Item 2. 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 interim unaudited condensed consolidated financial statements and related notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31,
2016
(the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at
www.sec.gov
and on our website at
www.matadorresources.com
. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (the “Quarterly Report”), references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole and references to “Matador” refer solely to Matador Resources Company.
For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly 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” 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 Quarterly 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 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 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;
|
|
|
•
|
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 Quarterly Report or in our other filings with the SEC that are not historical.
|
Although we believe that the expectations conveyed by the forward-looking statements in this Quarterly 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 do not intend 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.
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 Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.
Second Quarter and Year-to-Date Highlights
For the
three months ended June 30, 2017
, our total oil equivalent production was
3.4 million
BOE, and our average daily oil equivalent production was
36,922
BOE per day, of which
19,423
Bbl per day, or
53%
, was oil and
105.0
MMcf per day, or
47%
, was natural gas. Our oil production of
1.77
million Bbl for the
three months ended June 30, 2017
increased
44%
year-over-year from
1.23
million Bbl for the
three months ended June 30, 2016
. Our natural gas production of
9.6
Bcf for the
three months ended June 30, 2017
increased
21%
year-over-year from
7.9
Bcf for the
three months ended June 30, 2016
. For the
six months ended June 30, 2017
, our total oil equivalent production was
6.3 million
BOE, and our average daily oil equivalent production was
34,972
BOE per day, of which
18,876
Bbl per day, or
54%
, was oil and
96.6
MMcf per day, or
46%
, was natural gas. Our oil production of
3.4 million
Bbl for the
six months ended June 30, 2017
increased
50%
year-over-year from
2.3 million
Bbl for the
six months ended June 30, 2016
. Our natural gas production of
17.5
Bcf for the
six months ended June 30, 2017
increased
19%
year-over-year from
14.7
Bcf for the
six months ended June 30, 2016
.
For the
second quarter
of
2017
, we reported net income attributable to Matador Resources Company shareholders of approximately
$28.5 million
, or
$0.28
per diluted common share on a GAAP basis, as compared to a net loss attributable to Matador Resources Company shareholders of
$105.9 million
, or
$1.15
per diluted common share, for the
second quarter
of 2016. For the
second quarter
of
2017
, our Adjusted EBITDA attributable to Matador Resources Company shareholders (“
Adjusted EBITDA
”), a non-GAAP financial measure, was
$72.7 million
, as compared to
Adjusted EBITDA
of
$38.9 million
during the
second quarter
of
2016
. 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 “— Liquidity and Capital Resources — Non-GAAP Financial
Measures.” For more information regarding our financial results for the second quarter of
2017
, see “— Results of Operations” below.
For the
six months ended June 30, 2017
, we reported net income attributable to Matador Resources Company shareholders of approximately
$72.5 million
, or
$0.72
per diluted common share on a GAAP basis, as compared to a net loss attributable to Matador Resources Company shareholders of
$213.5 million
, or
$2.40
per diluted common share, for the
six months ended June 30, 2016
. For the
six months ended June 30, 2017
, our
Adjusted EBITDA
, a non-GAAP financial measure, was
$142.6 million
, as compared to
Adjusted EBITDA
of
$56.1 million
during the
six months ended June 30, 2016
. 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 “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for the second quarter of
2017
, see “— Results of Operations” below.
During the
second quarter
of
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 and expect to operate five rigs in the Delaware Basin throughout the remainder of 2017, including three rigs in our Rustler Breaks and Antelope Ridge asset areas, one rig in our Wolf and Jackson Trust asset areas and one rig in our Ranger/Arrowhead and Twin Lakes asset areas. We expect to direct over 90% of our estimated 2017 capital expenditure budget (excluding capital expenditures related to acreage, mineral and seismic data acquisitions) to drilling and completion and midstream activities in the Delaware Basin. At
June 30, 2017
, we had incurred approximately
$241 million
, or
51%
, of our
2017
capital expenditure budget of between $456 and $484 million (excluding capital expenditures related to acreage, mineral and seismic data acquisitions).
In July 2017, we took delivery of a sixth drilling rig on a temporary basis for the purpose of drilling a second salt water disposal well in the Rustler Breaks asset area for San Mateo. Upon delivery of the sixth drilling rig, the salt water disposal well was not ready to spud, so at
August 2, 2017
, we were using this rig to drill an additional oil and natural gas well in our Rustler Breaks asset area. At
August 2, 2017
, we had no plans to use this sixth rig to drill additional oil and natural gas wells for the remainder of 2017.
We also finished drilling our five-well program in the Eagle Ford shale in South Texas during the second quarter of 2017. Two of these wells were completed and turned to sales in mid-June 2017. The other three wells were completed and turned to sales in early July 2017, and thus, did not contribute to second quarter 2017 production volumes. The rig used to drill these five wells was released in May 2017, and we have no additional operated drilling activities planned in the Eagle Ford shale for the remainder of 2017.
We completed and turned to sales a total of 21 gross (14.2 net) wells in the Delaware Basin during the
second quarter
of
2017
, including 16 gross (13.5 net) operated and five gross (0.7 net) non-operated horizontal wells. In the Rustler Breaks asset area, we began producing oil and natural gas from a total of 13 gross (8.2 net) wells during the
second quarter
of
2017
, including nine gross (7.6 net) operated and four gross (0.6 net) non-operated wells. Of the nine gross operated wells in the Rustler Breaks asset area, five were Wolfcamp A-XY completions, one was a Wolfcamp A-Lower completion and three were Wolfcamp B-Blair completions. In addition, we began producing oil and natural gas from five gross (4.2 net) operated wells in the Wolf asset area during the
second quarter
of
2017
, including one Wolfcamp A-XY completion and four Second Bone Spring completions. In the Ranger, Arrowhead and Twin Lakes asset areas, we began producing oil and natural gas from a total of one gross (0.1 net) non-operated well, one gross (0.7 net) operated well and one gross (1.0 net) operated well, respectively, during the
second quarter
of
2017
. The well in the Arrowhead asset area, a Second Bone Spring completion, and the well in the Twin Lakes asset area, a Wolfcamp D completion, were the first operated horizontal wells we had tested in their respective asset areas.
As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production has continued to increase over the past twelve months. Our total Delaware Basin production for the
second quarter
of
2017
was 27,622 BOE per day, consisting of 16,645 Bbl of oil per day and 65.9 MMcf of natural gas per day, a 90% increase from production of 14,525 BOE per day, consisting of 9,789 Bbl of oil per day and 28.4 MMcf of natural gas per day, in the
second quarter
of
2016
. The Delaware Basin contributed approximately 86% of our daily oil production and approximately 63% of our daily natural gas production in the
second quarter
of
2017
, as compared to approximately 72% of our daily oil production and approximately 33% of our daily natural gas production in the
second quarter
of
2016
.
During the second quarter of 2017 and through August 2, 2017, we acquired approximately 8,300 net acres in the Delaware Basin, mostly in and around our existing acreage positions, including new leasing activities, acquisitions of small interests from mineral and working interest owners in our operated wells and acreage trades or term assignments with other operators. We incurred capital expenditures of approximately $28.0 million to acquire this additional acreage throughout the Delaware Basin, as well as for new 3-D seismic data across portions of our Wolf asset area. At
August 2, 2017
, we held approximately
189,500
gross (
108,000
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. We plan to continue our leasing and acquisitions efforts in the Delaware Basin during the remainder of 2017 and may also continue acquiring acreage in the Eagle Ford and Haynesville shales as strategic opportunities are identified.
