Matador Resources Company Annual Report 2017

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FY2017 Annual Report · Matador Resources Company

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2017 ANNUAL REPORT

CHARGING AHEAD:
ON THE RISE

MATADOR RESOURCES COMPANY

Matador is an independent energy company engaged in the exploration, development, production and acquisition

of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other

unconventional plays. Its current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp

and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. Matador also operates in the

Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and

East Texas. Additionally, Matador conducts midstream operations primarily through its midstream joint venture, San

Mateo Midstream, LLC, in support of its exploration, development and production operations and provides natural

gas processing, oil transportation services, natural gas, oil and salt water gathering services and salt water disposal

services to third parties.

FINANCIAL AND OPERATING HIGHLIGHTS

($ in millions)

2015

2016

2017

Operating Data
Oil and Natural Gas Revenues
% Oil in Revenues
Net (Loss) Income(1)
Adjusted EBITDA(1),(2)

Balance Sheet Data
Cash
Net Property and Equipment
Total Assets
Current Liabilities
Long-Term Liabilities
Total Shareholders’ Equity

Net Production Volumes
Oil (MBbl)
Natural Gas (Bcf)
Total Oil Equivalent (MBOE)(4),(5)
% Oil in Production Volumes(5)
Average Daily Production (BOE/d)(5)

Reserves Information
Total Proved Reserves (MMBOE)(5),(6)
% Oil in Proved Reserves(5)
Standardized Measure
PV-10(7)

$ 278.3

73%

$
(679.8)
$ 223.1

59.8(3)

$
$ 1,012.4
$ 1,140.9
$ 136.8
$ 515.1
$ 489.0

4,492
27.7
9,109

49%

24,955

85.1

54%

$ 529.2
$ 541.6

$ 291.2

72%

$
(97.4)
$ 157.9

$ 212.9
$ 1,184.5
$ 1,464.7
$ 169.5
$ 603.7
$ 691.4

5,096
30.5
10,180

50%

27,813

105.8

54%
$ 575.0
$ 581.5

$
$

528.7

73%

125.9
336.1

$
96.5
$ 1,881.5
$ 2,145.7
282.6
$
$
605.5
$ 1,257.5

7,851
38.2
14,212

55%

38,936

152.8

57%
$ 1,258.6
$ 1,333.4

(1) Attributable to Matador Resources Company shareholders after giving effect to amounts attributable to third-party non-controlling interests.
(2) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our
net income (loss) and net cash provided by operating activities, see “Selected Financial Data – Non-GAAP Financial Measures” in the
Annual Report on Form 10-K enclosed herein.

(3) Including $43 million of restricted cash held in escrow at December 31, 2015.
(4) Thousands of barrels of oil equivalent.
(5) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(6) Millions of barrels of oil equivalent.
(7) PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved

Reserves” in the Annual Report on Form 10-K enclosed herein.

SOUTHEAST NEW MEXICO
AND WEST TEXAS

NORTHWEST
LOUISIANA
AND EAST TEXAS

SOUTH TEXAS

AREAS OF OPERATION

MATADOR RESOURCES COMPANY TOTALS

Production: 43,700 BOE/d(1)

Proved Reserves: 152.8 MMBOE(2)

Acreage: 256,900 gross / 165,800 net(2)

Locations: 5,355 gross / 2,318 net(2)

SOUTHEAST NEW MEXICO
AND WEST TEXAS

Production: 34,900 BOE/d(1)

Proved Reserves: 129.0 MMBOE(2)

Acreage: 199,600 gross / 114,000 net(2)

Locations: 4,630 gross / 1,958 net(2)

(1) For the three months ended December 31, 2017.
(2) At December 31, 2017.

NORTHWEST LOUISIANA
AND EAST TEXAS

Production: 4,300 BOE/d(1)

Proved Reserves: 11.4 MMBOE(2)

Acreage: 25,500 gross / 22,800 net(2)

Locations: 484 gross / 152 net(2)

SOUTH TEXAS

Production: 4,500 BOE/d(1)

Proved Reserves: 12.3 MMBOE(2)

Acreage: 31,800 gross / 29,000 net(2)

Locations: 241 gross / 208 net(2)

DEAR SHAREHOLDERS AND FRIENDS

Matador’s Board of Directors, staff and I are pleased to report
our 2017 operating and ﬁnancial results. Once again, we are
reporting record results as well as substantial and continuing
progress in growing Matador since we went public in February
of 2012. The record results achieved this year compared
to the results achieved in 2016 include oil and natural gas
revenues of $529 million (an increase of 82%); net income of
$126 million (compared to a net loss of $97 million); Adjusted
EBITDA of $336 million (an increase of 113%); net total oil
equivalent production of 14.2 million BOE (an increase of
40%); total proved oil and natural gas reserves of 153 million
BOE (an increase of 44%, including a 52% increase in proved
oil reserves); PV-10 of total proved reserves of $1.33 billion
(compared to $0.58 billion); and an increase of 21% in net acres
in the Delaware Basin, the most active and competitive oil and
natural gas basin in the country (Lea and Eddy Counties, New
Mexico and Loving County, Texas), to 114,000 net acres from
94,300 net acres at year-end 2016. In addition, through its 51%
owned subsidiary, San Mateo Midstream, LLC (“San Mateo”),
Matador has established a growing midstream business with
the ability to provide oil, natural gas and water midstream
services throughout our Rustler Breaks and Wolf asset areas,
increased transportation options for oil, natural gas and
NGLs and the capacity to attract third party contracts into
our system. This midstream expansion has not only created
operational advantages for Matador but also added several
hundred million dollars in value for Matador’s shareholders.

In 2017, Matador focused on building value through selective
acreage acquisitions, traditional E&P operations through the
drill bit and our growing midstream operations in our areas
of interest. In fact, the operations group has continued to drill
excellent wells in each of our asset areas with 105 gross (66.0
net) operated and non-operated wells completed and turned to
sales in 2017, increasing average daily oil equivalent production
to an exit rate of 43,700 BOE per day in the fourth quarter
of 2017. We expect that our midstream team will continue
building on its signiﬁcant progress in 2017 and early 2018,
which included the formation of San Mateo, the expansion of
the Black River processing plant in the Rustler Breaks asset
area and the establishment of a strategic relationship with
Plains All American Pipeline, L.P. (“Plains”) to gather oil in the
Delaware Basin for transport to other markets. Details of these
achievements and much more information about Matador and
our 2017 performance are provided in the attached Annual
Report on Form 10-K.

In achieving these value creating results, Matador has
continued to keep an eye on the balance sheet. Throughout its
history, Matador has kept its debt levels to a very conservative
and manageable amount. In another sign of growing ﬁnancial

strength, as of the end of the ﬁrst quarter of 2018, Matador
had no borrowings under its bank line of credit, yet had
authorization from its lenders to borrow up to $725 million.
Additionally, Matador ﬁnished 2017 with close to $100 million
in cash in the bank, bonds that are trading above par and, most
recently, an upgrade in Matador’s credit rating by one of the
nation’s largest credit rating services.

In 2018, Matador expects to continue to pursue its selective
capital spending strategy in each of its focus areas, as well
as to be opportunistic for other value creating endeavors,
especially with regard to our acreage position in the northern
Delaware Basin and our midstream opportunities, as such
opportunities may only be available for a limited time.
Altogether Matador expects to operate six rigs in the Delaware
Basin during 2018, with the potential to add a seventh rig as
additional drilling opportunities may arise later in the year. Any
capital expenditures are dependent, of course, on commodity
prices, service costs, expected well returns, cash ﬂow and
balance sheet considerations.

During 2018, like 2017, we expect virtually all of Matador’s
operated drilling and completion activities to be focused on
the Delaware Basin in southeastern New Mexico (Eddy and Lea
Counties) and in Loving County, Texas. During 2017, Matador
continued to achieve drilling and completion efficiencies,
reduce costs and improve overall well results. For example,
our lease operating and general and administrative expenses
on a unit-of-production basis were the lowest achieved since
we became a public company. Matador also drilled the best
Bone Spring well to date in New Mexico. This well, the Mallon
#1H, drilled and turned to sales in late 2016, and two offsetting
wells, drilled and turned to sales at the same time, are three
of the top 15 Bone Spring wells drilled in New Mexico as
measured by ﬁrst-year oil production. Matador has now tested
16 different horizons in the Delaware Basin and continues to
be a leader in the exploration and delineation of the various
productive horizons throughout the basin. Going forward this
year, additional emphasis will be focused on our Arrowhead,
Ranger and Twin Lakes asset areas in Lea and Eddy Counties
as we continue the methodical process of testing and
delineating our acreage from south to north.

Matador’s midstream business has added signiﬁcant value to
our total asset proﬁle and to the net value of your shares. San
Mateo has seen signiﬁcant progress and growth in oil, natural
gas and water operations, both in terms of volumes and cash
ﬂow. The Black River processing plant in Eddy County, New
Mexico is being expanded from its initial designed capacity
of 60 MMcf/d to a total designed capacity of 260 MMcf/d.
San Mateo has also recently started ﬂowing its NGLs into

a pipeline at the tailgate of the Black River processing
plant, reducing operational expenses for San Mateo and
transportation expenses for Matador and third parties.
On January 22, 2018, San Mateo announced its strategic
relationship with Plains to work together through a joint tariff
arrangement and related transactions to offer crude
oil gathering and transportation services to third-party
producers located within a joint development area of
approximately 400,000 acres (or 625 square miles) in Eddy
County, New Mexico. San Mateo has also been actively
expanding its water gathering and disposal infrastructure in
Loving County, Texas and Eddy County, New Mexico, making
Matador’s San Mateo joint venture one of the few midstream
companies in the area to offer midstream services for all three
production streams—oil, natural gas and water.

As a company, Matador is most focused on “proﬁtable
growth at a measured pace” as measured by per share
growth in value. In doing so, Matador tends to focus more on
execution rather than grand strategy, and we are conﬁdent
that Matador’s Board, management and technical staff will
continue to work together creatively with its working interest
owners, its vendors and other interested parties to meet the

challenges that lie ahead. Matador greatly appreciates and
values the special relationships that have developed between
our shareholders, our bondholders, our vendors, our staff,
our Board and other interested parties. Consequently, we
invite each of you to attend our annual shareholders’ meeting
scheduled for 9:30 a.m. on Thursday, June 7, 2018, in Dallas
at The Westin Galleria Dallas hotel, and to a continental
breakfast preceding the meeting beginning at 8:30 a.m.
to meet and visit with our staff and directors in person. We
hope to see all of you there.

Very truly yours,

Joseph Wm. Foran
Chairman and Chief Executive Officer

(Left to right): David M. Posner, William M. Byerley, James A. Rolfe, George M. Yates, Tara W. Lewis, Reynald A. Baribault, Scott E. King,
Joseph Wm. Foran, Craig T. Burkert, Dr. Steven W. Ohnimus, Kenneth L. Stewart, Julia P. Forrester, Timothy E. Parker, R. Gaines Baty

BOARD OF DIRECTORS

Joseph Wm. Foran

SPECIAL BOARD ADVISORS

Scott E. King

Founder, Chairman and Chief Executive Officer of Matador
Resources Company (Matador II); Founder and Chief Executive
Officer of Matador Petroleum Corporation (Matador I)

Former VP, Geophysics and New Ventures, Matador Resources
Company; Former VP, Exploration & Development, Petro
Harvester Oil & Gas, LLC

Reynald A. Baribault

Tara W. Lewis

Lead Director; Vice President/Engineering and Co-Founder, NP
Resources, LLC; President and CEO, IPR Energy Partners, LLC;
Former Vice President, Netherland, Sewell & Associates, Inc.

R. Gaines Baty

Consultant, Director and Former Vice President, HEYCO
Energy Group, Inc.; Former Director of Internal Audit, Apache
Corporation; Former Senior Tax Manager, World Petroleum Group,
PricewaterhouseCoopers (PwC)

Director; Chief Executive Officer, R. Gaines Baty Associates, Inc.

James A. Rolfe

Craig T. Burkert

Director; Chief Financial Officer, ROMCO Equipment Co.

William M. Byerley

Director; Retired Partner (energy focus), PricewaterhouseCoopers (PwC)

Julia P. Forrester

Director; Associate Provost, Southern Methodist University;
Professor of Law, SMU Dedman School of Law; Former real
estate attorney, Thompson & Knight LLP

Dr. Steven W. Ohnimus

Director; Retired Vice President and General Manager, Unocal Indonesia

Solo Practitioner; Retired United States Attorney, Northern
District of Texas

BOARD ADVISORS

Rick H. Fenlaw

Owner, Fenlaw Land Services

Wade I. Massad

Managing Member, Cleveland Capital Management, LLC;
Formerly with KeyBanc Capital Markets and RBC Capital Markets

Timothy E. Parker

Greg L. McMichael

Director; Former Portfolio Manager and Analyst – Natural Resources,
T. Rowe Price & Associates

Retired Vice President and Group Leader – Energy Research,
A.G. Edwards; Director, Denbury Resources, Inc.

David M. Posner

Dr. James D. Robertson

Director; President, EnVent Energy LLC; Former Vice President,
Marketing, Snyder Oil Corporation

Retired Vice President, Exploration, Chief Geophysicist,
ARCO International

Kenneth L. Stewart

Michael C. Ryan

Director; Partner, Chair – United States, Norton Rose Fulbright US LLP;
Former Global Chair of Fulbright & Jaworski LLP

Retired Partner, Berens Capital Management;
Former Director, Matador Resources Company

George M. Yates

Director; Chairman and Chief Executive Officer, HEYCO Energy
Group, Inc.

Surrounding Joe Foran, Matador’s Chairman and CEO (front, middle), are members of Matador’s staff. Matador had a total of 217 full-time employees
at December 31, 2017.

EXECUTIVE OFFICERS AND SENIOR MANAGEMENT

Joseph Wm. Foran

Robert T. Macalik

Founder, Chairman and Chief Executive Officer

Senior Vice President and Chief Accounting Officer

Matthew V. Hairford

Matthew D. Spicer

President and Chair of Operating Committee

Vice President and General Manager of Midstream

David E. Lancaster

Kathryn L. Wayne

Executive Vice President and Chief Financial Officer

Vice President, Controller and Treasurer

Craig N. Adams

Brian J. Willey

Executive Vice President – Land, Legal & Administration

Vice President and Co-General Counsel

Billy E. Goodwin

Bryan A. Erman

Executive Vice President and Head of Operations

Vice President and Co-General Counsel

Van H. Singleton, II

Executive Vice President of Land

Dr. Edmund L. Frost III

Vice President of Geoscience

Bradley M. Robinson

W. Thomas Elsener

Senior Vice President of Reservoir Engineering
and Chief Technology Officer

G. Gregg Krug

Senior Vice President – Marketing & Midstream

Vice President – Engineering & Asset Manager

James R. Basich

Vice President and Managing Director – IT

NET DEBT / LTM ADJUSTED EBITDA(1),(2),(3)

Net Debt
($ millions)

$101

$240

$256

$416

$444

$358

$549 $475

+
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1.6X 1.5X 1.5X

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2008

2009

2010

2011

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15

4Q15 1Q16

2Q16

3Q16 4Q16 1Q17

2Q17 3Q17 4Q17

Note: Ratio is a measurement of leverage commonly used to quantify and analyze the ability of a company to repay its debts—the smaller the ratio, the better. The
ratio approximates the number of years required by a company to pay off its debts if the trailing twelve months Adjusted EBITDA were held constant and ignoring
factors such as interest, income taxes, depreciation, depletion, amortization, working capital adjustments and capital expenditures.
(1) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net

cash provided by operating activities, see our March 6, 2018 Analyst Day Presentation. LTM is last twelve months.

(2) Net Debt is equal to debt outstanding less available cash (including Matador’s proportionate share of any restricted cash).
(3) Attributable to Matador Resources Company shareholders after giving effect to amounts attributable to third-party non-controlling interests.

2017 FORM 10-K

CHARGING AHEAD:
ON THE RISE

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
UNITED STATES SECURITIES AND EXCHANGE COMMISSIOSIONN
Washington, D.C. 20549

10M 10-K-K
FORM 10-K
FOR

(Mark One)
(cid:2)(cid:22)(cid:2)(cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the ﬁscal year ended December 31, 2017
or
(cid:2) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________

Commission ﬁle number: 001-34574

MATADOR RESOURCES COMPANY

(Exact name of registrant as speciﬁed in its charter)

Texas
(State or other jurisdiction of
incorporation or organization)

5400 LBJ Freeway, Suite 1500
Dallas, Texas 75240
(Address of principal executive ofﬁces)

27-4662601
(I.R.S. Employer
Identiﬁcation No.)

75240
(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

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

Title of each class

Common Stock, par value $0.01 per share

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 (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)
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 (cid:2) No (cid:2)(cid:22)(cid:2)(cid:2)

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 (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such ﬁles). Yes (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)

Indicate by check mark if disclosure of delinquent ﬁlers pursuant to Item 405 of Regulation S-K 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. (cid:2)

Indicate by check mark whether the registrant is a large accelerated ﬁler, an accelerated ﬁler, a non-accelerated ﬁler, or a smaller
reporting company, or an emerging growth company. See the deﬁnitions of “large accelerated ﬁler,” “accelerated ﬁler” and “smaller
reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated ﬁler (cid:2)(cid:22)(cid:2)(cid:2)
Non-accelerated ﬁler (cid:2) (Do not check if smaller reporting company)

(cid:2)

Accelerated ﬁler
Smaller reporting company (cid:2)
Emerging growth company (cid:2)

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. (cid:2)
Indicate by check mark whether the registrant is a shell company (as deﬁned in Rule 12b-2 of the Exchange Act). Yes (cid:2) No (cid:2)(cid:22)(cid:2)(cid:2)

The aggregate market value of the voting and non-voting common equity of the registrant held by non-afﬁliates, computed by
reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently
completed second ﬁscal quarter was $1,910,451,565.

As of February 21, 2018, there were 109,248,747 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference
to the registrant’s deﬁnitive proxy statement relating to the 2018 Annual Meeting of Shareholders, which will be ﬁled with the Securities
and Exchange Commission within 120 days after the end of the ﬁscal year to which this Annual Report on Form 10-K relates.

MATADOR RESOURCES COMPANY

Table of Contents

PART I

Item 1.

Item 1A.

Item 1B.

Item 2.

Item 3.

Item 4.

PART II

Item 5.

Item 6.

Item 7.

Item 7A.

Item 8.

Item 9.

Item 9A.

Item 9B.

PART III

Item 10.

Item 11.

Item 12.

Item 13.

Item 14.

PART IV

Item 15.

Page

Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases

of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . 77

Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . 104

Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Directors, Executive Ofﬁcers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

Security Ownership of Certain Beneﬁcial Owners and Management and

Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . 108

Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

FORM 10-K

2017 ANNUAL REPORT

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking
statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act,
and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally,
forward-looking statements may be made orally or in press releases, conferences, reports, on our website or
otherwise, in the future by us or on our behalf. Such statements are generally identiﬁable by the terminology
used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,”
“intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words,
although not all forward-looking statements contain such identifying words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that

may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties
and other factors that may cause actual results, levels of activity and achievements to differ materially from those
expressed or implied by such statements. Such factors include, among others: general economic conditions,
changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids,
the success of our drilling program, the timing of planned capital expenditures, the sufﬁciency of our cash ﬂow
from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating
proved reserves and forecasting production results, operational factors affecting the commencement or
maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them,
the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to
integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental
regulations or litigation and other legal or regulatory developments affecting our business, and the other factors
discussed below and elsewhere in this Annual Report and in other documents that we ﬁle with or furnish to the
United States Securities and Exchange Commission, or the SEC, all of which are difﬁcult to predict. Forward-looking
statements may include statements about:

• our business strategy;

• our reserves;

• our technology;

• our cash ﬂows and liquidity;

• our ﬁnancial strategy, budget, projections and operating results;

• our oil and natural gas realized prices;

•

the timing and amount of future production of oil and natural gas;

the availability of drilling and production equipment;

the availability of oil ﬁeld labor;

the amount, nature and timing of capital expenditures, including future exploration and development costs;

the availability and terms of capital;

• our drilling of wells;

• our ability to negotiate and consummate acquisition and divestiture opportunities;

• government regulation and taxation of the oil and natural gas industry;

• our marketing of oil and natural gas;

• our exploitation projects or property acquisitions;

•

the integration of acquisitions with our business;

FORM 10-K

MATADOR RESOURCES COMPANY

• our ability and the ability of our midstream joint venture to construct and operate midstream facilities,

including the expansion of our Black River cryogenic natural gas processing plant and the drilling of additional
salt water disposal wells;

•

the ability of our midstream joint venture to attract third-party volumes;

• our costs of exploiting and developing our properties and conducting other operations;

• general economic conditions;

• competition in the oil and natural gas industry, including in both the exploration and production and

midstream segments;

•

the effectiveness of our risk management and hedging activities;

• environmental liabilities;

• counterparty credit risk;

• developments in oil-producing and natural gas-producing countries;

• our future operating results;

• estimated future reserves and the present value thereof; and

• our plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report
are reasonable based on information available to us on the date hereof, no assurances can be given as to future
results, levels of activity, achievements or ﬁnancial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements

are predictions of future results, which may not occur as anticipated. Actual results could differ materially from
those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties
described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking
statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing
statements are not exclusive and further information concerning us, including factors that potentially could materially
affect our ﬁnancial results, may emerge from time to time. We undertake no obligation to update forward-looking
statements to reﬂect actual results or changes in factors or assumptions affecting such forward-looking statements,
except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

FORM 10-K

2017 ANNUAL REPORT

Part I

ITEM 1. BUSINESS.

In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and

its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to
Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary
of Oil and Natural Gas Terms” included in this Annual Report.

GENERAL

We are an independent energy company engaged in the exploration, development, production and acquisition

of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other
unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp
and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the
Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and
East Texas. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo
Midstream, LLC (“San Mateo”), in support of our exploration, development and production operations and provide
natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water
disposal services to third parties.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began
his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in
contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador
Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive
Ofﬁcer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash
transaction for an enterprise value of approximately $388.5 million.

On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the
symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash ﬂows
at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the
following business strategies:

•

focus our exploration and development activities primarily on unconventional plays, including the
Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play in South Texas and the
Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas;

identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced
portfolio of oil and natural gas properties;

• continue to improve operational and cost efﬁciencies;

•

identify and develop midstream opportunities that support and enhance our exploration and development
activities and that generate value for San Mateo;

• maintain our ﬁnancial discipline; and

• pursue opportunistic acquisitions, divestitures and joint ventures.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Despite a challenging commodity price environment since 2014, the successful execution of our business
strategies in 2017 led to signiﬁcant increases in our oil and natural gas production and proved oil and natural gas
reserves. We also continued to increase our leasehold position in the Delaware Basin. In addition, we concluded
several important transactions in 2017, including the formation of San Mateo in February 2017, the October 2017
public offering of 8,000,000 shares of our common stock and multiple increases in the borrowing base under our
Credit Agreement (as deﬁned below). These transactions increased our operational ﬂexibility and opportunities and
further strengthened our balance sheet.

For information about our segment reporting, see Note 17 to the consolidated ﬁnancial statements in this

Annual Report.

2017 HIGHLIGHTS

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2017, we achieved record oil, natural gas and average daily oil equivalent
production. In 2017, we produced 7.9 million Bbl of oil, an increase of 54%, as compared to 5.1 million Bbl of oil
produced in 2016. We also produced 38.2 Bcf of natural gas, an increase of 25% from 30.5 Bcf of natural gas
produced in 2016. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE
per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, an increase of 40%, as compared
to 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, for the year
ended December 31, 2016. The increase in oil and natural gas production was primarily attributable to our ongoing
delineation and development drilling activities in the Delaware Basin throughout 2017, but also to production from
ﬁve operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in
the third quarter of 2017. Oil production comprised 55% of our total production (using a conversion ratio of one
Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2017, as compared to 50% for the year ended
December 31, 2016.

Increased Oil and Oil Equivalent Reserves

At December 31, 2017, our estimated total proved oil and natural gas reserves were 152.8 million BOE,
including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, an increase of 44% from 105.8 million BOE, including
57.0 million Bbl of oil and 292.6 Bcf of natural gas, at December 31, 2016. The associated Standardized Measure
and PV-10 of our estimated total proved oil and natural gas reserves increased 119% and 129% to $1.26 billion
and $1.33 billion, respectively, at December 31, 2017, from $575.0 million and $581.5 million, respectively, at
December 31, 2016, primarily as a result of our ongoing delineation and development drilling activities in the
Delaware Basin. PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure,
see “—Estimated Proved Reserves.”

Our proved oil reserves grew 52% to 86.7 million Bbl at December 31, 2017 from 57.0 million Bbl at

December 31, 2016. Our proved natural gas reserves increased 35% to 396.2 Bcf at December 31, 2017 from
292.6 Bcf at December 31, 2016. This growth in oil and natural gas reserves was primarily attributable to our
ongoing delineation and development drilling activities in the Delaware Basin during 2017.

At December 31, 2017, proved developed reserves included 37.0 million Bbl of oil and 190.1 Bcf of natural gas,
and proved undeveloped reserves included 49.8 million Bbl of oil and 206.1 Bcf of natural gas. Proved developed
reserves and proved oil reserves comprised 45% and 57%, respectively, of our total proved oil and natural gas
reserves at December 31, 2017. Proved developed reserves and proved oil reserves comprised 41% and 54%,
respectively, of our total proved oil and natural gas reserves at December 31, 2016.

FORM 10-K PART I

2017 ANNUAL REPORT

Operational Highlights

We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per

well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical
approach to track and monitor the effectiveness of our drilling and completion techniques and service providers.
This allows us to better manage operating costs, the pace of development activities, technical applications, the
gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas,
which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we
believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin
wells, particularly over the past four years, as we continue to apply what we learned from our Eagle Ford shale and
Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2018.

We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin
in 2017, including 65 gross (56.1 net) operated and 21 gross (3.5 net) non-operated wells. We also added to and
upgraded our acreage position in the Delaware Basin during 2017. As a result, at December 31, 2017, our total
acreage position in the Delaware Basin had increased to approximately 199,600 gross (114,000 net) acres, primarily
in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been pleased with the
aggregate performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in
our seven main asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County,
Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger
and Twin Lakes asset areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become
an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the
Delaware Basin increased approximately 85% to 29,463 BOE per day (76% of total oil equivalent production),
including 18,023 Bbl of oil per day (84% of total oil production) and 68.6 MMcf of natural gas per day (66% of total
natural gas production), in 2017, as compared to 15,941 BOE per day (57% of total oil equivalent production),
including 10,395 Bbl of oil per day (75% of total oil production) and 33.3 MMcf of natural gas per day (40% of total
natural gas production), in 2016. We expect our Delaware Basin production to increase throughout 2018 as we
continue the delineation and development of these asset areas.

Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production
Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2017 included:

•

in our Rustler Breaks asset area, the extension of Wolfcamp A-XY operations to the northwest region
of the asset area, the initial testing of the Wolfcamp A-Lower interval and the continued delineation and
development of previously tested horizons;

in our Jackson Trust asset area, the results from the Totum E 18-TTT-C24 NL #211H well, whose 24-hour
initial potential test result and subsequent well performance marked the best result we have achieved in
the Wolfcamp A-Lower interval in either the Wolf or Jackson Trust asset areas;

in our Wolf asset area, a positive ﬁrst test of the Wolfcamp B interval;

in our Ranger asset area, the continued success of the three wells drilled and completed in the Third Bone
Spring formation on our Mallon leasehold, which were placed on gas lift during the third quarter of 2017 and
have together produced over 1.1 million Bbl of oil in just over one year of production;

in our Twin Lakes asset area, a positive test of the Wolfcamp D formation from the D. Culbertson
26-15S-36E TL State #234H well, our ﬁrst horizontal well in the Twin Lakes asset area;

in our Arrowhead asset area, the drilling and completion of our ﬁrst operated wells, which further
illustrated the potential of the Second Bone Spring and the Third Bone Spring in our northern Delaware
Basin acreage position;

FORM 10-K PART I

MATADOR RESOURCES COMPANY

•

in our Antelope Ridge asset area, the drilling of our ﬁrst two operated wells, the ﬁrst of which was
completed in early 2018 and was a positive test of the Wolfcamp A interval that we believe conﬁrms the
prospectivity of the Antelope Ridge asset area; and

the signiﬁcant progress made in our midstream operations, including (i) the ongoing expansion of
San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the
“Black River Processing Plant”), (ii) the ongoing buildout of oil, natural gas and water pipeline systems
in both the Rustler Breaks and Wolf asset areas and (iii) the drilling and completion of additional commercial
salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks
and Wolf asset areas, signiﬁcantly increasing San Mateo’s salt water disposal capacity in these asset areas.

We also completed and began producing oil and natural gas from eight gross (5.8 net) wells in the Eagle Ford
shale in South Texas in 2017, including ﬁve gross (5.0 net) operated and three gross (0.8 net) non-operated wells.
We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest
Louisiana and East Texas during 2017, although we did participate in the drilling and completion of 11 gross (0.6 net)
non-operated Haynesville shale wells that began producing in 2017.

Financing Arrangements

On October 10, 2017, we completed a public offering of 8,000,000 shares of our common stock, receiving
proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were
used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin
at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities.
The remaining proceeds have been and are expected to be used for other midstream development, leasehold
and mineral acquisitions and general corporate purposes, including to fund a portion of our current and future
capital expenditures.

Midstream Joint Venture

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary

of Five Point Capital Partners LLC (“Five Point”). The midstream assets that were contributed to San Mateo
included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water
disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt
water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering
systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream
Assets”). We received $171.5 million in connection with the formation of San Mateo. Through January 31, 2018,
we had earned an additional $14.7 million in performance incentives to be paid by Five Point in the ﬁrst quarter
of 2018 and may earn up to an additional $58.8 million in performance incentives over the next four years. We
continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and
Five Point own 51% and 49% of San Mateo, respectively. San Mateo continues to provide ﬁrm capacity service
to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and
Rustler Breaks asset areas.

2018 RECENT DEVELOPMENTS

On January 22, 2018, we announced a strategic relationship between a subsidiary of San Mateo and a subsidiary
of Plains All American Pipeline, L.P. (“Plains”) to gather and transport crude oil for us and third-party customers in and
around the Rustler Breaks asset area. Subsidiaries of San Mateo and Plains have agreed to work together through a
joint tariff arrangement and related transactions to offer third-party producers located within a joint development area
of approximately 400,000 acres in Eddy County, New Mexico crude oil transportation services from the wellhead to
Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary
of Plains has agreed to purchase our oil production in the Rustler Breaks and Wolf asset areas.

FORM 10-K PART I

2017 ANNUAL REPORT

EXPLORATION AND PRODUCTION SEGMENT

Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play
in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During
2017, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations
in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since
our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with
well-established production histories offering the potential for multiple-zone completions. We have also sought to
balance the risk proﬁle of our asset areas by exploring for more conventional targets as well, although for the year
ended December 31, 2017, essentially all of our efforts were focused on unconventional plays.

The following table presents certain summary data for each of our operating areas as of and for the year ended

December 31, 2017.

Southeast New Mexico/
West Texas:

Producing
Wells

Total Identiﬁed
Drilling Locations (1)

Gross
Acreage

Net
Acreage

Gross

Net

Gross

Net

Estimated Net
Proved Reserves (2)

Avg. Daily
Production
%
MBOE(3) Developed (BOE/d)(3)

Delaware Basin (4)

199,600

114,000

450

211.5

4,630

1,957.7

128,999

40.6

29,463

South Texas:

Eagle Ford (5)

Northwest Louisiana/
East Texas:

Haynesville
Cotton Valley (6)
Area Total (7)
Total

31,800

29,000

142

119.8

241

208.5

12,346

72.2

4,413

19,600
21,100
25,500
256,900

12,000
18,600
22,800
165,800

217
81
298
890

20.5
54.3
74.8
406.1

413
71
484
5,355

102.0
50.0
152.0
2,318.2

10,106
1,320
11,426
152,771

59.5
100.0
64.1
44.9

4,697
363
5,060
38,936

Identiﬁed and engineered drilling locations. These locations have been identiﬁed for potential future drilling and were not producing at
December 31, 2017. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating
area by our working interest participation in such locations. At December 31, 2017, these engineered drilling locations included only 261 gross
(130.5 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the
Brushy Canyon, Avalon and Strawn formations in the Delaware Basin, 12 gross (12.0 net) locations to which we have assigned proved undeveloped
reserves in the Eagle Ford and nine gross (3.3 net) locations to which we have assigned proved undeveloped reserves in the Haynesville.

(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas
Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.

(3) Production volumes and proved reserves reported in two streams; oil and natural gas, including both dry and liquids-rich natural gas. Estimated

using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in

the Delaware Basin at December 31, 2017.

(5) Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from

the San Miguel formation in Zavala County, Texas.

(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore,

the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes
acreage that we are producing from or that we believe to be prospective for these formations.

We are active both as an operator and as a co-working interest owner with various industry participants. At

December 31, 2017, we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and
West Texas. In those wells where we are not the operator, our working interests are often relatively small. At
December 31, 2017, we also were the operator for approximately 94% of our Eagle Ford acreage and approximately

FORM 10-K PART I

MATADOR RESOURCES COMPANY

64% of our Haynesville acreage, including approximately 32% of our acreage in what we believe is the core area
of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by an
afﬁliate of Chesapeake Energy Corporation.

While we do not always have direct access to our operating partners’ drilling plans with respect to future
well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical
staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure
budget and our booking of any related proved undeveloped well locations and reserves. We review these locations
with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their
concurrence with our estimates of these drilling plans and our approach to booking these reserves.

Southeast New Mexico and West Texas — Delaware Basin

The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production
province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in
many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir
targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and
hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich
shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the
Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered
low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced
hydraulic fracturing techniques.

In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring

(also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of
shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine
depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced
in the basin. Historically, production has come from conventional reservoirs; however, we and other industry
players have realized that the source rocks also have sufﬁcient porosity and permeability to be commercial reservoirs.
In addition, the source rocks are interbedded with reservoir layers that have ﬁlled with hydrocarbons, both of
which can produce signiﬁcant volumes of oil and natural gas when connected by horizontal wellbores with multi-
stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a
given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring
and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identiﬁed and targeted by
companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First,
Second and Third Sand) and several intervals within the Wolfcamp shale, often identiﬁed as Wolfcamp A through D.

As noted above in “—2017 Highlights—Operational Highlights,” we increased our acreage position in the

Delaware Basin during 2017, and as a result, at December 31, 2017, our total acreage position in Southeast
New Mexico and West Texas was approximately 199,600 gross (114,000 net) acres, primarily in Loving County,
Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 28,800 gross
(15,500 net) acres in our Ranger asset area in Lea County, 56,600 gross (23,400 net) acres in our Arrowhead asset
area in Eddy County, 41,000 gross (21,200 net) acres in our Rustler Breaks asset area in Eddy County, 12,000
gross (8,900 net) acres in our Antelope Ridge asset area in Lea County, 13,600 gross (9,400 net) acres in our Wolf
and Jackson Trust asset areas in Loving County and 46,100 gross (34,400 net) acres in our Twin Lakes asset area
in Lea County at December 31, 2017. We consider the vast majority of our Delaware Basin acreage position to be
prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on
certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian,
Penn Shale, Atoka and Morrow formations. At December 31, 2017, our acreage position in the Delaware Basin was

FORM 10-K PART I

2017 ANNUAL REPORT

approximately 45% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only
one vertical and one horizontal well, our acreage position in the Delaware Basin was approximately 59% held by
existing production at December 31, 2017.

During the year ended December 31, 2017, we continued the delineation and development of our Delaware

Basin acreage. We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the
Delaware Basin, including 65 gross (56.1 net) operated wells and 21 gross (3.5 net) non-operated wells, throughout
our various asset areas. At December 31, 2017, we had tested a number of different producing horizons at various
locations across our acreage position, including the Brushy Canyon, Avalon, two benches of the Second Bone
Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic,
lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of
our delineation and development efforts have been focused on multiple completion targets between the Second
Bone Spring and the Wolfcamp B.

As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production

increased signiﬁcantly in 2017. Our average daily oil equivalent production from the Delaware Basin increased
approximately 85% to 29,463 BOE per day (76% of total oil equivalent production), including 18,023 Bbl of oil per
day (84% of total oil production) and 68.6 MMcf of natural gas per day (66% of total natural gas production), in 2017,
as compared to 15,941 BOE per day (57% of total oil equivalent production), including 10,395 Bbl of oil per day
(75% of total oil production) and 33.3 MMcf of natural gas per day (40% of total natural gas production), in 2016.
Our average daily oil equivalent production from the Delaware Basin also grew approximately 69% from 20,670 BOE
per day in the fourth quarter of 2016 to 34,859 BOE per day in the fourth quarter of 2017.

At December 31, 2017, approximately 84% of our estimated total proved oil and natural gas reserves, or
129.0 million BOE, was attributable to the Delaware Basin, including approximately 77.5 million Bbl of oil and
308.9 Bcf of natural gas, a 62% increase, as compared to 79.4 million BOE for the year ended December 31, 2016.
Our Delaware Basin proved reserves at December 31, 2017 comprised approximately 89% of our proved oil
reserves and 78% of our proved natural gas reserves, as compared to approximately 82% of our proved oil reserves
and 67% of our proved natural gas reserves at December 31, 2016.

At December 31, 2017, we had identiﬁed 4,630 gross (1,957.7 net) engineered locations for potential future drilling

on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower
Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 2,954 gross
(1,775.5 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these
locations. These engineered locations have been identiﬁed on a property-by-property basis and take into account
criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated
recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities
observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion
costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
Our engineered well locations at December 31, 2017 do not yet include all portions of our acreage position and
do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our
second anticipated operated horizontal test of the Wolfcamp D formation in 2018). Our identiﬁed well locations
presume that these properties may be developed on 80- to 160-acre well spacing and that multiple intervals may
be prospective at any one surface location. Although we believe that denser well spacing may be possible,
at December 31, 2017, the majority of our estimated locations were based on the assumption of 160-acre well
spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify
additional locations for future drilling. At December 31, 2017, these potential future drilling locations included only
261 gross (130.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in
the Brushy Canyon, Avalon and Strawn formations, to which we have assigned proved undeveloped reserves.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

At December 31, 2017, we were operating six drilling rigs in the Delaware Basin, and we expect to operate
those rigs in the Delaware Basin throughout 2018, including three rigs in the Rustler Breaks asset area, one rig in the
Wolf/Jackson Trust asset areas, one rig in the Ranger/Arrowhead and Twin Lakes asset areas and one rig in the
Antelope Ridge asset area. One of the three rigs operating in the Rustler Breaks asset area is also expected to drill
at least two commercial salt water disposal wells in that area during 2018 for San Mateo. As a result, we expect
that this rig will spend only approximately three-quarters of the year drilling oil and natural gas wells. We are also
planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2018. We have
allocated substantially all of our 2018 estimated capital expenditure budget to our drilling and completion program
and midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations
in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated
well opportunities.

Rustler Breaks Asset Area - Eddy County, New Mexico

We operated three drilling rigs in our Rustler Breaks asset area during most of 2017. We completed and turned

to sales 53 gross (34.5 net) horizontal wells in the Rustler Breaks asset area in 2017, including 37 gross (32.4 net)
operated and 16 gross (2.1 net) non-operated wells. Most of these wells were completed in the Wolfcamp A-XY
or Wolfcamp B-Blair intervals, and the well results achieved were consistent with previous wells drilled and
completed in those intervals.

One of the key achievements of our drilling and completions program in our Rustler Breaks asset area in 2017

was the success of our wells drilled in the northwestern portion of our acreage position. Early performance from
these wells is comparable to or better than Wolfcamp A-XY wells in other portions of our Rustler Breaks asset area.
As examples, the Joe Coleman 13-23S-27E RB #206H (Joe Coleman #206H) and the Tom Walters 12-23S-27E RB
#203H (Tom Walters #203H) wells tested 1,840 BOE per day (75% oil) and 1,554 BOE per day (74% oil), respectively,
during 24-hour initial potential tests. In just nine months of production, the Joe Coleman #206H well has produced
approximately 275,000 BOE (71% oil), and in approximately one year of production, the Tom Walters #203H well has
produced approximately 255,000 BOE (73% oil).

In addition, two Wolfcamp A-Lower wells completed in 2017 represented our ﬁrst tests of the Wolfcamp
A-Lower interval in the Rustler Breaks asset area. The Guitar 10-24S-28E RB #205H well tested 1,155 BOE per day
(75% oil) and the Charlie Sweeney Fed Com #204H well tested 1,188 BOE per day (75% oil), during 24-hour
initial potential tests. We believe that these tests conﬁrm the potential of the Wolfcamp A-Lower interval as another
completion target in the Rustler Breaks asset area.

Wolf and Jackson Trust Asset Areas - Loving County, Texas

In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY, Wolfcamp

A-Lower and Second Bone Spring formations in 2017. We operated one drilling rig in our Wolf and Jackson Trust
asset areas during 2017, and we completed and turned to sales 13 gross (11.0 net) operated horizontal wells in these
asset areas. Most of these wells were completed in the Wolfcamp A-Lower and Second Bone Spring intervals.

In early January 2017, we completed and placed on production the Totum E 18-TTT-C24 NL #211H (Totum #211H)

well. This well tested 2,247 BOE per day (72% oil) during a 24-hour initial potential test, which was the highest
24-hour initial potential test for any Wolfcamp A-Lower well completed by us in either our Wolf or Jackson Trust
asset areas. We attribute this signiﬁcant improvement in well performance to both the selection of an improved
landing target, identiﬁed through the use of 3-D seismic data, and an improved stimulation design. In almost one
year of production, the Totum #211H well has produced approximately 300,000 BOE (77% oil).

FORM 10-K PART I

2017 ANNUAL REPORT

The Barnett 90-TTT-B01 WF #224H (Barnett #224H) well was our ﬁrst test of the Wolfcamp B interval in our
Wolf asset area. The Barnett #224H well tested 1,803 BOE per day (28% oil) at 4,125 psi during a 24-hour initial
potential test. This well exhibited the highest ﬂowing casing pressure on any well yet completed by us in the
Wolf asset area. The initial test results and early performance from the Barnett #224H well exceeded our expectations
and were similar to those from the Wolfcamp B-Blair interval in the Rustler Breaks asset area. We were pleased
with the results of this initial test of the Wolfcamp B interval, which we believe conﬁrms the potential of the
Wolfcamp B interval as another completion target in the Wolf asset area.

Arrowhead and Ranger Asset Areas - Eddy and Lea Counties, New Mexico

We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2017. We completed

and turned to sales 18 gross (13.4 net) horizontal wells in these asset areas in 2017, including 15 gross (12.7 net)
operated and three gross (0.7 net) non-operated wells. Most of these wells were completed in the Second Bone
Spring and Third Bone Spring intervals.

In the second and third quarters of 2017, we completed and turned to sales our ﬁrst operated horizontal wells in
our Arrowhead asset area on our Stebbins leasehold. The Stebbins 20 Federal #123H (Stebbins 20 #123H) well was
a Second Bone Spring test, and the Stebbins 20 Federal #133H (Stebbins 20 #133H) well was a Third Bone Spring
test. The Stebbins 20 #123H and #133H wells tested 1,010 BOE per day (82% oil) and 1,202 BOE per day (70% oil),
respectively, during 24-hour initial potential tests. We completed and turned to sales three additional wells on
the Stebbins leasehold in the fourth quarter of 2017, two completed in the Second Bone Spring interval and one
completed in the Third Bone Spring interval, with comparable 24-hour initial potential test results to the initial
Stebbins wells.

The contiguous nature of the Stebbins acreage has already lent itself to several operational efﬁciencies, such as
batch drilling and completion operations, as well as centralized facilities, each of which contribute to lower overall
project costs. Drilling times for the Stebbins wells have improved by as much as 4.1 days since development began
on the Stebbins leasehold in 2017. In addition, we expect to be able to drill 1.5 and 2-mile laterals as part of our
future development of this acreage.

