated herein by reference)
SM Energy Company Equity Incentive Compensation Plan, amended and restated effective as of May 22, 2018 (filed as
Annex A in the registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 12, 2018, and incorporated herein by
reference)
Lock-Up and Registration Rights Agreement, dated December 21, 2016, by and among SM Energy Company, QStar LLC
and RRP-QStar, LLC (filed as Exhibit 4.13 to the registrant’s Annual Report on Form 10-K for the year ended December
31, 2016, and incorporated herein by reference)
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement,
Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent,
dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20,
2009, and incorporated herein by reference)
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed
as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by
reference)
Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed
as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, and
incorporated herein by reference)
Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by
reference)
Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit
10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein
by reference)
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of December 31, 2010 (filed
as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and
incorporated herein by reference)
Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as
Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated
herein by reference)
Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC
Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2011, and incorporated herein by reference)
Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed
as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated
herein by reference)
Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as
Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and
incorporated herein by reference)
125
10.13†
10.14†
10.15†
10.16†
10.17†
10.18†
10.19†
Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as
Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and
incorporated herein by reference)
Performance Stock Unit Award Agreement as of July 1, 2016 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference)
Restricted Stock Unit Award Agreement as of July 1, 2016 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference)
Non-Employee Director Restricted Stock Award Agreement as of May 25, 2016 (filed as Exhibit 10.3 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference)
SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the
registrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference)
Cash Bonus Plan, As Amended and Restated as of February 1, 2014 (filed as Exhibit 10.41 to the registrant’s Annual
Report on Form 10-K filed for the year ended December 31, 2013, and incorporated herein by reference)
Section 162(m) Cash Bonus Plan, effective as of May 21, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on
Form 8-K filed on May 28, 2014, and incorporated herein by reference)
10.20*†
Summary of Compensation Arrangements for Non-Employee Directors
10.21
10.22†
10.23†
Sixth Amended and Restated Credit Agreement dated as of September 28, 2018, among SM Energy Company, Wells
Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the
registrant’s Current Report on Form 8-K filed on October 4, 2018, and incorporated herein by reference)
Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
filed on October 20, 2015, and incorporated herein by reference)
Amendment No. 3 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2016 (filed as
Exhibit 10.29 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2015, and
incorporated herein by reference)
10.24***
Amendment to Amended and Restated Gas Gathering Agreement, effective as of September 1, 2015, by and between SM
Energy Company and Regency Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
filed on September 15, 2015, and incorporated herein by reference)
10.25
10.26
10.27
10.28
10.29
10.30
10.31
Amendment to Amended and Restated Gas Gathering Agreement, effective as of February 1, 2016, by and between SM
Energy Company and ETC Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on
February 22, 2016, and incorporated herein by reference)
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and Wells Fargo Bank, National
Association (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated
herein by reference)
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and Bank of America, N.A. (filed as
Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and JPMorgan Chase Bank,
National Association (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and
incorporated herein by reference)
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and Wells Fargo Bank, National
Association (filed as Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated
herein by reference)
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and Bank of America, N.A. (filed
as Exhibit 10.5 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by
reference)
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and JPMorgan Chase Bank,
National Association (filed as Exhibit 10.6 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and
incorporated herein by reference)
10.32†
SM Energy Company Employee Stock Purchase Plan, amended and restated effective as of April 6, 2017 (filed as Annex
A in the registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 13, 2017, and incorporated herein by
reference)
10.33†
Performance Share Unit Award Agreement as of July 1, 2018 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2018, and incorporated herein by reference)
21.1*
23.1*
23.2*
24.1*
31.1*
Subsidiaries of Registrant
Consent of Ernst & Young LLP
Consent of Ryder Scott Company L.P.
Power of Attorney
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
126
31.2*
32.1**
99.1*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
Ryder Scott Audit Letter
101.INS* XBRL Instance Document
101.SCH* XBRL Schema Document
101.CAL* XBRL Calculation Linkbase Document
101.LAB* XBRL Label Linkbase Document
101.PRE* XBRL Presentation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
* Filed with this report.
** Furnished with this report.
*** Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange
Commission pursuant to Rule 24b-2 under the Exchange Act.
Exhibit constitutes a management contract or compensatory plan or agreement.
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to
reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material
changes to the substantive terms and conditions in this document.
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on
†
††
+
November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal
Revenue Code. There were no material changes to the substantive terms and conditions in this document.
(c) Financial Statement Schedules. See Item 15(a) above.