Estimated Proved Reserves
The following table sets forth our estimated total proved oil and natural gas reserves at
June 30, 2017
,
December 31, 2016
and
June 30, 2016
. 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 associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. 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. 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 would be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total proved reserves are estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2017
|
|
December 31,
2016
|
|
June 30,
2016
|
Estimated Proved Reserves Data:
(1)
(2)
|
|
|
|
|
|
Estimated proved reserves:
|
|
|
|
|
|
Oil (MBbl)
(3)
|
74,954
|
|
|
56,977
|
|
|
52,337
|
|
Natural Gas (Bcf)
(4)
|
356.5
|
|
|
292.6
|
|
|
258.7
|
|
Total (MBOE)
(5)
|
134,373
|
|
|
105,752
|
|
|
95,457
|
|
Estimated proved developed reserves:
|
|
|
|
|
|
Oil (MBbl)
(3)
|
28,454
|
|
|
22,604
|
|
|
19,913
|
|
Natural Gas (Bcf)
(4)
|
159.7
|
|
|
126.8
|
|
|
114.4
|
|
Total (MBOE)
(5)
|
55,075
|
|
|
43,731
|
|
|
38,978
|
|
Percent developed
|
41.0
|
%
|
|
41.4
|
%
|
|
40.8
|
%
|
Estimated proved undeveloped reserves:
|
|
|
|
|
|
Oil (MBbl)
(3)
|
46,500
|
|
|
34,373
|
|
|
32,424
|
|
Natural Gas (Bcf)
(4)
|
196.8
|
|
|
165.9
|
|
|
144.3
|
|
Total (MBOE)
(5)
|
79,298
|
|
|
62,021
|
|
|
56,479
|
|
Standardized Measure
(6)
(in millions)
|
$
|
1,001.9
|
|
|
$
|
575.0
|
|
|
$
|
468.3
|
|
PV-10
(7)
(in millions)
|
$
|
1,086.9
|
|
|
$
|
581.5
|
|
|
$
|
473.2
|
|
_______________
|
|
(1)
|
Numbers in table may not total due to rounding.
|
|
|
(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 period from July 2016 through June 2017 were
$45.42
per Bbl for oil and
$3.01
per MMBtu for natural gas, for the period from January 2016 through December 2016 were
$39.25
per Bbl for oil and
$2.48
per MMBtu for natural gas and for the period from July 2015 through June 2016 were
$39.63
per Bbl for oil and
$2.24
per MMBtu for natural gas. These prices were adjusted by property 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 natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.
|
|
|
(3)
|
One thousand barrels of oil.
|
|
|
(4)
|
One billion cubic feet of natural gas.
|
|
|
(5)
|
One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
(6)
|
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.
|
|
|
(7)
|
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
June 30, 2017
,
December 31, 2016
and
June 30, 2016
may be reconciled to the 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
June 30, 2017
,
December 31, 2016
and
June 30, 2016
were
$85.0 million
,
$6.5 million
and
$4.9 million
, respectively.
|
At
June 30, 2017
, our estimated total proved oil and natural gas reserves were
134.4 million
BOE, including
75.0 million
Bbl of oil and
356.5
Bcf of natural gas, with a Standardized Measure of
$1,001.9 million
and a PV-10, a non-GAAP financial measure, of
$1,086.9 million
. 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, and at
June 30, 2016
, our estimated total proved oil and natural gas reserves were
95.5 million
BOE, including
52.3 million
Bbl of oil and
258.7
Bcf of natural gas. Our proved oil reserves of
75.0 million
Bbl at
June 30, 2017
increased
32%
, as compared to
57.0 million
Bbl at
December 31, 2016
, and increased
43%
, as compared to
52.3 million
Bbl at
June 30, 2016
. At
June 30, 2017
, approximately
41%
of our total proved reserves were proved developed reserves,
56%
of our total proved reserves were oil and
44%
of our total proved reserves were natural gas.
As a result of our drilling, completion and delineation activities in Southeast New Mexico and West Texas since 2014, our Delaware Basin oil and natural gas reserves have become a more significant component of our total oil and natural gas reserves. Our estimated Delaware Basin proved oil and natural gas reserves increased
63%
from
66.2 million
BOE at
June 30, 2016
, or
69%
of our total proved oil and natural gas reserves, including
40.3 million
Bbl of oil and
155.3
Bcf of natural gas, to
108.1 million
BOE, or
80%
of our total proved oil and natural gas reserves, including
64.9 million
Bbl of oil and
259.2
Bcf of natural gas, at
June 30, 2017
.
There have been no changes to the technology we used to establish reserves or to our internal control over the reserves estimation process from those set forth in the Annual Report.
Critical Accounting Policies
There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.
Recent Accounting Pronouncements
See Note 2 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of recent accounting pronouncements that we believe may have an impact on our financial statements upon adoption.
Results of Operations
Revenues
The following table summarizes our unaudited revenues and production data for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Operating Data:
|
|
|
|
|
|
|
|
Revenues (in thousands):
(1)
|
|
|
|
|
|
|
|
Oil
|
$
|
81,322
|
|
|
$
|
52,691
|
|
|
$
|
164,958
|
|
|
$
|
82,849
|
|
Natural gas
|
32,442
|
|
|
16,645
|
|
|
63,653
|
|
|
30,413
|
|
Total oil and natural gas revenues
|
113,764
|
|
|
69,336
|
|
|
228,611
|
|
|
113,262
|
|
Third-party midstream services revenues
(2)
|
2,099
|
|
|
918
|
|
|
3,654
|
|
|
1,391
|
|
Realized gain (loss) on derivatives
|
558
|
|
|
2,465
|
|
|
(1,661
|
)
|
|
9,528
|
|
Unrealized gain (loss) on derivatives
|
13,190
|
|
|
(26,625
|
)
|
|
33,821
|
|
|
(33,464
|
)
|
Total revenues
|
$
|
129,611
|
|
|
$
|
46,094
|
|
|
$
|
264,425
|
|
|
$
|
90,717
|
|
Net Production Volumes:
(1)
|
|
|
|
|
|
|
|
Oil (MBbl)
(3)
|
1,767
|
|
|
1,230
|
|
|
3,417
|
|
|
2,274
|
|
Natural gas (Bcf)
(4)
|
9.6
|
|
|
7.9
|
|
|
17.5
|
|
|
14.7
|
|
Total oil equivalent (MBOE)
(5)
|
3,360
|
|
|
2,550
|
|
|
6,330
|
|
|
4,720
|
|
Average daily production (BOE/d)
(6)
|
36,922
|
|
|
28,022
|
|
|
34,972
|
|
|
25,934
|
|
Average Sales Prices:
|
|
|
|
|
|
|
|
Oil, without realized derivatives (per Bbl)
|
$
|
46.01
|
|
|
$
|
42.84
|
|
|
$
|
48.28
|
|
|
$
|
36.43
|
|
Oil, with realized derivatives (per Bbl)
|
$
|
46.34
|
|
|
$
|
43.29
|
|
|
$
|
47.97
|
|
|
$
|
39.08
|
|
Natural gas, without realized derivatives (per Mcf)
|
$
|
3.40
|
|
|
$
|
2.10
|
|
|
$
|
3.64
|
|
|
$
|
2.07
|
|
Natural gas, with realized derivatives (per Mcf)
|
$
|
3.39
|
|
|
$
|
2.34
|
|
|
$
|
3.61
|
|
|
$
|
2.31
|
|
_________________
|
|
(1)
|
We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues.