In the Ranger asset area, we drilled the Airstrip 31-18S-35E RN State Com #132H (Airstrip #132H) well, a Third
Bone Spring test north of our Mallon leasehold. The Airstrip #132H well tested 1,263 BOE per day (93% oil) during a
24-hour initial potential test. The Airstrip #132H well has produced approximately 95,000 BOE (92% oil) in its ﬁrst
six months of production.

During the third quarter of 2017, we installed gas lift on the three Mallon wells—the Mallon 27 Federal Com #1H,

#2H and #3H (Mallon #1H, #2H and #3H) wells in the Ranger asset area. Each of these three wells was drilled and
completed in the Third Bone Spring and turned to sales in the fourth quarter of 2016. The Mallon wells each tested
initially between 2,400 and 2,800 BOE per day (91% oil) and continued to perform well throughout their ﬁrst ten
to eleven months of production prior to the installation of gas lift. Unlike most Third Bone Spring wells completed in
the Arrowhead and Ranger asset areas, these wells were tested while ﬂowing up casing (rather than on electrical
submersible pump), and the wells continued to ﬂow up casing until the installation of gas lift on each well in the
third quarter of 2017.

Each of the Mallon wells exhibited a strong production response to the installation of gas lift. Daily production
rates from the Mallon #1H well, which had declined to 600 to 700 Bbl of oil per day, increased to an average of over
1,300 Bbl of oil per day in the ﬁrst 30 days following gas lift installation. Daily production rates from the Mallon #2H
well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of almost 1,500 Bbl of oil per day
in the ﬁrst 30 days following gas lift installation. Daily production rates from the Mallon #3H well, which had
declined to 400 to 500 Bbl of oil per day, increased to an average of approximately 900 Bbl of oil per day in the ﬁrst
30 days following gas lift installation. Natural gas production from these wells responded in a similar fashion.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Production declines resumed on these wells at a similar rate to what was observed prior to the installation of gas
lift, but from higher daily production rates. The three Mallon wells have produced about 1.3 million BOE (90% oil) in
the aggregate, including over 1.1 million Bbl of oil in just over one year of production.

Twin Lakes Asset Area - Lea County, New Mexico

In 2017, we performed our ﬁrst horizontal test of the Wolfcamp D formation in the eastern portion of our
Twin Lakes asset area in northern Lea County, New Mexico. This well, the D. Culbertson 26-15S-36E TL State #234H
(D. Culbertson #234H) well, tested approximately 600 BOE per day (82% oil) during a 24-hour initial potential test,
including 493 Bbl of oil per day and 640 Mcf of natural gas per day, from a completed lateral length of approximately
4,400 feet. We were pleased and encouraged with the initial results from this discovery well, which we believe
conﬁrmed our exploration concept and validated the prospectivity of the Wolfcamp D in the Twin Lakes asset area.
To our knowledge, this discovery well is the northernmost horizontal test of the Wolfcamp formation in New Mexico,
and this well demonstrates the potential for horizontal exploitation and development of the Wolfcamp formation
far to the north of the most active areas of current drilling in the Wolfcamp play in the Delaware Basin. Overall, the
D. Culbertson #234H well provided us with a solid ﬁrst step in our understanding of the Wolfcamp D formation
in this area. We plan to drill a second Wolfcamp D test on the western portion of our Twin Lakes acreage position
in 2018.

Antelope Ridge Asset Area - Lea County, New Mexico

We drilled our ﬁrst operated well in the Antelope Ridge asset area, the Florence State 23-23S-34E #202H
(Florence #202H) well, in mid-November 2017. This well was completed and turned to sales in January 2018. The
Florence #202H well tested 1,947 BOE per day (81% oil) at 1,700 psi during a 24-hour initial potential test. We were
pleased with the initial performance of this well and believe it conﬁrms the prospectivity of the Antelope Ridge asset
area. We intend to continue the delineation of our acreage position in Antelope Ridge, where other operators in the
area have successfully tested the Brushy Canyon, First, Second and Third Bone Spring and Upper Wolfcamp intervals.

South Texas — Eagle Ford Shale and Other Formations

The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming
a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and
lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the
Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly
sized structural perturbations. As a result, depth of burial increases consistently southwards along with the
thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more
oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone.
The transition between being more oil prone and more natural gas prone includes an interval that typically produces
liquids-rich natural gas with condensate.

At December 31, 2017, our properties included approximately 31,800 gross (29,000 net) acres in the Eagle Ford
shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe
that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas
with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 86% of our
Eagle Ford acreage was held by production at December 31, 2017, and approximately 98% of our Eagle Ford
acreage was either held by production at December 31, 2017 or not burdened by lease expirations before 2019.

In 2017, we drilled and completed ﬁve operated wells in the Eagle Ford shale in South Texas. Two of these wells,

the Falls City #1H and #2H wells, both located in Karnes County, were turned to sales in mid-June 2017. The other
three wells, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells, all located in La Salle
County, were turned to sales in early July 2017. We have a 100% working interest in each of these ﬁve wells.

FORM 10-K PART I

2017 ANNUAL REPORT

These ﬁve Eagle Ford shale wells tested between approximately 1,100 and 1,700 BOE per day at oil cuts
between 90% and 94% during 24-hour initial potential tests. The initial results from this ﬁve-well drilling program
almost doubled our average daily oil equivalent production from the Eagle Ford shale in the third quarter of 2017,
as compared to production levels in the second quarter of 2017.

At December 31, 2017, the Falls City #1H and #2H wells had the highest estimated ultimate oil recoveries of any

of our wells in the Eagle Ford shale. Further, the Martin Ranch C #11H well and the Martin MAK D #49H and D
#50H wells were drilled and completed for an average of approximately $4.5 million per well, among the lowest well
costs we have achieved in the Eagle Ford shale. Despite not being active in the Eagle Ford shale since the second
quarter of 2015, we were able to achieve our fastest drilling time for an Eagle Ford shale well from spud to total depth
in one of these Martin Ranch wells.

Our average daily oil equivalent production from the Eagle Ford shale decreased 11% to 4,413 BOE per day,
including 3,475 Bbl of oil per day and 5.6 MMcf of natural gas per day, during 2017, as compared to 4,952 BOE per
day, including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016. For the year ended
December 31, 2017, 11% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During
the year ended December 31, 2016, approximately 18% of our total daily oil equivalent production was attributable
to the Eagle Ford shale.

At December 31, 2017, approximately 8% of our estimated total proved oil and natural gas reserves, or

12.3 million BOE, was attributable to the Eagle Ford shale, including approximately 9.2 million Bbl of oil and 19.0 Bcf
of natural gas. Our Eagle Ford total proved reserves comprised approximately 11% of our proved oil reserves and
5% of our proved natural gas reserves at December 31, 2017, as compared to approximately 18% of our proved oil
reserves and 7% of our proved natural gas reserves at December 31, 2016.

At December 31, 2017, we had identiﬁed 241 gross (208.5 net) engineered locations for potential future drilling

on our Eagle Ford acreage. These locations have been identiﬁed on a property-by-property basis and take into
account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return,
estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data,
drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal
lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities
and surface considerations, among other factors. The identiﬁed well locations presume that we will be able to
develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the speciﬁc property and the wells we
have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle,
northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties,
particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing.
At December 31, 2017, these 241 gross (208.5 net) identiﬁed drilling locations included only 12 gross (12.0 net)
locations to which we have assigned proved undeveloped reserves.

These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We

believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the
Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to
produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be
prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly
oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch
property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective
for the Buda formation. At December 31, 2017, we had not included any future drilling locations in the upper
portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the
Austin Chalk or Buda formations, even though recent activity from other operators in these formations around our
South Texas acreage position has demonstrated the potential prospectivity of these intervals.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Northwest Louisiana and East Texas — Haynesville Shale, Cotton Valley and Other Formations

The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and

Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad
region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River
Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces
primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided
into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges
in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.

We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest
Louisiana and East Texas during 2017, although we did participate in the drilling and completion of 11 gross (0.6 net)
non-operated Haynesville shale wells that were turned to sales in 2017. We do not plan to drill any operated
Haynesville shale or Cotton Valley wells in 2018.

At December 31, 2017, we held approximately 25,500 gross (22,800 net) acres in Northwest Louisiana and
East Texas, including 19,600 gross (12,000 net) acres in the Haynesville shale play and 21,100 gross (18,600 net)
acres in the Cotton Valley play. We operate all of our Cotton Valley and shallower production on our leasehold
interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside
of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the
13,200 gross (6,400 net) acres that we consider to be in the core area of the Haynesville play. We believe the core
area of the play includes that area in which the most Haynesville shale wells have been drilled by operators and
from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well from an approximate 5,000-foot
horizontal lateral.

For the year ended December 31, 2017, approximately 13% of our average daily oil equivalent production,
or 5,060 BOE per day, including 12 Bbl of oil per day and 30.4 MMcf of natural gas per day, was attributable to
our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties
comprised approximately 29% of our daily natural gas production for 2017, but oil production from these properties
comprised only about 0.1% of our daily oil production during 2017, as compared to approximately 50% of our
daily natural gas production and approximately 0.1% of our daily oil production during 2016. During the year ended
December 31, 2016, approximately 25% of our average daily oil equivalent production, or 6,920 BOE per day,
including 12 Bbl of oil per day and 41.4 MMcf of natural gas per day, was attributable to our properties in Northwest
Louisiana and East Texas.

For the year ended December 31, 2017, approximately 27% of our daily natural gas production, or 28.3 MMcf
of natural gas per day, was produced from the Haynesville shale, with approximately 2%, or 2.1 MMcf of natural gas
per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended
December 31, 2016, approximately 47% of our daily natural gas production, or 39.1 MMcf of natural gas per day,
was produced from the Haynesville shale, with approximately 3%, or 2.3 MMcf of natural gas per day, produced
from the Cotton Valley and other shallower formations on these properties. At December 31, 2017, approximately
7% of our estimated total proved reserves, or 10.1 million BOE, was attributable to the Haynesville shale with
another 1% of our proved reserves, or 1.3 million BOE, attributable to the Cotton Valley and shallower formations
underlying this acreage.

At December 31, 2017, we had identiﬁed 413 gross (102.0 net) engineered locations for potential future
drilling in the Haynesville shale play and 71 gross (50.0 net) engineered locations for potential future drilling in the
Cotton Valley formation. These locations have been identiﬁed on a property-by-property basis and take into account
criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated

FORM 10-K PART I

2017 ANNUAL REPORT

recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public
data, drilling densities observed on properties of other operators, including on some of our non-operated properties,
estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established
by regulatory authorities and surface conditions, among other criteria. Of the 413 gross (102.0 net) locations
identiﬁed for future drilling on our Haynesville acreage, 339 gross (49.0 net) locations have been identiﬁed within the
13,200 gross (6,400 net) acres that we believe are located in the core area of the Haynesville play. As we explore
and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify
additional locations for future drilling. At December 31, 2017, these potential future drilling locations included
only nine gross (3.3 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have
assigned proved undeveloped reserves.

MIDSTREAM SEGMENT

The midstream segment conducts midstream operations in support of our exploration, development and
production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt
water gathering services and salt water disposal services to third parties. Through the ownership and operation
of these facilities, we improve our ability to manage costs and control the timing of bringing on new production,
and we enhance the value received for our production. As noted above, we contributed the Delaware Midstream
Assets to San Mateo in February 2017 and continued to operate them, as well as San Mateo’s other assets, at
December 31, 2017.

Southeast New Mexico and West Texas — Delaware Basin

During 2017, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in

Eddy County, New Mexico to add an incremental 200 MMcf per day to the existing 60 MMcf per day of inlet
cryogenic natural gas processing capacity. At February 21, 2018, the expansion project was proceeding on schedule
with the plant expansion expected to become operational by the end of the ﬁrst quarter of 2018. At December 31,
2017 and February 21, 2018, the Black River Processing Plant was effectively full with Matador-operated natural
gas. The Black River Processing Plant and associated gathering system were built to support our ongoing and future
development efforts in the Rustler Breaks asset area and to provide us with ﬁrm takeaway and processing services
for our Rustler Breaks natural gas production. It may also provide additional income through the gathering and
processing of third-party natural gas after the plant expansion becomes operational. We had previously completed
the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout
the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather
almost all of our natural gas production at Rustler Breaks. In addition, in October 2017 and January 2018, San Mateo
placed into service its second and third, respectively, commercial salt water disposal wells in the Rustler Breaks
asset area. San Mateo disposed of approximately 7.9 million Bbl of Matador-operated and third-party salt water in
the Rustler Breaks asset area during 2017 and, at February 21, 2018, its salt water disposal wells there had a
disposal capacity of approximately 90,000 Bbl of salt water per day. San Mateo plans to add to that disposal capacity
in 2018 by upgrading two of the existing salt water disposal wells by installing larger tubing and drilling and
completing at least two additional commercial salt water disposal wells and constructing the associated commercial
salt water disposal facilities in the Rustler Breaks asset area. We expect these additional wells to be completed
in 2018, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to a total
of ﬁve. At February 21, 2018, San Mateo was also building out an oil gathering and transportation system in the
Rustler Breaks asset area.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

In our Wolf asset area in Loving County, Texas, San Mateo has oil, natural gas and salt water gathering systems

that gather our oil, natural gas and water production. We retained this three-pipeline system following the sale of
our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area
(the “Loving County Processing System”) to an afﬁliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015.
The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing
Plant”) and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the
Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed
to San Mateo in February 2017. During 2017, San Mateo disposed of approximately 15.5 million Bbl of salt water in
the Wolf asset area, including disposal of third-party salt water on a commercial basis. San Mateo completed its
third salt water disposal well in the Wolf asset area during 2017, increasing San Mateo’s disposal capacity in the
Wolf asset area to approximately 70,000 Bbl of salt water per day. At February 21, 2018, San Mateo was also
expanding its oil gathering system in the Wolf asset area.

South Texas / Northwest Louisiana and East Texas

In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our

operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and
treat natural gas from most of our operated leases and from third parties. We also have ﬁve non-commercial salt
water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana
and East Texas are not part of San Mateo.

OPERATING SUMMARY

The following table sets forth certain unaudited production and operating data for the years ended December 31,

2017, 2016 and 2015.

Unaudited Production Data:
Net Production Volumes:

Oil (MBbl)
Natural gas (Bcf)

Total oil equivalent (MBOE) (1)

Average daily production (BOE/d) (1)

Average Sales Prices:

Oil, without realized derivatives (per Bbl)
Oil, with realized derivatives (per Bbl)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)

Operating Expenses (per BOE):

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
General and administrative

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31,

2017

2016

2015

7,851
38.2
14,212
38,936

$ 49.28
$ 48.81
$ 3.72
$ 3.70

$ 4.10
$ 4.74
$ 0.92
$ 12.49
$ 4.65

5,096
30.5
10,180
27,813

$ 41.19
$ 42.34
2.66
$
2.78
$

4.23
$
5.52
$
$
0.53
$ 11.99
5.41
$

4,492
27.7
9,109
24,955

$ 45.27
$ 59.13
$ 2.71
$ 3.24

$ 3.91
$ 6.01
$ 0.38
$ 19.63
$ 5.50

FORM 10-K PART I

2017 ANNUAL REPORT

The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2017 from our operating areas, which we consider to be distinct ﬁelds for purposes
of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana/East Texas

Delaware Basin Eagle Ford (1)

Haynesville Cotton Valley (2)

Total

6,579
25.1
10,754

75.7%

1,268
2.0
1,611
11.3%

—
10.3
1,714
12.1%

4
0.8
133
0.9%

7,851
38.2
14,212
100.0%

18,023
68.6
29,463

$ 49.08
$ 4.03
$ 39.41

3,475
5.6
4,413

$ 50.29
$ 4.69
$ 45.58

—
28.3
4,697

12
2.1
363

21,510
104.6
38,936

$ —
$ 2.83
$ 16.96

$ 45.52
$ 2.79
$ 17.69

$ 49.28
$ 3.72
$ 37.20

Production Costs (5)
Lease operating, transportation and processing (per BOE)

$ 5.80

$ 10.92

$ 4.21

$ 16.77

$ 6.29

Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from
the San Miguel formation in Zavala County, Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion

ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2016 from our operating areas, which we consider to be distinct ﬁelds for purposes
of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana/East Texas

Delaware Basin Eagle Ford (1)

Haynesville Cotton Valley (2)

Total

Annual Net Production Volumes
Oil (MBbl)
Natural gas (Bcf)
Total oil equivalent (MBOE) (3)
Percentage of total annual net production
Average Net Daily Production Volumes
Oil (Bbl/d)
Natural gas (MMcf/d)
Total oil equivalent (BOE/d)
Average Sales Prices (4)
Oil (per Bbl)
Natural gas (per Mcf)
Total oil equivalent (per BOE)
Production Costs (5)
Lease operating, transportation and processing (per BOE)

3,805
12.2
5,834
57.3%

1,286
3.1
1,813

—
14.3
2,385

17.8%

23.4%

10,395
33.3
15,941

$ 41.76
$ 3.15
$ 33.81

3,517
8.6
4,952

$ 39.49
$ 3.11
$ 33.46

—
39.1
6,517

$ —
$ 2.17
$13.04

$38.78
$ 2.27
$14.39

5
0.9
148
1.5%

12
2.3
403

5,096
30.5
10,180
100.0%

13,924
83.3
27,813

$ 41.19
$
2.66
$ 28.60

$ 7.32

$ 12.74

$ 4.73

$17.07

7.82

(1)

Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from
the San Miguel formation in Zavala County, Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion

ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

FORM 10-K PART I

2017 ANNUAL REPORT

The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2015 from our operating areas, which we consider to be distinct ﬁelds for purposes
of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana/East Texas

Delaware Basin Eagle Ford (1)

Haynesville Cotton Valley (2)

Total

1,697
4.1
2,379
26.1%

$43.54
$ 3.00
$36.21

4,648
11.2
6,518

2,789
5.7
3,746
41.1%

7,642
15.7
10,263

$ 46.33
$ 3.17
$ 39.35

—
16.9
2,822

31.0%

—
46.4
7,731

6
1.0
162
1.8%

16
2.6
443

$ —
$ 2.49
$14.97

$43.68
$ 2.45
$15.69

4,492
27.7
9,109
100.0%

12,306
75.9
24,955

$ 45.27
$
2.71
$ 30.56

$ 9.25

$ 4.91

$19.23

7.90

(1)

Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from
the San Miguel formation in Zavala County, Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion

ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

(6) Amounts have been adjusted to reﬂect the reclassiﬁcation of certain lease operating expenses to plant and other midstream services operating

expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.

Our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017

increased 40% from our total oil equivalent production of approximately 10.2 million BOE for the year ended
December 31, 2016. This increased production was primarily due to our delineation and development operations in
the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average
daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, as compared to
27,813 BOE per day for the year ended December 31, 2016. Our average daily oil production for the year ended
December 31, 2017 was 21,510 Bbl of oil per day, an increase of 54% from 13,924 Bbl of oil per day for the year
ended December 31, 2016. Our average daily natural gas production for the year ended December 31, 2017 was
104.6 MMcf of natural gas per day, an increase of 25% from 83.3 MMcf of natural gas per day for the year ended
December 31, 2016.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016

increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended
December 31, 2015. This increased production was primarily due to our delineation and development operations
in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where, as
of December 31, 2016, we had not drilled any new operated wells since the second quarter of 2015. Our average
daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, as compared
to 24,955 BOE per day for the year ended December 31, 2015. Our average daily oil production for the year ended
December 31, 2016 was 13,924 Bbl of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year
ended December 31, 2015. Our average daily natural gas production for the year ended December 31, 2016 was
83.3 MMcf of natural gas per day, an increase of 10% from 75.9 MMcf of natural gas per day for the year ended
December 31, 2015.

PRODUCING WELLS

The following table sets forth information relating to producing wells at December 31, 2017. Wells are classiﬁed as

oil wells or natural gas wells according to their predominant production stream. We had an approximate average
working interest of 75% in all wells that we operated at December 31, 2017. For wells where we are not the operator,
our working interests range from less than 1% to as much as just over 50%, and average approximately 11%.
In the table below, gross wells are the total number of producing wells in which we own a working interest and net
wells represent the total of our fractional working interests owned in the gross wells.

Southeast New Mexico/West Texas:

Delaware Basin (1)

South Texas:

Eagle Ford (2)

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley (3)
Area Total
Total

Oil Wells

Natural Gas Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

372

174.8

36.7

450

211.5

138

115.8

4.0

142

119.8

—
2
2
512

—
2.0
2.0
292.6

217
79
296
378

20.5
52.3
72.8
113.5

217
81
298
890

20.5
54.3
74.8
406.1

(1)

Includes 217 gross (55.4 net) vertical wells that were acquired in multiple transactions.

(2) Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from

the San Miguel formation in Zavala County, Texas.

(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

ESTIMATED PROVED RESERVES

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2017, 2016 and

2015. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and
liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford
shale, the economic value of the natural gas liquids (“NGLs”) associated with the natural gas is included in the
estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves
estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness
by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared
in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are
for proved reserves only and do not include any unproved reserves classiﬁed as probable or possible reserves that
might exist for our properties, nor do they include any consideration that could be attributable to interests in

FORM 10-K PART I

2017 ANNUAL REPORT

unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil
and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.

Estimated Proved Reserves Data:(2)
Estimated proved reserves:

Oil (MBbl)
Natural Gas (Bcf) (3)
Total (MBOE) (4)

Estimated proved developed reserves:

Oil (MBbl)
Natural Gas (Bcf) (3)
Total (MBOE) (4)

Percent developed

Estimated proved undeveloped reserves:

Oil (MBbl)
Natural Gas (Bcf) (3)
Total (MBOE) (4)

Standardized Measure (5) (in millions)
PV-10 (6) (in millions)

(1) Numbers in table may not total due to rounding.

At December 31,(1)

2017

2016

2015

86,743
396.2
152,771

36,966
190.1
68,651

56,977
292.6
105,752

22,604
126.8
43,731

45,644
236.9
85,127

17,129
101.4
34,037

44.9%

41.4%

40.0%

49,777
206.1
84,120

34,373
165.9
62,021

$ 1,258.6
$ 1,333.4

$ 575.0
$ 581.5

28,515
135.5
51,090

$ 529.2
$ 541.6

(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving
effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the
ﬁrst-day-of-the-month prices for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas,
for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, and for the 12 months ended
December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy
content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.
We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is
included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold.

(3) Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously

classiﬁed proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated
properties in the Haynesville shale.

(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural
gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classiﬁed
proved undeveloped reserves from our total proved reserves in 2016.

(5) Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less estimated future

development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reﬂect the timing of
future cash ﬂows. Standardized Measure is not an estimate of the fair market value of our properties.

(6) PV-10 is a non-GAAP ﬁnancial measure and generally differs from Standardized Measure, the most directly comparable GAAP ﬁnancial measure,

because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our
properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
and of the potential return on investment related to the companies’ properties without regard to the speciﬁc tax characteristics of such entities.
Our PV-10 at December 31, 2017, 2016 and 2015 may be reconciled to our Standardized Measure of discounted future net cash ﬂows at such
dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at
December 31, 2017, 2016 and 2015 were, in millions, $74.8, $6.5 and $12.4, respectively.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our estimated total proved oil and natural gas reserves increased 44% from 105.8 million BOE at December 31,
2016 to 152.8 million BOE at December 31, 2017. We added 45.2 million BOE in proved oil and natural gas reserves
through extensions and discoveries throughout 2017, approximately 3.2 times our 2017 annual production of
14.2 million BOE. Our proved oil reserves grew 52% from approximately 57.0 million Bbl at December 31, 2016 to
approximately 86.7 million Bbl at December 31, 2017. Our proved natural gas reserves increased 35% from
292.6 Bcf at December 31, 2016 to 396.2 Bcf at December 31, 2017. This increase in proved oil and natural gas
reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2017.
We incurred approximately 9.6 million BOE in net upward revisions to our proved reserves during 2017 primarily as
a result of upward technical revisions resulting from better-than-projected well performance from certain wells
and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017, as
compared to December 31, 2016. Our proved reserves to production ratio at December 31, 2017 was 10.8x, an
increase of 4% from 10.4x at December 31, 2016.

The Standardized Measure of our total proved oil and natural gas reserves increased 119% from $575.0 million

at December 31, 2016 to $1.26 billion at December 31, 2017. The PV-10 of our total proved oil and natural gas
reserves increased 129% from $581.5 million at December 31, 2016 to $1.33 billion at December 31, 2017.
The increases in our Standardized Measure and PV-10 are primarily a result of our delineation and development
operations in the Delaware Basin during 2017 and higher weighted average oil and natural gas prices used to
estimate proved reserves at December 31, 2017, as compared to December 31, 2016. The unweighted arithmetic
averages of ﬁrst-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31,
2017 were $47.79 per Bbl and $2.98 per MMBtu, an increase of 22% and 20%, respectively, as compared to average
oil and natural gas prices of $39.25 per Bbl and $2.48 per MMBtu used to estimate proved reserves at December 31,
2016. Our total proved reserves were made up of 57% oil and 43% natural gas at December 31, 2017, as compared
to 54% oil and 46% natural gas at December 31, 2016.

Our proved developed oil and natural gas reserves increased 57% from 43.7 million BOE at December 31, 2016

to 68.7 million BOE at December 31, 2017 due primarily to our delineation and development operations in the
Delaware Basin. Our proved developed oil reserves increased 64% from 22.6 million Bbl at December 31, 2016 to
37.0 million Bbl at December 31, 2017. Our proved developed natural gas reserves increased 50% from 126.8 Bcf
at December 31, 2016 to 190.1 Bcf at December 31, 2017.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2017.

As of December 31, 2016

Extensions and discoveries
Purchases of minerals-in-place
Revisions of prior estimates
Production
Conversion of proved undeveloped to proved developed

As of December 31, 2017

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Proved
Developed
Reserves

(MBOE)(1)

43,731
14,335
1,614
6,375
(14,212)
16,808
68,651

FORM 10-K PART I

2017 ANNUAL REPORT

Our proved undeveloped oil and natural gas reserves increased 36% from 62.0 million BOE at December 31,
2016 to 84.1 million BOE at December 31, 2017. Our proved undeveloped oil and natural gas reserves increased
from 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016 to 49.8 million Bbl and 206.1 Bcf,
respectively, at December 31, 2017, primarily as a result of our delineation and development operations in the
Delaware Basin.

At December 31, 2017, we had no proved undeveloped reserves in our estimates that remained undeveloped
for ﬁve years or more following their initial booking, and we currently have plans to use anticipated capital resources
to develop the proved undeveloped reserves remaining as of December 31, 2017 within ﬁve years of booking
these reserves.

The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2017.

As of December 31, 2016

Extensions and discoveries
Purchases of minerals-in-place
Revisions of prior estimates
Conversion of proved undeveloped to proved developed

As of December 31, 2017

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Proved
Undeveloped
Reserves

(MBOE)(1)

62,021
30,834
4,868
3,205
(16,808)
84,120

The following table sets forth, since 2014, proved undeveloped reserves converted to proved developed

reserves during each year and the investments associated with these conversions (dollars in thousands).

Proved Undeveloped Reserves
Converted to
Proved Developed Reserves

Oil

Natural Gas

(MBbl)

(Bcf)

Investment in
Conversion
of Proved
Undeveloped
Reserves
to Proved
Total Developed
Reserves

(MBOE)(1)

2014
2015
2016
2017

Total

3,780
2,854
4,705
9,300
20,639

44.7
23.4
13.1
45.0
126.2

11,223
6,747
6,883
16,808
41,661

$201,950
104,989
94,579
211,860
$613,378

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The following table sets forth additional summary information by operating area with respect to our estimated

net proved reserves at December 31, 2017.

Southeast New Mexico/West Texas:

Delaware Basin

South Texas:

Eagle Ford (5)

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley (6)
Area Total
Total

(1) Numbers in table may not total due to rounding.

Net Proved Reserves (1)

Oil

(MBbl)

Natural Gas

Oil
Equivalent

Standardized
Measure(2)

PV-10 (3)

(Bcf)

(MBOE)(4)

(in millions)

77,508

308.9

128,999

$ 1,088.4

$ 1,153.1

9,189

19.0

12,346

130.6

138.4

—
46
46
86,743

60.7
7.6
68.3
396.2

10,106
1,320
11,426
152,771

35.7
3.9
39.6
$ 1,258.6

37.8
4.1
41.9
$ 1,333.4

(2) Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less estimated future

(3) PV-10 is a non-GAAP ﬁnancial measure and generally differs from Standardized Measure, the most directly comparable GAAP ﬁnancial measure,

because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties.
We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of
the potential return on investment related to the companies’ properties without regard to the speciﬁc tax characteristics of such entities.
Our PV-10 at December 31, 2017 may be reconciled to our Standardized Measure of discounted future net cash ﬂows at such date by reducing
our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2017
were approximately $74.8 million.

(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5) Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from

the San Miguel formation in Zavala County, Texas.

(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

Technology Used to Establish Reserves

Under current SEC rules, proved reserves are those quantities of oil and natural 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. The term “reasonable certainty” implies a high degree of conﬁdence that the quantities of
oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established
using techniques that have been proven effective by actual production from projects in the same reservoir or
an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable
technology is a grouping of one or more technologies (including computational methods) that have been ﬁeld
tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies

that have been demonstrated to yield results with consistency and repeatability. The technologies and technical
data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs,
core analyses, geologic maps and available pressure and production data, seismic data and well test data.
Reserves for proved developed producing wells were estimated using production performance and material balance
methods. Certain new producing properties with little production history were forecast using a combination of
production performance and analogy to offset production. Non-producing reserves estimates for both developed
and undeveloped properties were forecast using either volumetric and/or analogy methods.

FORM 10-K PART I

2017 ANNUAL REPORT

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity,

accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir
Engineering and Chief Technology Ofﬁcer is primarily responsible for overseeing the preparation of our reserves
estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M
University, is a Licensed Professional Engineer in the State of Texas and has over 40 years of industry experience.
Following the preparation of our reserves estimates, these estimates are audited for their reasonableness
by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Operations and Engineering
Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and
the results of the reserves report and the independent audit of our reserves are reviewed by other members of
our Board of Directors as well.

ACREAGE SUMMARY

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at

December 31, 2017.

Southeast New Mexico/West Texas:

Delaware Basin

South Texas:
Eagle Ford

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley
Area Total (1)

Total

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

100,500

50,600

99,100

63,400

199,600

114,000

27,600

24,900

4,200

4,100

31,800

29,000

16,200
17,600
21,500
149,600

8,600
15,600
19,300
94,800

3,400
3,500
4,000
107,300

3,400
3,000
3,500
71,000

19,600
21,100
25,500
256,900

12,000
18,600
22,800
165,800

(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley

formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest
Louisiana and East Texas.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

UNDEVELOPED ACREAGE EXPIRATION

The following table sets forth the approximate number of gross and net undeveloped acres at December 31,
2017 that will expire over the next four years by operating area unless production is established within the spacing
units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or
continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped
acreage expiring in 2022 and beyond represents an immaterial amount of our overall undeveloped acreage.

Acres Expiring 2018

Acres Expiring 2019

Acres Expiring 2020

Acres Expiring 2021

Gross

Net

Gross

Net

Gross

Net

Gross

Nets

Southeast New Mexico/West Texas:

Delaware Basin (1)

25,600

18,900

14,400

11,300

8,900

7,800

19,000

11,700

South Texas:
Eagle Ford

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley
Area Total (2)
Total

900

700

1,500

1,400

1,600

—

—
—
—
26,500

—
—
—
19,600

300
—
300
16,200

300
—
300
13,000

200
—
200
10,700

200
—
200
9,600

—
—
—
19,000

—
—
—
11,700

(1) Approximately 59% of the acreage expiring in the Delaware Basin in the next four years is associated with our Twin Lakes asset area in northern
Lea County, New Mexico. We expect to hold or extend portions of the expiring acreage through our 2018 drilling activities or by paying an
additional lease bonus, where applicable.

(2) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation.

Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and
East Texas.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective
primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of
the primary term or production from the acreage has been established prior to such date, in which event the lease
will remain in effect until the cessation of production in commercial quantities in most cases. We also have options
to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the
primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our
acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases
expire at the end of their respective terms and production has not been established prior to such date or operations
are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2017, our leases
are primarily fee and state leases with primary terms of three to ﬁve years and federal leases with primary terms
of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both
primary term and royalty interests.

DRILLING RESULTS

The following table summarizes our drilling activity for the years ended December 31, 2017, 2016 and 2015.

Development Wells

Productive
Dry

Exploration Wells

Productive
Dry
Total Wells

Productive
Dry

FORM 10-K PART I

Year Ended December 31,

2017

2016

2015

Gross

Net

Gross

Net

Gross

Net

72
—

33
—

105
—

43.7
—

22.3
—

66.0
—

44
—

23.5
—

53
—

28
—

15.6
—

72
—

39.1
—

28
—

81
—

26.7
—

17.5
—

44.2
—

2017 ANNUAL REPORT

MARKETING AND CUSTOMERS

Our crude oil is generally sold under short-term, extendable and cancellable agreements with unafﬁliated
purchasers based on published price bulletins reﬂecting an established ﬁeld posting price. As a consequence, the
prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with
the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and
down independently of any relationship between the crude oil and natural gas markets. Transportation costs
related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas

produced by us is sold at various delivery points to both unafﬁliated independent marketing companies and
unafﬁliated midstream companies. The prices we receive are calculated based on various pipeline indices. When
there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’
processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids
based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other
negotiated pricing arrangements using then-current market pricing less ﬁxed rate processing, transportation and
fractionation fees.

The prices we receive for our oil and natural gas production ﬂuctuate widely. Factors that, directly or indirectly,
cause price ﬂuctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions,
hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental
regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the
domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions.
Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues,
proﬁtability and cash ﬂows. Short-term disruptions of our oil and natural gas production occur from time to time
due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance
and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities
and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the
Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May
Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and
Financial Obligations.”

For the years ended December 31, 2017, 2016 and 2015, we had four, three and three signiﬁcant purchasers,

respectively, that accounted for approximately 60%, 48% and 59%, respectively, of our total oil, natural gas and
NGL revenues. Due to the nature of the markets for oil, natural gas and NGLs, we do not believe that the loss of any
one of these purchasers would have a material adverse impact on our ﬁnancial condition, results of operations or
cash ﬂows for any signiﬁcant period of time.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

TITLE TO PROPERTIES

We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil

and natural gas industry. We expect that some of our acreage will be obtained through farmout agreements,
term assignments and other contractual arrangements with third parties, the terms of which often will require the
drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in
the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulﬁllment of these
obligations. Our properties are also subject to customary royalty interests, liens incident to ﬁnancing arrangements,
operating agreements, taxes and other burdens that we believe will not materially interfere with the use and
operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting
operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where
required, prior to expiration of various time periods to avoid lease termination. See “Risk Factors — We May Incur
Losses or Costs as a Result of Title Deﬁciencies in the Properties in Which We Invest.”

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject

to customary encumbrances, such as customary interests generally retained in connection with the acquisition of
real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other
burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe
that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use
and operation of these properties in the conduct of our business. In addition, we believe that we have obtained
sufﬁcient right-of-way grants and permits from public authorities and private parties for us to operate our business.

SEASONALITY

Generally, but not always, the demand and price levels for natural gas increase during winter months and
decrease during summer months. To lessen seasonal demand ﬂuctuations, pipelines, utilities, local distribution
companies and industrial users utilize natural gas storage facilities and forward purchase some of their
anticipated winter requirements during the summer. However, increased summertime demand for electricity can
place increased demand on storage volumes. Demand for oil and heating oil 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 where equipment may not be available during periods
of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors —
Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets
Relating to a Particular Area Could Have a Material Impact on Our Business.”

COMPETITION

The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural

gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment
and labor required to drill, complete, operate and develop our properties. We also compete with public and private
midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and
disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in
the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing
arrangements for the services offered. San Mateo competes with other midstream companies that provide similar
services in its areas of operations, and such companies may have legacy relationships with producers in those
areas and may have a longer history of efﬁciency and reliability.

FORM 10-K PART I

2017 ANNUAL REPORT

Many of our competitors have substantially greater ﬁnancial resources, staffs, facilities and other resources.
In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and
regulations more easily than we can, which could adversely affect our competitive position. These competitors
may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas
properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number
of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their
own drilling rigs and hydraulic fracturing equipment.

Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream

services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. We have been conducting ﬁeld operations since
2004 while many of our competitors may have a longer history of operations. Additionally, most of our
competitors have demonstrated the ability to operate through industry cycles.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and

fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the
Oil and Natural Gas Industry Is Intense, Making It More Difﬁcult for Us to Acquire Properties, Market Oil and Natural
Gas, Provide Midstream Services and Secure Trained Personnel.”

REGULATION

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production, midstream and related operations are subject to

extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and
regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden
on the oil and natural gas industry increases our cost of doing business and affects our proﬁtability. Because these
laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are
promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations
to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject
to the same regulatory requirements and restrictions that affect our operations.

Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and

reports concerning operations and impose other requirements relating to the exploration, development and
production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and
natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and
restoration of properties upon which wells are drilled, the prohibition or restriction on venting or ﬂaring natural gas,
the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and
abandonment of wells. Many states restrict production to the market demand for oil and natural gas. Some states
have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some
regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the
rate of ﬂow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and
natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production
and sale of oil, natural gas and NGLs within its jurisdiction.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies
of the states in which we operate. These leases contain various restrictions on access and development and other
requirements that may impede our ability to conduct operations on the acreage represented by these leases.

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms

and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural
gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of
1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Natural gas
gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil
pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act, or the ICA. We believed,
as of February 21, 2018, that the natural gas pipelines in our gathering systems met the traditional tests FERC has
used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and the crude oil pipelines in our
gathering systems met the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility
not subject to FERC jurisdiction. State regulation of natural gas gathering facilities and intrastate crude oil pipeline
facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take
requirements or complaint-based rate regulation.

In 2005, Congress enacted the Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act,
among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate
transparency in the market for the sale or transportation of natural gas in interstate commerce and to signiﬁcantly
increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder.
FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market
manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-
party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate

regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate
natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all
intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any
states in which we operate will not affect our operations in any way that is materially different from our competitors
that are similarly situated.

At February 21, 2018, San Mateo was developing a common carrier pipeline that we expect to be subject to

regulation by FERC under the ICA and the Energy Policy Act of 1992, or EP Act. The ICA and its implementing
regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and
generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly
discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil
pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the
rules and regulations governing these services, to be maintained on ﬁle with FERC and posted publicly. The EP Act
and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates
up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level
if the index is negative.

The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of

transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can
change rates based on an inﬂation index, though other rate mechanisms may be used in speciﬁc circumstances.
Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions,
which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on
our operations.

FORM 10-K PART I

2017 ANNUAL REPORT

In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other

things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or
petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission
may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for
violations thereunder.

The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements
on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the
Hazardous Liquid Pipeline Safety Act, each as amended. In recent years, pursuant to these laws and the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines,
subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public
education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural
gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016,
PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements,
expand assessment and repair requirements in areas with medium population densities and extend regulatory
requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued,
but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear
when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations
that had been sent to the Ofﬁce of the Federal Register, but not yet published, be immediately withdrawn for
further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate
gathering and transmission lines.

Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or

costly safety standards, which could result in increased operating costs or operational delays.

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural

gas products we sell and, for many of our wells, sales and use taxes on signiﬁcant portions of our drilling and
operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction
of hydrocarbons, and additional increases may occur. In addition, from time to time there has been a signiﬁcant
amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals,
including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible
drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our
ﬁnancial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject
to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with
Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could
Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors —
Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net
Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.”

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well
that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing
training programs taught by industry professionals. Although average drilling and completion costs for each area
will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the
total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused
on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling
and completion of our wells and are included in and funded through our normal capital expenditure budget.
A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs
and adversely affect our business and ﬁnancial results. See “Risk Factors — Federal and State Legislation and
Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating
Restrictions or Delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal

regulations and apply industry standard practices for groundwater protection in our operations. These measures are
subject to close supervision by state and federal regulators (including the Bureau of Land Management, or the
BLM, with respect to federal acreage).

Although rare, if the cement and steel casing used in well construction requires remediation, we deal with
these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature
logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate
remedial measures.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of

man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives
that are used in fracturing operations as required by the appropriate governmental agencies. These service
companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect
the environment through rigorous safety procedures, and also work to develop more environmentally friendly
fracturing ﬂuids. We also follow safety procedures and monitor all aspects of our fracturing operations in an attempt
to ensure environmental protection. We do not pump any diesel in the ﬂuid systems of any of our fracture
stimulation procedures.

While current fracture stimulation procedures utilize a signiﬁcant amount of water, we typically recover less
than 10% of this fracture stimulation water before produced salt water becomes a signiﬁcant portion of the ﬂuids
produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated
disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have also
been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling
produced salt water mitigates the need for salt water disposal and also provides cost savings to us.

Environmental Regulation

The exploration, development, production, gathering and processing of oil and natural gas, including the operation

of salt water injection and disposal wells, are subject to various federal, state and local environmental laws
and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and
operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities
are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of
1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response,
Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air
Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA,

FORM 10-K PART I

2017 ANNUAL REPORT

as well as comparable state statutes and regulations. We are also subject to regulations governing the handling,
transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive
materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal ﬁnes
and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally,
these laws and regulations require the acquisition of permits or other governmental authorizations before
undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and
require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with
currently applicable environmental laws and regulations and do not expect that these laws and regulations will
have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude

oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in
the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner
or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several ﬁnancial liability
for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill
that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal
enforcement action.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced
waters, ﬁll materials and other materials into navigable waters. These controls have become more stringent over the
years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge
pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands.
The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination
resulting from such discharges.

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the

original conduct, on various classes of persons that are considered to have contributed to the release of a
“hazardous substance” into the environment. These persons include the owner or operator of the site where
the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances
found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural
resources. In addition, it is not uncommon for neighboring landowners and other third parties to ﬁle claims for
personal injury and property damage allegedly caused by hazardous substances released into the environment.
Although CERCLA generally exempts petroleum from the deﬁnition of hazardous substances, our operations may,
and in all likelihood will, involve the use or handling of materials that are classiﬁed as hazardous substances
under CERCLA.

RCRA and comparable state and local statutes govern the management, including treatment, storage and

disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid
waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes
associated with crude oil and natural gas exploration and production to be classiﬁed as nonhazardous waste.
A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall
within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate
the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modiﬁcations of
this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes,
would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as
well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent
and costly disposal requirements than nonhazardous wastes.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources,
including oil and natural gas production. These laws and any implementing regulations impose stringent air permit
requirements and require us to obtain pre-approval for the construction or modiﬁcation of certain projects or facilities
expected to produce air emissions, or to use speciﬁc equipment or technologies to control emissions. See “Risk
Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Signiﬁcant Costs.”
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.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent
and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely
affect our operations and ﬁnancial condition, as well as those of the oil and natural gas industry in general. For
instance, recent scientiﬁc studies have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
atmosphere. Based on these ﬁndings, the Environmental Protection Agency, or the EPA, has begun adopting and
implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing
provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions
could, and in all likelihood would, require us to incur increased operating costs adversely affecting our proﬁts and
could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and
natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could
Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce while the
Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Signiﬁcant Costs in
Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our
Operations Could Cause Us to Incur Signiﬁcant Costs.”