ITEM 16. FORM 10-K SUMMARY
None.
127
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SIGNATURES
Date:
February 21, 2019
By:
/s/ JAVAN D. OTTOSON
SM ENERGY COMPANY
(Registrant)
Javan D. Ottoson
President and Chief Executive Officer
(Principal Executive Officer)
GENERAL POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Javan D. Ottoson
and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone,
for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal
year ended December 31, 2018 , and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange
Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
Signature
Title
Date
/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President, Chief Executive Officer, and Director
February 21, 2019
(Principal Executive Officer)
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial Officer
February 21, 2019
(Principal Financial Officer)
/s/ PATRICK A. LYTLE
Patrick A. Lytle
Controller and Assistant Secretary
(Principal Accounting Officer)
February 21, 2019
128
Signature
Title
Date
/s/ WILLIAM D. SULLIVAN
William D. Sullivan
/s/ CARLA J. BAILO
Carla J. Bailo
/s/ LARRY W. BICKLE
Larry W. Bickle
/s/ STEPHEN R. BRAND
Stephen R. Brand
/s/ LOREN M. LEIKER
Loren M. Leiker
/s/ RAMIRO G. PERU
Ramiro G. Peru
/s/ JULIO M. QUINTANA
Julio M. Quintana
/s/ ROSE M. ROBESON
Rose M. Robeson
Chairman of the Board of Directors
February 21, 2019
Director
February 21, 2019
Director
February 21, 2019
Director
February 21, 2019
Director
February 21, 2019
Director
February 21, 2019
Director
February 21, 2019
Director
February 21, 2019
129
EXHIBIT 10.20
SUMMARY OF COMPENSATION ARRANGEMENTS FOR NON-EMPLOYEE DIRECTORS
The following is a description of the standard arrangements pursuant to which directors of SM Energy are compensated for services
provided as a director, including additional amounts payable for committee participation:
DIRECTOR COMPENSATION
Employee directors do not receive additional compensation for serving on the Board of Directors or any committee.
For service in 2018 - 2019 as it relates to the period from May 2018 through May 2019, target compensation for each member of the Board
of Directors has been set at $180,000 annually, plus a retainer paid in lieu of committee and attendance fees. As described more fully below, the
actual value of compensation may be higher or lower depending on the results of the restricted stock component of director compensation. Primary
director compensation is in the form of stock grants and is fully described below. The retainer component of director compensation for non-employee
directors consists of an annual retainer of $90,000 for committee and board meeting fees paid in SM Energy common stock or cash as selected by
the director; provided that in the event any director attends in excess of 30 Board and committee meetings in the aggregate during the period from
May 2018 through May 2019, such director shall receive $1,500 per meeting for each meeting in excess of 30. In addition, each non-employee
director is reimbursed for expenses incurred in attending Board and committee meetings and director education programs.
The committee chairs receive the cash payments identified in the list below in recognition of the additional workload of their respective
committee assignments. These amounts are paid at the beginning of the annual service period.
•
•
•
Audit Committee - $20,000
Compensation Committee - $15,000
Nominating and Corporate Governance Committee - $10,000
The stock compensation for non-employee directors is as follows:
Annual compensation payable upon election to the Board by the stockholders, valued at $180,000. This resulted in a grant of
restricted stock to each non-employee director of 6,780 shares of SM Energy common stock issued on June 25, 2018, under SM
Energy's Equity Incentive Compensation Plan. These shares vested on December 31, 2018. Ms. Bailo received a pro rata grant of
shares of our common stock.
A retainer for the Non-Executive Chairman of the Board valued at $115,000. This resulted in a grant of 4,332 shares of SM Energy
common stock issued on June 25, 2018, under SM Energy's Equity Incentive Compensation Plan. These shares vested on
December 31, 2018.
Loren M. Leiker and William D. Sullivan each elected to receive SM Energy common stock for their retainer, which resulted in a
grant of 3,390 shares of SM Energy common stock issued on June 25, 2018, under SM Energy's Equity Incentive Compensation
Plan. These shares vested on December 31, 2018. Larry W. Bickle, Stephen Brand, Ramiro G. Peru, Julio M. Quintana and Rose
Robeson each elected to receive a $90,000 cash payment for their retainer.