|
|
|
(2)
|
Reclassified from other income for the three and six months ended June 30, 2016 due to the midstream segment becoming a reportable segment.
|
|
|
(3)
|
One thousand barrels of oil.
|
|
|
(4)
|
One billion cubic feet of natural gas.
|
|
|
(5)
|
One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
(6)
|
Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
Three Months Ended June 30, 2017
as Compared to
Three Months Ended June 30, 2016
Oil and natural gas revenues
. Our oil and natural gas revenues
increase
d $
44.4 million
to
$113.8 million
, or
64%
, for the
three months ended June 30, 2017
, as compared to
$69.3 million
for the
three months ended June 30, 2016
. Our oil revenues
increase
d
$28.6 million
, or
54%
, to
$81.3 million
for the
three months ended June 30, 2017
, as compared to
$52.7 million
for the
three months ended June 30, 2016
. The
increase
in oil revenues resulted from (i) a higher weighted average oil price realized for the
three months ended June 30, 2017
of
$46.01
per Bbl, as compared to
$42.84
per Bbl realized for the
three months ended June 30, 2016
, and (ii) the
44%
increase
in oil production to
1.77 million
Bbl of oil for the
three months ended June 30, 2017
, or about
19,423
Bbl of oil per day, as compared to
1.23 million
Bbl of oil, or about
13,516
Bbl of oil per day, for the
three months ended June 30, 2016
. The
increase
in oil production is primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues
increase
d by
$15.8 million
, or
95%
, to
$32.4 million
for the
three months ended June 30, 2017
, as compared to
$16.6 million
for the
three months ended June 30, 2016
. The
increase
in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the
three months ended June 30, 2017
of
$3.40
per Mcf, as compared to
$2.10
per Mcf realized for the
three months ended June 30, 2016
, and (ii) the
21%
increase in our natural gas production to
9.6
Bcf for the
three months ended June 30, 2017
, as compared to
7.9
Bcf for the
three months ended June 30, 2016
. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.
Third-party midstream services revenues.
Our third-party midstream services revenues increased to
$2.1 million
, or
129%
, for the
three months ended June 30, 2017
, as compared to
$0.9 million
for the
three months ended June 30, 2016
. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately
$1.6 million
for the
three months ended June 30, 2017
, as compared to
$0.3 million
for the
three months ended June 30, 2016
, due to (i) our natural gas gathering system and the Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) in the Rustler Breaks asset area being placed into service in the second half of 2016 and (ii) increased natural gas production in our Wolf asset area.
Realized gain on derivatives
. Our realized net gain on derivatives was
$0.6 million
for the
three months ended June 30, 2017
, as compared to a realized net gain of
$2.5 million
for the
three months ended June 30, 2016
. We realized a net gain of
$0.6 million
from our oil derivative contracts for the
three months ended June 30, 2017
, resulting from oil prices below the floor prices of certain of our oil costless collar contracts. We realized net gains of
$0.6 million
and
$1.9 million
from our oil and natural gas derivative contracts, respectively, for the
three months ended June 30, 2016
, resulting from oil and natural gas prices below the floor prices of the majority of our oil and natural gas costless collar contracts. We realized an average gain of approximately
$0.47
per Bbl hedged on all of our open oil costless collar contracts during the
three months ended June 30, 2017
, as compared to an average gain of
$0.81
per Bbl hedged for the
three months ended June 30, 2016
. Our oil volumes hedged for the
three months ended June 30, 2017
were
78%
higher
as compared to the
three months ended June 30, 2016
. We realized an average gain of approximately
$0.65
per MMBtu hedged on all of our open natural gas costless collar contracts for the
three months ended June 30, 2016
. Our total natural gas volumes hedged for the
three months ended June 30, 2017
were
109%
higher
than the total natural gas volumes hedged for the
three months ended June 30, 2016
.
Unrealized gain (loss) on derivatives.
Our unrealized net gain on derivatives was
$13.2 million
for the
three months ended June 30, 2017
, as compared to an unrealized net loss of
$26.6 million
for the
three months ended June 30, 2016
. During the
three months ended June 30, 2017
, the aggregate net fair value of our open oil and natural gas derivative contracts increased to an asset of approximately
$8.9 million
from a liability of
$4.3 million
at
March 31, 2017
, resulting in an unrealized net gain on derivatives of
$13.2 million
for the
three months ended June 30, 2017
. During the
three months ended June 30, 2016
, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a liability of $17.2 million from an asset of $9.4 million at March 31, 2016, resulting in an unrealized loss on derivatives of
$26.6 million
for the
three months ended June 30, 2016
.
Six Months Ended June 30, 2017
as Compared to
Six Months Ended June 30, 2016
Oil and natural gas revenues.
Our oil and natural gas revenues
increase
d
$115.3 million
to
$228.6 million
, or
102%
, for the
six months ended June 30, 2017
, as compared to
$113.3 million
for the
six months ended June 30, 2016
. Our oil revenues
increase
d
$82.1 million
, or
99%
, to
$165.0 million
for the
six months ended June 30, 2017
, as compared to
$82.8 million
for the
six months ended June 30, 2016
. The
increase
in oil revenues resulted from (i) a higher weighted average oil price realized for the
six months ended June 30, 2017
of
$48.28
per Bbl, as compared to
$36.43
per Bbl realized for the
six months ended June 30, 2016
, and (ii) the
50%
increase
in oil production to
3.42 million
Bbl of oil in the
six months ended June 30, 2017
, or about
18,876
Bbl of oil per day, as compared to
2.27 million
Bbl of oil, or about
12,495
Bbl of oil per day, in the
six months ended June 30, 2016
. This
increase
d oil production is primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues
increase
d by
$33.2 million
, or
109%
, to
$63.7 million
for the
six months ended June 30, 2017
, as compared to
$30.4 million
for the
six months ended June 30, 2016
. The
increase
in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the
six months ended June 30, 2017
of
$3.64
per Mcf, as compared to
$2.07
per Mcf realized for the
six months ended June 30, 2016
, and (ii) the
19%
increase
in our natural gas production to
17.5
Bcf for the
six months ended June 30, 2017
, as compared to
14.7
Bcf for the
six months ended June 30, 2016
. The
increase
in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.
Third-party midstream services revenues.
Our third-party midstream services revenues increased to
$3.7 million
, or
163%
, for the
six months ended June 30, 2017
, as compared to
$1.4 million
for the
six months ended June 30, 2016
. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately
$2.8 million
for the
six months ended June 30, 2017
, as compared to
$0.7 million
for the
six months ended June 30, 2016
, due to (i) our natural gas gathering system and the Black River Processing Plant in the Rustler Breaks asset area being placed into service in the second half of 2016 and (ii) increased natural gas production in our Wolf asset area.
Realized gain (loss) on derivatives.
Our realized net loss on derivatives was
$1.7 million
for the
six months ended June 30, 2017
, as compared to a net gain of approximately
$9.5 million
for the
six months ended June 30, 2016
. We realized net losses of
$1.1 million
and
$0.6 million
from our oil and natural gas derivative contracts, respectively, for the
six months ended June 30, 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
$6.0 million
and
$3.5 million
from our oil and natural gas derivative contracts, respectively, for the
six months ended June 30, 2016
, resulting from oil and natural gas prices below the floor prices of the majority of our oil and natural gas costless collar contracts. We realized an average loss of approximately
$0.48
per Bbl hedged on all of our open oil costless collar contracts during the
six months ended June 30, 2017
, as compared to an average gain of
$5.11
per Bbl hedged for the
six months ended June 30, 2016
. Our oil volumes hedged for the
three months ended June 30, 2017
were
86%
higher
as
compared to the
six months ended June 30, 2016
. We realized an average loss of approximately
$0.05
per MMBtu hedged on all of our open natural gas costless collar contracts during the
six months ended June 30, 2017
, as compared to an average gain of approximately
$0.61
per MMBtu hedged on all of our open natural gas costless collar contracts for the
six months ended June 30, 2016
. Our total natural gas volumes hedged for the
six months ended June 30, 2017
were
102%
higher
than the total natural gas volumes hedged for the
six months ended June 30, 2016
.
Unrealized gain (loss) on derivatives.
Our unrealized gain on derivatives was approximately
$33.8 million
for the
six months ended June 30, 2017
, as compared to an unrealized loss of approximately
$33.5 million
for the
six months ended June 30, 2016
. During the period from
December 31, 2016
through
June 30, 2017
, the aggregate net fair value of our open oil and natural gas derivative contracts
increase
d from a liability of approximately $25.0 million to an asset of approximately
$8.9 million
, resulting in an unrealized gain on derivatives of approximately
$33.8 million
for the
six months ended June 30, 2017
. This gain is primarily attributable to the decrease in oil and natural gas futures prices during the
six months ended June 30, 2017
. During the period from December 31, 2015 through June 30, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts decreased from an asset of approximately $16.3 million to a liability of approximately $17.2 million, resulting in an unrealized loss on derivatives of approximately $33.5 million for the six months ended June 30, 2016.
Expenses
The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
(In thousands, except expenses per BOE)
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Expenses:
|
|
|
|
|
|
|
|
Production taxes, transportation and processing
|
$
|
12,875
|
|
|
$
|
10,556
|
|
|
$
|
24,682
|
|
|
$
|
18,459
|
|
Lease operating
(1)
|
16,040
|
|
|
12,183
|
|
|
31,797
|
|
|
26,695
|
|
Plant and other midstream services operating
|
2,942
|
|
|
1,061
|
|
|
5,283
|
|
|
2,088
|
|
Depletion, depreciation and amortization
|
41,274
|
|
|
31,248
|
|
|
75,266
|
|
|
60,170
|
|
Accretion of asset retirement obligations
|
314
|
|
|
289
|
|
|
614
|
|
|
552
|
|
Full-cost ceiling impairment
|
—
|
|
|
78,171
|
|
|
—
|
|
|
158,633
|
|
General and administrative
|
17,177
|
|
|
13,197
|
|
|
33,515
|
|
|
26,360
|
|
Total expenses
|
$
|
90,622
|
|
|
$
|
146,705
|
|
|
$
|
171,157
|
|
|
$
|
292,957
|
|
Operating income (loss)
|
$
|
38,989
|
|
|
$
|
(100,611
|
)
|
|
$
|
93,268
|
|
|
$
|
(202,240
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
Net gain on asset sales and inventory impairment
|
$
|
—
|
|
|
$
|
1,002
|
|
|
$
|
7
|
|
|
$
|
2,067
|
|
Interest expense
|
(9,224
|
)
|
|
(6,167
|
)
|
|
(17,679
|
)
|
|
(13,365
|
)
|
Other income
(2)
|
1,922
|
|
|
29
|
|
|
1,991
|
|
|
124
|
|
Total other expense
|
$
|
(7,302
|
)
|
|
$
|
(5,136
|
)
|
|
$
|
(15,681
|
)
|
|
$
|
(11,174
|
)
|
Net income (loss)
|
$
|
31,687
|
|
|
$
|
(105,747
|
)
|
|
$
|
77,587
|
|
|
$
|
(213,414
|
)
|
Net income attributable to non-controlling interest in subsidiaries
|
(3,178
|
)
|
|
(106
|
)
|
|
(5,094
|
)
|
|
(93
|
)
|
Net income (loss) attributable to Matador Resources Company shareholders
|
$
|
28,509
|
|
|
$
|
(105,853
|
)
|
|
$
|
72,493
|
|
|
$
|
(213,507
|
)
|
Expenses per BOE:
|
|
|
|
|
|
|
|
Production taxes, transportation and processing
|
$
|
3.83
|
|
|
$
|
4.14
|
|
|
$
|
3.90
|
|
|
$
|
3.91
|
|
Lease operating
(1)
|
$
|
4.77
|
|
|
$
|
4.78
|
|
|
$
|
5.02
|
|
|
$
|
5.66
|
|
Plant and other midstream services operating
|
$
|
0.88
|
|
|
$
|
0.42
|
|
|
$
|
0.83
|
|
|
$
|
0.44
|
|
Depletion, depreciation and amortization
|
$
|
12.28
|
|
|
$
|
12.25
|
|
|
$
|
11.89
|
|
|
$
|
12.75
|
|
General and administrative
|
$
|
5.11
|
|
|
$
|
5.18
|
|
|
$
|
5.29
|
|
|
$
|
5.58
|
|
_________________
|
|
(1)
|
$1.1 million
, or
$0.42
per BOE, and
$2.1 million
, or
$0.44
per BOE, was reclassified to plant and other midstream services operating expenses for the three and six months ended June 30, 2016, respectively, due to our midstream business becoming a reportable segment.
|
|
|
(2)
|
$0.9 million
and
$1.4 million
was reclassified to midstream services revenues for the three and six months ended June 30, 2016, respectively, due to our midstream business becoming a reportable segment.
|
Three Months Ended June 30, 2017
as Compared to
Three Months Ended June 30, 2016
Production taxes, transportation and processing.
Our production taxes, transportation and processing expenses
increase
d by
$2.3 million
to
$12.9 million
, or
22%
, for the
three months ended June 30, 2017
, as compared to
$10.6 million
for the
three months ended June 30, 2016
. The
increase
in production taxes, transportation and processing expenses was primarily attributable to the
increase
in our production taxes of
$3.1 million
to
$6.9 million
for the
three months ended June 30, 2017
, as compared to
$3.9 million
for the
three months ended June 30, 2016
, primarily due to the
64%
increase
in oil and natural gas revenues for the
three months ended June 30, 2017
, as compared to the
three months ended June 30, 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 to continue to experience increased production tax expenses. The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to
$5.9 million
for the
three months ended June 30, 2017
, as compared to transportation and processing expenses of
$6.7 million
for the
three months ended June 30, 2016
. This decrease of
$0.8 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 the 34% decrease in natural gas production between the two periods in Northwest Louisiana and East Texas where our transportation and processing charges are highest on a unit-of-production basis. On a unit-of-production basis, our production taxes, transportation and processing expenses
decrease
d
7%
to
$3.83
per BOE for the
three months ended June 30, 2017
, as
compared to
$4.14
per BOE for the
three months ended June 30, 2016
. On a unit‑of-production basis, these
second quarter
2017
expenses benefited from significantly higher total oil equivalent production, which increased
32%
in the
second quarter
of
2017
, as compared to the
second quarter
of 2016.
Lease operating.
Our lease operating expenses
increase
d by
$3.9 million
to
$16.0 million
, or an
increase
of
32%
, for the
three months ended June 30, 2017
, as compared to
$12.2 million
for the
three months ended June 30, 2016
. Our lease operating expenses on a unit-of-production basis remained consistent at
$4.77
per BOE for the
three months ended June 30, 2017
, as compared to
$4.78
per BOE for the
three months ended June 30, 2016
. Our total oil equivalent production increased
32%
to approximately
3.4 million
BOE for the
three months ended June 30, 2017
from approximately
2.6 million
BOE for the
three months ended June 30, 2016
. The increase in lease operating expenses on an absolute basis for the
three months ended June 30, 2017
, as compared to the
three months ended June 30, 2016
, was primarily attributable to an increase in costs of services and equipment related to the increased number of wells at June 30,
2017
, as compared to June 30, 2016, as a result of our increased delineation and development activities in the Delaware Basin.
Plant and other midstream services operating.
Our plant and other midstream services operating expenses
increase
d by
$1.9 million
to
$2.9 million
, an
increase
of
177%
, for the
three months ended June 30, 2017
, as compared to
$1.1 million
for the
three months ended June 30, 2016
. This
increase
was partially attributable to the expenses associated with our salt water disposal operations of
$1.5 million
for the
three months ended June 30, 2017
, as compared to
$0.7 million
for the
three months ended June 30, 2016
, as a result of additional salt water disposal wells operating in the second quarter of 2017. Most of the remaining increase was attributable to expenses of
$0.8 million
associated with the Black River Processing Plant, which began operating in August 2016.
Depletion, depreciation and amortization.
Our depletion, depreciation and amortization expenses
increase
d by
$10.0 million
to
$41.3 million
, or an
increase
of
32%
, for the
three months ended June 30, 2017
, as compared to
$31.2 million
for the
three months ended June 30, 2016
. On a unit-of-production basis, our depletion, depreciation and amortization expenses
increase
d
slightly
to
$12.28
per BOE for the
three months ended June 30, 2017
, as compared to
$12.25
per BOE for the
three months ended June 30, 2016
. The increase in our total depletion, depreciation and amortization expenses was primarily attributable to (i) increased well costs, largely as a result of increased well stimulation costs, since December 31, 2016, and (ii) the
32%
increase in oil and natural gas production to
3.4
million BOE for the
three months ended June 30, 2017
, as compared to
2.6
million BOE for the
three months ended June 30, 2016
. The impact of the increase in well costs and oil and natural gas production on depletion, depreciation and amortization was mostly offset by higher total proved reserves of
134.4 million
BOE, or an increase of
41%
, at
June 30, 2017
, as compared to total proved reserves of
95.5 million
BOE at
June 30, 2016
. The 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. In addition, depreciation expenses attributable to our midstream segment were approximately
$1.3 million
for the
three months ended June 30, 2017
, as compared to
$0.5 million
for the
three months ended June 30, 2016
.
Full-cost ceiling impairment.
At
June 30, 2017
, we recorded
no
impairment charge to the net capitalized costs of our oil and natural gas properties. We recorded an impairment charge of
$78.2 million
to the net capitalized costs of our oil and natural gas properties for the
three months ended June 30, 2016
.
General and administrative.
Our general and administrative expenses
increase
d
$4.0 million
to
$17.2 million
, an
increase
of
30%
, for the
three months ended June 30, 2017
, as compared to
$13.2 million
for the
three months ended June 30, 2016
. The increase in our general and administrative expenses was attributable to the
$3.7 million
increase in non-cash stock-based compensation expense to
$7.0 million
for the
three months ended June 30, 2017
, as compared to
$3.3 million
for the
three months ended June 30, 2016
. The increase in our general and administrative expenses was also attributable to increased payroll expenses of approximately
$1.4 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. The
increase
in our non-cash stock-based compensation was attributable to the increased expense related to the continued vesting of awards granted from 2013 through 2017 and the granting of new awards during the second quarter of 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. These increases were partially offset by the increase in capitalized general and administrative expense of
$1.3 million
due to our increased delineation and development activities in the Delaware Basin for the
three months ended June 30, 2017
, as compared to the
three months ended June 30, 2016
. As a result, our general and administrative expenses
decrease
d
1%
on a unit-of-production basis to
$5.11
per BOE for the
three months ended June 30, 2017
, as compared to
$5.18
per BOE for the
three months ended June 30, 2016
.
Interest expense.
For the
three months ended June 30, 2017
, we incurred total interest expense of approximately
$11.1 million
. We capitalized approximately
$1.9 million
of our interest expense on certain qualifying projects for the
three months ended June 30, 2017
and expensed the remaining
$9.2 million
to operations. For the
three months ended June 30, 2016
, we incurred total interest expense of approximately
$7.9 million
. We capitalized
$1.7 million
of our interest expense on certain qualifying projects for the
three months ended June 30, 2016
and expensed the remaining
$6.2 million
to operations. The
increase
in total interest expense of
$3.3 million
for the
three months ended June 30, 2017
, as compared to the
three months ended June 30,
2016
, was attributable to an increase in the average debt outstanding. At
June 30, 2017
, we had
no
borrowings outstanding and
$0.8 million
in letters of credit outstanding under our revolving credit agreement (the “Credit Agreement”) and
$575.0 million
in outstanding senior notes. At
June 30, 2016
, we had
no
borrowings outstanding and
$0.6 million
in letters of credit outstanding under our Credit Agreement and
$400.0 million
in outstanding senior notes.
Total income tax benefit
. Our deferred tax assets exceeded our deferred tax liabilities at
June 30, 2017
due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. 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
June 30, 2017
due to uncertainties regarding the future realization of our deferred tax assets.
Six Months Ended June 30, 2017
as Compared to
Six Months Ended June 30, 2016
Production taxes, transportation and processing.
Our production taxes, transportation and processing expenses
increase
d by approximately
$6.2 million
to
$24.7 million
, or
34%
, for the
six months ended June 30, 2017
, as compared to
$18.5 million
for the
six months ended June 30, 2016
. On a unit-of-production basis, our production taxes, transportation and processing expenses remained consistent at
$3.90
per BOE for the
six months ended June 30, 2017
, as compared to
$3.91
per BOE for the
six months ended June 30, 2016
. The
increase
in production taxes, transportation and processing expenses was primarily attributable to the
$8.0 million
increase
in our production taxes to
$14.1 million
for the
six months ended June 30, 2017
, as compared to
$6.1 million
for the
six months ended June 30, 2016
, primarily due to the
$115.3 million
increase
in oil and natural gas revenues for the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 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 to continue to experience increased production tax expenses. The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to
$10.6 million
for the
six months ended June 30, 2017
, as compared to transportation and processing expenses of
$12.4 million
for the
six months ended June 30, 2016
. This decrease of
$1.8 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 the 36% decrease in natural gas production between the two periods in Northwest Louisiana and East Texas where our transportation and processing charges are highest on a unit-of-production basis. On a unit-of-production basis, the expenses for the
six months ended June 30, 2017
also benefited from significantly higher total oil equivalent production, which increased
34%
in the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 2016
.
Lease operating.
Our lease operating expenses
increase
d by
$5.1 million
to
$31.8 million
, or
19%
, for the
six months ended June 30, 2017
, as compared to
$26.7 million
for the
six months ended June 30, 2016
. Our lease operating expenses unit-of-production basis
decrease
d
11%
to
$5.02
per BOE for the
six months ended June 30, 2017
, as compared to
$5.66
per BOE for the
six months ended June 30, 2016
. The
decrease
achieved in lease operating expenses on a unit-of-production basis was attributable to several key factors, including (i) decreased costs associated with our Eagle Ford operations, including workover, salt water disposal and chemical costs, (ii) additional salt water disposal and gathering capacity added in both the Wolf and Rustler Breaks asset areas and (iii) increased oil equivalent production as compared to the
six months ended June 30, 2016
. This decrease was partially offset by increased workover expenses in the Wolf asset area during the
six months ended June 30, 2017
.
Plant and other midstream services operating.
Our plant and other midstream services operating expenses
increase
d by
$3.2 million
to
$5.3 million
, an
increase
of
153%
, for the
six months ended June 30, 2017
, as compared to
$2.1 million
for the
six months ended June 30, 2016
. This
increase
was partially attributable to the expenses associated with our salt water disposal operations of
$3.0 million
for the
six months ended June 30, 2017
, as compared to
$1.6 million
for the
six months ended June 30, 2016
, as a result of additional salt water disposal wells operating in the second quarter of 2017. The remaining increase was attributable to expenses of
$1.8 million
associated with the Black River Processing Plant, which began operating in August 2016.
Depletion, depreciation and amortization.
Our depletion, depreciation and amortization expenses
increase
d by
$15.1 million
to
$75.3 million
, or
25%
, for the
six months ended June 30, 2017
, as compared to
$60.2 million
for the
six months ended June 30, 2016
. On a unit-of-production basis, our depletion, depreciation and amortization expenses
decrease
d
7%
to
$11.89
per BOE for the
six months ended June 30, 2017
, as compared to
$12.75
per BOE for the
six months ended June 30, 2016
. The
increase
in our total depletion, depreciation and amortization expenses was primarily attributable to (i) increased well costs, largely as a result of increased well stimulation costs, since December 31, 2016, and (ii) the
34%
increase in oil and natural gas production to
6.3
million BOE for the
six months ended June 30, 2017
, as compared to
4.7
million BOE for the
six months ended June 30, 2016
. The
decrease
in our depletion, depreciation and amortization expenses on a unit-of-production basis was attributable to (i) the impairment charges recorded in 2016 and (ii) higher total proved reserves of
134.4 million
BOE, or an increase of
41%
, at
June 30, 2017
, as compared to total proved reserves of
95.5 million
BOE at
June 30, 2016
. The 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. In addition, depreciation expenses attributable to our midstream segment were approximately
$2.5 million
for the
six months ended June 30, 2017
, as compared to
$1.0 million
for the
six months ended June 30, 2016
.
Full-cost ceiling impairment.
At
June 30, 2017
, we recorded no impairment charge to the net capitalized costs of our oil and natural gas properties. We recorded an impairment charge of
$158.6 million
to the net capitalized costs of our oil and natural gas properties for the
six months ended June 30, 2016
.
General and administrative.
Our general and administrative expenses
increase
d
$7.2 million
to
$33.5 million
, an
increase
of
27%
, for the
six months ended June 30, 2017
, as compared to
$26.4 million
for the
six months ended June 30, 2016
. The
increase
in our general and administrative expenses was attributable to the
$5.6 million
increase in non-cash stock-based compensation expense to
$11.2 million
for the
six months ended June 30, 2017
, as compared to
$5.6 million
for the
six months ended June 30, 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 the second quarter of 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. The increase in our general and administrative expenses was also attributable to transaction costs of approximately
$3.5 million
related to the formation of San Mateo and increased payroll expenses of approximately
$4.0 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. These increases were partially offset by the increase in capitalized general and administrative expenses of
$4.9 million
due to our increased delineation and development activities in the Delaware Basin for the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 2016
. Our general and administrative expenses
decrease
d
5%
on a unit-of-production basis to
$5.29
per BOE for the
six months ended June 30, 2017
, as compared to
$5.58
per BOE for the
six months ended June 30, 2016
, primarily due to our increased total oil equivalent production.
Interest expense.
For the
six months ended June 30, 2017
, we incurred total interest expense of approximately
$20.8 million
. We capitalized approximately
$3.2 million
of our interest expense on certain qualifying projects for the
six months ended June 30, 2017
and expensed the remaining
$17.7 million
to operations. For the
six months ended June 30, 2016
, we incurred total interest expense of approximately
$15.6 million
. We capitalized
$2.2 million
of our interest expense on certain qualifying projects for the
six months ended June 30, 2016
and expensed the remaining
$13.4 million
to operations. The
increase
in total interest expense of
$5.3 million
for the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 2016
, was attributable to an increase in the average debt outstanding. At
June 30, 2017
, we had
no
borrowings outstanding and
$0.8 million
in letters of credit outstanding under our Credit Agreement and
$575.0 million
in outstanding senior notes. At
June 30, 2016
, we had
no
borrowings outstanding and
$0.6 million
in letters of credit outstanding under our Credit Agreement and
$400.0 million
in outstanding senior notes.
Total income tax benefit
. Our deferred tax assets exceeded our deferred tax liabilities at
June 30, 2017
due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. 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
June 30, 2017
due to uncertainties regarding the future realization of our deferred tax assets.
Liquidity and Capital Resources
Our primary use of capital has been, and we expect will continue to be during the remainder of 2017 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 the remainder of 2017 with a combination of cash on hand (including proceeds we received in connection with the formation of the Joint Venture), operating cash flows 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.
On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point to operate and expand our Delaware Basin midstream assets. We received
$171.5 million
in connection with the formation of the Joint Venture and may earn up to an additional
$73.5 million
in performance incentives over the next five years. We continue to operate the Delaware Basin midstream assets and retain operational control of the Joint Venture. The Company and Five Point own
51%
and
49%
of the Joint Venture, respectively. San Mateo will continue 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.
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2017. We operated five contracted drilling rigs in the Delaware Basin and one contracted drilling rig in the Eagle Ford during the second quarter of 2017. Our 2017 estimated capital expenditure budget consists of
$400 to $420
million for drilling, completions, facilities and infrastructure and
$56 to $64
million for midstream capital expenditures, which represents our
51%
share of an estimated 2017 capital expenditure budget of
$110 to $125
million for San Mateo. We
have allocated substantially all of our estimated 2017 capital expenditures 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 (including the five wells drilled and completed in 2017) and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. For the remainder of 2017, our Delaware Basin drilling program will continue to focus on the development of the Wolf and Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead, Antelope Ridge and Twin Lakes asset areas, although we may also continue to delineate previously untested zones in the Wolf and Rustler Breaks asset areas.
During the second quarter of 2017 and through August 2, 2017, we acquired approximately 8,300 net acres in the Delaware Basin, mostly in and around our existing acreage positions, including new leasing activities, acquisitions of small interests from mineral and working interest owners in our operated wells and acreage trades or term assignments with other operators. We incurred capital expenditures of approximately $28.0 million to acquire this additional acreage throughout the Delaware Basin, as well as for new 3-D seismic data across portions of our Wolf asset area. At
August 2, 2017
, we held approximately
189,500
gross (
108,000
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.
We plan to continue our leasing and acquisitions efforts in the Delaware Basin during the remainder of 2017 and may also continue acquiring acreage in the Eagle Ford and Haynesville shales. These expenditures are opportunity-specific and per-acre prices can vary significantly based on the opportunity. As a result, it is difficult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for the remainder of 2017.
At
June 30, 2017
, we had cash totaling approximately
$131.5 million
and restricted cash totaling approximately
$15.0 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 Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. Additionally, at June 30, 2017, we had no outstanding borrowings under our Credit Agreement, which has a borrowing base of $450.0 million and an elected commitment of $400.0 million.
Our 2017 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, including the expansion of the Black River Processing Plant, the ability of our Joint Venture partner to meet its 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 the remainder of 2017 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 Northwest 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 the remainder of 2017 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 natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. As of
August 2, 2017
, we had approximately
65%
of our anticipated oil production and approximately
70%
of our anticipated natural gas production hedged for the remainder of 2017. See Note 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at
June 30, 2017
.
Our unaudited cash flows for the
six months ended June 30, 2017
and
2016
are presented below:
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
(In thousands)
|
2017
|
|
2016
|
Net cash provided by operating activities
|
$
|
121,242
|
|
|
$
|
49,600
|
|
Net cash used in investing activities
|
(383,478
|
)
|
|
(166,032
|
)
|
Net cash provided by financing activities
|
180,818
|
|
|
140,573
|
|
Net change in cash
|
$
|
(81,418
|
)
|
|
$
|
24,141
|
|
Adjusted EBITDA
(1)
attributable to Matador Resources Company shareholders
|
$
|
142,611
|
|
|
$
|
56,145
|
|
__________________
|
|
(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.
|
Cash Flows Provided by Operating Activities
Net cash provided by operating activities
increase
d
$71.6 million
to
$121.2 million
for the
six months ended June 30, 2017
from
$49.6 million
for the
six months ended June 30, 2016
. Excluding changes in operating assets and liabilities, net cash provided by operating activities
increase
d to
$130.9 million
for the
six months ended June 30, 2017
from
$43.5 million
for the
six months ended June 30, 2016
. This
increase
was primarily attributable to higher oil and natural gas production and higher commodity prices and was partially offset by the
decrease
in our realized gains on derivatives and an increase in certain expenses. Changes in our operating assets and liabilities between the two periods resulted in a net
decrease
of approximately
$15.8 million
in net cash provided by operating activities for the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 2016
.
Our operating cash flows are sensitive to a number of variables, including changes in our production and 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 natural gas liquids prices. In addition, we attempt to avoid long-term service agreements where possible in order to minimize ongoing future commitments.
Cash Flows Used in Investing Activities
Net cash used in investing activities
increase
d by
$217.4 million
to
$383.5 million
for the
six months ended June 30, 2017
from
$166.0 million
for the
six months ended June 30, 2016
. This
increase
in net cash used in investing activities is primarily due to an
increase
of
$166.5 million
in oil and natural gas properties capital expenditures for the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 2016
. Cash used for oil and natural gas properties capital expenditures for the
six months ended June 30, 2017
was primarily attributable to the acquisition of additional leasehold and mineral interests and our operated drilling and completion activities in the Delaware Basin. A small portion of our capital expenditures for the
six months ended June 30, 2017
was directed to our participation in non-operated wells and our operated drilling and completion activities in the Eagle Ford shale. Additionally, there was an increase in cash outflows related to restricted cash of approximately
$57.7 million
between the two periods. These increases were partially offset by a decrease in cash used for other property and equipment of approximately
$5.8 million
.
Cash Flows Provided by Financing Activities
Net cash provided by financing activities
increase
d by
$40.2 million
to
$180.8 million
for the
six months ended June 30, 2017
from
$140.6 million
for the
six months ended June 30, 2016
. The increase in net cash provided by financing activities for the
six months ended June 30, 2017
was primarily attributable to (i) the increase of
$171.5 million
related to contributions from the formation of the Joint Venture and (ii) the net increase of $12.7 million related to contributions from and distributions to the non-controlling interest owners of less-than-wholly-owned subsidiaries, which were offset by (x) an increase in cash outflows of $2.7 million related to the purchase of the non-controlling interest of a less-than-wholly-owned subsidiary and (y) an increase in cash outflows of $2.0 million related to taxes paid in connection with the net share settlement of stock-based compensation. The net cash provided by financing activities for the
six months ended June 30, 2016
was primarily attributable to the net proceeds from our March 2016 equity offering of
$142.4 million
(
$141.6 million
including cost to issue equity).
See Note 5 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our debt, including our Credit Agreement and the senior notes.
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.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
(In thousands)
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
|
|
|
|
|
|
|
|
Net income (loss) attributable to Matador Resources Company shareholders
|
$
|
28,509
|
|
|
$
|
(105,853
|
)
|
|
$
|
72,493
|
|
|
$
|
(213,507
|
)
|
Net income attributable to non-controlling interest in subsidiaries
|
3,178
|
|
|
106
|
|
|
5,094
|
|
|
93
|
|
Net income (loss)
|
31,687
|
|
|
(105,747
|
)
|
|
77,587
|
|
|
(213,414
|
)
|
Interest expense
|
9,224
|
|
|
6,167
|
|
|
17,679
|
|
|
13,365
|
|
Depletion, depreciation and amortization
|
41,274
|
|
|
31,248
|
|
|
75,266
|
|
|
60,170
|
|
Accretion of asset retirement obligations
|
314
|
|
|
289
|
|
|
614
|
|
|
552
|
|
Full-cost ceiling impairment
|
—
|
|
|
78,171
|
|
|
—
|
|
|
158,633
|
|
Unrealized (gain) loss on derivatives
|
(13,190
|
)
|
|
26,625
|
|
|
(33,821
|
)
|
|
33,464
|
|
Stock-based compensation expense
|
7,026
|
|
|
3,310
|
|
|
11,192
|
|
|
5,553
|
|
Net gain on asset sales and inventory impairment
|
—
|
|
|
(1,002
|
)
|
|
(7
|
)
|
|
(2,067
|
)
|
Consolidated Adjusted EBITDA
|
76,335
|
|
|
39,061
|
|
|
148,510
|
|
|
56,256
|
|
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
|
(3,683
|
)
|
|
(115
|
)
|
|
(5,899
|
)
|
|
(111
|
)
|
Adjusted EBITDA attributable to Matador Resources Company shareholders
|
$
|
72,652
|
|
|
$
|
38,946
|
|
|
$
|
142,611
|
|
|
$
|
56,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
(In thousands)
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
$
|
59,933
|
|
|
$
|
31,242
|
|
|
$
|
121,242
|
|
|
$
|
49,600
|
|
Net change in operating assets and liabilities
|
7,198
|
|
|
1,944
|
|
|
9,653
|
|
|
(6,117
|
)
|
Interest expense, net of non-cash portion
|
9,204
|
|
|
5,875
|
|
|
17,615
|
|
|
12,773
|
|
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
|
(3,683
|
)
|
|
(115
|
)
|
|
(5,899
|
)
|
|
(111
|
)
|
Adjusted EBITDA attributable to Matador Resources Company shareholders
|
$
|
72,652
|
|
|
$
|
38,946
|
|
|
$
|
142,611
|
|
|
$
|
56,145
|
|
The net income attributable to Matador Resources Company shareholders increased by
$134.4 million
to
$28.5 million
for the
three months ended June 30, 2017
, as compared to a net loss attributable to Matador Resources Company shareholders of
$105.9 million
for the
three months ended June 30, 2016
. This increase in net income attributable to Matador Resources Company shareholders for the
three months ended June 30, 2017
as compared to the
three months ended June 30, 2016
is primarily attributable to (i) the decrease of
$78.2 million
in the full-cost ceiling impairment, (ii) the increase in oil and natural gas revenues of
$44.4 million
and (iii) a change of $39.8 million from unrealized loss to unrealized gain on derivatives, offset by (x) the increase in certain expenses, including a $10.0 million increase in depletion, depreciation and amortization expenses, (y) a
$3.1 million
increase in interest expense and (z) a $3.7 million increase in stock-based compensation expense.
The net income attributable to Matador Resources Company shareholders increased by
$286.0 million
to
$72.5 million
for the
six months ended June 30, 2017
, as compared to a net loss attributable to Matador Resources Company shareholders of
$213.5 million
for the
six months ended June 30, 2016
. This increase in net income attributable to Matador Resources Company shareholders for the
six months ended June 30, 2017
as compared to the
six months ended June 30, 2016
is primarily attributable to (i) the decrease of
$158.6 million
in the full-cost ceiling impairment, (ii) the increase in oil and natural gas revenues of
$115.3 million
and (iii) a change of $67.3 million from unrealized loss to unrealized gain on derivatives, offset by (x) the increase in certain expenses, including a $15.1 million increase in depletion, depreciation and amortization expenses, (y) a $4.3 million increase in interest expense and (z) a
$5.6 million
increase in stock-based compensation expense.
Our
Adjusted EBITDA
increased by
$33.7 million
to
$72.7 million
for the
three months ended June 30, 2017
, as compared to
$38.9 million
for the
three months ended June 30, 2016
. This increase in our
Adjusted EBITDA
is primarily
attributable to higher oil and natural gas production and higher commodity prices, which were partially offset by a decrease in the realized gain on derivatives and an increase in certain expenses for the
three months ended June 30, 2017
, as compared to the
three months ended June 30, 2016
.
Our
Adjusted EBITDA
increased by
$86.5 million
to
$142.6 million
for the
six months ended June 30, 2017
, as compared to
$56.1 million
for the
six months ended June 30, 2016
. This increase in our
Adjusted EBITDA
is primarily attributable to higher oil and natural gas production and higher commodity prices, which were partially offset by a decrease in the realized gain on derivatives and an increase in certain expenses for the
six months ended June 30, 2017
, as compared to the
six months ended June 30, 2016
.
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
June 30, 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, disposal and fractionation 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, fractionation 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 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.
Obligations and Commitments
We had the following material contractual obligations and commitments at
June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
(In thousands)
|
Total
|
|
Less
Than
1 Year
|
|
1 - 3
Years
|
|
3 - 5
Years
|
|
More
Than
5 Years
|
Contractual Obligations:
|
|
|
|
|
|
|
|
|
|
Revolving credit borrowings, including letters of credit
(1)
|
$
|
821
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
821
|
|
|
$
|
—
|
|
Senior unsecured notes
(2)
|
575,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
575,000
|
|
Office leases
|
23,864
|
|
|
2,494
|
|
|
5,051
|
|
|
5,314
|
|
|
11,005
|
|
Non-operated drilling commitments
(3)
|
19,697
|
|
|
19,697
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Drilling rig contracts
(4)
|
41,974
|
|
|
27,295
|
|
|
14,679
|
|
|
—
|
|
|
—
|
|
Asset retirement obligations
|
23,094
|
|
|
703
|
|
|
572
|
|
|
3,737
|
|
|
18,082
|
|
Gas processing agreements with non-affiliates
(5)
|
11,858
|
|
|
3,795
|
|
|
8,063
|
|
|
—
|
|
|
—
|
|
Gathering, processing and disposal agreements with San Mateo
(6)
|
256,412
|
|
|
—
|
|
|
36,110
|
|
|
69,994
|
|
|
150,308
|
|
Natural gas plant engineering, procurement, construction and installation contract
(7)
|
47,026
|
|
|
47,026
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total contractual cash obligations
|
$
|
999,746
|
|
|
$
|
101,010
|
|
|
$
|
64,475
|
|
|
$
|
79,866
|
|
|
$
|
754,395
|
|
__________________
|
|
(1)
|
At
June 30, 2017
, we had
no
borrowings outstanding under our Credit Agreement and approximately
$0.8 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.
|
|
|
(3)
|
At
June 30, 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
June 30, 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
$19.7 million
at
June 30, 2017
, which we expect to incur within the next year.
|
|
|
(4)
|
We do not own or operate our own drilling rigs, but instead enter into contracts with third parties for such drilling rigs. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our contractual commitments.
|
|
|
(5)
|
Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. 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. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our 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 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our 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 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our contractual commitments.
|
General Outlook and Trends
For the
three months ended June 30, 2017
, oil prices averaged
$48.15
per Bbl, ranging from a high of
$53.40
per Bbl in
mid-April
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 an average oil price of
$46.01
per Bbl (
$46.34
per Bbl including realized gains from oil derivatives) for our oil production for the
three months ended June 30, 2017
, as compared to
$42.84
per Bbl (
$43.29
per Bbl including realized gains from oil derivatives) for the
three months ended June 30, 2016
. At
August 2, 2017
, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had increased from the weighted average price for the
second quarter
of 2017, settling at
$49.59
per Bbl, which was also an increase as compared to
$39.51
per Bbl at
August 2, 2016
.
For the
three months ended June 30, 2017
, natural gas prices averaged
$3.14
per MMBtu, ranging from a high of approximately
$3.42
per MMBtu in
mid-May
to a low of approximately
$2.89
per MMBtu in
late June
, 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
$3.40
per Mcf (
$3.39
per Mcf including realized losses from natural gas derivatives) for our natural gas production (including revenues attributable to natural gas liquids) for the
three months ended June 30, 2017
, as compared to
$2.10
per Mcf (
$2.34
per Mcf including realized gains from natural gas derivatives) for the
three months ended June 30, 2016
. At
August 2, 2017
, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had decreased from the weighted average price for the
second quarter
of 2017, settling at
$2.81
per MMBtu, which was a small increase as compared to
$2.73
per MMBtu at
August 2, 2016
.
The prices we receive for oil, natural gas and natural gas liquids heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and natural gas liquids 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, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or natural gas liquids prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and natural gas liquids we can produce economically. We are uncertain if oil and natural gas prices may rise from their current levels, and in fact, oil and natural gas prices may decrease again in future periods.
From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids 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 natural gas liquids 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.
Coinciding with the recent improvements in oil and natural gas prices since the latter part of 2016, we have begun to experience 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 could experience additional price increases for drilling, completion and production products and services, although we can provide no estimates 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 natural gas liquids price declines, however, drilling certain oil or natural gas wells may not be economical, 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.
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.