Underground injection is the subsurface placement of ﬂuid through a well, such as the reinjection of brine
produced and separated from oil and natural gas production. In our industry, underground injection not only allows
us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil
production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary
objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of
ﬂuids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by
underground injection is subject to stricter requirements than the disposal of produced water. As of December 31,
2017, we owned and operated over ﬁfteen underground injection wells and we expect to own and operate similar
wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could
subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation
of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of ﬂawed
well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the
location and operation of underground injection wells. In addition, a number of lawsuits have been ﬁled in some
states alleging that ﬂuid injection or oil and natural gas extraction have caused damage to neighboring properties or
otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators
in some states are seeking to impose additional requirements, including requirements regarding the permitting of
produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells.
For example, on October 28, 2014, the Texas Railroad Commission, or TRC, adopted disposal well rule amendments
designed, among other things, to require applicants for new disposal wells that will receive non-hazardous
produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological
Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square

FORM 10-K PART I

2017 ANNUAL REPORT

miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to
demonstrate that the produced water or other ﬂuids are conﬁned to the disposal zone or if scientiﬁc data indicates
such a disposal well is likely to be, or determined to be, contributing to seismic activity, then TRC may deny,
modify, suspend or terminate the permit application or existing operating permit for that disposal well. TRC has
used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local
legislation and regulations intended to address induced seismic activity in the areas in which we operate could
restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such
activities, which could result in increased costs and additional operating restrictions or delays. We do not expect
these developments to have a material adverse effect on our business, ﬁnancial condition, results of operations
and cash ﬂows.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations,

see “— Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal
regulation as underground injection (unless diesel is a component of the fracturing ﬂuid) under the SDWA. The
process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and
localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely
restricted or prohibited those activities. In addition, separate and apart from the referenced potential connection
between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be
correlated to induced seismicity. The scientiﬁc community and regulatory agencies at all levels are studying the
possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies
have modiﬁed their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for
hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level
imposing any restrictions on the use of hydraulic fracturing, this could have a signiﬁcant impact on our ﬁnancial
condition, results of operations and cash ﬂows. Additional burdens upon hydraulic fracturing, such as reporting or
permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic
fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing
Could Result in Increased Costs and Additional Operating Restrictions or Delays.”

Oil and natural gas exploration and production, operations and other activities have been conducted at some of

our properties by previous owners and operators. Materials from these operations remain on some of the
properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers
of producing properties from whom we acquire the properties against some of the liability for environmental claims
associated with the properties. While we do not believe that costs we incur for compliance with environmental
regulations and remediating previously or currently owned or operated properties will be material, we cannot provide
any assurances that these costs will not result in material expenditures that adversely affect our proﬁtability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing

leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and
environmental compliance. It is also possible that our oil and natural gas operations may require us to manage
NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and
may become concentrated in scale, ﬁlm and sludge in equipment that comes in contact with crude oil and natural
gas production and processing streams. Some states, including Texas, have enacted regulations governing the
handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of
only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others,
the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances,
be attributable to us.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication

Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and
Reauthorization Act and similar state statutes require us to organize information about hazardous materials used,
released or produced in our operations. Certain of this information must be provided to employees, state and local
governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA
workplace standards.

The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant

to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely
affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.
The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of
the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material
restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations
in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling
activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See
“Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws,
Which Could Require Signiﬁcant Expenditures.” Our ability to maximize production from our leases may be
adversely impacted by these restrictions.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that
are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since
these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance.
We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or
that we will not otherwise incur material expenses in connection with environmental laws and regulations in the
future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex
Environmental Laws, Which Could Require Signiﬁcant Expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may

affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement
policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport,
disposal or remediation requirements could have a material adverse effect on our operations and ﬁnancial condition.
We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases
or spills may occur in the course of our operations, and we have no assurance that we will not incur signiﬁcant costs
and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural
resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and
operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance
if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and
environmental risks generally are not fully insurable. If a signiﬁcant accident or other event occurs and is not fully
covered by insurance, it could materially adversely affect our ﬁnancial condition, results of operations and cash ﬂows.

FORM 10-K PART I

2017 ANNUAL REPORT

OFFICE LEASE

Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas
75240. See Note 13 to the consolidated ﬁnancial statements in this Annual Report for more details regarding our
ofﬁce lease. Such information is incorporated herein by reference.

EMPLOYEES

At December 31, 2017, we had 217 full-time employees. We believe that our relationships with our employees

are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the
services of independent consultants and contractors to perform various professional services, particularly in the
areas of geology and geophysics, land, production and midstream operations, construction, design, well site
surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and
accounting services. Independent contractors, at our request, drill all of our wells and usually perform ﬁeld and
on-site production operation services for us, including midstream services, facilities construction, pumping,
maintenance, dispatching, inspection and testing. If signiﬁcant opportunities for company growth arise and require
additional management and professional expertise, we will seek to employ qualiﬁed individuals to ﬁll positions
where that expertise is necessary to develop those opportunities.

AVAILABLE INFORMATION

Our Internet website address is www.matadorresources.com. We make available, free of charge, through our

website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the
charters of our Audit Committee, Strategic Planning and Compensation Committee, Corporate Governance
Committee, Executive Committee and Nominating Committee, and our Code of Ethics and Business Conduct for
Ofﬁcers, Directors and Employees, are available through our website, and we also intend to disclose any
amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive
Ofﬁcer, Chief Financial Ofﬁcer or Chief Accounting Ofﬁcer, on our website. All of these corporate governance
materials are available free of charge and in print to any shareholder who provides a written request to the
Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of
our website are not intended to be incorporated by reference into this Annual Report or any other report or document
we ﬁle and any reference to our website is intended to be an inactive textual reference only.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

ITEM 1A. RISK FACTORS.

RISKS RELATED TO THE OIL AND NATURAL GAS INDUSTRY AND OUR BUSINESS

Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the
Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet
Our Capital Expenditure Requirements and Financial Obligations.

The prices we receive for our oil and natural gas heavily inﬂuence our revenue, proﬁtability, cash ﬂow available
for capital expenditures, access to capital, borrowing capacity under our third amended and restated revolving credit
agreement, as amended (the “Credit Agreement”), and future rate of growth. Oil and natural gas are
commodities and, therefore, their prices are subject to wide ﬂuctuations in response to relatively minor changes in
supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be
volatile in the future. During 2017, the average price of oil was $50.80 per Bbl, based upon the NYMEX West Texas
Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was
$3.02 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery
date. Starting in the ﬁrst quarter of 2017, oil and natural gas prices began to increase from their previous lows.
Oil prices increased 42% from $42.53 per Bbl in late June 2017 to $60.42 per Bbl in late December 2017, and
natural gas prices increased 34% from $2.56 per MMBtu in late February 2017 to $3.42 per MMBtu in mid-May 2017,
but had declined to $2.60 per MMBtu in late December 2017.

Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may
be impacted by declining prices of oil and natural gas. Signiﬁcant price declines caused us to recognize full-cost
ceiling impairments in each of the quarters of 2015 and in the ﬁrst two quarters of 2016, and should prices
decline again, we may recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce
the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our
cash ﬂows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the
Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect
Our Financial Condition.”

The prices we receive for our production, and the levels of our production, depend on numerous factors. These

factors include, but are not limited to, the following:

•

the domestic and foreign supply of, and demand for, oil and natural gas;

the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil
companies relating to oil price and production controls;

the prices and availability of competitors’ supplies of oil and natural gas;

the price and quantity of foreign imports;

the impact of U.S. dollar exchange rates;

• domestic and foreign governmental regulations and taxes;

• speculative trading of oil and natural gas futures contracts;

•

the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural
gas and NGLs;

•

the availability of reﬁning capacity;

FORM 10-K PART I

2017 ANNUAL REPORT

•

the prices and availability of alternative fuel sources;

• weather conditions and natural disasters;

• political conditions in or affecting oil and natural gas producing regions or countries, including the

United States, Middle East, South America and Russia;

•

the continued threat of terrorism and the impact of military action and civil unrest;

• public pressure on, and legislative and regulatory interest within, federal, state and local governments

to stop, signiﬁcantly limit or regulate hydraulic fracturing activities;

•

the level of global oil and natural gas inventories and exploration and production activity;

the impact of energy conservation efforts;

technological advances affecting energy consumption; and

• overall worldwide economic conditions.

These factors make it difﬁcult to predict future commodity price movements with any certainty. Substantially
all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices
and are not pursuant to long-term ﬁxed price contracts. Further, oil and natural gas prices do not necessarily
ﬂuctuate in direct relation to each other.

Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and

natural gas that we can produce economically and could reduce the amount we may borrow under our Credit
Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an
extended period of time, we may elect to delay some of our exploration and development plans for our prospects,
to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics
from such activities or to cease or delay further expansion of our midstream projects, each of which could have
a material adverse effect on our business, ﬁnancial condition, results of operations and reserves. In addition, such
declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be
less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide
additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount
sufﬁcient to cover such excess or repay the deﬁcit in equal installments over a period of six months.

Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital
Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be
Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating

cash ﬂows, contributions from our joint venture partners and potential future borrowings, under our Credit
Agreement or otherwise, may not be sufﬁcient to fund all of our future acquisitions or future capital expenditures.
The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms
we determine to be acceptable.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

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

• our estimated proved oil and natural gas reserves;

•

the amount of oil and natural gas we produce from existing wells;

the prices at which we sell our production;

the costs of developing and producing our oil and natural gas reserves;

the costs of constructing, operating and maintaining our midstream facilities;

• our ability to attract third-party customers for our midstream services;

• our ability to acquire, locate and produce new reserves;

•

the ability and willingness of banks to lend to us; and

• our ability to access the equity and debt capital markets.

In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas,
or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, ﬁnancial
market disruptions, general economic recessions, oil and natural gas industry recessions, large company
bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in
the ﬁnancial and capital markets, has caused ﬁnancial institutions, credit rating agencies and the public to more
closely review the ﬁnancial statements, capital structures and earnings of public companies, including energy
companies. Such events have constrained the capital available to the energy industry in the past, and such events
or similar events could adversely affect our access to funding for our operations in the future.

If our revenues decrease as a result of lower oil and natural gas prices, operating difﬁculties, declines in reserves

or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain
our operations at current levels, further develop and exploit our current properties or invest in certain opportunities.
Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our
properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through
the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream
assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise to meet any increase
in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities
to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors
may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital
through the issuance of new debt securities or additional indebtedness, we may become subject to additional
covenants that restrict our business activities. If we are unable to raise additional capital from available sources at
acceptable terms, our business, ﬁnancial condition and future results of operations could be adversely affected.

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree
of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and ﬁnancial risk, which

precludes us from deﬁnitively predicting the costs involved and time required to reach certain objectives. Our drilling
locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require
substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing
and operating wells are often exceeded and such costs can increase signiﬁcantly due to various complications that
may arise during drilling, completion and operation. Before a well is spud, we may incur signiﬁcant geological,

FORM 10-K PART I

2017 ANNUAL REPORT

geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually produces
commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than
development wells. The analogies we draw from available data from other wells, more fully explored locations or
producing ﬁelds may not be applicable to our drilling locations. If our actual drilling and development costs are
signiﬁcantly more than our estimated costs, we may not be able to continue our operations as proposed and could
be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs
will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate
in wells that are productive, but that do not produce sufﬁcient net revenues to return a proﬁt after drilling, operating
and other costs. There is no way to afﬁrmatively determine in advance of drilling and testing whether any particular
location will yield oil or natural gas in sufﬁcient quantities to recover exploration, drilling and completion costs
or to be economically viable. Even if sufﬁcient amounts of oil or natural gas exist, we may damage the potentially
productive hydrocarbon-bearing formation or experience mechanical difﬁculties while drilling or completing the
well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and
proﬁtability of a well may be negatively affected by a number of additional factors, including the following:

• general economic and industry conditions, including the prices received for oil and natural gas;

• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and

qualiﬁed personnel;

• potential drainage of oil and natural gas from our properties by adjacent operators;

•

the existence or magnitude of faults or unanticipated geological features;

loss of or damage to oilﬁeld development and service tools;

• accidents, equipment failures or mechanical problems;

•

title defects of the underlying properties;

increases in severance taxes;

• adverse weather conditions that delay drilling activities or cause producing wells to be shut in;

• domestic and foreign governmental regulations; and

• proximity to and capacity of gathering, processing and transportation facilities.

Furthermore, our exploration and production operations involve using some of the latest drilling and completion
techniques developed by us, other operators and service providers. For example, risks that we face while drilling and
completing horizontal wells include, but are not limited to, the following:

•

landing our wellbore in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

•

running our casing the entire length of the wellbore;

fracture stimulating the planned number of stages; and

• being able to run tools and other equipment consistently through the horizontal wellbore.

If we do not drill productive and proﬁtable wells in the future, our business, ﬁnancial condition, results of

operations, cash ﬂows and reserves could be materially and adversely affected.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May
Not Be Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production,

gathering, transportation and processing, including:

• natural disasters;

• adverse weather conditions;

•

loss of drilling ﬂuid circulation;

• blowouts where oil or natural gas ﬂows uncontrolled at a wellhead;

• cratering or collapse of the formation;

• pipe or cement leaks, failures or casing collapses;

• damage to pipelines, processing plants and disposal wells and associated facilities;

• ﬁres or explosions;

•

releases of hazardous substances or other waste materials that cause environmental damage;

• pressures or irregularities in formations; and

• equipment failures or accidents.

In addition, there is an inherent risk of incurring signiﬁcant environmental costs and liabilities in the performance of

our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and
wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic
fracturing ﬂuids and historical industry operations and waste disposal practices. Any of these or other similar
occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or
loss of human life, signiﬁcant damage to property, environmental pollution and substantial revenue losses. The
location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas,
commercial business centers and industrial sites, could signiﬁcantly increase the level of damages resulting from
these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including

development and completion risks that are generally not recoverable from third parties or insurance. Pollution
and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could,
therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover,
insurance may not be available in the future at commercially reasonable prices or on commercially reasonable
terms. Changes in the insurance markets due to various factors may make it more difﬁcult for us to obtain certain
types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we
would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not
cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles.
Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds
could have a material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

FORM 10-K PART I

2017 ANNUAL REPORT

Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and
Markets Relating to a Particular Area Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties

in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the
Haynesville shale in Northwest Louisiana and East Texas. In 2015, 2016 and 2017, the vast majority of our capital
expenditures were allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in
2018 will continue to be in the Delaware Basin.

The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our
oil and natural gas production due to signiﬁcant competition for gathering systems, pipelines, processing facilities
and oil, condensate and salt water trucking operations. For example, infrastructure constraints have in the past
required, and may in the future require, us to ﬂare natural gas occasionally, decreasing the volumes sold from our
wells. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or
interruptions of production from our wells in our operating areas caused by transportation capacity constraints or
interruptions, curtailment of production, availability of equipment, facilities, personnel or services, signiﬁcant
governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance.

Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical

storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and
equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely
manner. For example, in recent years the Delaware Basin has experienced periods of severe winter weather
that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in power
outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In
recent years, certain areas of the Delaware Basin have also experienced periods of severe ﬂooding that impacted
our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating
production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly
face these and other challenges posed by severe weather.

Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane
Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational
interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future
storms might cause more severe damage and interruptions or disrupt our ability to market production from our
operating areas, including the Eagle Ford shale and the Delaware Basin.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of

the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they
might have on other companies that have a more diversiﬁed portfolio of properties. For example, our operations in
the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and
requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse
effect on our ﬁnancial condition, results of operations and cash ﬂows.

We May Not Be Able to Generate Sufﬁcient Cash to Service All of Our Indebtedness and May Be
Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May
Not Be Successful.

Our ability to make scheduled payments on or to reﬁnance our indebtedness obligations depends on our

ﬁnancial condition and operating performance, which are subject to prevailing economic and competitive conditions
and certain ﬁnancial, business and other factors beyond our control. We may not be able to maintain a level of
cash ﬂows from operating activities sufﬁcient to permit us to pay the principal, premium, if any, and interest on
our indebtedness.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

If our cash ﬂows and capital resources are insufﬁcient to fund debt service obligations, we may be forced to
reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or reﬁnance
indebtedness. Our ability to restructure or reﬁnance indebtedness will depend on the condition of the capital
markets and our ﬁnancial condition at such time. Any reﬁnancing of indebtedness could be at higher interest rates
and may require us to comply with more onerous covenants, which could further restrict business operations.
The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In
addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would
likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the
absence of sufﬁcient cash ﬂows and capital resources, we could face substantial liquidity problems and might be
required to dispose of material assets or operations to meet debt service and other obligations. Our Credit
Agreement and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets
and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and
the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These
alternative measures may not be successful and may not permit us to meet scheduled debt service obligations,
which could have a material adverse effect on our ﬁnancial condition and results of operations.

We May Incur Additional Indebtedness, Which Could Reduce Our Financial Flexibility, Increase Interest
Expense and Adversely Impact Our Operations and Our Unit Costs.

As of February 21, 2018, the maximum facility amount under the Credit Agreement was $500.0 million and our

elected borrowing commitment was $400.0 million. Borrowings under the Credit Agreement are limited to the
lowest of the borrowing base, maximum facility amount and elected borrowing commitment. At February 21, 2018,
we had available borrowings of approximately $397.9 million under our Credit Agreement (after giving effect to
outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on
the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request
one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured
by our interests in the majority of our oil and natural gas properties, and contains covenants restricting our ability to
incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base
is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required
to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an
amount sufﬁcient to cover such excess or repay the deﬁcit in equal installments over a period of six months. If we
are required to do so, we may not have sufﬁcient funds to fully make such repayments.

In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other

instruments governing our other outstanding indebtedness (including our Credit Agreement), we may incur
signiﬁcant amounts of additional indebtedness, including under our Credit Agreement, through the issuance of
additional notes or otherwise, in order to fund acquisitions, develop our properties or invest in certain opportunities.
Interest rates on such future indebtedness may be higher than current levels, causing our ﬁnancing costs to
increase accordingly.

FORM 10-K PART I

2017 ANNUAL REPORT

A high level of indebtedness could affect our operations in several ways, including the following:

requiring a signiﬁcant portion of our cash ﬂows to be used for servicing our indebtedness;

increasing our vulnerability to general adverse economic and industry conditions;

* placing us at a competitive disadvantage compared to our competitors that are less leveraged and,

therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us
from pursuing;

restricting our ability to obtain additional ﬁnancing in the future for working capital, capital expenditures,
acquisitions and general corporate or other purposes; and

increasing the risk that we may default on our debt obligations.

The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination, and We Are
Subject to Interest Rate Risk under Our Credit Agreement.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by
the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and
June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the
borrowing base once each between scheduled redetermination dates. In addition, our lenders have the ﬂexibility to
reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 21,
2018, our borrowing base was $525.0 million, and we had no outstanding borrowings under, and approximately
$2.1 million in outstanding letters of credit issued pursuant to, the Credit Agreement. As of February 21, 2018, the
maximum facility amount under the Credit Agreement was $500.0 million and our elected borrowing commitment
was $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base,
maximum facility amount and elected borrowing commitment. We could be required to repay a portion of any
outstanding bank debt to the extent that, after a redetermination, our outstanding borrowings at such time
exceeded the redetermined borrowing base. We may not have sufﬁcient funds to make such repayments, which
could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder,
requiring us to negotiate renewals, arrange new ﬁnancing or sell signiﬁcant assets, all of which could have a material
adverse effect on our business and ﬁnancial results.

Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company
borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime
rate for such day or (ii) the Federal Funds Effective Rate (as deﬁned in the Credit Agreement) on such day, plus
0.50% or (iii) the daily adjusting LIBOR rate (as deﬁned in the Credit Agreement) plus 1.0% plus, in each case, an
amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit
Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to
(i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum
rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves
on Eurocurrency Liabilities (as deﬁned in Regulation D of the Board of Governors of the Federal Reserve System)
plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the
Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so
will our interest costs, which may have a material adverse effect on our results of operations and ﬁnancial condition.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and
Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions.

Our Credit Agreement and the indenture governing our senior notes contain, and any future indebtedness we
incur will likely contain, a number of restrictive covenants that impose signiﬁcant operating and ﬁnancial restrictions,
including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of
these agreements include covenants that, among other things, restrict our ability to:

incur or guarantee additional debt or issue certain types of preferred stock;

* pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated

indebtedness;

transfer or sell assets;

* make certain investments;

* create certain liens;

* enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as

deﬁned in the indenture) to us;

* consolidate, merge or transfer all or substantially all of our assets;

* engage in transactions with afﬁliates; and

* create unrestricted subsidiaries.

A breach of any of these covenants could result in an event of default under our Credit Agreement and the
indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt
to EBITDA ratio, which is deﬁned as total debt outstanding divided by a rolling four quarter EBITDA calculation, of
4.25 or less. Low oil and natural gas prices or any decline in the prices of oil or natural gas may adversely impact our
EBITDA, cash ﬂows and debt levels, and therefore our ability to comply with this covenant. Upon the occurrence
of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be
immediately due and payable and all applicable commitments to extend further credit could be terminated. If
indebtedness under our Credit Agreement or indenture is accelerated, there can be no assurance that we will have
sufﬁcient assets to repay such indebtedness. The operating and ﬁnancial restrictions and covenants in these debt
agreements and any future ﬁnancing agreements could adversely affect our ability to ﬁnance future operations or
capital needs or to engage in other business activities.

Our Credit Rating May Be Downgraded, Which Could Reduce Our Financial Flexibility, Increase Interest
Expense and Adversely Impact Our Operations.

As of February 21, 2018, our corporate credit rating from Standard & Poor’s Rating Services was “B” and our

corporate credit rating from Moody’s Investors Service was “B2.” We cannot assure you that our credit ratings
will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating
agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any
indebtedness incurred in the future.

Any increase in our ﬁnancing costs resulting from a credit rating downgrade could adversely affect our ability

to obtain additional ﬁnancing in the future for working capital, capital expenditures, acquisitions and general
corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing
signiﬁcant working capital requirements or otherwise lacked liquidity, our results of operations could be materially
adversely affected.

FORM 10-K PART I

2017 ANNUAL REPORT

We Depend upon Several Signiﬁcant Purchasers for the Sale of Most of Our Oil and Natural Gas Production.
The Loss of One or More of These Purchasers Could, Among Other Factors, Limit Our Access to Suitable
Markets for the Oil and Natural Gas We Produce.

We depend upon several signiﬁcant purchasers for the sale of most of our oil and natural gas production. For the
years ended December 31, 2017, 2016 and 2015, we had four, three and three signiﬁcant purchasers, respectively,
that collectively accounted for approximately 60%, 48% and 59%, respectively, of our total oil, natural gas and
NGL revenues. We cannot assure you that we will continue to have ready access to suitable markets for our future
production. If we lost one or more of these customers and were unable to sell our production to other customers on
terms we consider acceptable, it could materially and adversely affect our business, ﬁnancial condition, results of
operations and cash ﬂows.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and
Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to
Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which
Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including
sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States
or a particular operating area increases, associated costs typically also increase, including those costs related to
drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products
of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become
unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which
may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively
affect our business, ﬁnancial condition, results of operations and cash ﬂows. In addition, should oil and natural
gas prices decline, third-party service providers may face ﬁnancial difﬁculties and be unable to provide services.
A reduction in the number of service providers available to us may negatively impact our ability to retain qualiﬁed
service providers, or obtain such services at costs acceptable to us.

In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing
equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear
of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas ﬁelds characterized
by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew
shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews
were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our
business, ﬁnancial condition, results of operations and cash ﬂows.

If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing
Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable
Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial
Quantities Could Be Impaired.

We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain
sufﬁcient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing,
could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced
severe drought. As a result, we may experience difﬁculty in securing the necessary volumes of water for 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 waste, including, but not limited to,
produced water, drilling ﬂuids and other wastes associated with the exploration, development and production of oil and
natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal,

FORM 10-K PART I

MATADOR RESOURCES COMPANY

storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating
costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all
of which could have an adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

If Regulatory Changes Prevent Our Ability to Continue to Drill Wells in the Manner We Have Been, It Could
Have a Material Adverse Impact on Our Future Production Results.

In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not
pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in
order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation
wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such
wells, the applicable state agency denies or signiﬁcantly delays the permitting of such wells, legislation is enacted
that negatively impacts the current process under which such wells are permitted or litigation challenges the
regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to
drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our
anticipated future production.

Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline,
Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil

and natural gas reserves and production and, therefore, our income and cash ﬂow, are highly dependent on our
success in efﬁciently developing and exploiting our current reserves and economically ﬁnding or acquiring additional
oil and natural gas producing properties. We are currently focusing primarily on increasing our production and
reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we
may have difﬁculty expanding our current production or acquiring new properties in this area and may experience
such difﬁculty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may
no longer be economic, and it will become more difﬁcult to raise the capital necessary to ﬁnance expansion
activities. If we are unable to replace our current and future production, our reserves will decrease, and our business,
ﬁnancial condition, results of operations and cash ﬂows would be adversely affected.

We Conduct a Portion of Our Operations through Joint Ventures, Which Subjects Us to Additional Risks
That Could Have a Material Adverse Effect on the Success of These Operations, Our Financial Position,
Results of Operations or Cash Flows.

We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we

may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a
portion of control with unafﬁliated third parties. If our joint venture partners do not fulﬁll their contractual and other
obligations, the affected joint venture may be unable to operate according to its business plan, and we may be
required to increase our level of ﬁnancial commitment or seek third-party capital, which could dilute our ownership
in the applicable joint venture. If we do not timely meet our ﬁnancial commitments or otherwise comply with our
joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced
or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful
or generate cash ﬂows at the level we have anticipated, or at all. Differences in views among joint venture participants
could also result in delays in business decisions or otherwise, failures to agree on major issues, operational
inefﬁciencies and impasses, litigation or other issues. We provide management functions for San Mateo and may
provide such services for future joint venture arrangements, which may require additional time and attention of
management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a
joint venture’s liabilities. These issues or any other difﬁculties that cause a joint venture to deviate from its original
business plan could have a material adverse effect on our ﬁnancial condition, results of operations and cash ﬂows.

FORM 10-K PART I

2017 ANNUAL REPORT

Our Midstream Operations Are Subject to Operational Risks, Which Could Result in Signiﬁcant Damages
and the Loss of Revenue.

San Mateo owns, and we operate, the Black River Processing Plant. There are signiﬁcant risks associated with

the operation of cryogenic natural gas processing plants. Natural gas and NGLs are volatile and explosive and may
include carcinogens. Damage to or improper operation of a cryogenic natural gas processing plant could result in an
explosion or the discharge of toxic gases, which could result in signiﬁcant damage claims, interrupt a revenue
source and prevent us from processing some or all of the natural gas produced from our wells located in the Rustler
Breaks asset area. Furthermore, if we were unable to process such natural gas, we may be forced to ﬂare natural
gas from, or shut in, the affected wells for an indeﬁnite period of time.

In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities

owned and operated by unafﬁliated third parties. The continuing operation of, and our continuing access to, such
third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines,
plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair,
maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of
receipt or deliveries due to insufﬁcient capacity or because of damage from severe weather conditions or other
operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines signiﬁcantly
increase, its proﬁtability could be reduced. If any such increase in costs occurs, if any of these pipelines or other
midstream facilities become unable to receive, transport or process product, or if the volumes San Mateo gathers,
processes or transports do not meet the product quality requirements of such pipelines or facilities, our and
San Mateo’s revenues and cash ﬂow could be adversely affected.

Because of the Natural Decline in Production in the Regions of San Mateo’s Midstream Operations,
San Mateo’s Long-Term Success Depends on its Ability to Obtain New Sources of Supplies, Which Depends
on Certain Factors Beyond San Mateo’s Control. Any Decrease in Supplies to its Midstream Facilities
Could Adversely Affect San Mateo’s Business and Operating Results.

San Mateo’s midstream facilities are or will be connected to oil and natural gas wells operated by us or by third

parties from which production will naturally decline over time, which means that the cash ﬂows associated with
these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties
are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s
gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new
supplies. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in
part, on the level of successful drilling and production activity near its gathering and transportation systems and
other midstream facilities. San Mateo has no control over the level of third-party activity in the areas of its operations,
the amount of reserves associated with the wells or the rate at which production from a well will decline. In
addition, San Mateo has no control over third-party producers or their drilling or production decisions, which are
affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of
reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and
development costs and the availability and cost of capital.

We Do Not Own All of the Land on Which Our Midstream Assets Are Located, Which Could Disrupt
Our Operations.

We do not own all of the land on which our midstream assets are located, and we are therefore subject to the

possibility of more onerous terms and/or increased costs or royalties to retain necessary land use if we do not
have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the
rights to land owned by third parties and governmental agencies for a speciﬁc period of time. Our loss of these

FORM 10-K PART I

MATADOR RESOURCES COMPANY

rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations
on the affected land or ﬁnd alternative locations for our operations at increased costs, each of which could have a
material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Construction of Midstream Projects Subjects Us to Risks of Construction Delays, Cost Over-Runs,
Limitations on Our Growth and Negative Effects on Our Financial Condition, Results of Operations,
Cash Flows and Liquidity.

From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which

may take a number of months before commercial operation, such as San Mateo’s expansion of the Black River
Processing Plant or the drilling of additional commercial salt water disposal wells and construction of related
facilities. These projects are complex and subject to a number of factors beyond our control, including delays from
third-party landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions,
environmental hazards, ﬁnancing, accidents, weather and other factors. Any delay in the completion of these
projects could have a material adverse effect on our business, results of operations, liquidity and ﬁnancial condition.
The construction of salt water disposal facilities, pipelines and gathering and processing facilities requires the
expenditure of signiﬁcant amounts of capital, which may exceed our estimated costs. Estimating the timing and
expenditures related to these development projects is very complex and subject to variables that can signiﬁcantly
increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and ﬁnancial
condition could be adversely affected. This level of development activity requires signiﬁcant effort from our
management and technical personnel and places additional requirements on our ﬁnancial resources and internal
ﬁnancial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the
skills required to bring complicated projects to successful conclusions.

Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws
That Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business.

The operations of our midstream business, including San Mateo, and 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 that require obtaining and maintaining numerous permits, approvals and certiﬁcations from various federal,
state and local government authorities. Substantial costs may be incurred in order to comply with existing laws
and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new laws
and regulations become applicable to operations, these changes may affect the costs that we pay for such services
or the results of our midstream business, including San Mateo. Similarly, a failure to comply with such laws and
regulations by us or the parties on whom we rely could have a material adverse effect on our business, ﬁnancial
condition, results of operations and cash ﬂows. See “Business — Regulation.”

Our Oil and Natural Gas Reserves Are Estimated and May Not Reﬂect the Actual Volumes of Oil and
Natural Gas We Will Recover, and Signiﬁcant Inaccuracies in These Reserves Estimates or Underlying
Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent

uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production
data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic
assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

the quality and quantity of available data;

the interpretation of that data;

the judgment of the persons preparing the estimate; and

the accuracy of the assumptions used.

FORM 10-K PART I

2017 ANNUAL REPORT

The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of

production history. Due to the limited production history of many of our properties, the estimates of future production
associated with these properties may be subject to greater variance to actual production than would be the case
with properties having a longer production history. As our wells produce over time and more data becomes
available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to
reﬂect new information based upon our actual production history, results of exploration and development, prevailing
oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating

expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that
future production declines in our wells may be greater than we have estimated. Any signiﬁcant variance from our
estimates could materially affect the quantities and present value of our reserves.

The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will
Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash ﬂows included in this Annual Report is the
current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations,
the estimated discounted future net cash ﬂows from proved oil and natural gas reserves are based on current
costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average
of ﬁrst-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the
date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used
for these estimates and will be affected by factors such as:

* actual prices we receive for oil and natural gas;

* actual costs and timing of development and production expenditures;

the amount and timing of actual production; and

* changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for

reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most
appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our
business and the oil and natural gas industry in general.

Approximately 55% of Our Total Proved Reserves at December 31, 2017 Consisted of Undeveloped and
Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At December 31, 2017, approximately 55% of our total proved reserves were undeveloped and less than 1% of

our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing
reserves may never be developed or produced or such reserves may not be developed or produced within the time
periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions,
proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within ﬁve
years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop
such reserves would reduce the present value of our estimated proved undeveloped reserves and future net
revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total
proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices
used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves
as unproved reserves. Any reduction in our proved reserves caused by the reclassiﬁcation of undeveloped or
developed non-producing reserves could materially affect our business, ﬁnancial condition, results of operations
and cash ﬂows.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our Identiﬁed Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to
Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.

Our management team has identiﬁed and scheduled drilling locations in our operating areas over a multi-year
period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas
prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital,
approval by regulators, lease terms and seasonal conditions. The ﬁnal determination on whether to drill any of
these locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some
degree, the results of our drilling activities with respect to our established drilling locations. Because of these
uncertainties, we do not know if the drilling locations we have identiﬁed will be drilled within our expected timeframe,
or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling
locations. Our actual drilling activities may be materially different from our current expectations, which could adversely
affect our business, ﬁnancial condition, results of operations and cash ﬂows.

Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next
Several Years Unless Production Is Established on Units Containing the Acreage.

At December 31, 2017, we had leasehold interests in approximately 53,900 net acres across all of our areas of

interest that are not currently held by production and are subject to leases with primary or renewed terms that
expire prior to 2022. Unless we establish and maintain production, generally in paying quantities, on units containing
these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases
may increase signiﬁcantly, and we may not be able to renew such leases on commercially reasonable terms or
at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and
could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases,
we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ
from our current expectations, which could adversely affect our business, ﬁnancial condition, results of operations
and cash ﬂows.

The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk,
Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our
Results of Operations and Cash Flows.

We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities
where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon
indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically
producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic
and geological data can be expensive to license or obtain and we may not be able to license or obtain such data
at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves
and adversely affect our business, ﬁnancial condition, results of operations and cash ﬂows.

Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difﬁcult for Us to Acquire
Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.

Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to ﬁnd

and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and
to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural
gas and securing trained personnel. Similarly, our midstream business, and particularly the success of San Mateo,
depends in part on our ability to compete with other midstream service companies to attract third-party customers

FORM 10-K PART I

2017 ANNUAL REPORT

to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in
its areas of operations, and such companies may have legacy relationships with producers in those areas and may
have a longer history of efﬁciency and reliability. Also, there is substantial competition for capital available for
investment in the oil and natural gas industry. Many of our competitors possess and employ ﬁnancial, technical and
personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil
and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of
properties and prospects than our ﬁnancial, technical or personnel resources permit. In addition, other companies
may be able to offer better compensation packages to attract and retain qualiﬁed personnel than we are able to offer.
The cost to attract and retain qualiﬁed personnel has increased in recent years due to competition and may increase
substantially in the future. We may not be able to compete successfully in the future in acquiring prospective
reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality
personnel and raising additional capital, which could have a material adverse effect on our business, ﬁnancial
condition, results of operations and cash ﬂows.

Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or
That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.

Our industry is subject to rapid and signiﬁcant advancements in technology, including the introduction of new
products, equipment and services using new technologies and databases. As our 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, many of our 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. We cannot be certain that we will be able to implement
technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use
or that we may implement in the future may become obsolete, and our operations may be adversely affected.

Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability
to Conduct Our Operations.

Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas

interests and acreage and conduct our midstream activities depends on our developing and maintaining close
working relationships with industry participants and on our ability to select and evaluate suitable acquisition
opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our
ability to grow may be impaired.

To develop our business, we endeavor to use the business relationships of our management, board and special
board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other
oil and natural gas companies and service companies, including those that supply equipment and other resources
that we expect to use in our business, as well as midstream companies and certain ﬁnancial institutions. We may not
be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition,
the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we
would not otherwise be inclined to incur or undertake in order to fulﬁll our obligations to these partners or maintain
our relationships. If our strategic relationships are not established or maintained, our business prospects may be
limited, which could diminish our ability to conduct our operations.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The Marketability of Our Production Is Dependent upon Oil, Natural Gas and NGL Gathering, Processing
and Transportation Facilities, and the Unavailability of Satisfactory Oil, Natural Gas and NGL Gathering,
Processing and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue.

The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements

may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a
ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for,
and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability
to market our production depends in substantial part on the availability and capacity of gathering systems,
pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include
those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing
operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless
of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on
acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines
and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to
higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because
of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory
requirements and curtailments of receipt or deliveries due to insufﬁcient capacity or because of damage from
severe weather conditions or other operational issues.

We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines,

gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to
realize revenue from those wells until production arrangements were made to deliver our production to market.
Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain
mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we
may be required to ﬂare natural gas, which would decrease the volumes sold from our wells, and, in certain
circumstances, would require us to pay royalties on such ﬂared natural gas.

The disruption of our or third-party facilities due to maintenance, weather or other factors could negatively impact
our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines
signiﬁcantly increase, our proﬁtability could be reduced. Third parties control when or if their facilities are restored
and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions
and capacity and infrastructure constraints associated with natural gas production, which has, among other things,
required us to ﬂare natural gas occasionally. While we have entered into natural gas processing and transportation
agreements covering the anticipated natural gas production from a signiﬁcant portion of our Delaware Basin acreage
in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these
issues completely, and we may be required to pay deﬁciency payments under such agreements if we do not meet
the gathering, disposal or processing commitments, as applicable. We may experience similar interruptions and
processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other
liquids-rich plays in the Delaware Basin in 2018. If we were required to shut in our production or ﬂare our natural gas
for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities,
it could have a material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Financial Difﬁculties Encountered by Our Oil and Natural Gas Purchasers, Third-Party Operators or
Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration
and Development of Our Prospects and Assets.

We derive most of our revenues from the sale of our oil, natural gas and NGLs to unafﬁliated third-party

purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to
the concentration of our oil and natural gas receivables with several signiﬁcant customers. We cannot predict the

FORM 10-K PART I

2017 ANNUAL REPORT

extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices
remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays
in payments from our purchasers caused by ﬁnancial problems encountered by them will have an immediate
negative effect on our results of operations and cash ﬂows.

Liquidity and cash ﬂow problems encountered by our working interest co-owners or the third-party operators of

our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our
working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become
due. In the case of a farmout party, we would have to ﬁnd a new farmout party or obtain alternative funding in
order to complete the exploration and development of the prospects subject to a farmout agreement. In the case
of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.
If we are not able to obtain the capital necessary to fund either of these contingencies or ﬁnd a new farmout party,
our results of operations and cash ﬂows could be negatively affected.

We Have Entered into Certain Long-Term Contracts That Require Us to Pay Fees to Our Service Providers
Based on Minimum Volumes Regardless of Actual Volume Throughput and That May Limit Our Ability to
Use Other Service Providers.

In connection with the sale of the Loving County Processing System in October 2015, we entered into a 15-year

ﬁxed-fee natural gas gathering and processing agreement covering the anticipated natural gas production from
a signiﬁcant portion of our acreage in the Wolf asset area in the Delaware Basin (the “Wolf Gathering Agreement”).
In addition, in connection with the formation of San Mateo, we entered into certain 15-year ﬁxed-fee natural gas,
oil and salt water gathering agreements and salt water disposal agreements covering the Rustler Breaks and Wolf
asset areas and a natural gas processing agreement covering the Rustler Breaks asset area (collectively, the
“Joint Venture Agreements”). We have also entered into an 18-year ﬁxed-fee natural gas transportation agreement
relating to transportation of a portion of the residue natural gas from the tailgate of the Black River Processing Plant.
In each of these agreements we have provided certain minimum volume commitments. Lower commodity prices
may lead to reductions in our drilling program, which may result in insufﬁcient production to fulﬁll our obligations
under these agreements. In addition, in late 2017, we also entered into a ﬁxed-fee NGL transportation and fractionation
agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing
Plant. These agreements obligate us to pay fees on minimum volumes to our service providers (including San Mateo)
regardless of actual throughput. As of December 31, 2017, our long-term contractual obligations under agreements
with minimum volume commitments, including the Joint Venture Agreements, totaled approximately $432.8 million
over the terms of the agreements. If we have insufﬁcient production to meet the minimum volumes, our cash
ﬂow from operations will be reduced, which may require us to reduce or delay our planned investments and capital
expenditures or seek alternative means of ﬁnancing, all of which may have a material adverse effect on our
results of operations.

Pursuant to the Wolf Gathering Agreement, the Joint Venture Agreements and other agreements with

midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to
EnLink, San Mateo and other midstream companies, as applicable. As a result, we will be limited in our ability to
use other gathering, processing, disposal and transportation service providers, even if such service providers are
able to offer us more favorable pricing or more efﬁcient service.

We Have Limited Control over Activities on Properties We Do Not Operate.

We are not the operator on some of our properties, particularly in the Haynesville shale. We also have other

non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas.
Because we are not the operator for these properties, our ability to exercise inﬂuence over the operations of these
properties or their associated costs is limited. Our dependence on the operators and other working interest owners

FORM 10-K PART I

MATADOR RESOURCES COMPANY

of these projects and our limited ability to inﬂuence operations and associated costs, or control the risks, could
materially and adversely affect the drilling results, reserves and future cash ﬂows from these properties. The
success and timing of our drilling and development activities on properties operated by others therefore depends
upon a number of factors, including:

the timing and amount of capital expenditures;

the operator’s expertise and ﬁnancial resources;

the rate of production of reserves, if any;

* approval of other participants in drilling wells; and

* selection and implementation or execution of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited inﬂuence on when,

how and at what pace our properties in those areas are developed. Further, the operators of those properties may
experience ﬁnancial problems in the future or may sell their rights to another operator not of our choosing, both
of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the
operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these
properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production
and associated revenues from these properties until the operator elects to return them to production.

A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete
Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider
economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition
for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and
completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity
ﬁnancing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to
continue to invest in operations and ﬁnancial and management information systems and to attract, retain, motivate
and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties,
our earnings could be reduced and our growth could be restricted.

In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The

inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions
and current operations, and could negatively impact our results of operations and growth potential. Members of our
senior management team may be required to devote considerable amounts of time to the integration process,
which will decrease the time they will have to manage our business.

Furthermore, our decision to acquire properties that are substantially different in operating or geologic

characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in
such areas. Our ﬁnancial condition, results of operations and cash ﬂows may ﬂuctuate signiﬁcantly from period
to period as a result of the completion of signiﬁcant acquisitions during particular periods.

We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or
increase substantially our capitalization to ﬁnance these acquisitions through the use of cash on hand, the issuance of
debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and
natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement and the indenture
governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were
to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer
dilution of their interests.

FORM 10-K PART I

2017 ANNUAL REPORT

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know about or
That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely
Affect Our Results of Operations.

Before acquiring oil and natural gas properties, we assess the potential reserves, future oil and natural gas prices,

operating costs, potential environmental liabilities and other factors relating to the properties. However, our review
involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not
discover all existing or potential problems associated with the properties we buy. We may not become sufﬁciently
familiar with the properties to assess fully their deﬁciencies and capabilities. We do not generally perform
inspections on every well or property, and we may not be able to observe mechanical and environmental problems
even when we conduct an inspection. The seller may not be willing or ﬁnancially able to give us contractual
protection against any identiﬁed problems, and we may decide to assume environmental and other liabilities in
connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about
or that we did not assess correctly, our ﬁnancial condition, results of operations and cash ﬂows could be adversely
affected as we settle claims and incur cleanup costs related to these liabilities.

Our Ability to Complete Dispositions of Assets, or Interests in Assets, May Be Subject to Factors Beyond
Our Control, and in Certain Cases We May Be Required to Retain Liabilities for Certain Matters.

From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the
asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic
assets, the disposition of which would increase capital resources available for other activities and create
organizational and operational efﬁciencies. Various factors could materially affect our ability to dispose of such
interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of
governmental agencies or third parties and the availability of purchasers willing to acquire the interests or purchase
the nonstrategic assets on terms and at prices acceptable to us.

Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of

litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained
liability or indemniﬁcation obligation may be difﬁcult to quantify at the time of the transaction and ultimately may be
material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees
or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may
remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails
to perform these obligations.

We May Incur Losses or Costs as a Result of Title Deﬁciencies in the Properties in Which We Invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has

been purchased in error from a person who is not the mineral interest owner or if the property has other title
deﬁciencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance,
all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant
to the terms of the lease prior to the discovery of the title defect would be lost.

It is not our practice in all acquisitions of oil and natural gas leases, or undivided interests in oil and natural gas
leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under
lease or already placed under lease. Rather, in certain acquisitions we rely upon the judgment of oil and natural
gas lease brokers and/or landmen who perform the ﬁeld work by examining records in the appropriate governmental
ofﬁce before attempting to acquire a lease on a speciﬁc mineral interest.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the
well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure
there are no obvious deﬁciencies in title to the well. Frequently, as a result of such examinations, certain curative
work must be done to correct deﬁciencies in the marketability of the title, and such title review and curative work
entails expense, which may be signiﬁcant and difﬁcult to accurately predict. Our failure to cure any title defects may
adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss
from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than
developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which
we hold an interest, we will suffer a ﬁnancial loss that could adversely affect our ﬁnancial condition, results of
operations and cash ﬂows.

We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules
and These Write-Downs Could Adversely Affect Our Financial Condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas properties
when oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have:

* downward adjustments to our estimated proved reserves;

increases in our estimates of development costs; or

* deterioration in our exploration and development results.

We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules.
Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may
not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and
costs projected forward from a single point in time, of estimated future after-tax net cash ﬂows from proved
reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred
income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the
period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods.
A write-down does not affect net cash ﬂows from operating activities, liquidity or capital resources, but it does
reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the
value of our common stock.

Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in
Financial Losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily

“costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with
downside price protection through the purchase of a put option, which is ﬁnanced through the sale of a call option.
Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially
“costless” to us. In the case of a costless collar, the put option and the call option have different ﬁxed price components.
In a swap contract, a ﬂoating price is exchanged for a ﬁxed price over the speciﬁed period, providing downside
price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a ﬁxed
price in the case of swaps so as to mitigate price volatility and increase the predictability of cash ﬂows. These
transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by
the call option or swap as applicable, and may offer protection if prices fall below the minimum price established
by the put option or swap, as applicable, only to the extent of the volumes then hedged.

FORM 10-K PART I

2017 ANNUAL REPORT

In addition, hedging transactions may expose us to the risk of ﬁnancial loss in certain other circumstances,
including instances in which our production is less than expected or the counterparties to our put and call option or
swap contracts fail to perform under the contracts. Disruptions in the ﬁnancial markets could lead to sudden
changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We
are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts
with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending
upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have
been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difﬁcult
and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and
we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ
from those that we have used in the past, and neither the continued application of our current strategies nor our
use of different hedging strategies may be successful. As of February 21, 2018, we had approximately 55% and
40% of our estimated remaining 2018 oil and natural gas production, respectively, hedged. We currently have no
hedges in place for NGLs and no hedges in place beyond 2018 for oil and natural gas.

An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and
the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial
Condition, Results of Operations and Cash Flows.

The prices that we receive for our oil and natural gas production sometimes reﬂect a discount to the relevant

benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the
benchmark prices and the prices we receive is called a differential. Increases in the differential between the
benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business,
ﬁnancial condition, results of operations and cash ﬂows. For example, we sell much of our natural gas produced
from the Delaware Basin at the Waha Hub. The differential between the Waha Hub index and the Henry Hub index
has recently increased as compared to prior years. We have derivative contracts covering the amount of the
basis differentials we experience with respect to only a portion of our production. As such, we will be exposed to
any increase in such differentials not covered by such contracts.

We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which
Could Require Signiﬁcant Expenditures.

The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas

in the United States are subject to many federal, state and local laws, rules and regulations, including complex
environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports
concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental
matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may
be required to make large expenditures that could materially adversely affect our ﬁnancial condition, results
of operations and cash ﬂows. In addition to expenditures required in order for us to comply with such laws and
regulations, these expenditures could also include payments for:

* personal injuries;

* property damage;

* containment and clean-up of oil and other spills;

* management and disposal of hazardous materials;

remediation, clean-up costs and natural resource damages; and

* other environmental damages.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure

to comply with these laws and regulations also may result in the suspension or termination of our operations and
subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or
other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the
changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability
on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We
may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or
regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by
numerous federal and state agencies. In addition, private parties, including the owners of properties upon which
our wells are drilled or facilities are located, or the owners of properties adjacent to or in close proximity to those
properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws,
rules and regulations. For example, a number of lawsuits have been ﬁled in some states alleging that ﬂuid injection
or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and
federal rules regulating waste disposal.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for

obtaining environmental assessments, environmental impact statements and/or plans of development before
commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our
operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed
to protect various wildlife. The designation of previously unprotected species as threatened or endangered species
could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs
arising from species protection measures or result in limitations on our exploration and production and midstream
activities, each of which could have an adverse impact on our ability to develop and produce our reserves.

We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or
Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect
to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation,
Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently

available to oil and natural gas exploration and production companies. Such changes include, but are not limited to,
(i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of
current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S.
production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical
costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the
United States. The recently enacted Tax Cuts and Jobs Act did not include any of these proposals, except for the
repeal of the domestic manufacturing tax deduction for oil and gas companies. However, it is possible that such
provisions could be proposed in the future. The passage of any legislation or any other similar change in U.S. federal
income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas
exploration and production activities and could negatively impact our ﬁnancial condition, results of operations and
cash ﬂows.

FORM 10-K PART I

2017 ANNUAL REPORT

Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions
and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.

The recently enacted Tax Cuts and Jobs Act includes provisions which, beginning in 2018, generally will (i) limit
our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our
business interest income) for the year, (ii) permit us to offset only 80% (rather than 100%) of our taxable income
with net operating losses we generate after 2017 and (iii) limit our ability to deduct certain elements of executive
compensation. Interest expense and net operating losses subject to these limitations may be carried forward by
us for use in later years, subject to these limitations. Additionally, the Tax Cuts and Jobs Act repealed the domestic
manufacturing tax deduction for oil and natural gas companies. These tax law changes could have the effect of
causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain
cases, could cause us to incur income tax liability that we might otherwise not have incurred, in the absence of
these tax law changes.

Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in
Increased Costs and Additional Operating Restrictions or Delays.

Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into
rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells
in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the
Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated
at the state and local level through permitting and compliance requirements. Federal, state and local-level laws or
regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been
proposed or implemented. In past sessions, Congress has considered, but did not pass, legislation to amend the
SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations
using ﬂuids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas
companies in the hydraulic fracturing process. Also at the federal level, the BLM issued ﬁnal rules to regulate hydraulic
fracturing on federal lands in March 2015, although these rules were rescinded by rule in December 2017.

In addition, a number of states and local regulatory authorities are considering or have implemented more
stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that
effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar
operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities
combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing.
Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of
legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information
regarding the substances used in the hydraulic fracturing process. Moreover, while the scientiﬁc community and
regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity
and induced seismicity, some state regulatory agencies have modiﬁed their regulations or guidance to regulate
potential causes of induced seismicity, including ﬂuid injection or oil and natural gas extraction.

The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or

prohibiting, the hydraulic fracturing process could make it more difﬁcult to complete oil and natural gas wells in
unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal
legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to
additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which
could adversely affect our business and results of operations.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The Potential Adoption of Federal, State and Local Legislation and Regulations Intended to Address
Potential Induced Seismic Activity in the Areas in Which We Operate Could Restrict Our Drilling and
Production Activities, as well as Our Ability to Dispose of Produced Water Gathered from Such Activities,
Which Could Decrease San Mateo’s Revenues and Result in Increased Costs and Additional Operating
Restrictions or Delays.

State and federal regulatory agencies recently have focused on a possible connection between the operation of

injection wells used for oil and natural gas waste disposal and the increased occurrence of seismic activity. When
caused by human activity, such events are called induced seismicity. Regulatory agencies at all levels are continuing
to study the possible linkage between oil and natural gas activity and induced seismicity. In addition, a number
of lawsuits have been ﬁled in some states alleging that ﬂuid injection or oil and natural gas extraction have caused
damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In
response to these concerns, regulators in some states are seeking to impose additional requirements, including
requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship
between seismicity and the use of such wells.

While the scientiﬁc community and regulatory agencies at all levels are continuing to study the possible linkage
between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas, have
modiﬁed their regulations or guidance to mitigate potential causes of induced seismicity.

Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our
operations and could lead to operational delays or increased operating costs. Additional regulation and attention
given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities.
We and San Mateo dispose of large volumes of produced water gathered from our or third parties’ drilling and
production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing
such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal
requirements are subject to change, which could result in the imposition of more stringent operating constraints or
new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental
authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or
regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could
decrease San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.

Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating
Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce while the Physical Effects of
Climate Change Could Disrupt Our Production and Cause Us to Incur Signiﬁcant Costs in Preparing for or
Responding to Those Effects.

We believe it is likely that scientiﬁc and political attention to issues concerning the extent, causes of and

responsibility for climate change will continue, with the potential for further regulations and litigation that could affect
our operations. Our operations result in greenhouse gas emissions. The EPA has published its ﬁnal ﬁndings that
emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and
welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s
atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a
cap and trade program, but that legislation did not pass. Further, various states have considered or adopted
legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally,
in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the
creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016,

FORM 10-K PART I

2017 ANNUAL REPORT

requires countries to review and “represent a progression” in their intended nationally determined contributions,
which set greenhouse gas emission reduction goals, every ﬁve years beginning in 2020. In June 2017, the Trump
administration announced its intention for the United States to withdraw from the Paris Agreement. Pursuant to
the terms of the Paris Agreement, the earliest date the United States can withdraw is November 2020. The EPA has
also ﬁnalized regulations targeting new sources of methane emissions from the oil and natural gas industry. Any
future international agreements, federal or state laws or implementing regulations that may be adopted to address
greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs,
adversely affecting our proﬁts, and could adversely affect demand for the oil and natural gas we produce,
depressing the prices we receive for oil and natural gas.

In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have
an effect on the severity of weather (including hurricanes and ﬂoods), sea levels, the arability of farmland and water
availability and quality. If such effects were to occur, there is the potential for our exploration and production
operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful
winds or rising waters in low-lying areas, disruption of our production, less efﬁcient or non-routine operating
practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects.
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 us or other 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. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable
to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to
Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to
Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate
change or other drought conditions occur, our ability to obtain water of a sufﬁcient quality and quantity could be
impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

New Regulations on All Emissions from Our Operations Could Cause Us to Incur Signiﬁcant Costs.

In recent years, the EPA issued ﬁnal rules to subject oil and natural gas operations to regulation under the
New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or
NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The
EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors,
controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules
have required changes to our operations, including the installation of new equipment to control emissions. The EPA
ﬁnalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. This more
stringent ozone NAAQS could result in additional areas being designated as non-attainment, including areas in which
we operate, which may result in an increase in costs for emission controls and requirements for additional
monitoring and testing, as well as a more cumbersome permitting process. The EPA anticipates promulgating ﬁnal
area designations under the new standard in the ﬁrst half of 2018. Although there may be an adverse ﬁnancial
impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated
with this revised regulation, the extent and magnitude of that impact cannot be reliably or accurately estimated due
to the present uncertainty regarding any additional measures and how they will be implemented. The EPA’s ﬁnal
rule has been judicially challenged by both industry and other interested parties, and the outcome of this litigation
may also impact implementation and revisions to the rule. In November 2016, the Department of the Interior issued

FORM 10-K PART I

MATADOR RESOURCES COMPANY

ﬁnal rules relating to the venting, ﬂaring and leaking of natural gas by oil and natural gas producers who operate
on federal and Indian lands. The rules limit routine ﬂaring of natural gas, require the payment of royalties on avoidable
natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair.
The BLM issued a two-year stay of these requirements in December 2017 and has indicated that the requirements
could be rescinded or signiﬁcantly revised in the future. Litigation challenging the delay has been ﬁled by certain
environmental groups and states. In February 2018, a federal district judge in California issued a preliminary
injunction requiring the BLM to enforce these regulations. If not withdrawn or signiﬁcantly revised, these rules are
expected to result in an increase to our operating costs and changes in our operations. In addition, several states are
pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and
natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the
oil and natural gas industry remain a possibility and could result in increased compliance costs on our operations.

We May Incur Signiﬁcant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations.

Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management.

For instance, the Department of Transportation, through PHMSA, has established a series of rules that require
pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil)
pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. PHMSA also recently
proposed rulemaking that would expand existing integrity management requirements to natural gas transmission
and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline
integrity management requirements may occur in the future. At this time, we cannot predict the cost of such
requirements, but they could be signiﬁcant. Moreover, violations of pipeline safety regulations can result in the
imposition of signiﬁcant penalties.

Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with

pipeline integrity laws and other pipeline safety regulations issued by state agencies such as TRC could result
in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws
and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future
compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations
or ﬁnancial position.

A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy
by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and
Operating Expenses to Increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We
believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish
a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated
transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the
classiﬁcation and regulation of our gathering facilities are subject to change based on future determinations by FERC,
the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under
the ICA. We believe that certain of our crude oil pipelines meet the traditional tests FERC has used to establish a
pipeline’s status as an intrastate facility not subject to FERC regulation. However, whether a pipeline provides
service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case
basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change
in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets,
which may cause our revenues to decline and operating expenses to increase.

FORM 10-K PART I

2017 ANNUAL REPORT

The Rates of Our Regulated Assets are Subject to Review and Reporting by Federal Regulators, Which
Could Adversely Affect Our Revenues.

Our proposed crude oil pipelines in New Mexico to be developed and owned by San Mateo are expected to
transport crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines
that transport crude oil in interstate commerce. If a party with an economic interest were to ﬁle either a complaint
against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation
of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found to be
in excess of levels justiﬁed by our cost of service, FERC could order us to reduce our rates, and to refund the amount
by which the rate increases were determined to be excessive, plus interest. If our existing rates were found to be
in excess of our cost of services, we could be ordered to refund the excess we collected for up to two years prior
to the date of the ﬁling of the complaint challenging the rates, and we could be ordered to reduce our rates
prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions
of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found
that our rates exceeded levels justiﬁed by our cost of service, the state commission could order us to reduce our
rates. Any such reductions may result in lower revenues and cash ﬂows. We anticipate that the shippers on our
FERC-regulated pipeline will agree not to challenge, or to cause others to challenge or assist others in challenging,
our tariff rates in effect during the terms of their respective agreements; however, other current or future shippers
may still challenge our tariff rates.

In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues
received on our proposed interstate oil pipeline and any other natural gas or crude oil pipeline that is determined to
be under the jurisdiction of FERC.

Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders,
We Could Be Subject to Substantial Penalties and Fines.

Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current
violations of up to approximately $1.2 million per day for each violation and disgorgement of proﬁts associated with
any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for
inﬂation. The nature of our gathering facilities is such that we have not yet been regulated by FERC. San Mateo’s
proposed crude oil pipelines in New Mexico are expected to transport crude oil in interstate commerce and be
subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or
adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the
future could subject us to civil penalty liability.

The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge
Risks Associated with Our Business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things,

established federal oversight and regulation of certain derivative products, including commodity hedges of the
type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to
promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has ﬁnalized certain
regulations, others remain to be ﬁnalized or implemented, and it is not possible at this time to predict when, or if,
this will be accomplished.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the

major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated
by the United States District Court for the District of Columbia in September 2012. However, in November 2013,
the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps
contracts for or linked to certain physical commodities, subject to exceptions for certain bona ﬁde hedging
transactions. During the last quarter of 2016, the CFTC decided to re-propose, rather than ﬁnalize, certain regulations,
including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed
position limit regulations. As these new position limit rules are not yet ﬁnal, the impact of those provisions on us
is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our
derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this
legislation could have a substantial impact on our counterparties and may increase the cost of our derivative
arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could
increase, which would increase the volatility of revenues and may decrease the amount of credit available to
us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash ﬂows,
which could adversely affect our ability to make capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which
some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural
gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing
regulations is to lower commodity prices.

Any of these consequences could have a material adverse effect on our business, ﬁnancial condition and results

of operations.

We May Have Difﬁculty Managing Growth in Our Business, Which Could Have a Material Adverse Effect
on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our
Business Plan in a Timely Fashion.

Because of our size, growth in accordance with our business plans, if achieved, will place a signiﬁcant strain
on our ﬁnancial, technical, operational and management resources. As and when we expand our activities, including
our midstream business, through San Mateo or otherwise, there will be additional demands on our ﬁnancial,
technical and management resources. The failure to continue to upgrade our technical, administrative, operating and
ﬁnancial control systems or the occurrence of unexpected expansion difﬁculties, including the inability to recruit
and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys
and ﬁnancial and accounting professionals, could have a material adverse effect on our business, ﬁnancial condition,
results of operations and cash ﬂows and our ability to execute our business plan in a timely fashion.

Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our
Chairman and Chief Executive Ofﬁcer, Management and Technical Team, the Members of Our Board
of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or
Special Board Advisor Could Disrupt Our Business Operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our
management and the success of our technical team in identifying, evaluating and developing prospects and
reserves. Our performance and success are dependent to a large extent on the efforts and continued employment
of our management and technical personnel, including our Chairman and Chief Executive Ofﬁcer, Joseph Wm.
Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities,
and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and

FORM 10-K PART I

2017 ANNUAL REPORT

other key personnel. However, these employment agreements do not ensure that these individuals will remain in
our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and
if they are not adequately replaced, our business operations could be adversely affected. With the exception of
Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in
our business and the determination of our operational strategies. Members of our Board of Directors work closely
with management to identify potential prospects, acquisitions and areas for further development. If any of our
directors resign or become unable to continue in their present role, it may be difﬁcult to ﬁnd replacements with the
same knowledge and experience and, as a result, our operations may be adversely affected.

In addition, our board consults regularly with our special advisors regarding our business and the evaluation,
exploration, engineering and development of our prospects. Due to the knowledge and experience of our special
advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions
and development. If any of our special advisors resign or become unable to continue in their present role, our
operations may be adversely affected.

A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or
Financial Loss.

The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development,

production, gathering, processing and ﬁnancial activities. We depend on digital technology to, among other things,
estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering,
processing and disposal operations, process and record ﬁnancial and operating data and communicate with
employees, shareholders, royalty owners and other third-party industry participants. If any of such programs or
systems were to fail or create erroneous information in our hardware or software network infrastructure or we
were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include ﬁnancial losses
and the inability to engage in any of the aforementioned activities. Any such consequence could have a material
adverse effect on our business.

While we have not experienced any material losses due to cyber incidents, we may suffer such losses in the
future. If our systems for protecting against cyber incidents prove to be insufﬁcient, we could be adversely affected
by unauthorized access to proprietary information, which could lead to data corruption, communication interruption,
exposure of our or third parties’ conﬁdential or proprietary information, operational disruptions or ﬁnancial loss.
As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and
enhance our protective systems or to investigate and remediate any vulnerabilities.

RISKS RELATING TO OUR COMMON STOCK

The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future.

Our stock price has experienced volatility and could vary signiﬁcantly as a result of a number of factors. In 2017,

our stock price ﬂuctuated between a high of $31.59 and a low of $20.13. In addition, the trading volume of our
common stock may continue to ﬂuctuate and cause signiﬁcant price variations to occur. In the event of a drop in the
market price of our common stock, you could lose a substantial part or all of your investment in our common stock.
In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the
operating performance of particular companies. These broad market ﬂuctuations may adversely affect the trading
price of our common stock.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Factors that could affect our stock price or result in ﬂuctuations in the market price or trading volume of our

common stock include:

• our actual or anticipated operating and ﬁnancial performance and drilling locations, including oil and natural

gas reserves estimates;

• quarterly variations in the rate of growth of our ﬁnancial indicators, such as net income per share, net

income and cash ﬂows, or those of companies that are perceived to be similar to us;

• changes in revenue, cash ﬂows or earnings estimates or publication of reports by equity research analysts;

• speculation in the press or investment community;

• announcement or consummation of acquisitions or dispositions by us;

• public reaction to our press releases, announcements and ﬁlings with the SEC;

• sales of our common stock by us or shareholders, or the perception that such sales may occur;

• general ﬁnancial market conditions and oil and natural gas industry market conditions, including ﬂuctuations

in the price of oil, natural gas and NGLs;

•

the realization of any of the risk factors presented in this Annual Report;

the recruitment or departure of key personnel;

• commencement of or involvement in litigation;

•

the success of our exploration and development operations, our midstream business (including San Mateo)
and the marketing of any oil, natural gas and NGLs we produce;

• changes in market valuations of companies similar to ours; and

• domestic and international economic, legal and regulatory factors unrelated to our performance.

If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to
Accurately Report Our Financial Results Could Be Adversely Affected.

As a public company with listed equity securities, we are required to comply with laws, regulations and

requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the
SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difﬁcult
and costly and occupies a signiﬁcant amount of time of our Board of Directors and management.

Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over ﬁnancial reporting. Our
efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls
over our ﬁnancial processes and reporting in the future and comply with the certiﬁcation and reporting obligations
under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls
and disclosure controls will prevent all possible error or all fraud. Further, our remediation efforts may not enable
us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material
misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject
us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls
could also cause investors to lose conﬁdence in our reported ﬁnancial information and adversely affect our business
and our stock price.

FORM 10-K PART I

2017 ANNUAL REPORT

We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares
of Our Common Stock.

We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.

Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other
things, our earnings, ﬁnancial condition, capital requirements, level of indebtedness, statutory and contractual
restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems
relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience
substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement and the
indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our
common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash ﬂow
from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid.

Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings
of Our Common Stock by Us Could Depress the Price of Our Common Stock.

The market price of our common stock could decline as a result of sales of a large number of shares of our
common stock in the market, including shares of equity or debt securities convertible into common stock, and the
perception that these sales could occur may also depress the market price of our common stock. If our existing
shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the
trading price of our common stock could decline signiﬁcantly. Sales of our common stock may make it more difﬁcult
for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could
also cause our stock price to decrease and make it more difﬁcult for you to sell shares of our common stock.

We may also sell or issue additional shares of common stock or equity or debt securities convertible into

common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future
issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales
of shares of our common stock or convertible securities would have on the market price of our common stock.

Provisions of Our Certiﬁcate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects
That Could Prevent a Change in Control Even if It Might Be Beneﬁcial to Our Shareholders.

Our certiﬁcate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger

or acquisition that our shareholders may consider favorable. These provisions include:

• authorization for our Board of Directors to issue preferred stock without shareholder approval;

• a classiﬁed Board of Directors so that not all members of our Board of Directors are elected at one time;

•

the prohibition of cumulative voting in the election of directors; and

• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our

outstanding shares of common stock.

Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us,

which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneﬁcially
owns more than 20% of our voting stock, or an afﬁliated shareholder, cannot acquire us for a period of three years
from the date this person became an afﬁliated shareholder, unless various conditions are met, such as approval
of the transaction by our Board of Directors before this person became an afﬁliated shareholder or approval of the
holders of at least two-thirds of our outstanding voting shares not beneﬁcially owned by the afﬁliated shareholder.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our Directors and Executive Ofﬁcers Own a Signiﬁcant Percentage of Our Equity, Which Could Give Them
Inﬂuence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive
Ofﬁcers Could Differ from Other Shareholders.

As of February 21, 2018, our directors and executive ofﬁcers beneﬁcially owned approximately 11% of our

outstanding common stock. These shareholders could inﬂuence or control to some degree the outcome of matters
requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certiﬁcate
of formation or bylaws and the approval of mergers and other signiﬁcant corporate transactions. Their inﬂuence or
control of the Company may have the effect of delaying or preventing a change of control of the Company and
may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest
in our common stock, our directors and executive ofﬁcers may be able to remain entrenched in their positions.

Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of
Holders of Our Common Stock and Make a Change of Control of the Company More Difﬁcult Even if It Might
Beneﬁt Our Shareholders.

Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to ﬁx the voting

powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of
preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or
dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock.

Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock,
may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of
control might beneﬁt our shareholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

Not applicable.

ITEM 2. PROPERTIES.

See “Business” for descriptions of our properties. We also have various operating leases for rental of ofﬁce
space and ofﬁce and ﬁeld equipment. See Note 13 to the consolidated ﬁnancial statements in this Annual Report
for the future minimum rental payments. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS.

We are a party to several lawsuits encountered in the ordinary course of our business. While the ultimate

outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these
lawsuits will have a material adverse impact on our ﬁnancial condition, results of operations or cash ﬂows.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

FORM 10-K PART I

2017 ANNUAL REPORT

Part II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY SECURITIES.

GENERAL MARKET INFORMATION

Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been
traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading
market for our common stock.

On February 21, 2018, we had 109,248,747 shares of common stock outstanding held by approximately

300 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.

The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for

the periods indicated.

First Quarter
Second Quarter
Third Quarter
Fourth Quarter

2017

2016

High

Low

High

Low

$ 28.51
$ 24.71
$ 27.78
$ 31.59

$ 21.15
$ 20.13
$ 20.52
$ 24.04

$20.94
$25.54
$24.71
$27.71

$11.13
$18.03
$18.56
$20.45

On February 21, 2018, the last reported sales price of our common stock on the NYSE was $28.68 per share.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable
future. We currently intend to retain future earnings to ﬁnance the expansion of our business. Our future dividend
policy is within the discretion of our Board of Directors and will depend upon various factors, including our results
of operations, ﬁnancial condition, capital requirements and investment opportunities. In addition, certain covenants
in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay
dividends on our common stock. During the years ended December 31, 2017 and 2016, we did not pay dividends
to holders of our common stock.

EQUITY COMPENSATION PLAN INFORMATION

The following table presents the securities authorized for issuance under our equity compensation plans as of

December 31, 2017.

Plan Category

Equity compensation plans approved by security holders (1) (2)
Equity compensation plans not approved by security holders

Total

Equity Compensation Plan Information

Number of Shares
to be Issued
Upon Exercise of
Outstanding Options,
Warrants and Rights

Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights

Number of Shares
Remaining Available
for Future Issuance
Under Equity
Compensation Plans

3,152,691
—
3,152,691

$ 21.14
—
$ 21.14

2,356,467
—
2,356,467

(1) Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and

Incentive Plan.

(2) The Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015
and approved by our shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8
to the consolidated ﬁnancial statements in this Annual Report.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

SHARE PERFORMANCE GRAPH

The following graph compares the cumulative return on a $100 investment in our common stock from

December 31, 2012 through December 31, 2017, to that of the cumulative return on a $100 investment in the
Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return,
reinvestment of dividends, if any, is assumed.

This graph is not “soliciting material,” is not deemed ﬁled with the SEC and is not to be incorporated by reference

in any of our ﬁlings under the Securities Act or the Exchange Act, whether made before or after the date hereof
and irrespective of any general incorporation language in any such ﬁling. This graph is included in accordance with
the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.

COMPARISON OF CUMULATIVE TOTAL RETURN AMONG MATADOR RESOURCES COMPANY,
THE RUSSELL 2000 INDEX AND THE RUSSELL 2000 ENERGY INDEX

500

400

300

200

100

12/31/12

06/30/13

12/31/13

06/30/14

12/31/14

06/30/15

12/31/15

06/30/16

12/31/16

06/30/17

12/31/17

MTDR

Russell 2000

Russell 2000 Energy

FORM 10-K PART I I

2017 ANNUAL REPORT

REPURCHASE OF EQUITY BY THE COMPANY OR AFFILIATES

During the quarter ended December 31, 2017, the Company re-acquired shares of common stock from certain

employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Period

Total Number of
Shares Purchased (1)

Average Price Paid
Per Share

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

Maximum Number of
Shares that May Yet
Be Purchased Under
the Plans or Programs

October 1, 2017 to October 31, 2017
November 1, 2017 to November 30, 2017
December 1, 2017 to December 31, 2017

Total

1,148
327
910
2,385

$ 25.69
28.23
31.13
$ 28.11

—
—
—
—

(1) The shares were not re-acquired pursuant to any repurchase plan or program.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

ITEM 6. SELECTED FINANCIAL DATA.

The following selected ﬁnancial information is summarized from our results of operations for the ﬁve-year period

ended December 31, 2017 and selected consolidated balance sheet and cash ﬂow data at December 31, 2017,
2016, 2015, 2014 and 2013. You should read the following selected ﬁnancial data in conjunction with
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated
ﬁnancial statements and related notes thereto included elsewhere in this Annual Report. The ﬁnancial
information included in this Annual Report may not be indicative of our future results of operations, ﬁnancial
condition or cash ﬂows.

(In thousands, except per share data)

Statement of operations data:
Revenues

Oil and natural gas revenues
Third-party midstream services revenue
Realized (loss) gain on derivatives
Unrealized gain (loss) on derivatives
Total revenues

Expenses

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
General and administrative

Total expenses
Operating income (loss)

Other income (expense)

Net gain (loss) on asset sales and inventory impairment
Interest expense
Other income (expense)

Total other (expense) income

Net income (loss)

Net (income) loss attributable to non-controlling

interest in subsidiaries

Net income (loss) attributable to

Year Ended December 31,

2017

2016

2015

2014

2013

$ 528,684
10,198
(4,321)
9,715
544,276

$ 291,156
5,218
9,286
(41,238)
264,422

$ 278,340
1,864
77,094
(39,265)
318,033

$367,712
1,213
5,022
58,302
432,249

$269,030
207
(909)
(7,232)
261,096

58,275
67,313
13,039
177,502
1,290
—
66,016
383,435
160,841

23
(34,565)
3,551
(30,991)
138,007

43,046
56,202
5,389
122,048
1,182
158,633
55,089
441,589
(177,167)

35,650
54,704
3,489
178,847
734
801,166
50,105
1,124,695
(806,662)

33,172
49,945
1,408
134,737
504
—
32,152
251,918
180,331

20,973
37,971
749
98,395
348
21,229
20,779
200,444
60,652

107,277
(28,199)
(4)

79,074
(97,057)

908
(21,754)
616
(20,230)
(679,524)

—
(5,334)
132
(5,202)
110,754

(192)
(5,687)
18
(5,861)
45,094

(12,140)

(364)

(261)

—

Matador Resources Company shareholders

$ 125,867

$ (97,421)

$ (679,785)

$110,771

$ 45,094

Earnings (loss) per common share
Basic
Diluted

$
$

1.23
1.23

$
$

(1.07)
(1.07)

$
$

(8.34)
(8.34)

$
$

1.58
1.56

$
$

0.77
0.77

FORM 10-K PART I I

2017 ANNUAL REPORT

(In thousands)

Balance sheet data:
Cash and cash equivalents
Restricted cash
Net property and equipment
Total assets
Current liabilities
Long-term liabilities
Total Matador Resources Company

shareholders’ equity

(In thousands)

Other ﬁnancial data:
Net cash provided by operating activities
Net cash used in investing activities

Oil and natural gas properties capital

2017

2016

2015

2014

2013

At December 31,

96,505
$
$
5,977
$ 1,881,456
$ 2,145,690
$ 282,606
$ 605,538

$ 212,884
$
1,258
$1,184,525
$1,464,665
$ 169,505
$ 603,715

16,732
$
$
44,357
$1,012,406
$1,140,861
$ 136,830
$ 515,072

8,407
$
$
609
$1,322,072
$1,434,490
$ 142,036
$ 425,913

6,287
$
$
—
$ 845,877
$ 890,330
$ 100,327
$ 221,079

$ 1,156,556

$ 690,125

$ 488,003

$ 866,408

$ 568,924

2017

2016

2015

2014

2013

Year Ended December 31,

$ 299,125
$ (824,003)

$ 134,086
$ (405,640)

$ 208,535
$ (425,154)

$ 251,481
$ (570,531)

$ 179,470
$(366,939)

expenditures

$ (699,445)

$ (379,067)

$ (432,715)

$ (560,849)

$(363,192)

Expenditures for midstream and other

property and equipment

Net cash provided by ﬁnancing activities
Adjusted EBITDA attributable to
Matador Resources Company shareholders

$ (120,816)
$ 408,499

$ (74,845)
$ 467,706

$ (64,499)
$ 224,944

$
(9,152)
$ 321,170

$
(3,977)
$ 191,661

$ 336,063

$ 157,892

$ 223,138

$ 262,943

$ 191,771

(1) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net

income (loss) and net cash provided by operating activities, see “— Non-GAAP Financial Measures” below.

NON-GAAP FINANCIAL MEASURES

We deﬁne Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and

amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses,
certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales
and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash ﬂows as determined by
GAAP. Adjusted EBITDA is a supplemental non-GAAP ﬁnancial measure that is used by management and external
users of our consolidated ﬁnancial statements, such as industry analysts, investors, lenders and rating agencies.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance

and compare the results of operations from period to period without regard to our ﬁnancing methods or capital
structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these
amounts can vary substantially from company to company within our industry depending upon accounting methods
and book values of assets, capital structures and the method by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash ﬂows

from operating activities as determined in accordance with GAAP or as a primary indicator of our operating
performance or liquidity. Certain items excluded from Adjusted EBITDA are signiﬁcant components of understanding
and assessing a company’s ﬁnancial performance, such as a company’s cost of capital and tax structure. Our
Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies
may not calculate Adjusted EBITDA in the same manner.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to

the GAAP ﬁnancial measures of net income (loss) and net cash provided by operating activities, respectively.

Year Ended December 31,

2017

2016

2015

2014

2013

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to
Net Income (Loss):
Net income (loss) attributable to

Matador Resources Company shareholders
Net income (loss) attributable to non-controlling

interest in subsidiaries
Net income (loss)

Interest expense
Total income tax (beneﬁt) provision
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
Unrealized (gain) loss on derivatives
Stock-based compensation expense
Net (gain) loss on asset sales and inventory impairment

Consolidated Adjusted EBITDA

Adjusted EBITDA attributable to non-controlling interest

in subsidiaries
Adjusted EBITDA attributable to

$ 125,867

$ (97,421)

$(679,785)

$110,771

$ 45,094

12,140
138,007
34,565
(8,157)
177,502
1,290
—
(9,715)
16,654
(23)
350,123

364
(97,057)
28,199
(1,036)
122,048
1,182
158,633
41,238
12,362
(107,277)
158,292

261
(679,524)
21,754
(147,368)
178,847
734
801,166
39,265
9,450
(908)
223,416

(17)
110,754
5,334
64,375
134,737
504
—
(58,302)
5,524
—
262,926

—
45,094
5,687
9,697
98,395
348
21,229
7,232
3,897
192
191,771

(14,060)

(400)

(278)

—

Matador Resources Company shareholders

$ 336,063

$ 157,892

$ 223,138

$262,943

$191,771

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to
Net Cash Provided by Operating Activities:
Net cash provided by operating activities
Net change in operating assets and liabilities
Interest expense, net of non-cash portion
Current income tax (beneﬁt) provision
Adjusted EBITDA attributable to non-controlling interest

in subsidiaries
Adjusted EBITDA attributable to

Year Ended December 31,

2017

2016

2015

2014

2013

$ 299,125
25,058
34,097
(8,157)

$ 134,086

$ 208,535

(1,809)
27,051
(1,036)

(8,980)
20,902
2,959

$251,481
5,978
5,334
133

$179,470
6,210
5,687
404

(14,060)

(400)

(278)

—

Matador Resources Company shareholders

$ 336,063

$ 157,892

$ 223,138

$262,943

$191,771

FORM 10-K PART I I

2017 ANNUAL REPORT

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS.

The following discussion and analysis of our ﬁnancial condition and results of operations should be read in

conjunction with our consolidated ﬁnancial statements and related notes appearing elsewhere in this Annual Report.
The following discussion contains “forward-looking statements” that reﬂect our future plans, estimates, beliefs
and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about
future events may, and often do, vary from actual results and the differences can be material. Some of the key
factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices,
the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties
in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas
and midstream operations, the condition of the capital markets generally, as well as our ability to access them,
the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of
acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments
affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which
are difﬁcult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed
may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

OVERVIEW

We are an independent energy company founded in July 2003 and engaged in the exploration, development,
production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural
gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich
portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas.
We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in
Northwest Louisiana and East Texas. Additionally, we conduct midstream operations, primarily through our midstream
joint venture, San Mateo, in support of our exploration, development and production operations and provide
natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water
disposal services to third parties.

2017 Operational Highlights

During the year ended December 31, 2017, we completed and began producing oil and natural gas from 65 gross

(56.1 net) operated and 21 gross (3.5 net) non-operated wells in the Delaware Basin and from ﬁve gross (5.0 net)
operated and three gross (0.8 net) non-operated Eagle Ford shale wells. We did not conduct any operated drilling
and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017, although
we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that began
producing in 2017.

During 2017, we continued our focus on the exploration, delineation and development of our Delaware Basin
acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We began 2017 operating four drilling rigs
in the Delaware Basin and continued to do so throughout the ﬁrst quarter of 2017. In late April 2017, we added a
ﬁfth drilling rig in the Delaware Basin, operating this rig in our Rustler Breaks asset area. During the third quarter of
2017, we took delivery of a sixth drilling rig for the initial purpose of drilling two commercial salt water disposal wells
in the Rustler Breaks asset area for San Mateo. Between August and October 2017, we used this rig to drill the
two salt water disposal wells, both of which were completed and were operational as of February 21, 2018. San Mateo
has elected to commission the drilling and completion of two additional commercial salt water disposal wells and
the construction of associated commercial salt water disposal facilities in the Rustler Breaks asset area, which,

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

when completed, will result in a total of ﬁve commercial salt water disposal wells in the Rustler Breaks asset area.
We anticipated spudding the fourth salt water disposal well at Rustler Breaks prior to the end of 2017, but due to a
delay in securing the water injection permit for this well, we elected to move the sixth rig to the Antelope Ridge
asset area to begin drilling our ﬁrst oil and natural gas wells in that area. We drilled two oil and natural gas wells in
the Antelope Ridge asset area during the fourth quarter of 2017. At December 31, 2017 and February 21, 2018,
we were operating six drilling rigs in the Delaware Basin.

The vast majority of our 2017 capital expenditures were directed to the delineation and development of our

leasehold position in the Delaware Basin, to the development of certain midstream assets to support our operations
there and to the acquisition of additional leasehold and mineral interests prospective for the Wolfcamp, Bone Spring
and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to our
ﬁve-well drilling and completion program in the Eagle Ford shale in South Texas, which was completed early in the
third quarter of 2017, and to our participation in several non-operated wells drilled and completed in the Eagle Ford
and Haynesville shales throughout 2017, as noted above. Our 2017 capital expenditures for drilling, completing and
equipping wells were approximately $493 million.

We increased our leasehold position signiﬁcantly in the Delaware Basin during 2017, acquiring 25,100 net acres

in the Delaware Basin, including a small volume of associated production. Excluding the value of the production
acquired, this acreage was added for a weighted average cost of between approximately $7,000 and $8,000 per net
acre. At December 31, 2017, we held approximately 199,600 gross (114,000 net) acres in the Permian Basin in
Southeast New Mexico and West Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico
and Loving County, Texas.

Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day,

including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, an increase of 40% as compared to
27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, for the year ended
December 31, 2016. Our average daily oil production in 2017 of 21,510 Bbl of oil per day increased 54%, as
compared to an average daily oil production of 13,924 Bbl of oil per day in 2016. This increase in oil production was
primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, but also to
production from ﬁve operated wells we completed and turned to sales in the Eagle Ford shale late in the second
quarter and early in the third quarter of 2017. Our average daily natural gas production of 104.6 MMcf per day for
the year ended December 31, 2017 increased 25% from 83.3 MMcf per day for the year ended December 31, 2016.
This increase in natural gas production was primarily attributable to increased natural gas production associated
with our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised
55% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended
December 31, 2017, as compared to 50% for the year ended December 31, 2016.

For the year ended December 31, 2017, our oil and natural gas revenues were $528.7 million, an increase of
82% from oil and natural gas revenues of $291.2 million for the year ended December 31, 2016. Our oil revenues
and natural gas revenues increased 84% and 75% to approximately $386.9 million and $141.8 million, respectively,
as compared to $209.9 million and $81.2 million, respectively, for the year ended December 31, 2016. The increase
in oil and natural gas revenues resulted from (i) the increases in oil and natural gas production for the year ended
December 31, 2017 as noted above and (ii) higher realized weighted average oil and natural gas prices of $49.28 per
Bbl and $3.72 per Mcf in 2017, respectively, as compared to $41.19 per Bbl and $2.66 per Mcf in 2016, respectively.

We reported net income attributable to Matador Resources Company shareholders of approximately

$125.9 million, or $1.23 per diluted common share, on a GAAP basis for the year ended December 31, 2017, as
compared to a net loss of $97.4 million, or $1.07 per diluted common share, for the year ended December 31,
2016. Adjusted EBITDA for the year ended December 31, 2017 was $336.1 million, as compared to Adjusted

FORM 10-K PART I I

2017 ANNUAL REPORT

EBITDA of $157.9 million reported for the year ended December 31, 2016. Adjusted EBITDA is a non-GAAP
ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income
(loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.”

At December 31, 2017, our estimated total proved oil and natural gas reserves were 152.8 million BOE, including

86.7 million Bbl of oil and 396.2 Bcf of natural gas, with a Standardized Measure of $1.26 billion and a PV-10 of
$1.33 billion. At December 31, 2016, our estimated total proved oil and natural gas reserves were 105.8 million BOE,
including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, with a Standardized Measure of $575.0 million and a
PV-10 of $581.5 million. Our estimated total proved reserves of 152.8 million BOE at December 31, 2017 represented
a 44% year-over-year increase, as compared to 105.8 million BOE at December 31, 2016. Our estimated proved oil
reserves of 86.7 million Bbl at December 31, 2017 increased 52%, as compared to 57.0 million Bbl at December 31,
2016. Our proved oil and natural gas reserves in the Delaware Basin increased 62% to 129.0 million BOE at
December 31, 2017, as compared to 79.4 million BOE at December 31, 2016, as a result of our ongoing delineation
and development operations in the Delaware Basin. At December 31, 2017, approximately 84% of our total
proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil
reserves in the Delaware Basin increased 65% to 77.5 million Bbl at December 31, 2017, as compared to 46.9 million
Bbl at December 31, 2016. Proved oil reserves comprised 57% of our total proved reserves at December 31, 2017,
as compared to 54% at December 31, 2016. These reserves estimates were based on evaluations prepared by our
engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by
Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the
present value of estimated future net cash ﬂows from proved reserves, less estimated future development,
production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reﬂect the
timing of future cash ﬂows. Standardized Measure is not an estimate of the fair market value of our properties.
PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business —
Estimated Proved Reserves.”

2017 Midstream Joint Venture

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary
of Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection with
the formation of San Mateo. As of January 31, 2018, we had earned an additional $14.7 million in performance
incentives to be paid to us by Five Point in the ﬁrst quarter of 2018, and we may earn up to an additional $58.8 million
in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and
retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively.
San Mateo provides ﬁrm capacity service to us at market rates, while also being a midstream service provider to
third parties in and around our Wolf and Rustler Breaks asset areas.

2018 Strategic Relationship with Plains

On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains
to gather and transport crude oil for the Company and third-party customers in and around the Rustler Breaks asset
area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through
a joint tariff arrangement and related transactions to offer third-party producers located within a joint development
area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil
transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and
the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase our oil production in the Rustler
Breaks asset area and in the Wolf asset area in Loving County, Texas.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

2018 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital

expenditures in 2018. We plan to operate six contracted drilling rigs drilling primarily oil and natural gas wells in
the Delaware Basin throughout 2018. One of the six rigs is also expected to drill at least two additional salt water
disposal wells in the Rustler Breaks asset area for San Mateo during 2018. As a result, we expect that this particular
rig will spend only approximately three-quarters of the year drilling oil and natural gas wells. Our 2018 estimated
capital expenditure budget consists of $530 to $570 million for drilling, completions, facilities and infrastructure and
$70 to $90 million for midstream capital expenditures, which reﬂects our 51% share of San Mateo’s estimated
2018 capital expenditures. Substantially all of our 2018 estimated capital expenditures will be allocated to the further
delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with
the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and
extend leases and to participate in certain non-operated well opportunities. Our 2018 Delaware Basin drilling
program will focus on the continued development of the Rustler Breaks and Wolf asset areas and the further
delineation and development of the Antelope Ridge, Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas,
although we do anticipate continuing to delineate previously untested intervals in the Rustler Breaks and Wolf
asset areas during 2018 as well.

We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2018.

These expenditures are opportunity-speciﬁc and per-acre prices can vary signiﬁcantly based on the prospect. As a
result, it is difﬁcult to estimate these 2018 capital expenditures with any degree of certainty; therefore, we have not
provided estimated capital expenditures related to acreage and mineral acquisitions for 2018.

At December 31, 2017, we had $96.5 million in cash (excluding restricted cash) and $397.9 million in undrawn
borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit). As a result, we
expect to fund our capital expenditures for 2018 through a combination of cash on hand, operating cash ﬂows,
performance incentives in connection with the formation of San Mateo that were earned in the ﬁrst quarter of 2018
and borrowings under our Credit Agreement (assuming availability under our borrowing base). We may also
consider funding a portion of our 2018 capital expenditures through borrowings under additional credit arrangements,
the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, particularly in our
non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none of which may be
available on satisfactory terms or at all. The aggregate amount of capital we expend may ﬂuctuate materially based
on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our
drilling results, the actual costs of our midstream activities, other opportunities that may become available to us
and our ability to obtain capital.

FORM 10-K PART I I

2017 ANNUAL REPORT

REVENUES

Our revenues are derived primarily from the sale of oil, natural gas and NGL production. Our revenues may vary
signiﬁcantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas
or NGL prices.

The following table summarizes our revenues and production data for the periods indicated.

Operating Data:
Revenues (in thousands): (1)

Oil
Natural gas

Total oil and natural gas revenues
Third-party midstream services revenues
Realized (loss) gain on derivatives
Unrealized gain (loss) on derivatives

Total revenues

Net Production Volumes: (1)
Oil (MBbl)
Natural gas (Bcf)

Total oil equivalent (MBOE) (2)
Average daily production (BOE/d) (2)

Average Sales Prices:
Oil, without realized derivatives (per Bbl)
Oil, with realized derivatives (per Bbl)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)

Year Ended December 31,

2017

2016

2015

$ 386,865
141,819
528,684
10,198
(4,321)
9,715
$ 544,276

$209,908
81,248
291,156
5,218
9,286
(41,238)

$264,422

$203,355
74,985
278,340
1,864
77,094
(39,265)
$318,033

7,851
38.2
14,212
38,936

5,096
30.5
10,180
27,813

4,492
27.7
9,109
24,955

$ 49.28
$ 48.81
3.72
3.70

$
$

$
$
$
$

41.19
42.34
2.66
2.78

$
$
$
$

45.27
59.13
2.71
3.24

(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with

NGLs are included with our natural gas revenues.

(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2017 as Compared to Year Ended December 31, 2016

Oil and natural gas revenues. Our oil and natural gas revenues increased $237.5 million to $528.7 million, or 82%,

for the year ended December 31, 2017, as compared to $291.2 million for the year ended December 31, 2016. Our
oil revenues increased $177.0 million, or 84%, to $386.9 million for the year ended December 31, 2017, as compared
to $209.9 million for the year ended December 31, 2016. The increase in oil revenues resulted from (i) a higher
weighted average oil price realized for the year ended December 31, 2017 of $49.28 per Bbl, as compared to $41.19
per Bbl realized for the year ended December 31, 2016, and (ii) the 54% increase in our oil production to 7.9 million
Bbl of oil for the year ended December 31, 2017, or about 21,510 Bbl of oil per day, as compared to 5.1 million Bbl of
oil, or about 13,924 Bbl of oil per day, for the year ended December 31, 2016. This increased oil production was
primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, but also to
production from the ﬁve operated wells we completed and turned to sales in the Eagle Ford shale late in the
second quarter and early in the third quarter of 2017. Our natural gas revenues increased by $60.6 million, or 75%, to
$141.8 million for the year ended December 31, 2017, as compared to $81.2 million for the year ended December 31,
2016. The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for
the year ended December 31, 2017 of $3.72 per Mcf, as compared to $2.66 per Mcf realized for the year ended
December 31, 2016, and (ii) the 25% increase in our natural gas production to 38.2 Bcf for the year ended
December 31, 2017, as compared to 30.5 Bcf for the year ended December 31, 2016. The increase in natural gas
production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Third-party midstream services revenues. Our third-party midstream services revenues increased $5.0 million

to $10.2 million, or 95%, for the year ended December 31, 2017, as compared to $5.2 million for the year ended
December 31, 2016. Third-party midstream services revenues are those revenues from midstream operations related
to third parties, including working interest owners in our operated wells. This increase was primarily attributable
to a signiﬁcant increase in natural gas gathering and processing revenues to approximately $7.9 million for the year
ended December 31, 2017, as compared to $3.6 million for the year ended December 31, 2016, due to (i) the
Black River Processing Plant being placed into service in the second half of 2016 and operating for the full year in
2017 and (ii) increased natural gas production in our Rustler Breaks and Wolf asset areas. The remaining increase
in our third-party midstream services revenues was primarily attributable to the increase in third-party salt water
disposal revenue to approximately $2.1 million during the year ended December 31, 2017, as compared to
approximately $1.6 million for the year ended December 31, 2016, primarily due to an increase in salt water gathering
and disposal at our facilities in the Rustler Breaks and Wolf asset areas in 2017.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $4.3 million for the year ended
December 31, 2017, as compared to a net gain of approximately $9.3 million for the year ended December 31, 2016.
We realized net losses of $3.7 million and $0.6 million from our oil and natural gas costless collar contracts,
respectively, for the year ended December 31, 2017, resulting from oil and natural gas prices that were above the
ceiling prices of certain of our oil and natural gas costless collar contracts. We realized net gains of $5.9 million and
$3.4 million from our oil and natural gas derivative contracts, respectively, for the year ended December 31, 2016,
resulting from oil and natural gas prices that were below the ﬂoor prices of certain of our oil and natural gas costless
collar contracts. We realized an average loss on our oil derivatives of approximately $0.47 per Bbl produced during
the year ended December 31, 2017, as compared to an average gain of $1.15 per Bbl produced during the year
ended December 31, 2016. Our total oil volumes hedged for the year ended December 31, 2017 represented 59%
of our total oil production, as compared to 50% of our total oil production the year ended December 31, 2016. We
realized an average loss on our natural gas and NGL derivatives of approximately $0.02 per Mcf produced during the
year ended December 31, 2017, as compared to an average gain of approximately $0.12 per Mcf produced for the
year ended December 31, 2016. Our total natural gas volumes hedged for the year ended December 31, 2017
represented 63% of our total natural gas production, as compared to 44% of our total natural gas production for the
year ended December 31, 2016.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $9.7 million for the
year ended December 31, 2017, as compared to an unrealized loss of $41.2 million for the year ended December 31,
2016. During the year ended December 31, 2017, the aggregate net fair value of our open oil and natural gas
derivatives contracts increased from a net liability of approximately $25.0 million to a net liability of approximately
$15.2 million, resulting in an unrealized gain on derivatives of approximately $9.7 million for the year ended
December 31, 2017. During the year ended December 31, 2016, the aggregate net fair value of our open oil and
natural gas derivative contracts decreased from a net asset of approximately $16.3 million to a net liability of
approximately $25.0 million, resulting in an unrealized loss on derivatives of approximately $41.2 million for the
year ended December 31, 2016.

Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015

Oil and natural gas revenues. Our oil and natural gas revenues increased $12.8 million to $291.2 million, or an

increase of 5%, for the year ended December 31, 2016, as compared to $278.3 million for the year ended
December 31, 2015. Our oil revenues increased $6.6 million, or an increase of 3%, to $209.9 million for the year
ended December 31, 2016, as compared to $203.4 million for the year ended December 31, 2015. The increase in
oil revenues resulted from the 13% increase in our oil production to 5.1 million Bbl of oil for the year ended
December 31, 2016, or about 13,924 Bbl of oil per day, as compared to 4.5 million Bbl of oil, or about 12,306 Bbl

FORM 10-K PART I I

2017 ANNUAL REPORT

of oil per day, for the year ended December 31, 2015. This increased oil production was primarily a result of our
ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the
Eagle Ford shale, where we had not drilled any new operated wells since the second quarter of 2015. The
increase in oil revenues was partially impacted by a lower weighted average oil price realized for the year ended
December 31, 2016 of $41.19 per Bbl, as compared to $45.27 per Bbl realized for the year ended December 31,
2015. Our natural gas revenues increased $6.3 million, or an increase of 8%, to $81.2 million for the year ended
December 31, 2016, as compared to $75.0 million for the year ended December 31, 2015. The increase in natural
gas revenues resulted from the 10% increase in our natural gas production to 30.5 Bcf for the year ended
December 31, 2016, as compared to 27.7 Bcf for the year ended December 31, 2015. The increased natural gas
production was primarily attributable to our ongoing delineation and development drilling in the Delaware Basin,
which offset declining natural gas production in the Eagle Ford and Haynesville shales where we had signiﬁcantly
reduced our activity since late 2014 and early 2015. The increase in natural gas revenues was partially impacted
by a lower weighted average natural gas price realized for the year ended December 31, 2016 of $2.66 per Mcf, as
compared to $2.71 per Mcf realized for the year ended December 31, 2015.

Third-party midstream services revenues. During the third quarter of 2016, our midstream operations became

a reportable business segment under GAAP. Our third-party midstream services revenues were previously
included in other income. Third-party midstream services revenues are primarily those revenues from midstream
operations related to third parties, including working interest owners in our operated wells; all midstream services
revenues associated with our production are eliminated in consolidation. Our third-party midstream services
revenues increased to $5.2 million, or an increase of almost three-fold, for the year ended December 31, 2016, as
compared to $1.9 million for the year ended December 31, 2015. This increase was primarily attributable to
a signiﬁcant increase in third-party salt water disposal revenue to approximately $1.6 million for the year ended
December 31, 2016, as compared to $0.2 million for the year ended December 31, 2015, due to increased salt
water disposal at our facilities in the Wolf asset area in 2016. The remaining increase was primarily attributable to
third-party natural gas gathering and processing fees of $3.6 million for the year ended December 31, 2016, as
compared to $1.7 million for the year ended December 31, 2015, including natural gas processing at the Black River
Processing Plant, which began operating in August 2016.

Realized gain on derivatives. Our realized net gain on derivatives was $9.3 million for the year ended

December 31, 2016, as compared to a realized net gain of $77.1 million for the year ended December 31, 2015. We
realized net gains of $5.9 million and $3.4 million from our oil and natural gas derivative contracts, respectively,
for the year ended December 31, 2016 resulting from oil and natural gas prices that were below the ﬂoor prices of
certain of our oil and natural gas costless collar contracts. Our realized net gain on derivatives was $77.1 million
for the year ended December 31, 2015. We realized net gains of $62.3 million, $12.7 million and $2.2 million from
our oil, natural gas and NGL derivative contracts, respectively, for the year ended December 31, 2015 resulting
from oil and natural gas prices being below the ﬂoor prices of most of our oil and natural gas costless collar
contracts and NGL prices being below the ﬁxed prices of all of our swap contracts. We realized an average gain
of approximately $2.29 per Bbl hedged on all of our open oil costless collar contracts during the year ended
December 31, 2016, as compared to an average gain of $22.89 per Bbl hedged for the year ended December 31, 2015.
Our oil volumes hedged for the year ended December 31, 2016 were also 6% lower as compared to the year
ended December 31, 2015. We realized an average gain of approximately $0.26 per MMBtu hedged on all of our
open natural gas costless collar contracts during the year ended December 31, 2016, as compared to an average
gain of approximately $0.73 per MMBtu hedged on all of our open natural gas costless collar contracts during the
year ended December 31, 2015. Our total natural gas volumes hedged for the year ended December 31, 2016 were
also 23% lower than the total natural gas volumes hedged for the year ended December 31, 2015. We realized an

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

average gain of approximately $1.15 per Bbl produced on our open oil derivative contracts during the year ended
December 31, 2016, as compared to an average gain of $13.86 per Bbl produced for the year ended December 31,
2015. Our total oil volumes hedged for the year ended December 31, 2016 represented 50% of our total oil
production for the year ended December 31, 2016, as compared to 61% of our total oil production for the year ended
December 31, 2015. We realized an average gain of approximately $0.12 per Mcf produced on our open natural
gas derivative contracts during the year ended December 31, 2016, as compared to an average gain of approximately
$0.53 per Mcf produced on our open natural gas costless collar contracts during the year ended December 31, 2015.
Our total natural gas volumes hedged for the year ended December 31, 2016 represented 44% of our total
natural gas production for the year ended December 31, 2016, as compared to 63% of our total natural gas
production for the year ended December 31, 2015.

Unrealized gain (loss) on derivatives. Our unrealized net loss on derivatives was $41.2 million for the year
ended December 31, 2016, as compared to an unrealized net loss of $39.3 million for the year ended December 31,
2015. During the year ended December 31, 2016, the net fair value of our open oil and natural gas derivatives
contracts decreased to a net liability of approximately $25.0 million from a net asset of $16.3 million for the year
ended December 31, 2015, resulting in an unrealized net loss on derivatives of $41.2 million for the year ended
December 31, 2016. During the year ended December 31, 2016, the net fair value of our open oil and natural gas
derivative contracts decreased $32.2 million and $9.1 million, respectively, due to the increase in the underlying
oil and natural gas futures prices at December 31, 2016, as well as realized gains from oil and natural gas derivative
contracts settled during the year ended December 31, 2016.

EXPENSES

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

Year Ended December 31,

2017

2016

2015

(In thousands, except expenses per BOE)

Expenses:

Operating income (loss)
Other income (expense):

$ 58,275
67,313
13,039
177,502
1,290
—
66,016
383,435
160,841

Net gain on asset sales and inventory impairment
Interest expense
Other income (expense)
Total other (expense) income
Income (loss) before income taxes
Total income tax beneﬁt
Net income attributable to non-controlling interest in subsidiaries
Net income (loss) attributable to Matador Resources Company shareholders
Expenses per BOE:

23
(34,565)
3,551
(30,991)
129,850
(8,157)
(12,140)
$ 125,867

$ 43,046
56,202
5,389
122,048
1,182
158,633
55,089
441,589
(177,167)

107,277
(28,199)
(4)
79,074
(98,093)
(1,036)
(364)
$ (97,421)

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
General and administrative

$
$
$

4.10
4.74
0.92
$ 12.49
4.65
$

$
$
$
$
$

4.23
5.52
0.53
11.99
5.41

35,650
54,704
3,489
178,847
734
801,166
50,105
1,124,695
(806,662)

908
(21,754)
616
(20,230)
(826,892)
(147,368)
(261)
$ (679,785)

$
$
$
$
$

3.91
6.01
0.38
19.63
5.50

FORM 10-K PART I I

2017 ANNUAL REPORT

Year Ended December 31, 2017 as Compared to Year Ended December 31, 2016

Production taxes, transportation and processing. Our production taxes, transportation and processing

expenses increased by approximately $15.2 million to $58.3 million, or 35%, for the year ended December 31, 2017,
as compared to $43.0 million for the year ended December 31, 2016. The increase in production taxes, transportation
and processing expenses on an absolute basis was primarily attributable to the $16.4 million increase in our
production taxes to $33.0 million for the year ended December 31, 2017, as compared to $16.6 million for the year
ended December 31, 2016, primarily due to the $237.5 million increase in oil and natural gas revenues for the
year ended December 31, 2017, as compared to the year ended December 31, 2016. In addition, the production tax
rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production
becomes attributable to New Mexico, we expect our production tax expenses to increase. The increased production
taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing
expenses decreased to $25.3 million for the year ended December 31, 2017, as compared to transportation and
processing expenses of $26.5 million for the year ended December 31, 2016. This decrease of $1.2 million was
primarily due to the start-up in late August 2016 of the Black River Processing Plant, which processes most of the
natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico, and which was operational
for the full year in 2017. On a unit-of-production basis, our production taxes, transportation and processing expenses
decreased to $4.10 per BOE for the year ended December 31, 2017, as compared to $4.23 per BOE for the year
ended December 31, 2016, due not only to the decreased transportation and processing charges attributable to the
start-up of the Black River Processing Plant, but also to the 40% increase in total oil equivalent production during
in the year ended December 31, 2017, as compared to the year ended December 31, 2016.

Lease operating expenses. Our lease operating expenses increased by $11.1 million to $67.3 million, or 20%,

for the year ended December 31, 2017, as compared to $56.2 million for the year ended December 31, 2016.
The increase in lease operating expenses on an absolute basis for the year ended December 31, 2017 was primarily
attributable to an increase in the costs of services and equipment related to the increased number of wells we
operated during the year ended December 31, 2017, as compared to the year ended December 31, 2016, resulting
from our increased delineation and development drilling activities in the Delaware Basin. Our lease operating
expenses on a unit-of-production basis decreased 14% to $4.74 per BOE for the year ended December 31, 2017, as
compared to $5.52 per BOE for the year ended December 31, 2016. The decrease in lease operating expenses on
a unit-of-production basis for the year ended December 31, 2017 was attributable to (i) increased efﬁciencies as
more salt water was gathered by pipeline to San Mateo’s disposal facilities in the Delaware Basin, (ii) decreased
workover expenses, (iii) decreased salt water disposal and chemical costs associated with our Eagle Ford operations
and (iv) a 40% increase in total oil equivalent production in 2017, as compared to 2016.

Plant and other midstream services operating. Our plant and other midstream services operating expenses
increased by $7.7 million to $13.0 million, an increase of 142%, for the year ended December 31, 2017, as compared
to $5.4 million for the year ended December 31, 2016. This increase was primarily attributable to (i) increased
expenses associated with our expanded commercial salt water disposal operations of $6.8 million for the year ended
December 31, 2017, as compared to $3.6 million for the year ended December 31, 2016, and (ii) increased
expenses associated with the Black River Processing Plant, which began operating in August 2016, of $4.6 million for
the year ended December 31, 2017, as compared to $0.7 million for the year ended December 31, 2016.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by

$55.5 million to $177.5 million, or 45%, for the year ended December 31, 2017, as compared to $122.0 million
for the year ended December 31, 2016. On a unit-of-production basis, our depletion, depreciation and amortization
expenses increased 4% to $12.49 per BOE for the year ended December 31, 2017, as compared to $11.99 per
BOE for the year ended December 31, 2016. The increase in both our total depletion, depreciation and amortization
and unit-of-production depletion, depreciation and amortization expenses was primarily attributable to (i) increased
depreciation expenses of approximately $5.2 million for the year ended December 31, 2017, as compared to
$2.7 million for the year ended December 31, 2016, associated with our new midstream assets placed into service
in 2017 and (ii) higher estimated future development costs associated with proved undeveloped oil and natural
gas reserves at December 31, 2017, both of which were offset by the increase in the Company’s total proved oil
and natural gas reserves between the respective periods.

Full-cost ceiling impairment. We recorded no impairment charge to the net capitalized costs of our oil and
natural gas properties for the year ended December 31, 2017. We recorded an impairment charge of $158.6 million
to the net capitalized costs of our oil and natural gas properties for the year ended December 31, 2016.

General and administrative. Our general and administrative expenses increased $10.9 million to $66.0 million,

an increase of 20%, for the year ended December 31, 2017, as compared to $55.1 million for the year ended
December 31, 2016. The increase in our general and administrative expenses was primarily attributable to increased
payroll expenses of approximately $10.4 million associated with additional employees joining the Company to
support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration
functions as a result of the continued growth of the Company and to the $4.3 million increase in non-cash stock-
based compensation expense to $16.7 million for the year ended December 31, 2017, as compared to $12.4 million
for the year ended December 31, 2016. The increase in our non-cash stock-based compensation was attributable to
the increased expense related to the vesting of awards granted from 2013 through 2017 and the granting of new
awards during 2017, as well as a change in the vesting schedule applicable to equity awards granted to our board of
directors resulting in a $1.5 million one-time stock-based compensation expense. Our general and administrative
expenses decreased 14% on a unit-of-production basis to $4.65 per BOE for the year ended December 31, 2017, as
compared to $5.41 per BOE for the year ended December 31, 2016, primarily due to the 40% increase in total oil
equivalent production between the respective periods.

Net gain on asset sales and inventory impairment. We recorded a net gain of $23,000 on asset sales and
inventory impairment for the year ended December 31, 2017, as compared to a net gain of $107.3 million for the
year ended December 31, 2016 related to the sale of our wholly-owned subsidiary that owned the Loving County
Processing System. See below and Note 5 to the consolidated ﬁnancial statements in this Annual Report for more
information on this sale.

Interest expense. For the year ended December 31, 2017, we incurred total interest expense of approximately
$41.9 million. We capitalized approximately $7.3 million of our interest expense on certain qualifying projects for the
year ended December 31, 2017 and expensed the remaining $34.6 million to operations. For the year ended
December 31, 2016, we incurred total interest expense of approximately $31.9 million. We capitalized $3.7 million
of our interest expense on certain qualifying projects for the year ended December 31, 2016 and expensed the
remaining $28.2 million to operations. The increase in total interest expense for the year ended December 31, 2017,
as compared to the year ended December 31, 2016, was primarily attributable to an increase in our average debt
outstanding. In December 2016, we issued an additional $175.0 million of 6.875% senior notes due 2023,
increasing our total senior notes outstanding to $575.0 million from $400.0 million. As a result, we incurred interest
on the entire $575.0 million in senior notes outstanding during the year ended December 31, 2017, as compared
to the year ended December 31, 2016, when the $575.0 million of senior notes were outstanding for only a portion
of December 2016.

FORM 10-K PART I I

2017 ANNUAL REPORT

Total income tax (beneﬁt) provision. Our deferred tax assets exceeded our deferred tax liabilities at

December 31, 2017 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded
in prior periods. We established a valuation allowance against the deferred tax assets beginning in the third
quarter of 2015, and we retained a full valuation allowance at December 31, 2017 due to uncertainties regarding
the future realization of our deferred tax assets. The current tax beneﬁt of $8.2 million for the year ended
December 31, 2017 was primarily the result of the Tax Cuts and Jobs Act, under which corporate alternative
minimum taxes were repealed. As a result, corporate alternative minimum tax carryforwards will be refunded.
The total income tax expense for the years ended December 31, 2017 and 2016 differed from amounts computed
by applying the U.S. federal statutory tax rate to the pre-tax loss due primarily to recording a valuation allowance
against the net deferred tax asset position as a result of the full-cost ceiling impairments recorded for the years
ended December 31, 2016 and 2015.

Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015

Production taxes, transportation and processing. Our production taxes, transportation and processing

expenses increased $7.4 million to $43.0 million, an increase of 21%, for the year ended December 31, 2016, as
compared to $35.7 million for the year ended December 31, 2015. On a unit-of-production basis, our production
taxes, transportation and processing expenses increased 8% to $4.23 per BOE for the year ended December 31,
2016, as compared to $3.91 per BOE for the year ended December 31, 2015. The increase in production taxes,
transportation and processing expenses was primarily attributable to higher transportation and processing expenses
of $26.5 million for the year ended December 31, 2016, as compared to transportation and processing expenses
of $22.4 million for the year ended December 31, 2015. This increase of $4.1 million was primarily due to the
increase in natural gas production in the Delaware Basin as a percentage of our total natural gas production for the
year ended December 31, 2016, as compared to the year ended December 31, 2015. Natural gas transportation and
processing expenses are higher in the Delaware Basin, as compared to the Eagle Ford shale, as the natural gas
gathering and processing infrastructure had yet to meet the demand for these services due to the increased drilling
activity in the Delaware Basin over the last few years.

Our production taxes increased $3.4 million to $16.6 million for the year ended December 31, 2016, as compared

to $13.2 million for the year ended December 31, 2015, primarily due to the 5% increase in oil and natural gas
revenues for the year ended December 31, 2016, as compared to the year ended December 31, 2015. In addition to
the increase in production taxes attributable to the 5% increase in oil and natural gas revenues, the production tax
rates in New Mexico are higher than production tax rates in Texas.

Lease operating expenses. Our lease operating expenses increased $1.5 million to $56.2 million, an increase of

3%, for the year ended December 31, 2016, as compared to $54.7 million for the year ended December 31, 2015.
Our lease operating expenses per unit of production decreased 8% to $5.52 per BOE for the year ended December 31,
2016, as compared to $6.01 per BOE for the year ended December 31, 2015. Our total oil and natural gas production
increased 12% to approximately 10.2 million BOE for the year ended December 31, 2016 from approximately
9.1 million BOE for the year ended December 31, 2015. The decrease achieved in lease operating expenses on a
unit-of-production basis was primarily attributable to several key factors, including (i) decreased ﬁeld supervisory
costs as a number of third-party contractors became full-time employees during the second quarter of 2016,
(ii) decreased costs associated with our Eagle Ford operations, including supervisory, salt water disposal and chemical
costs and (iii) increased oil equivalent production as compared to the year ended December 31, 2015. This
decrease was partially offset by (x) increased salt water disposal costs attributable to increased operations in the
Rustler Breaks asset area and (y) increased workover expenses in the Wolf asset area.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Plant and other midstream services operating. Our plant and other midstream services operating expenses
increased $1.9 million to $5.4 million, an increase of 54%, for the year ended December 31, 2016, as compared to
$3.5 million for the year ended December 31, 2015. This increase was primarily attributable to the expenses
associated with our salt water disposal operations of $3.6 million for the year ended December 31, 2016, as
compared to $2.2 million for the year ended December 31, 2015. The remaining increase was primarily attributable
to expenses associated with the Black River Processing Plant, which began operating in August 2016.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased

$56.8 million to $122.0 million, a decrease of 32%, for the year ended December 31, 2016, as compared to
$178.8 million for the year ended December 31, 2015. On a unit-of-production basis, our depletion, depreciation and
amortization expenses decreased 39% to $11.99 per BOE for the year ended December 31, 2016, as compared
to $19.63 per BOE for the year ended December 31, 2015. The decrease in our total depletion, depreciation and
amortization expenses resulted primarily from (i) higher total proved reserves of 105.8 million BOE, or an increase
of 24%, at December 31, 2016, as compared to total proved reserves of 85.1 million BOE at December 31, 2015,
(ii) the decreased cost on a unit-of-production basis associated with wells drilled in 2016, as compared to prior
periods and (iii) the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded
in 2015 and 2016. This increase in total proved oil and natural gas reserves was primarily attributable to the
continued delineation and development of our acreage in the Delaware Basin.

Full-cost ceiling impairment. Due primarily to the continued decline in oil and natural gas prices during the ﬁrst

half of 2016, the net capitalized costs of our oil and natural gas properties less related deferred income taxes
exceeded the cost center ceiling. As a result, we recorded an impairment charge of $158.6 million, exclusive of tax
effect, for the year ended December 31, 2016 to our net capitalized costs. This charge is reﬂected in our statement
of operations for the year ended December 31, 2016, with the related deferred income tax credit recorded net of a
valuation allowance. These full-cost impairment charges for the year ended December 31, 2016 were realized in
the ﬁrst two quarters of the year. Since that time, oil and natural gas prices improved and as a result, no full-cost ceiling
impairment charges were recorded in the third and fourth quarters of 2016.

Due primarily to the sharp decline in oil and natural gas prices during 2015, at December 31, 2015, the net
capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center
ceiling. As a result, we recorded an impairment charge of $801.2 million, exclusive of tax effect, to our net
capitalized costs. This charge is reﬂected in our statement of operations for the year ended December 31, 2015,
with the related deferred income tax credit recorded net of a valuation allowance.

General and administrative. Our general and administrative expenses increased $5.0 million to $55.1 million,

an increase of 10%, for the year ended December 31, 2016, as compared to $50.1 million for the year ended
December 31, 2015. The increase in our general and administrative expenses was primarily attributable to increased
payroll expenses associated with additional employees joining the Company during the year ended December 31,
2016 to support our increased land, geoscience, drilling, completion, production, midstream, accounting and
administration functions as a result of the continued growth of the Company. The remaining increase is largely due
to a $2.9 million increase in non-cash stock-based compensation expense to $12.4 million for the year ended
December 31, 2016, as compared to $9.5 million for the year ended December 31, 2015. The increase in our non-cash
stock-based compensation expense was attributable to the increased expense related to the continued vesting
of awards granted from 2012 through 2016. Our general and administrative expenses decreased 2% on a
unit-of-production basis to $5.41 per BOE for the year ended December 31, 2016, as compared to $5.50 per BOE
for the year ended December 31, 2015.

FORM 10-K PART I I

2017 ANNUAL REPORT

Net gain on asset sales and inventory impairment. We recorded a net gain of $107.3 million on asset sales
and inventory impairment for the year ended December 31, 2016, as compared to $0.9 million for the year ended
December 31, 2015. On October 1, 2015, we completed the sale of our wholly-owned subsidiary that owned the
Loving County Processing System to EnLink. The Loving County Processing System included the Wolf Processing
Plant and approximately six miles of high pressure gathering pipeline that connects our natural gas gathering
system to the Wolf Processing Plant.

Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and we received net proceeds
of approximately $139.8 million, after deducting customary purchase price adjustments of approximately $3.6 million.
Due to the terms of the Wolf Gathering Agreement, the transaction was accounted for as a sale and leaseback
transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the
consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million
between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded
as a deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the
gathering and processing agreement. See Note 5 to the consolidated ﬁnancial statements in this Annual Report for
more information on this agreement.

During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County,

Texas. Upon completion and successful testing of the new plant, EnLink began processing our natural gas at the
new plant. As such, the gathering and processing agreement was no longer considered a lease, and accordingly the
Company recognized the remaining unamortized gain on the sale of $107.3 million in the consolidated statement
of operations for the year ended December 31, 2016.

Interest expense. For the year ended December 31, 2016, we incurred total interest expense of approximately
$31.9 million. We capitalized approximately $3.7 million of our interest expense on certain qualifying projects for the
year ended December 31, 2016 and expensed the remaining $28.2 million to operations. For the year ended
December 31, 2015, we incurred total interest expense of approximately $25.7 million. We capitalized approximately
$3.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2015 and
expensed the remaining $21.8 million to operations. The increase in total interest expense of $6.2 million for the
year ended December 31, 2016, as compared to the year ended December 31, 2015, was attributable to an
increase in both the average debt outstanding and the coupon rate of 6.875% for the senior notes issued in 2015
and late 2016, as compared to the lower effective interest rates incurred on borrowings under our Credit
Agreement. In December 2016, we used a portion of the net proceeds from the December 2016 senior notes and
equity offerings to repay a total of $120.0 million of outstanding borrowings under our Credit Agreement. At
December 31, 2016, we had no outstanding borrowings under our Credit Agreement, $0.8 million in outstanding
letters of credit and $575.0 million in outstanding senior notes.

Total income tax (beneﬁt) provision. Our deferred tax assets exceeded our deferred tax liabilities at

December 31, 2016 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded
in 2016 and 2015. As a result, we established a valuation allowance against the deferred tax assets beginning in
the third quarter of 2015. We retained a full valuation allowance at December 31, 2016 due to uncertainties regarding
the future realization of our deferred tax assets. The current tax beneﬁt of $1.0 million for the year ended
December 31, 2016 was primarily attributable to a refund due from the Internal Revenue Service. The total income
tax expense for the year ended December 31, 2016 differed from amounts computed by applying the U.S. federal
statutory tax rate to the pre-tax loss due primarily to the recording of a valuation allowance against the net deferred
tax asset position as a result of the full-cost ceiling impairments recorded for the years ended December 31, 2016
and 2015.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

LIQUIDITY AND CAPITAL RESOURCES

Our primary use of capital has been, and we expect will continue to be during 2018 and for the foreseeable

future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments.
Excluding any possible signiﬁcant acquisitions, we expect to fund our capital expenditure requirements through
2018 through a combination of cash on hand, operating cash ﬂows, performance incentives in connection with the
formation of San Mateo that were earned in the ﬁrst quarter of 2018 and borrowings under our Credit Agreement
(assuming availability under our borrowing base). We continually evaluate other capital sources, including borrowings
under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing
assets or acreage, particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible
securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved
reserves and production will be highly dependent on our ability to access outside sources of capital and to generate
operating cash ﬂows.

At December 31, 2017, we had cash totaling approximately $96.5 million and restricted cash totaling approximately

$6.0 million, most of which is associated with San Mateo. By contractual agreement, the cash in the accounts held
by our less-than-wholly-owned subsidiaries is not to be commingled with other of our cash and is to be used only to
fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

On October 25, 2017, the lenders party to our Credit Agreement increased our borrowing base from $450.0 million

to $525.0 million, and the maximum facility amount remained at $500.0 million. We elected to keep the borrowing
commitment at $400.0 million. This October 2017 redetermination constituted the regularly scheduled November 1
redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the
maximum facility amount and the elected borrowing commitment. At December 31, 2017 and February 21, 2018,
the borrowing base under our Credit Agreement remained $525.0 million. At both dates, we had no outstanding
borrowings and approximately $2.1 million in outstanding letters of credit under the Credit Agreement, and we had
$575.0 million of outstanding senior notes.

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of

Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection
with the formation of San Mateo. As of January 31, 2018, we had earned an additional $14.7 million in performance
incentives to be paid by Five Point in the ﬁrst quarter of 2018, and we may earn up to an additional $58.8 million
in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and
retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo,
respectively. San Mateo provides ﬁrm capacity service to us at market rates, while also being a midstream service
provider to third parties in and around our Wolf and Rustler Breaks asset areas.

On October 10, 2017, we completed a public offering of 8.0 million shares of our common stock, receiving

proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were used
to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total
acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining
proceeds have been and are expected to be used for other midstream development, acreage acquisitions and
general corporate purposes, including to fund a portion of our current and future capital expenditures.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital

expenditures in 2018. We plan to operate six contracted drilling rigs in the Delaware Basin throughout 2018. One
of the six rigs is also expected to drill at least two additional salt water disposal wells in the Rustler Breaks asset
area for San Mateo during 2018. Our 2018 estimated capital expenditure budget consists of $530 to $570 million for
drilling, completions, facilities and infrastructure and $70 to $90 million for midstream capital expenditures, which

FORM 10-K PART I I

2017 ANNUAL REPORT

represents our 51% share of San Mateo’s 2018 capital expenditures. Substantially all of our 2018 estimated capital
expenditures will be allocated to the further delineation and development of our growing leasehold position
and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the
Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well
opportunities. Our 2018 Delaware Basin drilling program will focus on the continued development of the Wolf and
Rustler Breaks asset areas and the further delineation and development of the Antelope Ridge, Jackson Trust,
Ranger/Arrowhead and Twin Lakes asset areas, although we also anticipate continuing to delineate previously
untested intervals in the Wolf and Rustler Breaks asset areas during 2018 as well.

We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2018.

These expenditures are opportunity-speciﬁc and per-acre prices can vary signiﬁcantly based on the prospect.
As a result, it is difﬁcult to estimate these 2018 capital expenditures with any degree of certainty; therefore, we
have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2018.

Our 2018 capital expenditures may be adjusted as business conditions warrant and the amount, timing and
allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we
will expend may ﬂuctuate materially based on market conditions, the actual costs to drill, complete and place
on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream
activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may
become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase
signiﬁcantly, we have the ﬂexibility to defer a signiﬁcant portion of our capital expenditures until later periods to
conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate
near-term cash ﬂows. We routinely monitor and adjust our capital expenditures in response to changes in prices,
availability of ﬁnancing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory
approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual
obligations, drilling plans for properties we do not operate and other factors both within and outside our control.

Exploration and development activities are subject to a number of risks and uncertainties, which could cause
these activities to be less successful than we anticipate. A signiﬁcant portion of our anticipated cash ﬂows from
operations for 2018 is expected to come from producing wells and development activities on currently proved
properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and
the Haynesville shale in Louisiana. Our existing wells may not produce at the levels we are forecasting and our
exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our
anticipated cash ﬂows from operations are based upon current expectations of oil and natural gas prices for 2018
and the hedges we currently have in place. We use commodity derivative ﬁnancial instruments at times to mitigate
our exposure to ﬂuctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash ﬂows
from operations resulting from declines in commodity prices. See Note 11 to the consolidated ﬁnancial statements
in this Annual Report for a summary of our open derivative ﬁnancial instruments at December 31, 2017. See
“Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital
Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be
Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,”
“Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree
of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and
“Risk Factors — Our Identiﬁed Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to
Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Our cash ﬂows for the years ended December 31, 2017, 2016 and 2015 are presented below.

(In thousands)

Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by ﬁnancing activities
Net change in cash

Cash Flows Provided by Operating Activities

Year Ended December 31,

2017

2016

2015

$ 299,125

(824,003)
408,499
$ (116,379)

$ 134,086
(405,640)
467,706
$ 196,152

$ 208,535
(425,154)
224,944
8,325

Net cash provided by operating activities increased by $165.0 million to $299.1 million for the year ended

December 31, 2017, as compared to net cash provided by operating activities of $134.1 million for the year
ended December 31, 2016. Excluding changes in operating assets and liabilities, net cash provided by operating
activities increased to $324.2 million for the year ended December 31, 2017 from $132.3 million for the year
ended December 31, 2016. This increase was primarily attributable to higher oil and natural gas production and
higher commodity prices realized during the year ended December 31, 2017, as compared to the year ended
December 31, 2016. Changes in our operating assets and liabilities between December 31, 2016 and December 31,
2017 also resulted in a net decrease of approximately $26.9 million in net cash provided by operating activities for
the year ended December 31, 2017, as compared to the year ended December 31, 2016.

Net cash provided by operating activities decreased by $74.4 million to $134.1 million for the year ended

December 31, 2016, as compared to net cash provided by operating activities of $208.5 million for the year ended
December 31, 2015. Excluding changes in operating assets and liabilities, net cash provided by operating activities
decreased to $132.3 million for the year ended December 31, 2016 from $199.6 million for the year ended
December 31, 2015. This decrease was primarily attributable to the decrease in our realized gain on derivatives,
which declined $67.8 million to $9.3 million for the year ended December 31, 2016, as compared to $77.1 million for
the year ended December 31, 2015. Changes in our operating assets and liabilities between December 31, 2015
and December 31, 2016 also resulted in a net decrease of approximately $7.2 million in net cash provided by
operating activities for the year ended December 31, 2016, as compared to the year ended December 31, 2015.

Our operating cash ﬂows are sensitive to a number of variables, including changes in our production and

the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the
actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors signiﬁcantly impact
the prices of oil and natural gas. These factors are beyond our control and are difﬁcult to predict. We use commodity
derivative ﬁnancial instruments to mitigate our exposure to ﬂuctuations in oil, natural gas and NGL prices. In
addition, we attempt to avoid long-term service agreements where possible in order to minimize ongoing future
commitments. For additional information on the impact of changing prices on our ﬁnancial condition, see
“Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors — Our Success Is Dependent
on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices
May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and
Financial Obligations.”

FORM 10-K PART I I

2017 ANNUAL REPORT

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $418.4 million to $824.0 million for the year ended December 31,

2017 from $405.6 million for the year ended December 31, 2016. This increase in net cash used in investing
activities was primarily attributable to (i) an increase of $320.4 million in oil and natural gas properties capital
expenditures for the year ended December 31, 2017, as compared to the year ended December 31, 2016,
(ii) an increase of approximately $46.0 million in expenditures for midstream and other property and equipment,
which includes the construction and installation of an expansion of the Black River Processing Plant, additional salt
water disposal wells and new pipeline infrastructure and (iii) the release from escrow of $43.1 million of potential
like-kind-exchange funds during the year ended December 31, 2016 in connection with the sale of the Loving
County Processing System to EnLink in 2015, but no similar release of funds occurring in 2017. Cash used for oil
and natural gas properties capital expenditures for the year ended December 31, 2017 was primarily attributable
to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition
of additional leasehold acreage and mineral interests in the Delaware Basin.

Net cash used in investing activities decreased by $19.5 million to $405.6 million for the year ended December 31,

2016 from $425.2 million for the year ended December 31, 2015. This decrease in net cash used in investing
activities included (i) a decrease of $53.6 million in our oil and natural gas properties capital expenditures for the year
ended December 31, 2016, as compared to the year ended December 31, 2015, (ii) an increase of approximately
$10.3 million in expenditures for midstream and other property and equipment, which includes the construction of
the Black River Processing Plant and new pipeline infrastructure, (iii) a decrease in cash used for acquisitions, as the
merger with Harvey E. Yates Company, a subsidiary of HEYCO Energy Group, Inc., occurred in 2015, (iv) a reduction
in proceeds from sales of assets as the sale of the Loving County Processing System to EnLink occurred in 2015
and (v) a decrease in our restricted cash of $43.7 million attributable to the release from escrow of potential like-kind-
exchange funds in connection with the sale of the Loving County Processing System to EnLink. Cash used for oil
and natural gas properties capital expenditures for the year ended December 31, 2016 was primarily attributable to
our operated and non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition
of additional acreage and mineral interests in the Delaware Basin.

Cash Flows Provided by Financing Activities

Net cash provided by ﬁnancing activities was $408.5 million for the year ended December 31, 2017, as compared

to net cash provided by ﬁnancing activities of $467.7 million for the year ended December 31, 2016. The net cash
provided by ﬁnancing activities for the year ended December 31, 2017 was primarily attributable to the total proceeds
from our October 2017 equity offering of $208.7 million, contributions related to the formation of San Mateo of
$171.5 million and contributions from non-controlling interest owners of less-than-wholly subsidiaries of $44.1 million,
offset by distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries of $10.0 million,
the payment of $5.8 million in taxes related to net share settlement of stock-based compensation and the purchase
of the non-controlling interest in a less-than-wholly-owned subsidiary of $2.7 million.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Net cash provided by ﬁnancing activities was $467.7 million for the year ended December 31, 2016, as compared

to net cash provided by ﬁnancing activities of $224.9 million for the year ended December 31, 2015. The net cash
provided by ﬁnancing activities for the year ended December 31, 2016 was primarily attributable to the total proceeds
of the 2016 equity offerings of $288.5 million, the total proceeds of the December 2016 notes offering of
$184.6 million and borrowings under our Credit Agreement of $120.0 million, offset by the costs of the 2016 equity
offerings of $0.8 million, the costs of the December 2016 notes offering of $2.7 million, the repayment of
$120.0 million in borrowings under our Credit Agreement in December 2016 and the payment of $1.9 million in
taxes related to net share settlement of stock-based compensation.

Net cash provided by ﬁnancing activities was $224.9 million for the year ended December 31, 2015, as compared

to net cash provided by ﬁnancing activities of $321.2 million for the year ended December 31, 2014. The net cash
provided by ﬁnancing activities for the year ended December 31, 2015 was primarily attributable to the total
proceeds of our April 2015 equity offering of $188.7 million, the total proceeds of our April 2015 notes offering of
$400.0 million, borrowings under our Credit Agreement of $125.0 million and capital contributed from the non-
controlling interest owners in our less-than-wholly-owned subsidiaries of $0.6 million, offset by the costs of the
April 2015 equity offering of $1.2 million, the costs of the April 2015 notes offering of $9.6 million, the repayment
of $477.0 million in borrowings under our Credit Agreement during the period and the payment of $1.6 million in
taxes related to net share settlement of stock-based compensation.

See Note 6 to the consolidated ﬁnancial statements in this Annual Report for a summary of our debt, including

our Credit Agreement and the senior notes.

OFF-BALANCE SHEET ARRANGEMENTS

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material

off-balance sheet obligations. As of December 31, 2017, the material off-balance sheet arrangements and
transactions that we have entered into include (i) operating lease agreements, (ii) non-operated drilling commitments,
(iii) termination obligations under drilling rig contracts, (iv) ﬁrm transportation, gathering, processing and disposal
commitments and (v) contractual obligations for which the ultimate settlement amounts are not ﬁxed and
determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates,
gathering, treating and transportation commitments on uncertain volumes of future throughput, open delivery
commitments and indemniﬁcation obligations following certain divestitures. Other than the off-balance sheet
arrangements described above, the Company has no transactions, arrangements or other relationships with
unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or
availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 13
to the consolidated ﬁnancial statements in this Annual Report for more information regarding our off-balance sheet
arrangements. Such information is incorporated herein by reference.

FORM 10-K PART I I

2017 ANNUAL REPORT

OBLIGATIONS AND COMMITMENTS

We had the following material contractual obligations and commitments at December 31, 2017.

Payments Due by Period

Total

Less Than
1 Year

1-3 Years

3-5 Years

More Than
5 Years

(In thousands)

Contractual Obligations:
Revolving credit borrowings, including letters of credit (1)
Senior unsecured notes (2)
Ofﬁce leases
Non-operated drilling commitments (3)
Drilling rig contracts (4)
Asset retirement obligations
Natural gas transportation, gathering and processing

2,100
575,000
22,620
24,842
36,517
26,256

—
—
2,495
24,842
27,499
1,176

— $ 2,100
—
5,434
—
—
2,350

—
5,130
—
9,018
779

—
575,000
9,561
—
—
21,951

agreements with non-afﬁliates (5)

200,262

11,922

30,847

45,046

112,447

Gathering, processing and disposal agreements

with San Mateo (6)

Natural gas plant engineering, procurement,
construction and installation contract (7)
Total contractual cash obligations

232,555

—

12,253

69,994

150,308

5,580
$ 1,125,732

5,580
$ 73,514

—
$58,027

—
$124,924

—
$869,267

(1) At December 31, 2017, we had no borrowings outstanding under the Credit Agreement and approximately $2.1 million in outstanding letters of

credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020.

(2) The amounts included in the table above represent principal maturities only. Interest expense on our 6.875% senior notes due 2023 that are

outstanding as of December 31, 2017 is expected to be approximately $39.5 million each year until maturity.

3) At December 31, 2017, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working
interests in these wells are typically small, and certain of these wells were in progress at December 31, 2017. If all of these wells are drilled
and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $24.8 million at
December 31, 2017, which we expect to incur within the next year.

(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 13 to the

consolidated ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

(5) Effective October 1, 2015, we entered into a 15-year ﬁxed-fee natural gas gathering and processing agreement for a signiﬁcant portion of our

operated natural gas production in Loving County, Texas. In addition, effective October 25, 2017, we entered into an 18-year ﬁxed-fee natural gas
transportation agreement where we committed to deliver a portion of the residue natural gas production at the tailgate of the Black River
Processing Plant to transport through the counterparty’s pipeline in Eddy County, New Mexico. In late 2017, we also entered into a ﬁxed-fee NGL
transportation and fractionation agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing
Plant. We are committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion
and a fractionation facility by the counterparty, which is currently expected to be completed late in 2019. We have no rights to compel the
counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and
fractionation facility, then we do not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline
extension and fractionation facility on or prior to February 28, 2021, then we will have a commitment to deliver a minimum amount of NGLs
for seven years following the completion of the pipeline extension and fractionation facility. If we do not meet our NGL volume commitment
in any quarter during the seven-year commitment period, we will be required to pay a deﬁciency fee per gallon of NGL deﬁciency. The amounts
in the table assume that the seven-year period containing minimum NGL volume commitments begins in late 2019. See Note 13 to the
consolidated ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

(6) Effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to

15-year, ﬁxed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017,
we dedicated our current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, ﬁxed-fee natural gas
processing agreement. See Note 13 to the consolidated ﬁnancial statements in this Annual Report for more information regarding these
contractual commitments.

(7) Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement,

construction and installation of an expansion of the Black River Processing Plant, including required compression. See Note 13 to the consolidated
ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

GENERAL OUTLOOK AND TRENDS

Our business success and ﬁnancial results are dependent on many factors beyond our control, such as

economic, political and regulatory developments, as well as competition from other sources of energy. Commodity
price volatility, in particular, is a signiﬁcant risk to our business and results of operations. Commodity prices are
affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of
OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and
other factors. Historically, the markets for oil, natural gas and NGLs have been volatile and these markets will likely
continue to be volatile in the future. Prices for oil, natural gas and NGLs affect the cash ﬂows available to us for
capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or NGL prices
not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or NGLs that we can produce
economically, and as a result, could have an adverse effect on our ﬁnancial condition, results of operations, cash
ﬂows and reserves. From time to time, we use derivative ﬁnancial instruments to mitigate our exposure to commodity
price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what
production volumes to hedge are difﬁcult and depend on market conditions and our forecast of future production
and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may
affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the
capital markets. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and
Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and
Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

In 2017, oil and natural gas prices remained signiﬁcantly below their most recent highs in 2014, although oil

prices, in particular, did begin to improve in the latter half of 2017. Oil prices had increased to $60.42 per Bbl in
late December 2017 from $53.72 on December 31, 2016. Natural gas prices had increased to $3.42 per MMBtu in
mid-May 2017 from $2.34 per MMBtu on December 31, 2016, but had declined to $2.60 per MMBtu in late
December 2017. The sharp declines in oil and natural gas prices since late 2014 impacted our revenues, proﬁtability
and cash ﬂows in 2015 and 2016, as compared to 2014, but the improvement in commodity prices, as well as our
increased oil and natural gas production, resulted in signiﬁcant improvements in our revenues, proﬁtability and cash
ﬂows during 2017. Future declines in oil and natural gas prices could have an adverse impact on our borrowing
capacity, ability to obtain additional capital, revenues, proﬁtability and cash ﬂows. We are uncertain if oil and natural
gas prices may continue to rise from their current levels, and in fact, oil and natural gas prices may decrease again
in future periods.

For the year ended December 31, 2017, oil prices averaged $50.80 per Bbl, ranging from a high of $60.42 per Bbl

in late December to a low of $42.53 per Bbl in late June, based upon the NYMEX West Texas Intermediate oil futures
contract price for the earliest delivery date. We realized a weighted average oil price of $49.28 per Bbl ($48.81
per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2017,
as compared to $41.19 per Bbl ($42.34 per Bbl including realized gains from oil derivatives) for the year ended
December 31, 2016. At February 21, 2018, the NYMEX West Texas Intermediate oil futures contract for the earliest
delivery date had improved somewhat, closing at $61.68 per Bbl, as compared to $54.06 per Bbl at February 21, 2017.

For the year ended December 31, 2017, natural gas prices averaged $3.02 per MMBtu, ranging from a high of
approximately $3.42 per MMBtu in mid-May to a low of approximately $2.56 per MMBtu in late February, based upon
the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted
average natural gas price of $3.72 per Mcf ($3.70 per Mcf including realized losses from natural gas derivatives) for
our natural gas production for the year ended December 31, 2017, as compared to $2.66 per Mcf ($2.78 per Mcf
including realized gains from natural gas and NGL derivatives) for the year ended December 31, 2016. At February 21,
2018, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had remained relatively unchanged
from late December 2017, closing at $2.66 per MMBtu, as compared to $2.56 per MMBtu at February 21, 2017.

FORM 10-K PART I I

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Coinciding with the improvements in oil and natural gas prices during 2017, we have experienced price increases

from our service providers for some of the products and services we use in our drilling, completion and production
operations. If oil and natural gas prices remain at their current levels for a longer period of time or should they increase
further, we would anticipate receiving additional price increases for drilling, completion and production products and
services, although we can provide no assurances as to the eventual magnitude of these increases.

Like other oil and natural gas producing companies, our properties are subject to natural production declines.

By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to
overcome these production declines by drilling to develop and identify additional reserves, by exploring for new
sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines,
however, drilling additional oil or natural gas wells may not be economic, and we may ﬁnd it necessary to reduce
capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital
expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash ﬂows
and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development, Exploitation
and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from
Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms,
Which Could Adversely Affect Our Future Growth.”

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at

a level that is appropriate for long-term operations. Our ability to ﬁnd and develop sufﬁcient quantities of oil and
natural gas reserves at economical costs is critical to our long-term success. Future ﬁnding and development costs
are subject to changes in the costs of acquiring, drilling and completing our prospects.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of ﬁnancial statements in conformity with GAAP requires us to make estimates and assumptions

that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period.
We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will
not differ signiﬁcantly from those reported; however, such estimates and assumptions are subject to a number of
risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our
estimates. We consider the following to be our most critical accounting policies and estimates involving signiﬁcant
judgment or estimates by our management. See Note 2 to the consolidated ﬁnancial statements in this Annual
Report for further details on our accounting policies at December 31, 2017. Such information is incorporated herein
by reference.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this
method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas
properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and
accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.
Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped
properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects
and general and administrative expenses directly related to acquisition, exploration and development activities, but
do not include any costs related to production, selling or general corporate administrative activities.

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Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon

production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded
from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for
possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment
includes consideration of the following factors, among others: the assignment of proved reserves, geological and
geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the
costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory
dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or

loss recognized, unless such adjustments would signiﬁcantly alter the relationship between net capitalized costs
and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are
expensed as incurred. Signiﬁcant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less

related deferred income taxes or the cost center “ceiling.” The cost center ceiling is deﬁned as the sum of:

(a)

the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves,
reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c)

the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs
being amortized, if any, less

(d)

income tax effects related to the properties involved.

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations

as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test
computation as we do not designate these instruments as hedge instruments for accounting purposes.

Because the cost center ceiling calculation is based on the average of historical prices, which may or may not
be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be
indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized
costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the
ultimate value of the related reserves.

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Derivative Financial Instruments

From time to time, we use derivative ﬁnancial instruments to mitigate our exposure to commodity price risk
associated with oil, natural gas and NGL prices. These instruments typically consist of put and call options in the
form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price
protection through the purchase of a put option which is ﬁnanced through the sale of a call option. Because the call
option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In
the case of a costless collar, the put option and the call option have different ﬁxed price components. In a swap
contract, a ﬂoating price is exchanged for a ﬁxed price over a speciﬁed period, providing downside price protection.

Prior to settlement, our derivative ﬁnancial instruments are recorded on the balance sheet as either an asset or a

liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative ﬁnancial
instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in
our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized
gain (loss) on derivatives.” Changes in the fair value of these open derivative ﬁnancial instruments can have a
signiﬁcant impact on our reported results from period to period but do not impact our cash ﬂows from operations,
liquidity or capital resources. The fair value of our open derivative ﬁnancial instruments is determined using
industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value of money and (iii) current market and contractual prices for the underlying instruments, as well as other
relevant economic measures.

Realized gains and realized losses from the settlement of derivative ﬁnancial instruments do have a direct impact
on our cash ﬂow from operations and liquidity. The impact of these settlements is also reported under Revenues as
“Realized gain (loss) on derivatives.”

Revenue Recognition

We follow the sales method of accounting for our oil, natural gas and NGL revenue, whereby we recognize
revenue, net of royalties, on all oil, natural gas and NGLs sold to purchasers regardless of whether the sales are
proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural
gas and NGLs are produced and sold, and we accrue for revenue earned but not yet received. We recognize
midstream services revenues at the time services have been rendered and the price is ﬁxed and determinable.
See Note 2 to the consolidated ﬁnancial statements in this Annual Report for a description of the impact of the
adoption of Accounting Standard Update 2014-09, Revenue from Contracts with Customers (Topic 606) on our 2018
consolidated ﬁnancial statements.

)

Stock-Based Compensation

We account for stock-based compensation in accordance with Accounting Standards Codiﬁcation 718. Since
2012, all stock option awards have been granted under the 2012 Long-Term Incentive Plan or, for awards granted
after June 10, 2015, under the Amended and Restated 2012 Long-Term Incentive Plan, and all of these awards
were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards
were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these awards have been
accounted for as liability instruments. We used the fair value method to measure and recognize the liability
associated with our outstanding liability-based stock options and to measure and recognize the equity associated
with our equity-based stock options. Stock options typically vest over three or four years, and the associated
compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted
stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight
line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, prior to the

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beginning of 2016, we estimated the future volatility of our stock using the historical volatility of the common stock
of a group of companies we consider to be a representative peer group. Beginning in 2016, we began using our
own historical volatility to estimate the future volatility of our stock as we had four years of historical stock prices as
a publicly traded company. Management believes that, beginning in 2016, our own average historical volatility rates
are the best available indicator of future volatility.

We have adopted the “simpliﬁed method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the
expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a
term to maturity that is consistent with the expected term of the award.

Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding

liability-based option awards. The assumptions used may be impacted by actual ﬂuctuations in our stock price,
movements in market interest rates and option terms. The use of different assumptions produces a different fair
value for equity-based option awards and outstanding liability-based option awards and can signiﬁcantly impact the
amount of stock compensation expense recognized in our consolidated statement of operations. We use the
Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method
to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and
restricted stock unit awards is recognized based on the fair value of our stock on the date of the grant. See Note 8
to the consolidated ﬁnancial statements in this Annual Report for further details on our stock-based compensation
at December 31, 2017. Such information is incorporated herein by reference.

Income Taxes

We account for income taxes using the asset and liability approach for ﬁnancial accounting and reporting. The
amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state
taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses
and tax carryforwards. We evaluate the probability of realizing the future beneﬁts of our deferred tax assets and
provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income
tax beneﬁt in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the ﬁnancial statement beneﬁt of a tax position only

after determining that the relevant tax authority would more likely than not sustain the position following an audit.
For tax positions meeting the more likely than not threshold, the amount recognized in the ﬁnancial statements is
the beneﬁt that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax
authority. See Note 7 to the consolidated ﬁnancial statements in this Annual Report for additional information of the
impact of the 2017 Tax Cuts and Jobs Act to our consolidated ﬁnancial statements.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future

net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have
elected to present only proved reserves in this Annual Report. The applicable rules deﬁne proved reserves as the
quantities of oil and natural 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.

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Our engineers and technical staff must make many subjective assumptions based on their professional

judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent
production levels and other technical information about each well. Estimating oil and natural gas reserves is complex
and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations
of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and
reliability of both the data and the associated interpretations can vary. The process also requires certain economic
assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses,
capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our
estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are
ultimately recovered. Any signiﬁcant variance could materially and adversely affect our future reserves estimates,
ﬁnancial condition, results of operations and cash ﬂows. We cannot predict the amounts or timing of future reserves
revisions. If such revisions are signiﬁcant, they could signiﬁcantly affect future amortization of capitalized costs
and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves
Are Estimated and May Not Reﬂect the Actual Volumes of Oil and Natural Gas We Will Recover, and Signiﬁcant
Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and
Present Value of Our Reserves.”

Recent Accounting Pronouncements

See Note 2 to the consolidated ﬁnancial statements in this Annual Report for a description of recent accounting

pronouncements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty
and customer risk. We address these risks through a program of risk management including the use of derivative
ﬁnancial instruments, but we do not enter into derivative ﬁnancial instruments for trading purposes.

Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs ﬂuctuate

as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these
market ﬂuctuations, we have entered into derivative ﬁnancial instruments in the past and expect to enter into
derivative ﬁnancial instruments in the future to cover a signiﬁcant portion of our anticipated future production.

We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil,

natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of
a put option which is ﬁnanced through the sale of a call option. Because the call option proceeds are used to offset
the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the
put option and the call option have different ﬁxed price components. In a swap contract, a ﬂoating price is exchanged
for a ﬁxed price over a speciﬁed period, providing downside price protection.

We record all derivative ﬁnancial instruments at fair value. The fair value of our derivative ﬁnancial instruments is

determined using purchase and sale information available for similarly traded securities. At December 31, 2017,
RBC, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and SunTrust Bank (or afﬁliates thereof)
were the counterparties for all of our derivative instruments. We have considered the credit standing of the
counterparties in determining the fair value of our derivative ﬁnancial instruments.

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At December 31, 2017, we had entered into various costless collar and swap contracts to mitigate our exposure

to ﬂuctuations in oil, natural gas and NGL prices, each with an established price ﬂoor and ceiling for the costless
collars and ﬁxed price for the swaps. When the settlement price is below the price ﬂoor established by one or more
of these collars, we receive from our counterparty an amount equal to the difference between the settlement price
and the price ﬂoor multiplied by the contract oil, natural gas or NGL volume. When the settlement price is above
the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the
difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume.

During the year ended December 31, 2017, we entered into various swap contracts to mitigate our exposure to
price differences between NYMEX West Texas Intermediate Cushing and Argus West Texas Intermediate Midland
crude oil and to ﬂuctuations in NGL prices. When the settlement price is below the ﬁxed price established by one
or more of these swaps, we receive from the counterparty an amount equal to the difference between the
settlement price and the ﬁxed price multiplied by the contract oil or NGL volume. When the settlement price is
above the ﬁxed price established by one or more of these swaps, we pay to the counterparty an amount equal to
the difference between the settlement price and the ﬁxed price multiplied by the contract oil or NGL volume.

See Note 11 to the consolidated ﬁnancial statements in this Annual Report for a summary of our open derivative

ﬁnancial instruments at December 31, 2017. Such information is incorporated herein by reference.

Effect of Derivatives Legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the
Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products,
including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading
Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although
the CFTC has ﬁnalized certain regulations, others remain to be ﬁnalized or implemented, and it is not possible at
this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make
with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and
adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act
could result in the implementation of position limits and additional regulatory requirements on our derivative
arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation
could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements
in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact
on Our Ability to Hedge Risks Associated with Our Business.”

Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an
attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the ﬁrst
time in December 2010. At December 31, 2017, we had no outstanding borrowings under our Credit Agreement
and $575.0 million in senior notes outstanding at a coupon rate of 6.875% per annum. If we incur additional
indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives
would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial
interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases
on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit
risk due to concentration of our oil and natural gas receivables with several signiﬁcant customers. The inability
or failure of our signiﬁcant customers to meet their obligations to us or their insolvency or liquidation may adversely
affect our ﬁnancial condition, results of operations and cash ﬂows. In addition, our oil, natural gas and NGL
derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties.

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While we do not require our customers to post collateral and we do not have a formal process in place to
evaluate and assess the credit standing of our signiﬁcant customers for oil and natural gas receivables and the
counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem
appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to
determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest ﬁnancial
information and, in the case of a customer with which we have receivables, its historical payment record and the
ﬁnancial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence
necessary to determine credit terms and credit limits. The counterparties on our derivative ﬁnancial instruments in
place at February 21, 2018 were RBC, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and
SunTrust Bank (or afﬁliates thereof), which are lenders (or afﬁliates thereof) under our Credit Agreement, and we are
likely to enter into any future derivative instruments with such banks or other lenders (or afﬁliates thereof) party to
the Credit Agreement.

Impact of Inﬂation. Inﬂation in the United States has been relatively low in recent years and did not have a
material impact on our results of operations for the years ended December 31, 2017, 2016 and 2015. Although the
impact of inﬂation has been generally insigniﬁcant in recent years, it is still a factor in the U.S. economy and we
tend to speciﬁcally experience inﬂationary pressure on the cost of oilﬁeld services and equipment with increases in
oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp
and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk
Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and
Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish
and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a
Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our ﬁnancial statements appear at the end of this Annual Report. See the index to the ﬁnancial statements in

Item 15.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE.

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and
operation of the Company’s disclosure controls and procedures (as deﬁned in Rule 13a-15(e) under the Exchange
Act) under the supervision and with the participation of our management, including our Chief Executive Ofﬁcer
and our Chief Financial Ofﬁcer. Based on that evaluation, our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer
concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017 to
ensure that (i) information required to be disclosed in the reports it ﬁles and submits under the Exchange Act is
recorded, processed, summarized and reported within the time periods speciﬁed in the SEC’s rules and forms and
that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the
Company’s management, including our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer, as appropriate to
allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended September 30, 2017, we completed the implementation of new accounting and
land administration software applications. We have taken the necessary steps to monitor and maintain appropriate
internal control over ﬁnancial reporting during this period of change, including procedures to preserve the integrity of
the data converted during the application implementations. Additionally, we provided training related to these
applications to individuals using the applications to carry out their job responsibilities. We believe the new applications
will enhance our internal control over ﬁnancial reporting due to enhanced automation and integration of related
processes. As a result, we have modiﬁed the design and documentation of internal control processes and
procedures relating to the new applications to complement and supplement existing internal control documentation.
The implementation of the new applications was not undertaken in response to any deﬁciencies in our internal
control over ﬁnancial reporting.

During the three months ended December 31, 2017, we completed the implementation of a new reserves
software application. We have taken the necessary steps to monitor and maintain appropriate internal control over
ﬁnancial reporting during this period of change, including procedures to preserve the integrity of the data converted
during the application implementations. Additionally, we provided training related to this application to individuals
using the application to carry out their job responsibilities. We believe this new application will enhance our
internal control over ﬁnancial reporting due to enhanced automation and integration of related processes. We have
modiﬁed the design and documentation of internal control processes and procedures relating to this new
application to complement and supplement existing internal control documentation. The implementation of the
new reserves software application was not undertaken in response to any deﬁciencies in our internal control over
ﬁnancial reporting.

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During the three months ended December 31, 2017, we completed the design and documentation of internal

control processes and procedures relating to the new accounting, land administration and reserves software
applications. Testing of the controls related to the new applications is completed and is included in the scope of our
assessment of our internal control over ﬁnancial reporting for the year ended December 31, 2017.

There were no other changes in our internal controls that have materially affected or are reasonably likely to have

a material effect on our internal control over ﬁnancial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over ﬁnancial reporting

as deﬁned in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the
participation of our management, including our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer, we assessed
the effectiveness of our internal control over ﬁnancial reporting as of the end of the period covered by this Annual
Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Ofﬁcer
and our Chief Financial Ofﬁcer concluded that our internal control over ﬁnancial reporting was effective to provide
reasonable assurance regarding the reliability of our ﬁnancial reporting and the preparation of our ﬁnancial
statements for external purposes in accordance with U.S. generally accepted accounting principles.

KPMG, our independent registered public accounting ﬁrm, has issued an attestation report on our controls over

ﬁnancial reporting as of December 31, 2017 as included herein.

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over ﬁnancial reporting is
subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions
about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk
of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions and the risk that the degree of compliance with
policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that
any system of disclosure controls and procedures or internal control over ﬁnancial reporting will be successful in
preventing all errors or fraud or in making all material information known in a timely manner to the appropriate
levels of management.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
Matador Resources Company:

Opinion on Internal Control Over Financial Reporting

We have audited Matador Resources Company’s (the “Company”) internal control over ﬁnancial reporting as of
December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company
maintained, in all material respects, effective internal control over ﬁnancial reporting as of December 31, 2017, based
on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).

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, 2017 and 2016, the related
statements of operations, changes in shareholders’ equity, and cash ﬂows for each of the years in the three-year
period ended December 31, 2017, and the related notes (collectively, the “consolidated ﬁnancial statements”), and our
report dated February 28, 2018 expressed an unqualiﬁed opinion on those consolidated ﬁnancial statements.

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 of internal control over ﬁnancial reporting included obtaining an
understanding of internal control over ﬁnancial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit
also included 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/ KPMG LLP

Dallas, Texas
February 28, 2018

FORM 10-K PART I I

ITEM 9B. OTHER INFORMATION.

Not applicable.

2017 ANNUAL REPORT

107

FORM 10-K PART I I

108

MATADOR RESOURCES COMPANY

Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required in response to this Item 10 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 11. EXECUTIVE COMPENSATION.

The information required in response to this Item 11 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS.

Certain information regarding securities authorized for issuance under our equity compensation plans is included

under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report and is
incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by
reference to our deﬁnitive proxy statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated
under the Exchange Act not later than 120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR

INDEPENDENCE.

The information required in response to this Item 13 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required in response to this Item 14 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

FORM 10-K PART I I I

2017 ANNUAL REPORT

109

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

The following documents are ﬁled as part of this Annual Report:

1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm,

Consolidated Balance Sheets as of December 31, 2017 and 2016, Consolidated Statements of Operations
for the Years Ended December 31, 2017, 2016 and 2015, Consolidated Statements of Changes in
Shareholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015 and Consolidated Statements
of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015.

2. Exhibits: The exhibits required to be ﬁled by this Item 15 are set forth in the Exhibit Index accompanying

this Annual Report.

FORM 10-K PART I V

110

MATADOR RESOURCES COMPANY

Exhibit Index

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

2.10

2.11

2.12

3.1

3.2

3.3

3.4

3.5

4.1

Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company),
Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011
(incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1 ﬁled on August 12, 2011).

Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates
Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1
to the Current Report on Form 8-K ﬁled on January 20, 2015).*

Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.3 to the Annual Report on Form 10-K for the year ended December 31, 2014).

Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.4 to the Annual Report on Form 10-K for the year ended December 31, 2014).

Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.5 to the Annual Report on Form 10-K for the year ended December 31, 2014).*

Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.2 to the Current Report on Form 8-K ﬁled on March 2, 2015).*

Amendment No. 5 to Agreement and Plan of Merger, dated as of April 15, 2015, by and among HEYCO Energy Group,
Inc., Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K ﬁled on April 15, 2015).

Amendment No. 6 to Agreement and Plan of Merger, dated as of July 20, 2015, by and among HEYCO Energy Group,
Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by
reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Amendment No. 7 to Agreement and Plan of Merger, dated as of August 24, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Amendment No. 8 to Agreement and Plan of Merger, dated as of September 18, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Amendment No. 9 to Agreement and Plan of Merger, dated as of March 1, 2016, by and among HEYCO Energy Group,
Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by
reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016).

Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream
Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K ﬁled on February 24, 2017).*

Certiﬁcate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador
Merger Co. (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 ﬁled on August 12, 2011).

Amended and Restated Certiﬁcate of Formation of Matador Resources Company (incorporated by reference to Exhibit
3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

Certiﬁcate of Amendment to the Amended and Restated Certiﬁcate of Formation of Matador Resources Company
dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 2017).

Certiﬁcate of Amendment to the Amended and Restated Certiﬁcate of Formation of Matador Resources Company
effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 2017).

Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1
to the Current Report on Form 8-K ﬁled on February 22, 2018).

Form of Common Stock Certiﬁcate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration
Statement on Form S-1 ﬁled on January 19, 2012).

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111

Exhibit
Number

Description

4.2

4.3

4.4

4.5

4.6

4.7

10.1†

10.2†

10.3†

10.4†

10.5†

10.6†

10.7†

10.8†

10.9†

10.10†

10.11†

Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy
Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled on March 2, 2015).

Indenture, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party
thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current
Report on Form 8-K ﬁled on April 14, 2015).

First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf
Midstream, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by
reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled on October 5, 2015).

Second Supplemental Indenture, dated as of November 4, 2015, by and among Matador Resources Company, MRC
Permian LKE Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee
(incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Third Supplemental Indenture, dated as of June 8, 2016, by and among Matador Resources Company, Black River Water
Management Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee
(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled on June 14, 2016).

Fourth Supplemental Indenture, dated as of February 17, 2017, by and among Matador Resources Company, Black River
Water Management Company, LLC, DLK Black River Midstream, LLC, Longwood Midstream Holdings, LLC, the
Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit
4.1 to the Current Report on Form 8-K ﬁled on February 24, 2017).

Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to
Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on November 14, 2011).

Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to
Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on November 14, 2011).

Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to
Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on November 14, 2011).

Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to
Exhibit 10.6 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran
(incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on
November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster
(incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on
November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford
(incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on
November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson
(incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on
November 14, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran
(incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 ﬁled on
December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster
(incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 ﬁled on
December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford
(incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 ﬁled on
December 30, 2011).

FORM 10-K PART I V

112

MATADOR RESOURCES COMPANY

Exhibit
Number

10.12†

10.13†

10.14†

10.15†

10.16†

10.17†

10.18†

10.19†

10.20†

10.21†

10.22†

10.23†

10.24†

10.25†

10.26†

10.27†

Description

Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson
(incorporated by reference to Exhibit 10.15 to Amendment No. 2 to the Registration Statement on Form S-1 ﬁled on
December 30, 2011).

Matador Resources Company Amended and Restated Annual Incentive Plan for Management and Key Employees
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on June 14, 2016).

Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October
23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to the Registration Statement on Form S-1
ﬁled on November 14, 2011).

First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to the Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and
Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to the
Registration Statement on Form S-1 ﬁled on November 14, 2011).

Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement
on Form S-1 ﬁled on November 14, 2011).

Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and
Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to the
Registration Statement on Form S-1 ﬁled on December 30, 2011).

Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year
ended December 31, 2012).

Form of Indemniﬁcation Agreement between Matador Resources Company and each of the directors and executive
ofﬁcers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form
S-1 ﬁled on November 14, 2011).

Form of Non-Qualiﬁed Stock Option Agreement granted pursuant to the Matador Resources Company (now known as
MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report
on Form 10-K for the year ended December 31, 2011).

Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC
Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on
Form 10-K for the year ended December 31, 2011).

Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended
December 31, 2011).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report
on Form 10-Q for the quarter ended March 31, 2012).

FORM 10-K PART I V

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113

Exhibit
Number

10.28†

10.29†

10.30†

10.31

10.32

10.33

10.34

10.35

10.36

10.37

10.38

10.39

10.40

10.41

10.42

Description

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report
on Form 10-Q for the quarter ended March 31, 2012).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on
Form 10-Q for the quarter ended March 31, 2012).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on
Form 10-Q for the quarter ended March 31, 2012).

Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy
Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada,
as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on
October 4, 2012).

Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company,
Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of
September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended
December 31, 2012).

Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC
Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood
Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative
Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K
for the year ended December 31, 2012).

First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012).

Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled June 6, 2013).

Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).

Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013).

Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on September 8, 2014).

Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K ﬁled on April 14, 2015).

Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on October 21, 2015).

Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on November 2, 2016).

Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of
December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of
Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K ﬁled on
December 9, 2016).

FORM 10-K PART I V

114

MATADOR RESOURCES COMPANY

Exhibit
Number

10.43

10.44†

10.45†

10.46†

10.47†

10.48†

10.49†

10.50

10.51†

10.52†

10.53

10.54†

10.55†

10.56†

10.57†

10.58†

10.59†

Description

Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on May 4, 2017)

Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by
reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013).

Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective
February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended
December 31, 2014).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report
on Form 10-K for the year ended December 31, 2014).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.55 to the Annual Report
on Form 10-K for the year ended December 31, 2014).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company Amended and Restated
2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit
10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012
Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54
to the Annual Report on Form 10-K for the year ended December 31, 2015).

Purchase Agreement, dated as of April 9, 2015, by and among Matador Resources Company, the subsidiary guarantors
party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers
named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on April 14, 2015).

Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report
on Form 8-K ﬁled on June 11, 2015).

Matador Resources Company Nonqualiﬁed Deferred Compensation Plan for Non-Employee Directors (incorporated by
reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015).

Purchase Agreement, dated as of December 6, 2016, by and among Matador Resources Company, the subsidiary
guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial
purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on
December 9, 2016).

Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.62 to the Annual Report on Form 10-K for the year ended
December 31, 2016).

Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company
2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the
year ended December 31, 2016).

Form of Letter Agreement between Matador Resources Company and certain directors modifying Restricted Stock
Unit Award Agreements (incorporated by reference to Exhibit 10.64 to the Annual Report on Form 10-K for the year
ended December 31, 2016).

Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg
Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for
the quarter ended March 31, 2017).

Form of Restricted Stock Unit Award Agreement for Annual Grants relating to the Matador Resources Company
Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly
Report on Form 10-Q for the quarter ended June 30, 2017).

Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador
Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4
to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

FORM 10-K PART I V

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115

Exhibit
Number

10.60†

10.61†

10.62†

10.63†

10.64†

10.65†

10.66†

21.1

23.1

23.2

31.1

31.2

32.1

32.2

99.1

101

Description

Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended
September 30, 2017).

Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company Amended
and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on
Form 10-Q for the quarter ended September 30, 2017).

Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador
Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3
to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Nonqualiﬁed Stock Option Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to
Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Nonqualiﬁed Stock Option Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to
Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to
Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to
Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

List of Subsidiaries of Matador Resources Company (ﬁled herewith).

Consent of KPMG LLP (ﬁled herewith).

Consent of Netherland, Sewell & Associates, Inc. (ﬁled herewith).

Certiﬁcation of Principal Executive Ofﬁcer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (ﬁled herewith).

Certiﬁcation of Principal Financial Ofﬁcer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (ﬁled herewith).

Certiﬁcation of Principal Executive Ofﬁcer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (furnished herewith).

Certiﬁcation of Principal Financial Ofﬁcer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (furnished herewith).

Audit report of Netherland, Sewell & Associates, Inc. (ﬁled herewith).

The following ﬁnancial information from Matador Resources Company’s Annual Report on Form 10-K for the year
ended December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance
Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’
Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements
(submitted electronically herewith).

†

Indicates a management contract or compensatory plan or arrangement.

* Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the

SEC upon request.

FORM 10-K PART I V

116

MATADOR RESOURCES COMPANY

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has

duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 28, 2018

MATADOR RESOURCES COMPANY

By:

/s/ JOSEPH WM. FORAN
Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual 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/ JOSEPH WM. FORAN
Joseph Wm. Foran

Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

February 28, 2018

/s/ DAVID E. LANCASTER
David E. Lancaster

Executive Vice President and Chief Financial Ofﬁcer
(Principal Financial Ofﬁcer)

February 28, 2018

/s/ ROBERT T. MACALIK
Robert T. Macalik

Senior Vice President and Chief Accounting Ofﬁcer
(Principal Accounting Ofﬁcer)

February 28, 2018

/s/ REYNALD A. BARIBAULT
Reynald A. Baribault

/s/ R. GAINES BATY
R. Gaines Baty

/s/ CRAIG T. BURKERT
Craig T. Burkert

/s/ WILLIAM M. BYERLEY
William M. Byerley

/s/ JULIA P. FORRESTER
Julia P. Forrester

/s/ STEVEN W. OHNIMUS
Steven W. Ohnimus

/s/ TIMOTHY E. PARKER
Timothy E. Parker

/s/ DAVID M. POSNER
David M. Posner

/s/ KENNETH L. STEWART
Kenneth L. Stewart

/s/ GEORGE M. YATES
George M. Yates

FORM 10-K Signatures

Director

February 28, 2018

2017 ANNUAL REPORT

117

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this

Annual Report.

Batch drilling. The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the
surface holes for each well are drilled ﬁrst and then the production holes, including the horizontal laterals for each
well, are drilled.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil,

other liquid hydrocarbons or salt water.

Bcf. One billion cubic feet of natural gas.

BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids

to six Mcf of natural gas.

BOE/d. BOE per day.

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

degree Fahrenheit.

Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving

perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the
reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reservoir.

Conventional reservoirs or resources. Natural gas or oil that is produced by a well drilled into a geologic formation

in which the reservoir and ﬂuid characteristics permit the natural gas or oil to readily ﬂow to the wellbore.

Coring. The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter,

taken as a sample of an underground formation. It is common practice to take cores from wells in the process
of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the
formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its
characteristics (porosity, permeability, etc.) are determined.

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

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon

known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufﬁcient quantities such that proceeds from

the sale of such production exceed production-related expenses and taxes.

Exploratory well. A well drilled to ﬁnd and produce oil or natural gas reserves not classiﬁed as proved, to ﬁnd
a new reservoir in a ﬁeld previously found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease
assigns the working interest or a portion of the working interest to another party who desires to drill on the leased
acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.
The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a
“farmin” while the interest transferred by the assignor is a “farmout.”

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.

Glossary of Oil and Natural Gas Terms FORM 10-K

118

MATADOR RESOURCES COMPANY

Gross acres or gross wells. The total acres or wells in which a working interest is owned.

Held by production. An oil and natural gas property under lease in which the lease continues to be in force after

the primary term of the lease in accordance with its terms as a result of production from the property.

Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a

productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to
produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace
multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.

Hydraulic fracturing. The technique of improving a well’s production or injection rates by pumping a mixture of
ﬂuids into the formation and rupturing the rock, creating an artiﬁcial channel. As part of this technique, sand or other
material may also be injected into the formation to prop the channel open, so that ﬂuids or gases may more easily
ﬂow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to
as fracture stimulation.

Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane

and natural gasoline resulting from the further processing of liqueﬁable hydrocarbons separated from raw natural
gas by a natural gas processing facility.

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

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.

Net revenue interest. The interest that deﬁnes the percentage of revenue that an owner of a well receives from

the sale of oil, natural gas and/or natural gas liquids that are produced from the well.

NYMEX. New York Mercantile Exchange.

Overriding royalty interest. A fractional interest in the gross production of oil and natural gas under a lease, in
addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating,
marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is
an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest.

Pad. The surface constructed to accommodate the drilling, completion and production operations of an oil or

natural gas well.

Pad drilling. The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well

on the pad is drilled to total depth before the next well is initiated.

Permeability. A reference to the ability of oil and/or natural gas to ﬂow through a reservoir.

Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools
inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface,
then combining these measurements with other relevant geological and geophysical information to describe the
reservoir rock properties.

FORM 10-K Glossary of Oil and Natural Gas Terms

2017 ANNUAL REPORT

119

Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and
temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.

Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.

Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in

sum with proved reserves, are as likely as not to be recovered.

Producing well, or productive well. A well that is found to be capable of producing hydrocarbons in sufﬁcient
quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.

Properties. Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other

mineral fee, leasehold and related interests.

Prospect. A speciﬁc geographic area which, based on supporting geological, geophysical or other data and

preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the
discovery of commercial hydrocarbons.

Proved developed non-producing. Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the
production of which has been postponed pending installation of surface equipment or gathering facilities, or pending
the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classiﬁed
as proved developed but non-producing reserves.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and

facilities and by existing operating methods.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of

the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled

acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. Completing in the same wellbore to reach a new reservoir after production from the original

reservoir has been abandoned.

Repeatability. The potential ability to drill multiple wells within a prospect or trend.

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

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive

a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties
may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is
granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.

2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation

of reﬂection seismic data collected along a single source proﬁle.

3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the
interpretation of reﬂection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do 2-D seismic surveys and contribute signiﬁcantly to ﬁeld appraisal,
exploitation and production.

Glossary of Oil and Natural Gas Terms FORM 10-K

120

MATADOR RESOURCES COMPANY

Spud. The act of beginning to drill an oil or natural gas well.

Throughput. The volume of product transported or passing through a pipeline, plant or other facility.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully deﬁned,
having geological characteristics that have been ascertained through supporting geological, geophysical or other data
to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves

warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and
(ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural
gas resources.

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 and natural gas, regardless of whether such acreage contains
proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to
productive wells.

Unproved and unevaluated properties. Properties where no drilling or other actions have been undertaken that

permit such properties to be classiﬁed as proved and to which no proved reserves have been assigned.

Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water ﬂows or is pumped.

Visualization. An exploration technique in which the size and shape of subsurface features are mapped and

analyzed based upon information derived from well logs, seismic data and other well information.

Volumetric reserve analysis. A technique used to estimate the amount of recoverable oil and natural gas. It

involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation,
formation volume factor and recovery factor.

Walking rig. A drilling rig that is capable of moving from one drilling location to another a short distance away

using a series of hydraulic “feet” built into the substructure of the rig.

Wellbore. The hole made by a well.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating

activities on the property and receive a share of production.

FORM 10-K Glossary of Oil and Natural Gas Terms

2017 ANNUAL REPORT

F-1

Consolidated Financial Statements

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2017, 2016 and 2015

Contents

Page

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-2

Consolidated Financial Statements

Consolidated Balance Sheets as of December 31, 2017 and 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015 . . . . . . . . . . .

Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2017,

2016 and 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 . . . . . . . . . .

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-3

F-4

F-5

F-6

F-7

Unaudited Supplementary Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-42

Consolidated Financial Statements FORM 10-K

F-2

MATADOR RESOURCES COMPANY

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
Matador Resources Company:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries

(collectively the “Company”) as of December 31, 2017 and 2016 and the related consolidated statements of
operations, changes in shareholders’ equity and cash ﬂows for each of the years in the three-year period ended
December 31, 2017, and the related notes (collectively, the “consolidated ﬁnancial statements”). In our opinion,
the consolidated ﬁnancial statements present fairly, in all material respects, the ﬁnancial position of the Company as
of December 31, 2017 and 2016 and the results of its operations and its cash ﬂows for each of the years in the
three-year period ended December 31, 2017, 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, 2017, based
on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report dated February 28, 2018 expressed an unqualiﬁed
opinion on the effectiveness of the Company’s internal control over ﬁnancial reporting.

Basis for Opinion

These consolidated ﬁnancial statements are the responsibility of the Company’s management. Our responsibility

is to express an opinion on these consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated ﬁnancial statements. We believe that our audits provide a reasonable basis
for our opinion.

We have served as the Company’s auditor since 2014.

/s/ KPMG LLP

Dallas, Texas
February 28, 2018

FORM 10-K Consolidated Financial Statements

Consolidated Balance Sheets

Matador Resources Company and Subsidiaries

(In thousands, except par value and share data)

ASSETS
Current assets

Cash
Restricted cash
Accounts receivable
Oil and natural gas revenues
Joint interest billings
Other
Derivative instruments
Lease and well equipment inventory
Prepaid expenses and other assets

Total current assets
Property and equipment, at cost

Oil and natural gas properties, full-cost method
Evaluated
Unproved and unevaluated
Midstream and other property and equipment
Less accumulated depletion, depreciation and amortization

Net property and equipment

Other assets

Total assets

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Accounts payable
Accrued liabilities
Royalties payable
Amounts due to afﬁliates
Derivative instruments
Advances from joint interest owners
Amounts due to joint ventures
Other current liabilities

Total current liabilities

Long-term liabilities

Senior unsecured notes payable
Asset retirement obligations
Derivative instruments
Amounts due to joint ventures
Other long-term liabilities

Total long-term liabilities

Commitments and contingencies (Note 13)
Shareholders’ equity

Common stock — $0.01 par value, 160,000,000 and 120,000,000 shares authorized;
108,513,597 and 99,518,764 shares issued; and 108,510,160 and 99,511,931 shares
outstanding, respectively

Additional paid-in capital
Accumulated deﬁcit
Treasury stock, at cost, 3,437 and 6,833 shares, respectively

Total Matador Resources Company shareholders’ equity

Non-controlling interest in subsidiaries

Total shareholders’ equity

Total liabilities and shareholders’ equity

The accompanying notes are an integral part of these ﬁnancial statements.

2017 ANNUAL REPORT

F-3

December 31,

2017

2016

96,505
5,977

212,884
1,258

65,962
67,225
8,031
1,190
5,993
6,287
257,170

34,154
19,347
5,167
—
3,045
3,327
279,182

3,004,770
637,396
281,096
(2,041,806)
1,881,456
7,064
$ 2,145,690

2,408,305
479,736
160,795
(1,864,311)
1,184,525
958
$ 1,464,665

11,757
174,348
61,358
10,302
16,429
2,789
4,873
750
282,606

574,073
25,080
—
—
6,385
605,538

4,674
101,460
23,988
8,651
24,203
1,700
4,251
578
169,505

573,924
19,725
751
1,771
7,544
603,715

1,085
1,666,024
(510,484)
(69)
1,156,556
100,990
1,257,546
$ 2,145,690

995
1,325,481
(636,351)
—
690,125
1,320
691,445
$ 1,464,665

Consolidated Financial Statements FORM 10-K

F-4

MATADOR RESOURCES COMPANY

Consolidated Statements of Operations

Matador Resources Company and Subsidiaries

(In thousands, except per share data)

Revenues

Oil and natural gas revenues
Third-party midstream services revenues
Realized (loss) gain on derivatives
Unrealized gain (loss) on derivatives

Total revenues

Expenses

Operating income (loss)
Other income (expense)

Net gain on asset sales and inventory impairment
Interest expense
Other income (expense)

Total other (expense) income

Income (loss) before income taxes

Income tax (beneﬁt) provision

Current
Deferred
Total income tax beneﬁt
Net income (loss)

Net income attributable to non-controlling interest in subsidiaries

Net income (loss) attributable to Matador Resources Company shareholders

Earnings (loss) per common share

Basic

Diluted

Weighted average common shares outstanding

Basic

Diluted

The accompanying notes are an integral part of these ﬁnancial statements.

For the Years Ended December 31,

2017

2016

2015

$ 528,684
10,198
(4,321)
9,715
544,276

$ 291,156
5,218
9,286
(41,238)
264,422

$ 278,340
1,864
77,094
(39,265)
318,033

58,275
67,313
13,039
177,502
1,290
—
66,016
383,435
160,841

23
(34,565)
3,551
(30,991)
129,850

43,046
56,202
5,389
122,048
1,182
158,633
55,089
441,589
(177,167)

107,277
(28,199)
(4)
79,074
(98,093)

35,650
54,704
3,489
178,847
734
801,166
50,105
1,124,695
(806,662)

908
(21,754)
616
(20,230)
(826,892)

(8,157)
—
(8,157)
138,007
(12,140)
$ 125,867

(1,036)
—
(1,036)
(97,057)
(364)

2,959
(150,327)
(147,368)
(679,524)
(261)
$ (97,421) $ (679,785)

1.23

(1.07) $

(8.34)

102,029

91,273

102,543

91,273

81,537

FORM 10-K Consolidated Financial Statements

Consolidated Statements of Changes in Shareholders’ Equity

Matador Resources Company and Subsidiaries

For the Years Ended December 31, 2017, 2016 and 2015

Total
shareholders’

2017 ANNUAL REPORT

F-5

Common Stock

Preferred Stock

Shares Amount

Additional
paid-in
capital

Retained
earnings
accumulated
(deﬁcit)

Treasury Stock

Amount

Non-

equity
attributable controlling
to Matador
Resources
Company

interest
in
subsidiaries

Total
shareholders’
equity

(In thousands)

Balance at January 1, 2015
Issuance of common stock
Issuance of preferred stock
Cost to issue equity
Conversion of preferred stock

to common stock

Stock-based compensation expense
related to equity-based awards
Stock options exercised, net of options
forfeited in net share settlements
Liability-based stock option awards
settled
Restricted stock issued
Restricted stock forfeited
Vesting of restricted stock units
Cancellation of treasury stock
Capital contributed from less-than-
wholly-owned subsidiaries
Current period net (loss) income

Balance at December 31, 2015
Issuance of common stock pursuant

73,374 $ 734
104
10,329
—
—
—
—

— $ — $ 724,819 $ 140,855
—
—
—
150
—
—

260,148
32,489
(1,151)

—
1
—

31 $ — $ 866,408 $
—
—
—

260,252
32,490
(1,151)

—
—
—

1,500

(150)

(1)

(14)

—

9,333

—

9,333

—

25
429
—
52
(167)

—
—
—
4
—
—
1
—
(2) —

—
—

—
—
—
—
—

—
—

446
(4)
—
(1)
2

—

—
—
—
—
—

—
—
138
—
(167)

—
—
—
—
—

446
—
—
—
—

85,567

856

—

1,026,077

(538,930)

—

488,003

956

488,959

—
—

—
—
(679,785) —

—
—

—
(679,785)

562
261

562
(679,524)

133 $ 866,541
260,252
32,490
(1,151)

—
—
—

—

—
—
—
—
—

—

9,333

446
—
—
—
—

to public offerings

13,500

135

—

288,375

—

288,510

—

288,510

Issuance of common stock pursuant to
employee stock compensation plan
Issuance of common stock pursuant

to directors’ and advisors’

compensation plan
Cost to issue equity
Stock-based compensation expense
related to equity-based awards
Stock options exercised, net of options
forfeited in net share settlements
Liability-based stock option awards
settled
Restricted stock forfeited
Cancellation of treasury stock
Current period net (loss) income

Balance at December 31, 2016
Issuance of common stock pursuant

471

—

(4)

—

51
—

1
—

—
—

(1)
(1,190)

—
—

—
(1,190)

—

—
—

—

—
(1,190)

—

11,958

—

11,958

—

11,958

—

10
—
(116)
—

—
—

—
—
(1) —
—

—

—
—
—
—

255
—
1
—

—

—
—
120
—
(116)
—
(97,421) —

—
—
—
—

255
—
—
(97,421)

—

—
—
—
364

255
—
—
(97,057)

99,519

995

—

1,325,481

(636,351)

—

690,125

1,320

691,445

to public offerings

8,000

—

208,640

—

208,720

—

208,720

Issuance of common stock pursuant to
employee stock compensation plan
Issuance of common stock pursuant

to directors’ and advisors’

compensation plan
Cost to issue equity
Stock-based compensation expense
related to equity-based awards
including amounts capitalized

Stock options exercised, net of options
forfeited in net share settlements

Restricted stock forfeited
Purchase of non-controlling interest
of less-than-wholly-owned subsidiary
Contributions related to formation
of Joint Venture (see Note 5)
Contributions from non-controlling

interest owners of less-than-

wholly-owned subsidiaries
Distributions to non-controlling interest
owners of less-than wholly-owned
subsidiaries
Cancellation of treasury stock
Current period net income

530

—

(5)

—

77
—

1
—

—
—

(1)
(280)

—
—

—
(280)

—

—
—

—

—
(280)

—

19,594

—

19,594

—

19,594

514
—

5
—

—
—

(1,189)
—

—
—

—
123

—
(1,658)

(1,184)
(1,658)

—
—

(1,184)
(1,658)

—

(1,250)

—

(1,250)

(1,403)

(2,653)

—

116,622

—

116,622

54,878

171,500

—

44,100

—
(126)
—

—

—
(1) —
—

—

—
—
—

—
(1,588)
—

—
—
125,867

—
(126)
—

—
1,589
—

—
—
125,867

(10,045)
—
12,140

(10,045)
—
138,007

Balance at December 31, 2017

108,514 $ 1,085

— $ — $ 1,666,024 $ (510,484)

3 $

(69) $ 1,156,556 $ 100,990 $ 1,257,546

Consolidated Financial Statements FORM 10-K

F-6

MATADOR RESOURCES COMPANY

Consolidated Statements of Cash Flows

(In thousands)

Operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by

operating activities
Unrealized (gain) loss on derivatives

Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
Stock-based compensation expense
Deferred income tax beneﬁt
Amortization of debt issuance cost
Net gain on asset sales and inventory impairment

Changes in operating assets and liabilities

Accounts receivable

Lease and well equipment inventory
Prepaid expenses and other assets

Other assets

Accounts payable, accrued liabilities and other current liabilities
Royalties payable

Advances from joint interest owners
Income taxes payable
Other long-term liabilities

Net cash provided by operating activities

Investing activities

Oil and natural gas properties capital expenditures
Expenditures for midstream and other property and equipment
Proceeds from sale of assets
Business combination, net of cash acquired
Restricted cash
Restricted cash in less-than-wholly-owned subsidiaries

Net cash used in investing activities

Financing activities

Repayments of borrowings
Borrowings under Credit Agreement
Proceeds from issuance of common stock
Proceeds from issuance of senior unsecured notes
Cost to issue equity

Cost to issue senior unsecured notes
Proceeds from stock options exercised
Capital commitments from non-controlling interest owners of

less-than-wholly-owned subsidiaries

Contributions related to formation of Joint Venture
Contributions from non-controlling interest owners of

less-than-wholly-owned subsidiaries

Distributions to non-controlling interest owners of

less-than-wholly-owned subsidiaries

Taxes paid related to net share settlement of stock-based compensation
Purchase of non-controlling interest of less-than-wholly-owned subsidiary

Net cash provided by ﬁnancing activities

(Decrease) increase in cash
Cash at beginning of year
Cash at end of year

Supplemental disclosures of cash ﬂow information (Note 14)

The accompanying notes are an integral part of these ﬁnancial statements.

For the Years Ended December 31,

2017

2016

2015

$ 138,007

$ (97,057)

$ (679,524)

(9,715)
177,502
1,290
—
16,654
—
468
(23)

(82,549)
(3,623)
(2,960)
(6,425)
33,559
37,370
1,089
—
(1,519)
299,125

(699,445)
(120,816)
977
—
—
(4,719)
(824,003)

—
—
208,720
—
(280)
—
2,920

—
171,500

44,100

41,238
122,048
1,182
158,633
12,362
—
1,148
(107,277)

(14,259)
(700)
(124)
490
6,611
7,495
1,000
(2,848)
4,144
134,086

(379,067)
(74,845)
5,173
—
43,098
1
(405,640)

(120,000)
120,000
288,510
184,625
(847)
(2,734)
100

—
—

—

39,265
178,847
734
801,166
9,450
(150,327)
852
(908)

3,633
(180)
(544)
(552)
1,375
1,654
700
2,405
489
208,535

(432,715)
(64,499)
139,836
(24,028)
(43,098)
(650)
(425,154)

(476,982)
125,000
188,720
400,000
(1,158)
(9,598)
10

562
—

—

(10,045)
(5,763)
(2,653)
408,499
(116,379)
212,884
$ 96,505

—
(1,948)
—
467,706
196,152
16,732
$ 212,884

—
(1,610)
—
224,944
8,325
8,407
$ 16,732

FORM 10-K Consolidated Financial Statements

2017 ANNUAL REPORT

F-7

Notes to Consolidated Financial Statements

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2017, 2016 and 2015

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the

“Company”), is an independent energy company engaged in the exploration, development, production and acquisition
of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other
unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the
Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also
operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest
Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream
joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s
exploration, development and production operations and provides natural gas processing, oil transportation services,
oil, natural gas and salt water gathering services and salt water disposal services to third parties.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated ﬁnancial statements include the accounts of Matador Resources Company and its wholly-

owned and majority-owned subsidiaries. These consolidated ﬁnancial statements have been prepared in accordance
with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the
Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable
to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately
consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration.
All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of ﬁnancial statements in conformity with U.S. GAAP requires management to make estimates

and assumptions that affect the amounts reported in the ﬁnancial statements and accompanying notes. These
estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the ﬁnancial
statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting
period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the
discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated ﬁnancial statements are based on a number of signiﬁcant estimates, including oil

and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative
instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The
estimates of oil and natural gas reserves quantities and future net cash ﬂows are the basis for the calculations of
depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations
and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and
based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are
prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and
Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines
by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Notes to Consolidated Financial Statements FORM 10-K

F-8

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Restricted Cash

Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned
subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s
less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only
to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see
“ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the
Company does not believe that the loss of any one purchaser would signiﬁcantly impact operations. In addition,
the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas
wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and
natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator.
Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are
stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have
been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the

allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the
debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay
its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts
receivable for any reporting period presented.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or

equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under

this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural
gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and
accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the
United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals
on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying
projects and general and administrative expenses directly related to acquisition, exploration and development
activities, but do not include any costs related to production, selling or general corporate administrative activities.
The Company capitalized $23.1 million, $15.7 million and $6.9 million of its general and administrative costs in 2017,
2016 and 2015, respectively. The Company capitalized $7.3 million, $3.7 million and $3.9 million of its interest
expense for the years ended December 31, 2017, 2016 and 2015, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-9

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the
costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry
holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less

related deferred income taxes or the cost center “ceiling.” The cost center ceiling is deﬁned as the sum of:

(a)

the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves,
reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c)

the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs
being amortized, if any, less

(d)

income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged
to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included
in the ceiling test computation as the Company does not designate these instruments as hedge instruments for
accounting purposes.

The estimated present value of after-tax future net cash ﬂows from proved oil and natural gas reserves is
highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment.
The associated commodity prices and the applicable discount rate used in these estimates are in accordance
with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using
then-current operating and economic conditions, with no provision for price and cost changes in future periods
except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic
averages of the ﬁrst-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10%
discount factor is used to determine the present value of future net revenues. For the period from January through
December 2017, these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively.
For the period from January through December 2016, these average oil and natural gas prices were $39.25 per
Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and
natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. In estimating the present value of
after-tax future net cash ﬂows from proved oil and natural gas reserves, the average oil prices were further adjusted
by property for quality, transportation and marketing fees and regional price differentials, and the average natural
gas prices were further adjusted by property for energy content, transportation and marketing fees and regional
price differentials.

During the year ended December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less

related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during
the year ended December 31, 2017.

Notes to Consolidated Financial Statements FORM 10-K

F-10

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income
taxes periodically exceeded the full-cost ceiling. As a result, in the ﬁrst six months of 2016, the Company recorded
an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with
the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income

taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge
of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with
the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value

of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity,
but it has no impact on the Company’s net cash ﬂows as reported. Changes in oil and natural gas production rates,
oil and natural gas prices, reserves estimates, future development costs and other factors will determine the
Company’s actual ceiling test computation and impairment analyses in future periods.

Midstream and Other Property and Equipment

Midstream and other property and equipment are recorded at historical cost and include midstream equipment
and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate
assets, including furniture, ﬁxtures, equipment, land and leasehold improvements. Midstream equipment and
facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold
improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture,
ﬁxtures and other equipment are depreciated over their useful life (ﬁve to 30 years) using the straight-line method.
Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as
incurred. See Note 3 for a detail of midstream and other property and equipment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if

a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its
estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and
other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of
the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative ﬁnancial instruments to mitigate its exposure to commodity

price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative ﬁnancial
instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value.
The Company has elected not to apply hedge accounting for its existing derivative ﬁnancial instruments, and
as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its
consolidated statements of operations. The fair value of the Company’s derivative ﬁnancial instruments is
determined using industry-standard models that consider various inputs including: (i) quoted forward prices for
commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments,
as well as other relevant economic measures. Realized gains and losses from the settlement of derivative
ﬁnancial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled
derivative ﬁnancial instruments are reported under “Revenues” in the consolidated statements of operations.
See Note 11 for additional information about the Company’s derivative instruments.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-11

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues,

whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers
regardless of whether the sales are proportionate to the Company’s ownership in the property. Under this method,
revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company
accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time
services have been rendered and the price is ﬁxed and determinable. See below for a discussion of the impact
of the adoption of Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers
(Topic 606) on the Company’s 2018 consolidated ﬁnancial statements.

)

For the year ended December 31, 2017, four signiﬁcant purchasers accounted for 60% of the Company’s total

oil, natural gas and natural gas liquids revenues: Occidental Energy Marketing, Inc. (23%), Plains Marketing, L.P.
(14%), Shell Trading (US) Company (12%) and Western Reﬁning Crude Oil (11%). For the year ended December 31,
2016, three signiﬁcant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids
revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc.
(13%). For the year ended December 31, 2015, three signiﬁcant purchasers accounted for approximately 59% of
the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (33%), Enterprise
Crude Oil LLC (14%) and Sequent Energy Management, L.P. (12%). Due to the nature of the markets for oil, natural
gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material
adverse impact on the Company’s ﬁnancial condition, results of operations or cash ﬂows for any signiﬁcant period of
time. At December 31, 2017, 2016 and 2015, approximately 43%, 38% and 39%, respectively, of the Company’s
accounts receivable, including joint interest billings, related to these purchasers.

Stock-Based Compensation

The Company grants common stock, stock options, restricted stock and restricted stock units to members of its
Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are
generally recognized as a component of general and administrative expenses in the accompanying statements of
operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock
options granted under the 2003 Plan (as described and deﬁned in Note 8) as liability instruments as a result of the
Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of
the Company’s common stock.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options,
the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit
awards and the Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2017, 2016 and

2015 include a stock-based compensation (non-cash) expense of $16.7 million, $12.4 million and $9.5 million,
respectively. This stock-based compensation expense includes common stock issuances and restricted stock units
expense totaling $3.0 million (including a one-time expense of $1.5 million resulting from a change in the vesting
schedule applicable to equity awards granted to independent members of the Company’s Board of Directors),
$1.0 million and $0.9 million in 2017, 2016 and 2015, respectively, paid to independent members of the Board of
Directors and advisors as compensation for their services to the Company.

Notes to Consolidated Financial Statements FORM 10-K

F-12

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Income Taxes

The Company accounts for income taxes using the asset and liability approach for ﬁnancial accounting and

reporting. The Company evaluates the probability of realizing the future beneﬁts of its deferred tax assets and
records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the
beneﬁt from the deferred tax asset will not be realized.

The Company recognizes the tax beneﬁt of an uncertain tax position only if it is more likely than not that the tax
position will be sustained upon examination by the taxing authorities based on the technical merits of the position.
For tax positions meeting the more likely than not threshold, the amount recognized in the ﬁnancial statements is
the beneﬁt that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax
authority. At December 31, 2017, 2016 and 2015, the Company had not established any reserves for, nor recorded
any unrecognized tax beneﬁts related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense”

and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The
Company did not record any interest or penalties related to income taxes for the years ended December 31, 2017,
2016 and 2015.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The

legislation signiﬁcantly changes U.S. tax law by, among other things, lowering corporate income tax rates,
implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign
subsidiaries. The Tax Cuts and Jobs Act permanently reduces the U.S. corporate income tax rate from a maximum
of 35% to a ﬂat rate of 21% effective January 1, 2018. For the year ended December 31, 2017, the Company
re-valued its deferred tax assets and liabilities at the enacted rate (see Note 7).

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas

properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed
based on their fair values as of the acquisition date, which may occur many months after the announcement date.
Therefore, while the consideration to be paid may be ﬁxed, the fair value of the assets acquired and liabilities
assumed is subject to change during the period between the announcement date and the acquisition date. The
most signiﬁcant estimates in the allocation typically relate to the value assigned to proved oil and natural gas
reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to signiﬁcant
estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per

common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to
Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive
securities, unless their impact is anti-dilutive.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-13

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The following are reconciliations of the numerators and denominators used to compute the Company’s basic
and diluted earnings per common share as reported for the years ended December 31, 2017, 2016 and 2015 (in
thousands, except per share data).

Year Ended December 31,

2017

2016

2015

Net income (loss) attributable to Matador Resources Company shareholders —

numerator

$ 125,867

$(97,421)

$(679,785)

Weighted average common shares outstanding — denominator

Basic
Dilutive effect of options and restricted stock units
Diluted weighted average common shares outstanding

Earnings (loss) per common share attributable to
Matador Resources Company shareholders

Basic

Diluted

102,029
514
102,543

91,273
—
91,273

81,537
—
81,537

1.23

(1.07)

(8.34)

A total of 1.0 million options to purchase shares of the Company’s common stock were excluded from the

calculations above for the year ended December 31, 2017 because their effects were anti-dilutive.

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock
units were excluded from the calculations above for the year ended December 31, 2016 because their effects were
anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the
calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share
in the losses of the Company.

A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock
units were excluded from the calculations above for the year ended December 31, 2015 because their effects were
anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the
calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share
in the losses of the Company.

Credit Risk

The Company’s cash is held in ﬁnancial institutions and at times these amounts exceed the insurance limits of
the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks
are minimal based on the reputation and history of the institutions selected.

The Company uses derivative ﬁnancial instruments to mitigate its exposure to oil, natural gas and natural gas

liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties.
The Company manages counterparty credit risk through established internal derivatives policies that are reviewed
on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2017 were
with Royal Bank of Canada (“RBC”), The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and
SunTrust Bank (or afﬁliates thereof), parties that are lenders (or afﬁliates thereof) under the Company’s revolving
credit agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may
be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the ﬁnancial
condition and payment history of its purchasers and joint interest partners.

Notes to Consolidated Financial Statements FORM 10-K

F-14

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Recent Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”)

issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which speciﬁes how and when to
recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to
improve, and converge with international standards, the ﬁnancial reporting requirements for revenue from contracts
with customers. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09
for one year to ﬁscal years beginning after December 15, 2017. Entities have the option of using either a full
retrospective or modiﬁed approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20,
which clariﬁes disclosure requirements in ASU 2014-09. The Company adopted the new guidance effective
January 1, 2018 using the modiﬁed approach. The Company identiﬁed all revenue streams and reviewed all
contracts and procedures currently in place. The Company determined there is no material impact on its consolidated
ﬁnancial statements as a result of adoption, including no material impact to the timing or amount of revenue
recognized, although the Company will be required to include certain additional disclosures regarding revenue from
contracts with customers as a result of adoption of ASU 2014-09.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition
of lease assets and lease liabilities by lessees for those leases classiﬁed as operating leases under previous U.S.
GAAP. This ASU will become effective for ﬁscal years beginning after December 15, 2018 with early adoption
permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented
using a modiﬁed retrospective approach. The modiﬁed retrospective approach includes a number of optional
practical expedients that entities may elect to apply. These practical expedients relate to the identiﬁcation and
classiﬁcation of leases that commenced before the effective date, initial direct costs for leases that commenced
before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a
lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842),
which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company
should evaluate new or modiﬁed land easements under this ASU beginning at the date of adoption. Adoption of
ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease
standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the
impact of the adoption of these ASUs on its consolidated ﬁnancial statements, including identifying all leases,
as deﬁned under the new lease standard, determining which practical expedients the Company will use and
quantifying the impact of the new lease standard on existing leases. The Company expects to adopt this lease
standard on January 1, 2019.

Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows
(Topic 230), which speciﬁes that a statement of cash ﬂows explain the change during the period in the total of cash,
cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will
become effective for ﬁscal years beginning after December 15, 2017 and interim periods within those ﬁscal years.
The update should be applied using a retrospective transition method to each period presented. The Company
adopted ASU 2016-18 effective January 1, 2018 and believes that the adoption of this ASU will change the
presentation of its beginning and ending cash balances and eliminate the presentation of changes in restricted cash
balances from investing activities in its consolidated statement of cash ﬂows.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-15

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Clarifying the Deﬁnition of a Business. In January 2017, the FASB issued ASU 2017-01, Business

Combinations (Topic 805), which speciﬁes the minimum inputs and processes required for an integrated set of
assets and activities to meet the deﬁnition of a business. This ASU will become effective for ﬁscal years
beginning after December 15, 2017. Entities are required to apply guidance prospectively upon adoption. Effective
January 1, 2018, the Company adopted ASU 2017-01, which did not have a material impact on its consolidated
ﬁnancial statements.

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31,

2017 and 2016 (in thousands).

Oil and natural gas properties

Evaluated (subject to amortization)
Unproved and unevaluated (not subject to amortization)
Total oil and natural gas properties
Accumulated depletion
Net oil and natural gas properties

Midstream and other property and equipment

Midstream equipment and facilities
Furniture, ﬁxtures and other equipment
Software
Land
Leasehold improvements

Total midstream and other property and equipment

Accumulated depreciation

Net midstream and other property and equipment

Net property and equipment

December 31,

2017

2016

$ 3,004,770
637,396
3,642,166
(2,021,169)
1,620,997

258,725
6,109
7,942
2,892
5,428
281,096
(20,637)
260,459
$ 1,881,456

$ 2,408,305
479,736
2,888,041
(1,850,882)
1,037,159

145,662
5,487
3,206
1,437
5,003
160,795
(13,429)
147,366
$ 1,184,525

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not
subject to amortization as of December 31, 2017 and the year in which these costs were incurred (in thousands).

Description

Costs incurred for

Property acquisition

Development wells
Total

2017

2016

2015

2014 and prior

Total

$ 213,076
16,688
11,396
$ 241,160

$ 125,689
988
272
$ 126,949

$ 222,912
547
19
$ 223,478

$ 45,809
—
—
$ 45,809

$ 607,486
18,223
11,687
$ 637,396

Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases,
but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs
associated with developing oil and natural gas prospects on these properties. Property acquisition costs are
transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves
are established or impairment is determined. Unproved and unevaluated properties are assessed for possible
impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2017
are related almost entirely to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas during the past ﬁve years. These costs are

Notes to Consolidated Financial Statements FORM 10-K

F-16

MATADOR RESOURCES COMPANY

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

associated with acreage for which proved reserves have yet to be assigned. A signiﬁcant portion of these costs are
associated with properties that are held by production or have automatic lease renewal options. As the Company
drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if
any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.

Costs excluded from amortization also include those costs associated with exploration and development wells

in progress or awaiting completion at year-end. These costs are transferred into the amortization base on
an ongoing basis as these wells are completed and proved reserves are established or conﬁrmed. These costs
totaled $29.9 million at December 31, 2017. Of this total, $18.2 million was associated with exploration wells
and $11.7 million was associated with development wells. The Company anticipates that most of the $29.9 million
associated with these wells in progress at December 31, 2017 will be transferred to the amortization base
during 2018.

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

In general, the Company’s asset retirement obligations relate to future costs associated with plugging and

abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from
leased acreage and returning such land to its original condition. The amounts recognized are based on numerous
estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas,
future inﬂation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur
due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and
abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the
Company includes any gain or loss associated with the operation in the amortization base to the extent the actual
costs are different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended

December 31, 2017 and 2016 (in thousands).

Beginning asset retirement obligations
Liabilities incurred during period
Liabilities settled during period
Revisions in estimated cash ﬂows
Accretion expense
Ending asset retirement obligations

Less: current asset retirement obligations (1)
Long-term asset retirement obligations

(1)

Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2017 and 2016.

Year Ended December 31,

2017

2016

$ 20,640
2,920
(430)
1,836
1,290
26,256
(1,176)

$ 25,080

$15,420
1,791
(375)
2,622
1,182
20,640
(915)
$19,725

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-17

NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES

Joint Venture

On February 17, 2017, the Company contributed substantially all of its midstream assets located in the
Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to
San Mateo, a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream
assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks
asset area (the “Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt
water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial
salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water
gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware
Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo’s other
assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest
Louisiana, which are not part of San Mateo.

The Company and Five Point own 51% and 49% of San Mateo, respectively. Five Point provided initial cash

consideration of $176.4 million to San Mateo in exchange for its 49% interest. Approximately $171.5 million of
this cash contribution by Five Point was distributed by San Mateo to the Company as a special distribution. Through
January 31, 2018, the Company had earned an additional $14.7 million in performance incentives to be paid by
Five Point in the ﬁrst quarter of 2018 and may earn an additional $58.8 million in performance incentives over the
next four years. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to San Mateo in
exchange for its 51% interest. San Mateo is consolidated in the Company’s ﬁnancial statements with Five Point’s
interest in San Mateo being accounted for as a non-controlling interest.

The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas to

San Mateo pursuant to 15-year, ﬁxed-fee natural gas, oil and salt water gathering agreements and salt water
disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future
leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, ﬁxed fee natural gas
processing agreement (see Note 13).

Business Combinations

On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company

(“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned
subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural
gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of
approximately 58,600 gross (18,200 net) acres strategically located between the Company’s existing acreage in its
Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned
prior to the transaction.

As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed

debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of
Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible
into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an
amendment to the Company’s Amended and Restated Certiﬁcate of Formation to increase the number of
authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015).

Notes to Consolidated Financial Statements FORM 10-K

F-18

MATADOR RESOURCES COMPANY

NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued

Divestitures

On October 1, 2015, the Company completed the sale of its wholly-owned subsidiary that owned certain

natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County
Processing System”) to an afﬁliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing
System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the
“Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the
Company’s gathering system to the Wolf Processing Plant.

Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million, and the Company received

net proceeds of approximately $139.8 million after deducting customary purchase price adjustments of
approximately $3.6 million. In conjunction with the sale of the Loving County Processing System, the Company
dedicated a signiﬁcant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15-year
ﬁxed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for
priority one service. See Note 13 for more information related to this agreement.

Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction;

the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance
sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net
proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain
on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and
processing agreement.

During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County,

Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing
agreement, EnLink began processing the Company’s natural gas produced in this area at the new plant. As such,
the gathering and processing agreement the Company entered into with EnLink was no longer considered a
lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the
consolidated statement of operations for the year ended December 31, 2016.

The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions

in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central
delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water
disposal wells. On February 17, 2017, these assets were contributed to San Mateo.

NOTE 6 — DEBT

Credit Agreement

On September 28, 2012, the Company amended and restated its revolving credit agreement with the lenders

party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to
$500.0 million. MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the
ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries,
is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the
Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned
subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed
by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the
Credit Agreement (or afﬁliates thereof) are also secured by the collateral of and guaranteed by certain eligible
subsidiaries of MRC Energy Company.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-19

NOTE 6 — DEBT — Continued

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by

the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at
December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled
redetermination of the borrowing base once each between scheduled redetermination dates. Early in the fourth
quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30,
2017, and as a result, on October 25, 2017, the borrowing base was increased to $525.0 million and the maximum
facility amount remained at $500.0 million. This October 2017 redetermination constituted the regularly scheduled
November 1 redetermination. The Company elected to keep the borrowing commitment at $400.0 million.
Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility
amount and the elected commitment. The Credit Agreement matures on October 16, 2020.

In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal

to a percentage of the amount of the increase, which is determined based on market conditions at the time of
the increase. Total deferred loan costs were $1.0 million at December 31, 2017, and these costs are being amortized
over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest
method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding
borrowings under the Credit Agreement at any time, the Company would be required to provide additional
collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufﬁcient to
cover such excess or to repay the deﬁcit in equal installments over a period of six months.

At December 31, 2017 and February 21, 2018, the Company had no borrowings outstanding under the Credit
Agreement and approximately $2.1 million in outstanding letters of credit issued pursuant to the Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company

borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime
rate for such day or (ii) the Federal Funds Effective Rate (as deﬁned in the Credit Agreement) on such day, plus 0.50%
or (iii) the daily adjusting LIBOR rate (as deﬁned in the Credit Agreement) plus 1.0% plus, in each case, an amount
from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement.
If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the
quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during
such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as
deﬁned in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50%
to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest
period for Eurodollar borrowings may be one, two, three or six months as designated by the Company.

A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is
also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred ﬁnancing
costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as
interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the
Company to maintain a debt to EBITDA ratio, which is deﬁned as total debt outstanding divided by a rolling four
quarter EBITDA calculation, of 4.25 or less.

Notes to Consolidated Financial Statements FORM 10-K

F-20

MATADOR RESOURCES COMPANY

NOTE 6 — DEBT — Continued

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability

to take certain actions, including, but not limited to, the following:

•

incur indebtedness or grant liens on any of the Company’s assets;

• enter into commodity hedging agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with afﬁliates;

• engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and

•

take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity
of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the
following events:

•

failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under
any letter of credit when due or any fees or other amounts within certain grace periods;

failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other
loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving the Company or its subsidiaries; and

• a change of control, as deﬁned in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2017.

Senior Unsecured Notes

On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a

private placement. The Original Notes were issued at par value, and the net proceeds were used to pay down a
portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the
HEYCO Merger.

On October 21, 2015, and pursuant to a registered exchange offer, Matador exchanged all of the privately
placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under
the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as
the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional
interest relating to the Original Notes do not apply to the Registered Notes.

On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”)

in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by
the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of
par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5%. The Company
received net proceeds from the Notes Offering of approximately $181.5 million, including the issue premium, but
after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest
paid by buyers of the Additional Notes.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-21

NOTE 6 — DEBT — Continued

On May 24, 2017, pursuant to a registered exchange offer, Matador exchanged all of the privately placed

Additional Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the
Securities Act (the “Additional Registered Notes,” and, collectively with the Registered Notes, the “Notes”). The
terms of the Additional Registered Notes are substantially the same as the terms of the Additional Notes except
that the transfer restrictions, registration rights and provisions for additional interest relating to the Additional Notes
do not apply to the Additional Registered Notes.

The Notes are Matador’s senior unsecured obligations and are redeemable as described below. The Notes
mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

On or after April 15, 2018, Matador may redeem all or a portion of the Notes at any time or from time to time at

the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid
interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15
of the years indicated.

Year

2018
2019
2020
2021 and thereafter

Redemption Price

105.156%
103.438%
101.719%
100.000%

At any time prior to April 15, 2018, Matador may redeem up to 35% of the aggregate principal amount of the
Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount
of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in
aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding
immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries)
and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering.

In addition, at any time prior to April 15, 2018, Matador may redeem all or part of the Notes at a redemption price
equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time
of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such
Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal
to the Treasury Rate (as deﬁned in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes,
plus (iii) accrued and unpaid interest, if any, to the redemption date.

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take

certain actions, including, but not limited to, the following:

•

incur or guarantee additional debt or issue certain types of preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness;

•

transfer or sell assets;

• make certain investments;

• create certain liens;

• enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as deﬁned

in the Indenture) to the Company;

• consolidate, merge or transfer all or substantially all of its assets;

• engage in transactions with afﬁliates; and

• create unrestricted subsidiaries.

Notes to Consolidated Financial Statements FORM 10-K

F-22

MATADOR RESOURCES COMPANY

NOTE 6 — DEBT — Continued

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador,

any Restricted Subsidiary that is a Signiﬁcant Subsidiary (as deﬁned in the Indenture) or any group of Restricted
Subsidiaries that, taken together, would constitute a Signiﬁcant Subsidiary, all outstanding Notes will become due and
payable immediately without further action or notice. If any other event of default occurs and is continuing, the
trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to
be due and payable immediately. Events of default include, but are not limited to, the following events:

• default for 30 days in the payment when due of interest on the Notes;

• default in the payment when due of the principal of, or premium, if any, on the Notes;

•

failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required
pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply
with the covenant relating to merger, consolidation or sale of assets;

failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture;

failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture;

• payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted

Subsidiaries in the aggregate principal amount of $25.0 million or more;

•

failure by Matador or any Restricted Subsidiary to pay certain ﬁnal judgments aggregating in excess of
$25.0 million within 60 days;

• any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in

a judicial proceeding or being denied or disafﬁrmed by its maker; and

• certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is

a Signiﬁcant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a
Signiﬁcant Subsidiary.

On February 17, 2017, in connection with the formation of San Mateo (see Note 5), Matador entered into a

Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the indenture governing
the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of
Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River
Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released
as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the
Fourth Supplemental Indenture, are referred to herein as the “Guarantor Subsidiaries.” San Mateo and its
subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes, although they remain restricted
subsidiaries under the Indenture.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-23

NOTE 7 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the ﬁnancial statement carrying

values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2017
and 2016 is as follows (in thousands).

Deferred tax assets

Unrealized loss on derivatives
Net operating loss carryforwards
Alternative minimum tax carryforward
Percentage depletion carryover
Property and equipment
Basis increase related to the San Mateo transaction

Total deferred tax assets

Valuation allowance on deferred tax assets

Total deferred tax assets, net of valuation allowance

Deferred tax liabilities

Property and equipment
Other

Total deferred tax liabilities
Net deferred tax liabilities

December 31,

2017

2016

$ 3,200
118,134
—
1,582
—
18,382
141,298
(89,482)
51,816

(40,568)
(11,248)
(51,816)
—

8,734
137,757
8,633
2,595
44,391
—
202,110
(190,255)
11,855

—
(11,855)
(11,855)
—

At December 31, 2017, the Company had net operating loss carryforwards of $498.4 million for federal income

tax purposes and $17.0 million for state income tax purposes available to offset future taxable income, as limited
by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss
carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024;
however, the signiﬁcant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.

As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred
income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company
recorded impairment charges of $158.6 million and $801.2 million, respectively, exclusive of tax effect, to the net
capitalized costs of its oil and natural gas properties. At December 31, 2017 and 2016, the Company’s deferred tax
assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges
recorded in 2016 and 2015. As a result, the Company established a valuation allowance against most of the deferred
tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at December 31, 2017 and
2016 due to uncertainties regarding the future utilization of its deferred tax assets. The valuation allowance will
continue to be recognized until the realization of future deferred tax beneﬁts are more likely than not to be utilized.

The current income tax (beneﬁt) provision for the years ended December 31, 2017, 2016 and 2015 was

comprised of the following (in thousands).

Current income tax provision

State income tax
Federal alternative minimum tax
Net current income tax (beneﬁt) provision

Year Ended December 31,

2017

2016

2015

(8,178)
$ (8,157)

108
(1,144)
$(1,036)

$ 371
2,588
$2,959

Notes to Consolidated Financial Statements FORM 10-K

F-24

MATADOR RESOURCES COMPANY

NOTE 7 — INCOME TAXES — Continued

Reconciliations of the tax expense (beneﬁt) computed at the statutory federal rate to the Company’s total income

tax beneﬁt for the years ended December 31, 2017, 2016 and 2015 is as follows (in thousands).

Federal tax expense (beneﬁt) at statutory rate (1)
State income tax
Permanent differences (2)
Federal alternative minimum tax
AMT credit refundable (net of sequestration)
Tax Cuts and Jobs Act rate change
Change in federal valuation allowance
Change in state valuation allowance
Net deferred income tax beneﬁt
Net current income tax (beneﬁt) provision

Total income tax beneﬁt

Year Ended December 31,

2017

2016

2015

$ 45,447
368
(4,740)

—
8,178
51,525
(101,917)
1,139
—
(8,157)
(8,157)

$(34,333)
539
(499)
1,144
—
—
33,688
(539)
—
(1,036)
$ (1,036)

$(289,412)
(13,215)
698
(2,588)
—
—
145,777
8,413
(150,327)
2,959
$(147,368)

(1) The statutory federal tax rate was 35% for the years ended December 31, 2017, 2016 and 2015.

(2) Amount is primarily attributable to stock-based compensation.

The Company ﬁles a United States federal income tax return and several state tax returns, a number of which
remain open for examination. The earliest tax year open for examination for the State of New Mexico and the State
of Louisiana tax returns is 2015. The earliest tax years open for examination for the federal and the State of Texas
tax returns are 2013 and 2014, respectively.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes

that the material positions taken would more likely than not be sustained by examination. Therefore, at
December 31, 2017, the Company had not established any reserves for, nor recorded any unrecognized beneﬁts
related to, uncertain tax positions.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in

the years in which those temporary differences are expected to reverse. As a result of the reduction in the U.S.
corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act, the Company revalued its deferred
tax assets and liabilities at December 31, 2017, which resulted in a $51.5 million tax provision. As the Company
maintained a valuation allowance against its federal and state deferred tax assets at December 31, 2017, a
corresponding reduction in the valuation allowance was recorded against this tax provision; therefore, there was no
net impact to the Company’s consolidated statement of operations for the year ended December 31, 2017 as a
result of this corporate income tax rate change.

Corporate alternative minimum taxes were also repealed under the Tax Cuts and Jobs Act; therefore, corporate
alternative minimum tax carryforwards will be refunded. As a result, the Company recorded $8.2 million as a current
income tax beneﬁt in its consolidated statement of operations for the year ended December 31, 2017.

On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 to address the application of
U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed
(including computations) in reasonable detail to complete the accounting for certain income tax effects of the
Tax Cuts and Jobs Act. The Company has recognized the tax impacts related to the revaluation of deferred tax
assets and liabilities and the repeal of the corporate alternative minimum tax and included these amounts in its
consolidated ﬁnancial statements for the year ended December 31, 2017. The ultimate tax impacts may differ
from these provisional amounts, possibly materially, due to, among other things, additional analysis, changes in
interpretations and assumptions the Company has made, additional regulatory guidance that may be issued, and
actions the Company may take as a result of the Tax Cuts and Jobs Act.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-25

NOTE 8 — STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the
“2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the
aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards
under the 2003 Plan included employees, directors, contractors or advisors of the Company.

In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as

subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2017, the 2012 Incentive Plan
provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the
Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or
other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include
employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to
attract and retain key employees, key contractors and outside directors and advisors of the Company. With the
adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan,
but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled.

The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of

Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the
number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants
and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option
exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted
under the 2012 Incentive Plan and are equity-based awards for which the fair value is ﬁxed at the grant date, while
all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are
liability-based awards for which the fair value is remeasured at each reporting period.

Stock Options

Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise
price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical
maximum term of ﬁve, six or ten years.

The fair value of the 75,000, 77,500 and 87,500 stock option awards outstanding under the 2003 Plan at

December 31, 2017, 2016 and 2015, respectively, was estimated using the following weighted average assumptions.

Stock option pricing model
Expected option life
Risk-free interest rate
Volatility
Dividend yield
Estimated forfeiture rate

2017

2016

2015

Black Scholes Merton
2.14 years
1.98%
43.60%
—%
—%

Black Scholes Merton
3.14 years
1.70%
47.07%
—%
—%

Black Scholes Merton
0.39 years
0.64%
91.98%
—%
—%

Notes to Consolidated Financial Statements FORM 10-K

F-26

MATADOR RESOURCES COMPANY

NOTE 8 — STOCK-BASED COMPENSATION — Continued

The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan
was estimated using the following weighted average assumptions during the years ended December 31, 2017,
2016 and 2015.

Stock option pricing model
Expected option life
Risk-free interest rate
Volatility
Dividend yield
Estimated forfeiture rate
Weighted average fair value of stock option

2017

2016

2015

Black Scholes Merton
4.00 years
1.77%
47.00%
—%
3.66%

Black Scholes Merton
3.96 years
1.08%
45.68%
—%
1.16%

Black Scholes Merton
4.00 years
1.15%
56.89
—%
3.21%

awards granted during the year

$10.49

$5.65

$9.90

The Company estimated the future volatility of its common stock using the historical value of its stock for a
period of time commensurate with the expected term of the stock option. The expected term was estimated using
the simpliﬁed method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant
yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2017 under the 2003 Plan and the

2012 Incentive Plan is as follows.

Options outstanding at December 31, 2016

Options granted
Options exercised
Options forfeited
Options expired

Options outstanding at December 31, 2017

Number of
options
(in thousands)

Weighted
average
exercise price

2,887
1,034
(833)
(24)
—
3,064

$15.59
$ 27.09
$ 9.20
$ 23.81
$ —
$ 21.14

Range of exercise prices

$8.18 - $9.55
$13.22 - $17.80
$19.71 - $22.70
$23.40 - $27.33

Options outstanding at
December 31, 2017

Options exercisable at

December 31, 2017

Shares
outstanding
(in thousands)

Weighted average
remaining
contractual life

Weighted average
exercise price

Shares
exercisable
(in thousands)

Weighted
average
exercise price

294
625
839
1,306

0.69
3.10
2.05
4.33

$ 8.46
$ 15.01
$ 21.87
$ 26.47

294
11
73
141

$ 8.46
$ 16.45
$ 21.50
$ 24.21

At December 31, 2017, the aggregate intrinsic value was $30.6 million for outstanding options and $8.5 million

for exercisable options, based on the Company’s quoted closing market price of $31.13 per share on that date.
The remaining weighted average contractual term of exercisable options at December 31, 2017 was 1.07 years.

The total intrinsic value of options exercised during the years ended December 31, 2017, 2016 and 2015 was

$13.2 million, $1.6 million and $1.3 million, respectively. The tax related beneﬁt realized from the exercise of stock options
totaled $5.0 million, $0.5 million and $0.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.

At December 31, 2017, the total remaining unrecognized compensation expense related to unvested stock

options was approximately $9.8 million and the weighted average remaining requisite service period (vesting period)
of all unvested stock options was 0.78 years.

The fair value of options vested during 2017, 2016 and 2015 was $2.1 million, $3.0 million and $1.3 million,

respectively.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-27

NOTE 8 — STOCK-BASED COMPENSATION — Continued

Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside

directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted
stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are
issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting.
Restricted stock and restricted stock units granted in 2017, 2016 and 2015 were service based awards and vest
over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding
at December 31, 2017 were granted under the 2012 Incentive Plan.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2017 is presented

below (in thousands, except fair value).

Non-vested restricted stock
and restricted stock units

Non-vested at December 31, 2016
Granted
Vested
Forfeited
Non-vested at December 31, 2017

Restricted Stock

Restricted Stock Units

Weighted
average
fair value

$ 18.23
$ 26.25
$ 16.54
$ 22.94
$ 22.59

1,039
531
(429)
(37)
1,104

82
113
(124)
(6)
65

Weighted
average
fair value

$ 21.32
$ 23.77
$ 22.38
$ 23.45
$ 23.36

At December 31, 2017, the aggregate intrinsic value for the restricted stock and restricted stock units
outstanding was $36.4 million as calculated based on the maximum number of shares of restricted stock and
restricted stock units vesting, using the Company’s quoted closing market price of $31.13 per share on that date.

At December 31, 2017, the total remaining unrecognized compensation expense related to unvested restricted

stock and restricted stock units was approximately $14.4 million and the weighted average remaining requisite
service period (vesting period) of all non-vested restricted stock and restricted stock units was 0.95 years.

The fair value of restricted stock and restricted stock units vested during 2017, 2016 and 2015 was $9.9 million,

$4.6 million and $0.8 million, respectively.

The total tax beneﬁt recognized for all stock-based compensation was $6.8 million, $4.3 million and $3.4 million

for the years ended December 31, 2017, 2016 and 2015, respectively.

During the years ended December 31, 2017, 2016 and 2015, the total expense attributable to stock options was

$7.1 million, $5.9 million and $4.7 million, respectively. At December 31, 2017, 2016 and 2015, the Company had
recorded $0.4 million, $1.4 million and zero of long-term liabilities and zero, zero and $1.0 million of current liabilities,
respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based
awards in cash for the years ended December 31, 2017, 2016 and 2015, respectively.

During the years ended December 31, 2017, 2016 and 2015, the total expense attributable to restricted stock

and restricted stock units was $12.9 million, $6.6 million and $4.7 million, respectively. During the year ended
December 31, 2017, the Company capitalized $3.3 million related to stock-based compensation and expensed the
remaining $16.7 million.

In mid-February 2018, the Company granted awards of 667,488 shares of restricted stock and options to purchase
563,408 shares of the Company’s common stock at an exercise price of $29.68 per share to certain of its employees.
The fair value of these awards was approximately $26.9 million. All of these awards vest ratably over three years.

Notes to Consolidated Financial Statements FORM 10-K

F-28

MATADOR RESOURCES COMPANY

NOTE 9 — EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s deﬁned contribution retirement plan the ﬁrst

day of the calendar month immediately following their date of employment. Each employee may contribute up to
the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan
which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective
Contribution, which totaled $0.9 million, $0.7 million and $0.6 million in 2017, 2016 and 2015, respectively. In
addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions.
The Company’s discretionary matching contributions totaled $1.1 million, $0.9 million and $0.8 million in 2017, 2016
and 2015, respectively. The Company made no additional contributions in any reporting period presented.

NOTE 10 — EQUITY

Stock Offerings, Retirement and Issuances

On October 10, 2017, the Company completed a public offering of 8,000,000 shares of its common stock. After
deducting offering costs totaling approximately $0.3 million, the Company received net proceeds of approximately
$208.4 million. A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres
of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and
to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to
be used for other midstream development, acreage acquisitions and general corporate purposes, including to fund
a portion of the Company’s current and future capital expenditures.

On June 1, 2017, the shareholders of the Company approved an amendment to the Company’s Amended and
Restated Certiﬁcate of Formation that authorized an increase in the number of authorized shares of common stock
from 120,000,000 to 160,000,000 shares.

On December 9, 2016, the Company completed a public offering of 6,000,000 shares of its common stock. After
deducting offering costs totaling approximately $0.4 million, the Company received net proceeds of approximately
$145.8 million. On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common
stock. After deducting offering costs totaling approximately $0.8 million, the Company received net proceeds of
approximately $141.5 million.

On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After
deducting offering costs totaling approximately $1.2 million, the Company received net proceeds of approximately
$187.6 million.

As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new

series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant
to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares
of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by
Matador’s shareholders of an amendment to Matador’s Amended and Restated Certiﬁcate of Formation to increase
the number of shares of authorized Matador common stock.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-29

NOTE 10 — EQUITY — Continued

On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and
Restated Certiﬁcate of Formation that authorized an increase in the number of authorized shares of common stock
from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of
Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of
the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2017 to satisfy
certain conditions under the merger agreement.

Treasury Stock

On November 1, 2017, October 27, 2016 and October 30, 2015, Matador’s Board of Directors canceled all of
the shares of treasury stock outstanding as of September 30, 2017, 2016 and 2015, respectively. These shares were
restored to the status of authorized but unissued shares of common stock of the Company.

The shares of treasury stock outstanding at December 31, 2017, 2016 and 2015 represent forfeitures
of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share
settlements with employees.

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative ﬁnancial instruments to mitigate its exposure to commodity
price risk associated with oil, natural gas and natural gas liquids (“NGL”) prices. The Company records derivative
ﬁnancial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The
Company has elected not to apply hedge accounting for its existing derivative ﬁnancial instruments. As a result, the
Company recognizes the change in derivative fair value between reporting periods currently in its consolidated
statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative ﬁnancial instruments
is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for
commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments,
as well as other relevant economic measures. The Company has evaluated and considered the credit standings of
its counterparties in determining the fair value of its derivative ﬁnancial instruments.

At December 31, 2017, the Company had various costless collar and swap contracts open and in place to

mitigate its exposure to oil and natural gas price volatility, each with a speciﬁc term (calculation period), notional
quantity (volume hedged) and price ﬂoor and ceiling and ﬁxed price for the swaps. Each contract is set to expire
at varying times during 2018.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at

December 31, 2017.

Commodity

Oil - WTI (1)
Oil - LLS (2)
Natural Gas

Total open costless collar
contracts

Calculation Period

01/01/2018 - 12/31/2018
01/01/2018 - 12/31/2018
01/01/2018 - 12/31/2018

Notional
Quantity
(Bbl or MMBtu)

2,880,000
720,000
16,800,000

Weighted
Average
Price Floor
($/Bbl or $/MMBtu)

Weighted
Average
Price Ceiling
($/Bbl or $/MMBtu)

Fair Value
of Asset
(Liability)
(thousands)

$ 44.27
$ 45.00
$ 2.58

$ 60.29
$ 63.05
$ 3.67

$ (8,414)
(2,451)
1,190

$ (9,675)

(1) NYMEX West Texas Intermediate crude oil.

(2) Argus Louisiana Light Sweet crude oil.

Notes to Consolidated Financial Statements FORM 10-K

F-30

MATADOR RESOURCES COMPANY

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2017.

Commodity

Oil Basis Swaps

Total open swap contracts
Total open derivative ﬁnancial instruments

Calculation Period

Notional
Quantity
(Bbl or Gal)

Fixed Price
($/Bbl or $/Gal)

01/01/2018 - 12/31/2018

5,220,000

$ (1.02)

Fair Value
of Asset
(Liability)
(thousands)

$ (5,564)
$ (5,564)
$ (15,239)

From time-to-time, we enter into derivative ﬁnancial instruments with certain counterparties. These derivative

ﬁnancial instruments are subject to master netting arrangements, and all but one counterparty allow for
cross-commodity master netting provided the settlements dates for the commodities are the same. The Company
does not present different types of commodities with the same counterparty on a net basis in its consolidated
balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative

ﬁnancial instruments and the location of these balances in the consolidated balance sheets as of December 31,
2017 and December 31, 2016 (in thousands).

Derivative Instruments

December 31, 2017
Current assets
Current liabilities

Total

December 31, 2016
Current liabilities
Other liabilities

Total

Gross amounts
recognized

Gross amounts
netted in the
consolidated
balance sheets

Net amounts
presented in
the consolidated
balance sheets

$ 131,092
(146,331)
$ (15,239)

$ (129,902)
129,902
—

$ 1,190
(16,429)
$ (15,239)

$ (24,203)
(751)
$ (24,954)

—
—
—

$(24,203)
(751)
$(24,954)

The following table summarizes the location and aggregate fair value of all derivative ﬁnancial instruments
recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative
ﬁnancial instruments are not designated as hedging instruments.

Year Ended December 31,

Type of Instrument

Location in Statement of Operations

2017

2016

2015

Derivative Instrument

Oil
Natural Gas
Natural Gas Liquids (NGL)
Realized (loss) gain on derivatives
Oil
Natural Gas
Natural Gas Liquids (NGL)

Revenues: Realized (loss) gain on derivatives
Revenues: Realized (loss) gain on derivatives
Revenues: Realized (loss) gain on derivatives

Revenues: Unrealized gain (loss) on derivatives
Revenues: Unrealized gain (loss) on derivatives
Revenues: Unrealized loss on derivatives

Unrealized gain (loss) on derivatives

Total

$ (3,657)
(608)
(56)
(4,321)
2,638
7,077
—
9,715
$ 5,394

$ 5,851
3,435
—
9,286
(18,969)
(22,269)
—
(41,238)
$(31,952)

$ 62,259
12,653
2,182
77,094
(31,897)
(5,440)
(1,928)
(39,265)
$ 37,829

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-31

NOTE 12 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain ﬁnancial and non-ﬁnancial assets and liabilities on a fair value basis.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date (exit price). Fair value measurements are classiﬁed and
disclosed in one of the following categories.

Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly,

for substantially the full term of the asset or liability. This category includes those derivative instruments that
are valued with industry standard models that consider various inputs including: (i) quoted forward prices
for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Substantially all of these inputs are observable
in the marketplace throughout the full term of the derivative instrument and can be derived from
observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data which reﬂect a company’s own market

assumptions.

Financial and non-ﬁnancial assets and liabilities are classiﬁed based on the lowest level of input that is signiﬁcant

to the fair value measurement. The assessment of the signiﬁcance of a particular input to the fair value
measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their
placement within the fair value hierarchy levels.

At December 31, 2017 and 2016, the carrying values reported on the consolidated balance sheets for accounts

receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to afﬁliates,
advances from joint interest owners, amounts due to joint ventures and other current liabilities approximate their
fair values due to their short-term maturities.

At December 31, 2017 and 2016, the fair value of the Company’s Notes was $614.1 million and $605.2 million,

respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy.

The following tables summarize the valuation of the Company’s ﬁnancial assets and liabilities that were
accounted for at fair value on a recurring basis in accordance with the classiﬁcations provided above as of
December 31, 2017 and 2016 (in thousands).

Description

Assets (Liabilities)

Natural gas derivatives
Oil derivatives and basis swaps
Total

Description

Assets (Liabilities)

Oil and natural gas derivatives

Total

Fair Value Measurements at December 31, 2017 using

Level 1

Level 2

Level 3

Total

$ —
—
$ —

$ 1,190
(16,429)
$ (15,239)

$ —
—
$ —

$ 1,190
(16,429)
$ (15,239)

Fair Value Measurements at December 31, 2016 using

Level 1

Level 2

Level 3

Total

$ —
$ —

$(24,954)
$(24,954)

$ —
$ —

$(24,954)
$(24,954)

Additional disclosures related to derivative ﬁnancial instruments are provided in Note 11. For purposes of fair
value measurement, the Company determined that derivative ﬁnancial instruments (e.g., oil, natural gas and NGL
derivatives) should be classiﬁed as Level 2 in the fair value hierarchy.

Notes to Consolidated Financial Statements FORM 10-K

F-32

MATADOR RESOURCES COMPANY

NOTE 12 — FAIR VALUE MEASUREMENTS — Continued

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities
acquired in a business combination, lease and well equipment inventory when the market value is determined to be
lower than the cost of the inventory and other property and equipment that are reduced to fair value when they
are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or
other property and equipment in 2017 and 2016. The Company determined the value of the lease and well equipment
inventory using Level 3 inputs and assumptions.

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Ofﬁce Lease

The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas,

Texas 75240. The lease for the Company’s corporate headquarters expires during 2026. The base rate escalates
during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease.

From time to time, the Company also enters into leases for ﬁeld ofﬁces in locations where it has active ﬁeld
operations. These leases are typically for terms of less than ﬁve years and are not considered principal properties.

The following is a schedule of future minimum lease payments required under all ofﬁce lease agreements as of

December 31, 2017 (in thousands).

Year Ending December 31,

2018
2019
2020
2021
2022
Thereafter
Total

Amount

$ 2,495
2,528
2,602
2,660
2,774
9,561
$ 22,620

Rent expense, including fees for operating expenses and consumption of electricity, was $2.6 million, $2.9 million

and $1.7 million for 2017, 2016 and 2015, respectively.

Processing, Transportation and Salt Water Disposal Commitments

Delaware Basin — Loving County, Texas Natural Gas Processing

In late 2015, the Company entered into a 15-year, ﬁxed-fee natural gas gathering and processing agreement
whereby the Company committed to deliver the anticipated natural gas production from a signiﬁcant portion of its
Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the
counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for
transportation and processing at the facilities in a contract year, it may be required to pay a deﬁciency fee per MMBtu
of natural gas deﬁciency. At the end of each year of the agreement, the Company can elect to have the previous
year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining
years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing
commitment if the Company’s production in the Loving County area is less than the Company’s currently projected
production. If the Company ceased operations in this area at December 31, 2017, the total deﬁciency fee required
to be paid would be approximately $8.4 million. In addition, if the Company elects to reduce the gathering and
processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any
future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-33

NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued

commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating
the natural gas deﬁciency. The Company paid approximately $14.4 million and $9.8 million in processing and gathering
fees under this agreement during the years ended December 31, 2017 and 2016, respectively. The Company can
elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the
counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants.

Delaware Basin — Eddy County, New Mexico Natural Gas Transportation

In late 2017, the Company entered into an 18-year, ﬁxed-fee natural gas transportation agreement whereby the

Company committed to deliver a portion of the residue natural gas production at the tailgate of the Black River
Processing Plant to transport through the counterparty’s pipeline. Under this agreement, if the Company does not
meet the volume commitment for transportation in a contract year, it may be required to pay a deﬁciency fee
per MMBtu of natural gas deﬁciency. The minimum contractual obligation at December 31, 2017 was approximately
$59.4 million. The Company paid approximately $0.2 million in transportation fees, which included no deﬁciency
fees, under this agreement during the year ended December 31, 2017.

In late 2017, the Company also entered into a ﬁxed-fee NGL transportation and fractionation agreement whereby

the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant. The
Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion
of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed
late in 2019. The Company has no rights to compel the counterparty to construct this pipeline extension or
fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the
Company does not have any minimum volume commitments under the agreement. If the counterparty constructs
the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a
commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension
and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the
seven-year commitment period, it will be required to pay a deﬁciency fee per gallon of NGL deﬁciency. The
Company’s minimum contractual obligation over the seven-year period containing minimum NGL commitments
would be approximately $132.5 million.

Delaware Basin — San Mateo

The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas

pursuant to 15-year, ﬁxed-fee natural gas, oil and salt water gathering agreements and salt water disposal
agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks
asset area pursuant to a 15-year, ﬁxed-fee natural gas processing agreement (collectively with the gathering and salt
water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with ﬁrm service
under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum
contractual obligation under the Operational Agreements at December 31, 2017 was approximately $232.6 million.
The Company paid approximately $39.4 million in fees under the Operational Agreements during the year ended
December 31, 2017.

Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the

engineering, procurement, construction and installation of an expansion of the Black River Processing Plant,
including required compression. The expansion is expected to be placed into service in 2018. San Mateo’s total
commitments under these agreements are $55.3 million. The subsidiary of San Mateo paid approximately
$49.7 million under these agreements during the year ended December 31, 2017. As of December 31, 2017, the
remaining obligations under these agreements were $5.6 million, which are expected to be incurred within the
next year.

Notes to Consolidated Financial Statements FORM 10-K

F-34

MATADOR RESOURCES COMPANY

NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued

On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains

All American Pipeline, L.P. (“Plains”) (see Note 18).

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties

for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s
commitment for the drilling services to be provided. The Company would incur a termination obligation if the
Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for
the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective
contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its
drilling rig contracts were approximately $36.5 million at December 31, 2017.

At December 31, 2017, the Company had outstanding commitments to participate in the drilling and completion

of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum
outstanding aggregate commitments for its participation in these non-operated wells were approximately
$24.8 million at December 31, 2017. The Company expects these costs to be incurred within the next year.

Legal Proceedings

The Company is a party to several lawsuits encountered in the ordinary course of its business. While the

ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management,
it is remote that these lawsuits will have a material adverse impact on the Company’s ﬁnancial condition, results
of operations or cash ﬂows.

NOTE 14 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2017 and 2016

(in thousands).

Accrued evaluated and unproved and unevaluated property costs
Accrued support equipment and facilities costs
Accrued lease operating expenses
Accrued interest on debt
Accrued asset retirement obligations
Accrued partners’ share of joint interest charges
Other

Total accrued liabilities

December 31,

2017

2016

$ 105,347
14,823
12,611
8,345
1,176
27,628
4,418
$ 174,348

$ 54,273
15,139
16,009
6,541
915
5,572
3,011
$101,460

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-35

NOTE 14 — SUPPLEMENTAL DISCLOSURES — Continued

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash ﬂow information for the years ended December 31,

2017, 2016 and 2015 (in thousands).

Cash paid for income taxes
Cash paid for interest expense, net of amounts capitalized
Increase in asset retirement obligations related to mineral properties
(Decrease) increase in asset retirement obligations related to support equipment

and facilities

Increase (decrease) in liabilities for oil and natural gas properties

capital expenditures

(Decrease) increase in liabilities for support equipment and facilities
Issuance of restricted stock units for director and advisor services
Stock-based compensation expense recognized as liability
(Decrease) increase in liabilities for accrued cost to issue equity
Transfer of inventory (to) from oil and natural gas properties
Transfer of inventory to midstream and other property and equipment

NOTE 15 — SUBSIDIARY GUARANTORS

Year Ended December 31,

2017

2016

2015

$ —
$ 32,760
$ 4,385

$ 2,895
$27,464
$ 3,817

$
506
$ 16,154
$ 2,510

(60)

222

383

$ 48,929
$
(955)
$ —
$
362
(343)
$
(374)
$
(317)
$

$ 1,775
(588)
$
992
$
569
$
343
$
395
$
—
$

$(30,683)
$ 12,076
584
$
79
$
—
$
615
$
—
$

On April 14, 2015, Matador issued the Original Notes and on December 9, 2016, Matador issued the Additional

Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor
Subsidiaries”) on a full and unconditional basis (except for customary release provisions). Matador ﬁled a registration
statement on Form S-3 with the SEC on August 11, 2017, which became effective upon ﬁling, registering, among
other securities, senior and subordinated debt securities and guarantees of debt securities by the Guarantor
Subsidiaries. At December 31, 2017, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent
holding company and has no independent assets or operations, and there are no signiﬁcant restrictions on the
ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries
are not guarantors of the Notes.

Notes to Consolidated Financial Statements FORM 10-K

F-36

MATADOR RESOURCES COMPANY

NOTE 15 — SUBSIDIARY GUARANTORS — Continued

The following presents condensed consolidating ﬁnancial information of the issuer (Matador), the Non-Guarantor

Subsidiaries, the Guarantor Subsidiaries and all entities on a consolidated basis (in thousands). Elimination entries
are necessary to combine the entities. This ﬁnancial information is presented in accordance with the requirements
of Rule 3-10 of Regulation S-X. The following ﬁnancial information may not necessarily be indicative of results
of operations, cash ﬂows or ﬁnancial position had the Guarantor Subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheet

ASSETS

Intercompany receivable
Third-party current assets
Net property and equipment
Investment in subsidiaries
Third-party long-term assets
Total assets

LIABILITIES AND EQUITY
Intercompany payable

Senior unsecured notes payable
Other third-party long-term liabilities
Total equity attributable to
Matador Resources Company
Non-controlling interest in subsidiaries
Total liabilities and equity

Condensed Consolidating Balance Sheet

ASSETS

Intercompany receivable
Third-party current assets
Net property and equipment
Investment in subsidiaries
Third-party long-term assets

Total assets

LIABILITIES AND EQUITY
Intercompany payable
Third-party current liabilities
Senior unsecured notes payable
Other third-party long-term liabilities
Total equity attributable to
Matador Resources Company
Non-controlling interest in subsidiaries
Total liabilities and equity

Matador

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

December 31, 2017

$ 585,109
2,240
—
1,147,295
6,425
$ 1,741,069

$ 2,912
9,334
223,178
—
—
$ 235,424

—
245,596
1,658,278
111,077
3,642
$ 2,018,593

$ (588,021)
—
—
(1,258,372)
(3,003)
$ (1,849,396)

—
257,170
1,881,456
—
7,064
$ 2,145,690

—
8,847
574,073
1,593

—
19,891
—
3,466

$ 588,021
254,142
—
29,135

$ (588,021)
(274)
—
(2,729)

—
282,606
574,073
31,465

1,156,556
—
$ 1,741,069

111,077
100,990
$ 235,424

1,147,295
—
$ 2,018,593

(1,258,372)
—
$ (1,849,396)

1,156,556
100,990
$ 2,145,690

Matador

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

December 31, 2016

$ 316,791
101,102
33
856,762
—
$1,274,688

3,571
4,242
113,107
—
—
$120,920

12,091
173,838
1,071,385
90,275
958
$1,348,547

$ (332,453)
—
—
(947,037)

—
$(1,279,490)

—
279,182
1,184,525
—
958
$ 1,464,665

—
9,265
573,924
1,374

$ 12,091
16,632
—
602

$ 320,362
143,608
—
27,815

$ (332,453)
—
—
—

—
169,505
573,924
29,791

690,125
—
$1,274,688

90,275
1,320
$120,920

856,762
—
$1,348,547

(947,037)

—
$(1,279,490)

690,125
1,320
$ 1,464,665

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-37

NOTE 15 — SUBSIDIARY GUARANTORS — Continued

Condensed Consolidating Statement of Operations

Total revenues

Operating (loss) income

Net gain on asset sales and inventory impairment
Interest expense
Other income
Earnings in subsidiaries

Income before income taxes

Total income tax (beneﬁt) provision

Net income attributable to non-controlling

interest in subsidiaries
Net income attributable to

For the Year Ended December 31, 2017

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

$ 47,883
21,260
26,623
—
—
37
—
26,660
269

$ 531,508
391,680
139,828
23
—
3,487
14,251
157,589
—

$ (35,115)
(35,115)
—
—
—
—
(171,840)
(171,840)
—

$ 544,276
383,435
160,841
23
(34,565)
3,551
—
129,850
(8,157)

Matador

—
5,610
(5,610)
—
(34,565)
27
157,589
117,441
(8,426)

—

(12,140)

—

(12,140)

Matador Resources Company shareholders

$ 125,867

$ 14,251

$ 157,589

$ (171,840)

$ 125,867

Condensed Consolidating Statement of Operations

Total revenues
Total expenses

Operating (loss) income

Net gain on asset sales and inventory impairment
Interest expense
Other expense
(Loss) earnings in subsidiaries

(Loss) income before income taxes

Total income tax (beneﬁt) provision

Net income attributable to non-controlling

interest in subsidiaries

Net (loss) income attributable to
Matador Resources Company shareholders

For the Year Ended December 31, 2016

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

$ 17,302
7,031
10,271
—
—
—
—
10,271
97

$ 257,828
439,947
(182,119)
107,277
—
(4)

9,810
(65,036)
(687)

$ (10,708)
(10,708)
—
—
—
—
54,539
54,539
—

$ 264,422
441,589
(177,167)
107,277
(28,199)
(4)
—
(98,093)
(1,036)

Matador

—
5,319
(5,319)
—
(28,199)
—
(64,349)
(97,867)
(446)

—

(364)

—

(364)

$ (97,421)

$ 9,810

$ (64,349)

$ 54,539

$ (97,421)

Condensed Consolidating Statement of Operations

Total revenues
Total expenses

Operating (loss) income

Net gain on asset sales and inventory impairment
Interest expense
Other income
(Loss) earnings in subsidiaries

(Loss) income before income taxes

Total income tax (beneﬁt) provision

Net income attributable to non-controlling interest

in subsidiaries

Net (loss) income attributable to
Matador Resources Company shareholders

For the Year Ended December 31, 2015

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

$ 6,310
2,944
3,366
—
—
—
—
3,366
647

$ 316,067
1,120,356
(804,289)
908
(1,243)
616
2,458
(801,550)
(142,852)

$ (4,344)
(4,344)
—
—
—
—
656,240
656,240
—

Matador

—
5,739
(5,739)
—
(20,511)
—
(658,698)
(684,948)
(5,163)

Consolidated

$ 318,033
1,124,695
(806,662)
908
(21,754)
616
—
(826,892)
(147,368)

—

(261)

—

(261)

$(679,785)

$ 2,458

$ (658,698)

$656,240

$ (679,785)

Notes to Consolidated Financial Statements FORM 10-K

F-38

MATADOR RESOURCES COMPANY

NOTE 15 — SUBSIDIARY GUARANTORS — Continued

Condensed Consolidating Statement of Cash Flows

Net cash (used in) provided by operating activities

Net cash provided by (used in) ﬁnancing activities

Decrease in cash
Cash at beginning of year
Cash at end of year

Matador

$ (307,982)
33
208,440
(99,509)
99,795
286

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2017

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

$ 21,308
(119,922)
96,307
(2,307)
2,307
—

$ 585,799
(597,519)
(2,843)
(14,563)
110,782
$ 96,219

—
(106,595)
106,595
—
—
—

$ 299,125
(824,003)
408,499
(116,379)
212,884
$ 96,505

Net cash (used in) provided by operating activities
Net cash used in investing activities
Net cash provided by ﬁnancing activities

Increase in cash
Cash at beginning of year
Cash at end of year

For the Year Ended December 31, 2016

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

6,694
(64,683)
60,110
2,121
186
2,307

$ 172,607
(401,034)
322,743
94,316
16,466
$ 110,782

— $ 134,086
(405,640)
384,801
467,706
(384,801)
196,152
—
—
16,732
— $ 212,884

Matador

$ (45,215)
(324,724)
469,654
99,715
80
$ 99,795

Condensed Consolidating Statement of Cash Flows

Net cash (used in) provided by operating activities
Net cash used in investing activities
Net cash provided by ﬁnancing activities

(Decrease) increase in cash
Cash at beginning of year
Cash at end of year

Matador

$ (31,271)
(546,715)
577,973
(13)
93
80

For the Year Ended December 31, 2015

Non-Guarantor
Subsidiaries

Guarantor
Subsidiaries

Eliminating
Entries

Consolidated

$ 13,916

$ 225,890

(31,101)
17,353
168
18
186

(410,843)
193,123
8,170
8,296
$ 16,466

— $ 208,535
(425,154)
563,505
224,944
(563,505)
8,325
—
8,407
—
— $ 16,732

NOTE 16 — RELATED PARTY TRANSACTIONS

In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by

certain afﬁliates (the “HEYCO Afﬁliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The
HEYCO Afﬁliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and
certain of his afﬁliates. Pursuant to the terms of the transaction, the HEYCO Afﬁliates contributed an aggregate of
approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-
formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate
of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2017,
the Company had contributed an aggregate of approximately $4.4 million to the two entities. The Company’s
contributions will be used to fund future capital expenditures associated with the interests being acquired as well
as to fund acquisitions of other non-operated acreage opportunities.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-39

NOTE 17 — SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The

exploration and production segment is engaged in the acquisition, exploration and development of oil and natural
gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle
Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East
Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development
and production operations and provides natural gas processing, oil transportation services, natural gas, oil and salt
water gathering services and salt water disposal services to third parties. Substantially all of the Company’s
midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through
San Mateo (see Note 5).

The following tables present selected ﬁnancial information for the periods presented regarding the Company’s

operating segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the
consolidation and elimination entries necessary to arrive at the ﬁnancial information for the Company on a
consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those
revenues from midstream operations related to third parties, including working interest owners in the Company’s
operated wells. All midstream services revenues associated with Company-owned production are eliminated
in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the
Company does not allocate certain expenses to the individual segments, including general and administrative
expenses. Such expenses are reﬂected in the column labeled “Corporate.”

Exploration and
Production

Midstream

Corporate

Consolidations
and
Eliminations

Consolidated
Company

Year Ended December 31, 2017
Oil and natural gas revenues

Realized loss on derivatives
Unrealized gain on derivatives
Expenses (1)
Operating income (loss) (2)

$ 525,862
—
(4,321)
9,715
333,923
$ 197,333

$ 2,822
47,037
—
—
23,420
$ 26,439

—
—
—
—
62,931
$ (62,931)

—
(36,839)
—
—
(36,839)
—

(3)

$ 1,768,393

$ 257,871

$ 119,426

$ 753,157

$ 114,113

$ 5,688

—

$ 528,684
10,198
(4,321)
9,715
383,435
$ 160,841

$ 2,145,690

$ 872,958

Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream
segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million.

(2) Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

Notes to Consolidated Financial Statements FORM 10-K

F-40

MATADOR RESOURCES COMPANY

NOTE 17 — SEGMENT INFORMATION — Continued

Year Ended December 31, 2016
Oil and natural gas revenues
Midstream services revenues
Realized gain on derivatives
Unrealized loss on derivatives
Expenses (1)
Operating (loss) income (2)

Total assets

Capital expenditures

Exploration and
Production

Midstream

Corporate

Consolidations
and
Eliminations

Consolidated
Company

$ 289,512
—
9,286
(41,238)
391,098
$ (133,538)

1,644
18,982
—
—
8,254
$ 12,372

—
—
—
—
56,001
$ (56,001)

$1,098,525

$140,459

$225,681

$ 379,881

$ 67,566

6,913

—

(13,764)
—
—
(13,764)

—

$ 291,156
5,218
9,286
(41,238)
441,589
$ (177,167)

$1,464,665

$ 454,360

(1) Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream

segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling
impairment expense of $158.6 million for the exploration and production segment.

(2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

Year Ended December 31, 2015
Oil and natural gas revenues
Midstream services revenues
Realized gain on derivatives
Unrealized loss on derivatives
Expenses (1)
Operating (loss) income (2)

Total assets

Capital expenditures (3)

Exploration and
Production

Midstream

Corporate

Consolidations
and
Eliminations

Consolidated
Company

$ 277,844
—
77,094
(39,265)
1,078,534
$ (762,861)

496
11,485
—
—
5,178
$ 6,803

—
—
—
—
50,604
$(50,604)

$ —

(9,621)
—
—
(9,621)

$ —

$ 278,340
1,864
77,094
(39,265)
1,124,695
$ (806,662)

$1,000,075

$75,980

$ 64,806

$ —

$1,140,861

$ 622,642

$75,009

786

$ —

$ 698,437

(1) Includes depletion, depreciation and amortization expenses of $176.7 million and $1.6 million for the exploration and production and midstream

segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.5 million and full-cost ceiling
impairment expense of $801.2 million for the exploration and production segment.

(2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) In October 2015, the Company sold the Loving County Processing System to EnLink and the cost basis of $31.0 million for those assets was

removed from the total midstream assets.

FORM 10-K Notes to Consolidated Financial Statements

2017 ANNUAL REPORT

F-41

NOTE 18 — SUBSEQUENT EVENTS

On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains
to gather and transport crude oil for the Company and third-party customers in and around the Rustler Breaks asset
area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through
a joint tariff arrangement and related transactions to offer third-party producers located within a joint development
area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil
transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing
and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase Matador’s oil production in
the Rustler Breaks asset area and in the Wolf asset area in Loving County, Texas.

Notes to Consolidated Financial Statements FORM 10-K

F-42

MATADOR RESOURCES COMPANY

Unaudited Supplementary Information

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2017, 2016 and 2015

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration

and development of oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015
(in thousands).

Property acquisition costs

Proved
Unproved and unevaluated

Exploration costs
Development costs

Total costs incurred (1)

Year Ended December 31,

2017

2016

2015

$ 45,270
214,662
167,213
326,012
$ 753,157

—
108,206
113,562
158,113
$379,881

$ 16,524
253,923
122,495
229,700
$622,642

(1) Excludes midstream-related development and corporate costs of approximately $119.8 million, $74.5 million and $75.8 million for the years

ended December 31, 2017, 2016 and 2015, respectively.

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties,

including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended
December 31, 2017, 2016 and 2015, most of the Company’s property acquisition costs resulted from the acquisition
of unproved and unevaluated leasehold and mineral interests.

Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant

further examination and in examining speciﬁc areas that are considered to be prospective for oil and natural gas,
including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining
unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil
and natural gas properties.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting,

treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations
for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities.

Costs incurred also include new asset retirement obligations established, as well as changes to asset

retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations
included in the table above were approximately $4.8 million, $4.4 million and $3.3 million for the years ended
December 31, 2017, 2016 and 2015, respectively. Capitalized general and administrative expenses that are directly
related to acquisition, exploration and development activities are also included in the table above. The Company
capitalized $23.1 million, $15.7 million and $6.9 million of these internal costs for the years ended December 31, 2017,
2016 and 2015, respectively. Capitalized interest expense for qualifying projects is also included in the table above.
The Company capitalized $7.3 million, $3.7 million and $3.9 million of its interest expense for the years ended
December 31, 2017, 2016 and 2015, respectively.

FORM 10-K Unaudited Supplementary Information

2017 ANNUAL REPORT

F-43

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate

with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and
operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous
uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical,
petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated
interpretations of that data can vary. The process also requires certain economic assumptions, including, but not
limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses
and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.

The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry

and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and
Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in
South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead
natural gas price on those properties where the NGLs are extracted and sold. The Company’s oil and natural gas
reserves estimates for the years ended December 31, 2017, 2016 and 2015 were prepared by the Company’s
engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness
and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no

provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices
used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of ﬁrst-day-of-the-month
oil and natural gas prices for the previous 12-month period. For the period from January through December 2017,
these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period
from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per
MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas
prices were $46.79 per Bbl and $2.59 per MMBtu, respectively.

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net

proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to
properties located in the United States. The estimated reserves shown below are for proved reserves only and do
not include any value for unproved reserves classiﬁed as probable or possible reserves that might exist for these
properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond
those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas
is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas.

Unaudited Supplementary Information FORM 10-K

F-44

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Total at December 31, 2014

Revisions of prior estimates
Purchases of minerals-in-place
Extensions and discoveries
Production

Total at December 31, 2015

Revisions of prior estimates
Extensions and discoveries
Production

Total at December 31, 2016

Revisions of prior estimates
Purchases of minerals-in-place
Extensions and discoveries
Production

Total at December 31, 2017

Proved Developed Reserves
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017

Proved Undeveloped Reserves
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017

Net Proved Reserves

Oil

(MBbl)

24,184
(2,609)
1,102
27,459
(4,492)
45,644
(6,440)
22,869
(5,096)
56,977
3,847
5,257
28,513
(7,851)
86,743

14,053
17,129
22,604
36,966

10,131
28,515
34,373
49,777

Natural
Gas

(MMcf)

267,055
(75,433)
2,927
70,054
(27,702)
236,901
(28,481)
114,730
(30,501)
292,649
34,395
7,348
99,935
(38,163)
396,164

102,795
101,447
126,759
190,109

164,260
135,454
165,890
206,055

Oil
Equivalent

(MBOE)

68,693
(15,181)
1,589
39,135
(9,109)
85,127
(11,187)
41,992
(10,180)
105,752
9,580
6,482
45,169
(14,212)
152,771

31,185
34,037
43,731
68,651

37,508
51,090
62,021
84,120

The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for

the years ended December 31, 2017, 2016 and 2015.

The Company’s proved oil and natural gas reserves increased to 152,771 MBOE at December 31, 2017 from
105,752 MBOE at December 31, 2016. The Company’s proved oil and natural gas reserves increased by 61,231 MBOE
and the Company produced 14,212 MBOE during the year ended December 31, 2017, resulting in a net increase
of 47,019 MBOE. An increase of 45,169 MBOE in proved oil and natural gas reserves was a result of extensions
and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and
Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and
natural gas reserves increased by 9,580 MBOE during 2017 as a result of revisions of prior estimates, which were
attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural
gas prices used to estimate proved reserves in 2017, as compared to 2016. The Company also added 6,482 MBOE
in proved oil and natural gas reserves in 2017 as a result of purchases of minerals-in-place in the Delaware Basin.
The Company’s proved developed oil and natural gas reserves increased to 68,651 MBOE at December 31, 2017
from 43,731 MBOE at December 31, 2016, primarily due to proved developed reserves added as a result of drilling
operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2017, the Company’s
proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 45% proved
developed and approximately 55% proved undeveloped.

FORM 10-K Unaudited Supplementary Information

2017 ANNUAL REPORT

F-45

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The Company’s proved oil and natural gas reserves increased to 105,752 MBOE at December 31, 2016 from
85,127 MBOE at December 31, 2015. The Company’s proved oil and natural gas reserves increased by 30,805 MBOE
and the Company produced 10,180 MBOE during the year ended December 31, 2016, resulting in a net increase
of 20,625 MBOE. An increase of 41,992 MBOE in proved oil and natural gas reserves was a result of extensions and
discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas
reserves decreased by 11,187 MBOE during 2016 as a result of the reclassiﬁcation of proved undeveloped reserves
to contingent resources, primarily due to the decline in weighted average commodity prices used to estimate
proved reserves during 2016, as compared to 2015. The Company’s proved developed oil and natural gas reserves
increased to 43,731 MBOE at December 31, 2016 from 34,037 MBOE at December 31, 2015, primarily due to
proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the
Delaware Basin. At December 31, 2016, the Company’s proved reserves were made up of approximately 54% oil
and 46% natural gas and were approximately 41% proved developed and approximately 59% proved undeveloped.

The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from

68,693 MBOE at December 31, 2014. The Company’s proved oil and natural gas reserves increased by 25,543 MBOE
and the Company produced 9,109 MBOE during the year ended December 31, 2015, resulting in a net increase
of 16,434 MBOE. An increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and
discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas
reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the
removal of 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015, as
well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves,
primarily in the Haynesville shale in Northwest Louisiana, primarily resulting from the decline in commodity prices
during 2015. The Company also purchased minerals-in-place with proved reserves of 1,589 MBOE in 2015,
primarily as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to
34,037 MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014, primarily due to proved developed
reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and
the Eagle Ford shale and the conversion of previously undeveloped natural gas reserves in the Haynesville shale to
proved developed reserves. At December 31, 2015, the Company’s proved reserves were made up of
approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately
60% proved undeveloped.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to
Proved Oil and Natural Gas Reserves

The standardized measure of discounted future net cash ﬂows relating to proved oil and natural gas reserves is

not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural
gas properties. An estimate of fair market value would also take into account, among other things, the recovery of
reserves not presently classiﬁed as proved, anticipated future changes in prices and costs, potential improvements
in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different
discount rates.

Unaudited Supplementary Information FORM 10-K

F-46

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

As noted previously, for the period from January through December 2017, the unweighted, arithmetic averages
of ﬁrst-day-of-the-month oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the
period from January through December 2016, the comparable average oil and natural gas prices were $39.25 per
Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, the comparable
average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively.

Future net cash ﬂows were computed by applying these oil and natural gas prices, adjusted for all associated
transportation and gathering costs, gravity and energy content, and regional price differentials, to year-end quantities
of proved oil and natural gas reserves and accounting for any future production and development costs associated
with producing these reserves; neither prices nor costs were escalated with time in these computations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cash ﬂows

relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net
operating loss carryforwards available to the Company were also considered in the computation of future income
taxes. Future net cash ﬂows after income taxes were discounted using a 10% annual discount rate to derive the
standardized measure of discounted future net cash ﬂows.

The following table presents the standardized measure of discounted future net cash ﬂows relating to proved

oil and natural gas reserves for the years ended December 31, 2017, 2016 and 2015 (in thousands).

Year Ended December 31,

2017

2015

2014

Future cash inﬂows
Future production costs
Future development costs
Future income tax expense
Future net cash ﬂows

10% annual discount for estimated timing of cash ﬂows

$ 5,249,116

$2,684,877

(1,759,495)
(1,029,105)
(228,622)
2,231,894
(973,248)

(927,725)
(630,280)
(24,742)
1,102,130
(527,087)

Standardized measure of discounted future net cash ﬂows

$ 1,258,646

$ 575,043

$2,461,131
(843,117)
(615,692)
(43,956)
958,366
(429,185)
$ 529,181

The following table summarizes the changes in the standardized measure of discounted future net cash ﬂows
relating to proved oil and natural gas reserves for the years ended December 31, 2017, 2016 and 2015 (in thousands).

Year Ended December 31,

2017

2015

2014

$ 575,043

$ 529,181

$ 913,319

374,370
(298,504)
(403,095)
97,225
677,681
143,749
151,974
54,623
(3,929)
(110,491)

(92,477)
(74,142)
(191,908)
—
360,033
(95,917)
84,519
51,779
(1,962)
5,937
$ 575,043

(509,901)
(145,861)
(184,612)
16,321
401,895
(285,823)
121,543
82,574
2,029
117,697
$ 529,181

Balance, beginning of period
Net change in sales and transfer prices and in production (lifting) costs

related to future production

Changes in estimated future development costs
Sales and transfers of oil and natural gas produced during the period
Purchases of reserves in place
Net change due to extensions and discoveries
Net change due to revisions in estimates of reserves quantities
Previously estimated development costs incurred during the period
Accretion of discount
Other
Net change in income taxes

Standardized measure of discounted future net cash ﬂows

$ 1,258,646

FORM 10-K Unaudited Supplementary Information

2017 ANNUAL REPORT

F-47

SELECTED QUARTERLY FINANCIAL INFORMATION

The following table presents selected unaudited quarterly ﬁnancial information for 2017 (in thousands, except

per share data).

2017
Oil and natural gas revenues
Third-party midstream services revenues
Realized (loss) gain on derivatives
Unrealized (loss) gain on derivatives
Expenses
Other expense
Income before income taxes
Income tax beneﬁt
Net income
Net income attributable to non-controlling interest

in subsidiaries

Net income attributable to

December 31 September 30

June 30

March 31

$ 165,125
3,326
(3,145)
(11,734)
112,547
(6,741)
34,284
(8,157)
42,441

$ 134,948
3,218
485
(12,372)
99,730
(8,570)
17,979
—
17,979

$ 113,764
2,099
558
13,190
90,622
(7,302)
31,687
—
31,687

$ 114,847
1,555
(2,219)
20,631
80,536
(8,378)
45,900
—
45,900

(4,106)

(2,940)

(3,178)

(1,916)

Matador Resources Company shareholders

$ 38,335

$ 15,039

$ 28,509

$ 43,984

Earnings per common share

Basic

Diluted

0.36

0.35

0.15

0.28

0.44

The following table presents selected unaudited quarterly ﬁnancial information for 2016 (in thousands, except

per share data).

2016
Oil and natural gas revenues
Third-party midstream services revenues
Realized (loss) gain on derivatives
Unrealized (loss) gain on derivatives
Expenses (1)
Other income (expense) (2)
Income (loss) before income taxes
Income tax provision (beneﬁt)
Net income (loss)
Net (income) loss attributable to non-controlling

interest in subsidiaries

Net income (loss) attributable to

December 31 September 30

June 30

March 31

$ 94,815
2,261
(1,127)
(10,977)
76,753
96,196
104,415
105
104,310

$ 83,079
1,566
885
3,203
71,879
(5,948)
10,906
(1,141)
12,047

$ 69,336
918
2,465
(26,625)
146,705
(5,136)
(105,747)
—
(105,747)

$ 43,926
473
7,063
(6,839)
146,252
(6,038)
(107,667)
—
(107,667)

(155)

(116)

(106)

Matador Resources Company shareholders

$104,155

$ 11,931

$(105,853)

$(107,654)

Earnings (loss) per common share

Basic

Diluted

1.10

1.09

0.13

(1.15)

(1.26)

(1) Expenses for June 30 and March 31, 2016 included full-cost ceiling impairment charges of $78.2 million and $80.5 million, respectively.

(2) Other income (expense) for December 31, 2016 included gain on the sale of the Loving County Processing System of $104.1 million.

See Note 5.

Unaudited Supplementary Information FORM 10-K

MATADOR RESOURCES COMPANY

Exhibit 31.1

CERTIFICATION

I, Joseph Wm. Foran, certify that:

1. I have reviewed this annual report on Form 10-K of Matador Resources Company;

2. 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;

3. 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;

4. The registrant’s other certifying ofﬁcer(s) 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. 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;

b. 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;

c. 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

d. 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(s) 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. 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

b. 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.

February 28, 2018

FORM 10-K

/s/ Joseph Wm. Foran
Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

2017 ANNUAL REPORT

Exhibit 31.2

CERTIFICATION

I, David E. Lancaster, certify that:

1. I have reviewed this annual report on Form 10-K of Matador Resources Company;

2. 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;

3. 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;