EXHIBIT 21.1
SUBSIDIARIES
OF
SM ENERGY COMPANY
A. Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:
1. SMT Texas LLC, a Colorado limited liability company
2. Belring GP LLC, a Delaware limited liability company
3. St. Mary Energy Louisiana LLC, a Delaware limited liability company
4. Hilltop Investments, a Colorado general partnership
5. Parish Ventures, a Colorado general partnership
6. Green Canyon Offshore LLC, a Delaware limited liability company
7. Rock Ridge Water LLC, a Delaware limited liability company
B. Partnership or limited liability company interests held by SM Energy Company:
1. Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)
2.
3.
4.
1977 H.B Joint Account, a Colorado general partnership (8%)
1976 H.B Joint Account, a Colorado general partnership (9%)
1974 H.B Joint Account, a Colorado general partnership (4%)
C. Partnership interests held by SMT Texas, LLC:
1. St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM Energy Company)
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the following Registration Statements:
1. Post-Effective Amendment No. 1 to Registration Statement (Form S-8 Nos. 333-30055, 333-106438, 333-35352, and 333-88780) of SM Energy Company,
2. Registration Statement (Form S-8 Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, 333-219719, and 333-
226660) of SM Energy Company,
3. Post-Effective Amendment No. 1 to Registration Statement (Form S-3 No. 333-203936 and 333-226597) of SM Energy Company, and
4. Registration Statement (Form S-3 No. 333-216843) of SM Energy Company;
of our reports dated February 21, 2019 , with respect to the consolidated financial statements of SM Energy Company and subsidiaries, and the effectiveness of
internal control over financial reporting of SM Energy Company and subsidiaries, included in this Annual Report (Form 10-K) of SM Energy Company and
subsidiaries for the year ended December 31, 2018 .
/s/ Ernst & Young LLP
Denver, Colorado
February 21, 2019
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of SM Energy
Company for the year ended December 31, 2018 . We hereby further consent to the use of information contained in our reports, and the use of our audit letter,
as of December 31, 2018 , relating to estimates of revenues from SM Energy Company's oil, gas, and NGL reserves. We further consent to the incorporation by
reference thereof into SM Energy Company’s Post-Effective Amendment No. 1 to Registration Statement Nos. 333-30055, 333-106438, 333-35352, and 333-
88780 on Form S-8, Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, 333-219719, and
333-226660 on Form S-8, Post-Effective Amendment No. 1 to Registration Statement No. 333-203936 and 333-226597 on Form S-3, and Registration
Statement No. 333-216843 on Form S-3.
EXHIBIT 23.2
Houston, Texas
February 21, 2019
/s/ RYDER SCOTT COMPANY, L.P.
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
CERTIFICATION
EXHIBIT 31.1
I, Javan D. Ottoson, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of SM Energy Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a)
(b)
(c)
(d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent
fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a)
(b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control
over financial reporting.
Date: February 21, 2019
/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President and Chief Executive Officer
CERTIFICATION
EXHIBIT 31.2
I, A. Wade Pursell, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of SM Energy Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a)
(b)
(c)
(d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent
fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a)
(b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control
over financial reporting.
Date: February 21, 2019
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial and Accounting Officer
EXHIBIT 32.1
CERTIFICATION
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of SM Energy Company (the “Company”) for the fiscal year ended December 31, 2018 as filed with
the Securities and Exchange Commission on the date hereof (the “Report”), Javan D. Ottoson, as President and Chief Executive Officer of the Company, and A.
Wade Pursell, as Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to and solely for the purpose of 18
U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge and belief, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President and Chief Executive Officer
February 21, 2019
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial and Accounting Officer
February 21, 2019
EXHIBIT 99.1
SM ENERGY COMPANY
Estimated
Future Reserves
Attributable to Certain
Leasehold Interests
SEC Parameters
As of
December 31, 2018
/s/ Michael F. Stell
Michael F. Stell, P.E.
TBPE License No. 56416
Advising Senior Vice President
/s/ Val Rick Robinson
Val Rick Robinson
TBPE License No. 105137
Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
January 8, 2019
Mr. Levi J. Briese
Reserves Engineering Supervisor
SM Energy Company
1775 Sherman Street, Suite 1200
Denver, Colorado 80203
Gentlemen:
At the request of SM Energy Company (SM Energy), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves
audit of the estimates of the proved reserves as of December 31, 2018 prepared by SM Energy’s engineering and geological
staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC)
contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14,
2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 4, 2019 and presented
herein, was prepared for public disclosure by SM Energy in filings made with the SEC in accordance with the disclosure
requirements set forth in the SEC regulations. The estimated reserves shown herein represent SM Energy’s estimated net
reserves attributable to the leasehold interests in certain properties owned by SM Energy and the portion of those reserves
reviewed by Ryder Scott, as of December 31, 2018. The properties reviewed by Ryder Scott incorporate 1,027 SM Energy
reserve determinations and are located in the state of Texas.
The properties reviewed by Ryder Scott account for a portion of SM Energy’s total net proved reserves as of December
31, 2018. Based on the estimates of total net proved reserves prepared by SM Energy, the reserves audit conducted by Ryder
Scott addresses 90.5 percent of the total proved developed net liquid hydrocarbon reserves, 89.6 percent of the total proved
developed net gas reserves, 77.6 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 80.3 percent of
the total proved undeveloped net gas reserves of SM Energy.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating
and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of
reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or
Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies
employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation
process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the
estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to
the extent and value of petroleum properties.
Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our
opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves
as of December 31, 2018 comply with the current SEC regulations
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SM Energy Company
January 8, 2019
Page 2
and that the overall proved reserves for the reviewed properties as estimated by SM Energy are, in the aggregate, reasonable
within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
The estimated reserves presented in this report are related to hydrocarbon prices. SM Energy has informed us that in the
preparation of their reserves and income projections, as of December 31, 2018, they used average prices during the 12-month
period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-
day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the
SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the
hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually
received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by SM
Energy attributable to SM Energy's interest in properties that we reviewed and the reserves of properties that we did not review
are summarized below:
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold Interests of
SM Energy Company
As of December 31, 2018
Developed
Proved
Producing
Non-Producing
Undeveloped
50,059
58,180
623,330
6,983
1470
61,950
63,042
59,650
685,280
1,912
0
3,196
3,224
493
10,592
5,136
493
13,788
79,384
40,663
500,227
28,172
6,560
122,541
107,556
47,223
622,741
Total
Proved
137,355
98,843
1,126,753
38,379
8,523
195,056
175,734
107,366
1,321,809
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate - MBBL
Plant Products - MBBL
Gas – MMCF
Net Reserves of Properties
Not Audited by Ryder Scott
Oil/Condensate - MBBL
Plant Products - MBBL
Gas – MMCF
Total Net Reserves
Oil/Condensate - MBBL
Plant Products - MBBL
Gas – MMCF
Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels ( MBBL
). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and
pressure bases of the areas in which the gas reserves are located.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 3
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and
Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a)
entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “PETROLEUM RESERVES
DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the
shut-in category.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve
an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than
the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of
reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative
degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.
Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and
possible reserves to denote progressively increasing uncertainty in their recoverability. At SM Energy’s request, this report
addresses only the proved reserves attributable to the properties reviewed herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves
included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves,
when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or
as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of
geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate
recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”
Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental
agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should
not be construed as being exact quantities, and if recovered could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the
quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with
those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s
Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of
certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1)
performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in
combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select
the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of
reliable geoscience and
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 4
engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir
being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this
data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a
range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental
quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty
for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.
Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent
uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty
wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable
reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with
proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that
are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low
probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves
category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional
geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves
categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects
of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by SM Energy, for the properties that we reviewed were estimated by performance
methods, analogy, or a combination of methods. All of the proved producing and non-producing reserves attributable to
producing wells and/or reservoirs were estimated by performance methods. The performance methods, such as decline curve
analysis, utilized extrapolations of historical production data available through November 2018 in those cases where such data
were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by SM Energy or obtained from
public data sources and were considered sufficient for the purpose thereof.
All of the proved undeveloped reserves included herein were estimated by analogy. The analogs utilized data furnished
to Ryder Scott by SM Energy or which we have obtained from public data sources that were available through November 2018.
To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered
including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which
cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future
production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be
economically producible from a given date forward based on existing economic conditions including the prices and costs at
which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and other costs relating to such production may increase or decrease
from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward
based on existing economic conditions including the prices and costs at which economic
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 5
producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC
requirements to be economically producible, we have reviewed certain primary economic data utilized by SM Energy relating to
hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by SM Energy for the properties reviewed by us are based on SEC price parameters
using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted
arithmetic averages of the prices in effect on the first-day-of-the- month for each month within such period, unless prices were
defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and
determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration,
the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
The initial SEC hydrocarbon prices in effect on December 31, 2018 for the properties reviewed by us were determined
using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the
hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table
below summarizes the “benchmark prices” and “price reference” used by SM Energy for the geographic area reviewed by us. In
certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by SM Energy to determine the future gross revenue for each property
reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market,
referred to herein as “differentials.” The differentials used by SM Energy were accepted as factual data and reviewed by us for
their reasonableness; however, we have not conducted an independent verification of the data used by SM Energy.
The table below summarizes SM Energy’s net volume weighted benchmark prices adjusted for differentials for the
properties reviewed by us and referred to herein as SM Energy’s “average realized prices.” The average realized prices shown
in the table below were determined from SM Energy’s estimate of the total future gross revenue before production taxes for the
properties reviewed by us and SM Energy’s estimate of the total net reserves for the properties reviewed by us for the
geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for the
geographic area reviewed by us.
Geographic Area
North America
United States
Product
Oil/Condensate
NGLs
Gas
Price
Reference
WTI, Cushing
NGL
Henry Hub
Average
Benchmark
Prices
$65.56/BBL
$33.45/BBL
$3.10/MMBTU
Average
Realized
Prices
$57.85/BBL
$26.15/BBL
$3.58/MCF
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in SM
Energy’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates
reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 6
Operating costs furnished by SM Energy are based on the operating expense reports of SM Energy and include only
those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of
general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include
an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties
include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The
operating costs furnished by SM Energy were accepted as factual data and reviewed by us for their reasonableness; however,
we have not conducted an independent verification of the data used by SM Energy. No deduction was made for loan
repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or
wells.
Development costs furnished by SM Energy are based on authorizations for expenditure for the proposed work or actual
costs for similar projects. The development costs furnished by SM Energy were accepted as factual data and reviewed by us for
their reasonableness; however, we have not conducted an independent verification of the data used by SM Energy. The
estimated net cost of abandonment and salvage was included by SM Energy for properties where abandonment costs and
salvage were material. SM Energy’s estimates of the net abandonment costs were accepted without independent verification.
The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been
incorporated herein in accordance with SM Energy’s plans to develop these reserves as of December 31, 2018. The
implementation of SM Energy’s development plans as presented to us is subject to the approval process adopted by SM
Energy’s management. As the result of our inquiries during the course of our review, SM Energy has informed us that the
development activities for the properties reviewed by us have been subjected to and received the internal approvals required by
SM Energy’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted,
certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA)
requirements or other administrative approvals external to SM Energy. Additionally, SM Energy has informed us that they are not
aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change
from those under existing economic conditions as of December 31, 2018, such changes were, in accordance with rules adopted
by the SEC, omitted from consideration in making this evaluation.
Current costs used by SM Energy were held constant throughout the life of the properties.
SM Energy’s forecasts of future production rates are based on historical performance from wells currently on production.
If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of
curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied
to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future
production rates.
Test data and other related information were used by SM Energy to estimate the anticipated initial production rates for
those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence
at an anticipated date furnished by SM Energy. Wells or locations that are not currently producing may start producing earlier or
later than anticipated in SM Energy’s estimates due to unforeseen factors causing a change in the timing to initiate production.
Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting
wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may
be more or less than estimated because of changes including, but not limited to,
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 7
reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or
operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
SM Energy’s operations may be subject to various levels of governmental controls and regulations. These controls and
regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce
hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes
and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and
policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ
significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties in which SM Energy
owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report
to potential environmental liabilities that may exist nor were any costs included by SM Energy for potential liabilities to restore
and clean up damages, if any, caused by past operating practices.
Certain technical personnel of SM Energy are responsible for the preparation of reserves estimates on new properties
and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary
data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had
access to their workpapers and supporting data in the course of our audit.
SM Energy has informed us that they have furnished us all of the material accounts, records, geological and engineering
data, and reports and other data required for this investigation. In performing our audit of SM Energy’s forecast of future proved
production, we have relied upon data furnished by SM Energy with respect to property interests owned, production and well tests
from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing
fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs and
salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and
isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent verification of the data furnished by SM Energy. The data
described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our
examination, a matter of question came to our attention in which case the data were not accepted until all questions were
satisfactorily resolved. We consider the factual data furnished to us by SM Energy to be appropriate and sufficient for the
purpose of our review of SM Energy’s estimates of reserves. In summary, we consider the assumptions, data, methods and
analytical procedures used by SM Energy and as reviewed by us appropriate for the purpose hereof, and we have used all such
methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set
forth herein.
Audit Opinion
Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our
opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves
as of December 31, 2018 comply with the current SEC regulations and that the overall proved reserves for the reviewed
properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10
percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by SM Energy in their
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 8
estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in
estimates for these properties.
We were in reasonable agreement with SM Energy’s estimates of proved reserves for the properties which we reviewed;
although in certain cases there was more than an acceptable variance between SM Energy’s estimates and our estimates due to
a difference in interpretation of data or due to our having access to data which were not available to SM Energy when its
reserves estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented
herein for the properties that we reviewed fairly reflects the estimated net reserves owned by SM Energy.
Other Properties
Other properties, as used herein, are those properties of SM Energy which we did not review. The proved net reserves
attributable to the other properties account for 16.6 percent of the total proved net liquid hydrocarbon reserves and 14.8 percent
of the total proved net gas reserves based on estimates prepared by SM Energy as of December 31, 2018. The other properties
represent 15.7 percent of the total proved discounted future net income based on the unescalated pricing policy of the SEC as
taken from reserve and income projections prepared by SM Energy as of December 31, 2018.
The same technical personnel of SM Energy were responsible for the preparation of the reserve estimates for the
properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting
services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver,
Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By
virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and
gas company and are separate and independent from the operating and investment decision-making process of our clients. This
allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused
on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on
the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively
participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received
professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified
professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-
regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of
continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical
and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to SM Energy. Neither we nor any of our employees have any
financial interest in the subject properties, and neither the employment to do this
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 8, 2019
Page 9
work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and
engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for
overseeing the review of the reserves information discussed in this report, are included as attachments to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure
requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by SM
Energy.
SM Energy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SM Energy
has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K
is incorporated by reference. We have consented to the incorporation by reference thereof into the Company's Registration
Statements on Form S-8, of the references to our name as well as to the references to our third party report for SM Energy,
which appears in the December 31, 2018 annual report on Form 10-K of SM Energy. Our written consent for such use is
included as a separate exhibit to the filings made with the SEC by SM Energy.
We have provided SM Energy with a digital version of the original signed copy of this report letter. In the event there are
any differences between the digital version included in filings made by SM Energy and the original signed report letter, the
original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our
offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
/s/ Michael F. Stell
Michael F. Stell, P.E.
TBPE License No. 56416
Advising Senior Vice President
/s/ Val Rick Robinson
Val Rick Robinson
TBPE License No. 105137
Managing Senior Vice President
MFS-VRR (DPR)/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers
from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate
of the reserves, future production and income.
Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is
responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation
studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and
Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer
to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science
Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in
the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation
Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers
requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional
ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours
of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the
United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas
Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized
in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the
SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum
economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education
hours, Mr. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training
covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve
reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves,
evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2018, as of the date of
this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 37 years of practical experience in the estimation and
evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves
Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”
promulgated by the Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Engineer
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers
from Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of the
reserves, future production and income presented herein.
Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President
responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation
studies worldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil
Corporation. For more information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder
Scott Company website at www.ryderscott.com .
Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is a
licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers
requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional
ethics, which Mr. Robinson fulfills. As part of his 2017 continuing education hours, Mr. Robinson attended 28 hours of formalized
training including the 2017 RSC Reserves Conference and various professional society presentations covering such topics as
the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of
Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the
SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productive
basins of North America, computer software, and professional ethics.
Based on his educational background, professional training and more than 14 years of practical experience in the estimation and
evaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth in
Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the
Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil
and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The
“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of
Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies
Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to
Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take
effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after
January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part
210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC
document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as
of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of
the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated
quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic
and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty
may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are
less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to
denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after
January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in
documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources
other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such
information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as
economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include
all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples
of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use
of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum
technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations
are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method
applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or
coalseam methane (CBM/CSM), basin-
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require
specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from
different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or
there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production,
installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement
the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults
until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that
are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low
reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from
undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward,
from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the
time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with
it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 3
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential
exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable
certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but
not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the
project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental
entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price shall be 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.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be
made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following
reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the
aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required
equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the
extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-
classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at
the time of the estimate.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) completion intervals which are open at the time of the estimate, but which have not yet started producing;
(2) wells which were shut-in for market conditions or pipeline connections; or
(3) wells not capable of production for mechanical reasons.
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion
work or future re-completion prior to start of production with minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new
well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as
follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence using reliable technology exists that
establishes reasonable certainty of economic producibility at greater distances.
(ii) 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.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have
been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph
(a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS