Item 2. Management’s Discussion
and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist you in understanding our
business and results of operations together with our present financial
condition. This section should be read in conjunction with our historical
consolidated financial statements and notes.
Certain statements in our discussion below are forward-looking
statements. These forward-looking statements involve risks and uncertainties.
We caution that a number of factors could cause actual results to differ
materially from those implied or expressed by the forward-looking statements.
Please see “Cautionary Statement Regarding Forward-Looking Statements.”
Overview
We are an independent oil and natural gas company
engaged in the acquisition, development, exploration and production of oil and
natural gas properties. Our core operations are primarily focused in the
Permian Basin of Southeast New Mexico and West Texas. Concho’s legacy in the
Permian Basin provides us a deep understanding of operating and geological
trends. We are actively developing our resource base by utilizing extended length
lateral drilling, enhanced completion techniques, multi-well pad locations and
large-scale development projects throughout our operating areas.
Oil comprised 60 percent of our 840 MMBoe of estimated proved reserves at
December 31, 2017 and 63 percent of our 21 MMBoe of production for the six
months ended
June 30, 2018
. We seek to operate the
wells in which we own an interest, and we operated wells that accounted for 92
percent of our proved developed producing reserves and 79 percent of our 8,152
gross wells at December 31, 2017. By controlling operations, we are able to
more effectively manage the cost and timing of exploration and development of
our properties, including the drilling and stimulation methods used.
Financial and Operating Performance
Our
financial and operating performance for the six months ended June 30, 2018 and
2017 included the following highlights:
·
Net income was $
972 m
illion
($6.50
per diluted share) as compared to $802
m
illion ($5.39
per
diluted share) for the first six months of 2018 and 2017, respectively. The
increase was primarily due to:
•
$713 million increase in oil and natural gas revenues as a result
of
a
25
percent
increase in production and a 29 percent increase in commodity price
realizations per Boe
(excluding the effects of
derivative activities);
•
$170 million decrease in our income tax provision primarily due to
the lower U.S. federal statutory corporate income tax rate as a result of the
Tax Cuts and Jobs Act (the “TCJA”) for the six months ended June 30, 2018, as
compared to 2017;
•
$73 million increase in other income, primarily due to a gain of
approximately $103 million on the equity method investment distribution
received from Oryx Southern Delaware Holdings, LLC (“Oryx”); and
•
$70 million net increase in gain on disposition of assets due to a
gain of approximately $724 million during the six months ended June 30, 2018
primarily due to our February 2018 acquisition and divestiture and Southern
Delaware Basin divestitures, as compared to a gain of approximately $654
million during 2017 primarily due to our disposition of Alpha Crude Connector,
LLC (“ACC”);
partially
offset by:
•
$
663
million change in (gain) loss on
derivatives due to a $168 million loss on derivatives
during the six
months ended June 30, 2018, as compared to a
$495
million gain
during 2017;
•
$73 million increase in production expense, primarily due to (i) increased
production associated with our wells successfully drilled and completed in 2017
and 2018, (ii) our acquisitions and nonmonetary transactions during the last
half of 2017 and first half of 2018, (iii) increased cost of services and (iv)
increased workover costs;
•
$63 million increase in depreciation, depletion and amortization
expense, primarily due to an increase in production, partially offset by a
lower depletion rate per Boe; and
•
$48 million increase in production and ad valorem tax expense, primarily
due to increased production taxes as a result of increased oil and natural gas
sales.
·
Average daily sales volumes of
228 M
Boe
per day during the first six months of 2018 increased 25 percent as compared to
183 MBoe per day during 2017.
·
Net cash provided by operating activities increased by
approximately $285 million to $1,090
million
for
the first six months of 2018, as compared to $805
m
illion
in the first six months of 2017, primarily due to an increase in oil and
natural gas revenues, partially offset by (i) changes related to cash
settlements on derivatives, (ii) increased production expense and (iii) increased
production tax expense.
Commodity Prices
Our results of operations are heavily influenced by commodity prices. Commodity
prices may fluctuate widely in response to (i) relatively minor changes in the
supply of and demand for oil, natural gas and natural gas liquids, (ii) market
uncertainty and (iii) a variety of additional factors that are beyond our
control. Factors that may impact future commodity prices, including the price
of oil, natural gas and natural gas liquids, include, but are not limited to:
·
the overall global demand for oil, natural gas and
natural gas liquids;
·
the domestic and foreign supply of oil, natural gas
and natural gas liquids;
·
the overall North American oil, natural gas and
natural gas liquids supply and demand fundamentals, including:
·
the U.S. economy,
·
weather conditions, and
·
liquefied natural gas deliveries to and exports from
the United States;
·
risks related to the concentration of our operations
in the Permian Basin of Southeast New Mexico and West Texas and the level of
commodity inventory in the Permian Basin;
·
the proximity, capacity, cost and availability of
pipelines and other transportation facilities, as well as the availability of
commodity processing and gathering and refining capacity;
·
economic conditions worldwide;
·
the level of global inventories;
·
political and economic developments in oil and natural
gas producing regions, including Africa, South America and the Middle East;
·
the extent to which members of the Organization of
Petroleum Exporting Countries and other oil exporting nations are able to
influence global oil supply levels;
·
technological advances affecting energy consumption
and energy supply;
·
the effect of energy conservation efforts;
·
political and economic events that directly or
indirectly impact the relative strength or weakness of the U.S. dollar, on
which oil prices are benchmarked globally, against foreign currencies;
·
domestic and foreign governmental regulations,
including limits on the United States’ ability to export crude oil, and
taxation;
·
the quality of the oil we produce;
·
the price and availability of alternative fuels; and
·
the cost and availability of products and personnel
needed for us to produce oil and natural gas, including rigs, crews, sand,
water and water disposal.
Although we cannot predict the occurrence of events that may affect
future commodity prices or the degree to which these prices will be affected,
the prices for any commodity that we produce will generally approximate current
market prices in the geographic region of the production. From time to time, we
expect that we may economically hedge a portion of our commodity price risk to
mitigate the impact of price volatility on our business. See Notes 8 and 15 of
the Condensed Notes to Consolidated Financial Statements included in
“Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding our commodity derivative positions at June 30, 2018 and
additional derivative contracts entered into subsequent to June 30, 2018,
respectively.
Oil and natural gas prices have been subject to significant fluctuations
during the past several years. The average oil price was higher and the
average gas price was lower during the comparable periods of 2018 measured
against 2017, respectively. The following table sets forth the average New York
Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and six
months ended
June 30, 2018
and 2017, as well as the
high and low NYMEX prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
67.85
|
|
$
|
48.32
|
|
$
|
65.42
|
|
$
|
50.12
|
|
Natural gas (MMBtu)
|
|
$
|
2.83
|
|
$
|
3.15
|
|
$
|
2.84
|
|
$
|
3.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
74.15
|
|
$
|
53.40
|
|
$
|
74.15
|
|
$
|
54.45
|
|
|
Low
|
|
$
|
62.06
|
|
$
|
42.53
|
|
$
|
59.19
|
|
$
|
42.53
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
3.02
|
|
$
|
3.42
|
|
$
|
3.63
|
|
$
|
3.72
|
|
|
Low
|
|
$
|
2.66
|
|
$
|
2.89
|
|
$
|
2.55
|
|
$
|
2.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural gas price reached highs
and lows of $74.15 and $67.89 per Bbl and $2.92 and $2.72 per MMBtu,
respectively, during the period from
July 1, 2018
to July 30, 2018. At July 30, 2018, the NYMEX oil price
and NYMEX natural gas price were $70.13 per Bbl and $2.80 per MMBtu,
respectively.
Historically, and during the six months ended June 30, 2018, we derived a
significant portion of our total natural gas revenues from the value of the
natural gas liquids contained in our natural gas, with the remaining portion
coming from the value of the dry natural gas residue. Because of our
liquids-rich natural gas stream and the related value of the natural gas
liquids being included in our natural gas revenues, our realized natural gas
price (excluding the effects of derivatives) reflected a price greater than the
related NYMEX natural gas price for the three and six months ended June 30,
2018. The average Mont Belvieu price for a blended barrel of natural gas
liquids was $29.72 per Bbl and $21.99 per Bbl during the three months
ended June 30, 2018 and 2017, respectively, and $28.68 per Bbl and $23.09 per
Bbl during the six months ended June 30, 2018 and 2017, respectively.
Recent Events
RSP
Acquisition.
On July 19, 2018, we completed our acquisition of RSP Permian,
Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). Under
the terms of the Agreement and Plan of Merger (the “Acquisition Agreement”),
each share of RSP common stock was converted into 0.320 of a share of our
common stock. We issued approximately 51 million shares of common stock at a
price of $148.27 per share, resulting in total consideration paid to the former
RSP shareholders of approximately $7.6 billion.
Long-term
debt.
On July 2, 2018, we issued $1,600 million in aggregate principal
amount of unsecured senior notes, consisting of $1,000 million in aggregate
principal amount of 4.3% unsecured senior notes due 2028 (the “4.3% Notes”) and
$600 million in aggregate principal amount of 4.85% unsecured senior notes due
2048 (the “4.85% Notes” and, together with the 4.3% Notes, the “Notes”). The
net proceeds of approximately $1,579 million were used to redeem RSP’s outstanding
$700 million aggregate principal amount of 6.625% unsecured senior notes due
2022 and $450 million aggregate principal amount of 5.25% unsecured senior
notes due 2025 (collectively, the “RSP Notes”) and to repay a portion of the
outstanding indebtedness under RSP’s existing credit facility. We repaid the
remaining balance under RSP’s credit facility with borrowings under our Credit
Facility, as defined below.
2018 capital
budget.
In July 2018, our board approved a revised 2018 capital budget up
to $2.7 billion. The revised budget includes capital we plan to invest during
the second half of the year on the acquired RSP assets. We expect our 2018 capital
spending to range between $2.5 billion and $2.6 billion, excluding
acquisitions. Our 2018 capital budget, excluding acquisitions and based on our
current expectations of commodity prices and costs, is expected to be within
our operating cash flows.
Derivative Financial Instruments
Derivative
financial instrument exposure.
At June 30, 2018, the fair value
of our financial derivatives was a net liability of $353
million. Under the terms of our financial derivative
instruments, we do not have exposure to potential “margin calls” on our
financial derivative instruments. The terms of our credit facility, as amended
and restated (our “Credit Facility”), do not allow us to offset amounts we may
owe a lender against amounts we may be owed related to our financial
instruments with such party.
New commodity derivative contracts.
After June 30, 2018,
we entered into derivative
contracts to hedge additional amounts of estimated future production. Refer to
Note 15 of the Condensed Notes to Consolidated Financial Statements included in
“Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding these commodity derivative contracts
.
Results of Operations
The following table sets forth summary information concerning our
production and operating data for the three and six months ended
June 30,
2018
and 2017. Because of normal production declines,
increased or decreased drilling activities, fluctuations in commodity prices
and the effects of acquisitions and divestitures, the historical information
presented below should not be interpreted as being indicative of future
results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
13,029
|
|
|
10,303
|
|
|
25,968
|
|
|
20,527
|
|
|
Natural gas (MMcf)
|
|
|
46,837
|
|
|
39,018
|
|
|
92,285
|
|
|
75,615
|
|
|
Total (MBoe)
|
|
|
20,835
|
|
|
16,806
|
|
|
41,349
|
|
|
33,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
143,176
|
|
|
113,220
|
|
|
143,470
|
|
|
113,409
|
|
|
Natural gas (Mcf)
|
|
|
514,692
|
|
|
428,769
|
|
|
509,862
|
|
|
417,762
|
|
|
Total (Boe)
|
|
|
228,958
|
|
|
184,682
|
|
|
228,447
|
|
|
183,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
60.98
|
|
$
|
44.75
|
|
$
|
61.13
|
|
$
|
46.91
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
54.34
|
|
$
|
51.60
|
|
$
|
53.47
|
|
$
|
51.86
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
3.19
|
|
$
|
2.71
|
|
$
|
3.29
|
|
$
|
2.85
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
3.29
|
|
$
|
2.67
|
|
$
|
3.34
|
|
$
|
2.78
|
|
|
Total, without derivatives (Boe)
|
|
$
|
45.31
|
|
$
|
33.73
|
|
$
|
45.74
|
|
$
|
35.57
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
41.37
|
|
$
|
37.84
|
|
$
|
41.04
|
|
$
|
38.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe: (b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
$
|
6.24
|
|
$
|
5.91
|
|
$
|
6.28
|
|
$
|
5.64
|
|
|
Production and ad valorem taxes
|
|
$
|
3.37
|
|
$
|
2.62
|
|
$
|
3.39
|
|
$
|
2.77
|
|
|
Gathering, processing and transportation
|
|
$
|
0.45
|
|
$
|
-
|
|
$
|
0.49
|
|
$
|
-
|
|
|
Depreciation, depletion and amortization
|
|
$
|
14.88
|
|
$
|
16.69
|
|
$
|
15.16
|
|
$
|
17.02
|
|
|
General and administrative
|
|
$
|
3.37
|
|
$
|
3.70
|
|
$
|
3.35
|
|
$
|
3.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the effect of net cash
receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
(in millions)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(86)
|
|
$
|
70
|
|
$
|
(199)
|
|
$
|
101
|
|
|
|
Natural gas derivatives
|
|
|
4
|
|
|
(2)
|
|
|
5
|
|
|
(5)
|
|
|
|
|
Total
|
|
$
|
(82)
|
|
$
|
68
|
|
$
|
(194)
|
|
$
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation of average
prices with derivatives is a result of including the net cash receipts from
(payments on) commodity derivatives that are presented in our statements of
cash flows. This presentation of average prices with derivatives is a means
by which to reflect the actual cash performance of our commodity derivatives
for the respective periods and presents oil and natural gas prices with
derivatives in a manner consistent with the presentation generally used by
the investment community.
|
|
|
|
|
|
|
|
(b)
|
Per Boe amounts calculated using dollars and volumes rounded to
thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2018 Compared to Three
Months Ended June 30, 2017
Oil and natural gas revenues.
Revenue
from oil and natural gas operations was
$945 million
for the three months ended
June 30, 2018
, an
increase of
$378 million (67
percent
) from $567 million for
2017
.
This increase was primarily due to the increase in oil and natural gas production
as well as the increase in realized oil and natural gas prices (excluding the
effects of derivative activities). Additionally, on January 1, 2018, we adopted
Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts
with Customers,” (“ASC 606”), which requires certain costs related to
gathering, processing and transportation to be separately presented on the
consolidated statements of operations. Prior to the adoption of ASC 606, these
costs were generally accounted for as a deduction to revenue and included
within total operating revenues on the consolidated statements of operations.
We elected to use the modified retrospective approach for adopting ASC 606, and
as such prior period amounts have not been restated. See Note 2 of the
Condensed Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information
regarding the adoption of ASC 606. Specific factors affecting oil and natural
gas revenues include the following:
·
total oil production was 13,029 M
Bbl
for the three months ended
June 30, 2018
, an
increase
of 2,726 M
Bbl
(27
percent
) from
10,303 M
Bbl
for
2017
;
·
average realized oil price (excluding the effects of
derivative activities) was
$60.98
per Bbl during the three months
ended
June 30, 2018
, an increase of 36
percent
from
$44.75
per Bbl
during
2017
.
For the three months ended
June 30, 2018, our crude oil price differential relative to NYMEX was $(6.87)
per Bbl, or a realization of approximately 90 percent, as compared to a crude
oil price differential relative to NYMEX of $(3.57) per Bbl, or a realization
of approximately 93 percent, for 2017. The basis differential (referred to as
the “Mid-Cush differential”) between the location of Midland, Texas and
Cushing, Oklahoma (NYMEX pricing location) for our oil directly impacts our
realized oil price. For the three months ended June 30, 2018 and 2017, the average
market Mid-Cush differentials were price reductions of $
(5.15)
per Bbl and $
(0.83)
per
Bbl, respectively. Our crude oil price differential relative to NYMEX excluding
the Mid-Cush differential was $(1.72) per Bbl for the
three
months ended
June 30, 2018, as compared to $(2.74) per Bbl for the
three months ended
June 30, 2017. These amounts are
comprised of fixed deductions from the posted Midland oil price based on the
location of our oil within the Permian Basin and were less per Boe during the three
months ended June 30, 2018 as compared to 2017 primarily due to more production
transported through pipelines, successful renegotiation of fixed deductions for
trucked volumes and more favorable gathering system rates
;
·
total natural gas production was 46,837 M
Mcf
for the three months ended
June 30, 2018
, an
increase
of 7,819
MMcf
(20
percent
) from
39,018 M
Mcf
for
2017
; and
·
average realized natural gas price (excluding the
effects of derivative activities) was
$3.19
per Mcf during the three months ended
June 30, 2018
, an increase of 18
percent
from
$2.71
per Mcf during
2017. For the
three months ended June 30, 2018 and 2017, we realized approximately 113
percent and 86 percent, respectively, of the average NYMEX natural gas prices
for the respective periods. Historically, and during the
three months ended
June 30, 2018, we derived a
significant portion of our total natural gas revenues from the value of the
natural gas liquids contained in our natural gas, with the remaining portion
coming from the value of the dry natural gas residue. Because of our
liquids-rich natural gas stream and the related value of the natural gas
liquids being included in our natural gas revenues, our realized natural gas
price (excluding the effects of derivatives) reflected a price greater than the
related NYMEX natural gas price for the
three months
ended
June 30, 2018. The increase in our realized natural gas price
(excluding the effects of derivatives) as a percentage of NYMEX during the
three months ended June 30, 2018 as compared to 2017 was primarily due to an
increase in the average Mont Belvieu price for a blended barrel of natural gas
liquids, which was $29.72 per Bbl and $21.99 per Bbl during the three months
ended June 30, 2018 and 2017, respectively. The increase in our realized
natural gas price was also due to the adoption of ASC 606, as our natural gas
realized price was $0.13 per Mcf higher than what it would have been under the
previous revenue standard.
Oil and natural gas production expenses.
The following table provides the components of our oil and
natural gas production expenses for the three months ended
June 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
121
|
|
$
|
5.81
|
|
$
|
96
|
|
$
|
5.66
|
Workover costs
|
|
|
9
|
|
|
0.43
|
|
|
4
|
|
|
0.25
|
|
|
Total oil and natural gas production expenses
|
|
$
|
130
|
|
$
|
6.24
|
|
$
|
100
|
|
$
|
5.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $121 million ($5.81 per Boe) for the three
months ended
June 30, 2018
, which was an increase of
$25 million from $96 million ($5.66 per Boe) during
2017
. The increase in lease operating expenses during the
second quarter of 2018 as compared to 2017 was primarily due to (i) increased
production associated with our wells successfully drilled and completed in 2017
and 2018, (ii) our acquisitions and nonmonetary transactions during the second
half of 2017 and first half of 2018, particularly our July 2017 Midland Basin
acquisition and our February 2018 acquisition and divestiture, whose associated
properties incur higher lease operating expense per Boe than our legacy assets
and (iii) increased cost of services. The increase in lease operating expenses
per Boe was primarily due to the increase in lease operating expenses noted
above including higher expenses per Boe on properties associated with our recent
acquisitions, partially offset by an increase in production.
Workover costs were $9 million ($0.43 per Boe) for the three months ended
June 30, 2018
, which was an increase of
$5 million from $4 million ($0.25 per Boe) during
2017
. The increase in workover costs during the second quarter
of 2018 as compared to 2017 was primarily due to (i) increased workover
activity, (ii) higher expenses on properties associated with our recent
acquisitions and (iii) increased cost of services. The increase in workover
costs per Boe was primarily due to the increase in workover costs noted above,
partially offset by an increase in production.
Production and ad valorem taxes.
The following table provides the components of our production
and ad valorem tax expenses for the three months ended
June 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
64
|
|
$
|
3.07
|
|
$
|
40
|
|
$
|
2.41
|
Ad valorem taxes
|
|
|
6
|
|
|
0.30
|
|
|
4
|
|
|
0.21
|
|
|
Total production and ad valorem taxes
|
|
$
|
70
|
|
$
|
3.37
|
|
$
|
44
|
|
$
|
2.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $3.07 per Boe during the
three months ended
June 30, 2018
, an increase of 27 percent
from $2.41 per Boe during
2017
. Over the same
period, our revenue per Boe (excluding the effects of derivatives) increased 34
percent. The increase in production taxes per unit of production was directly
related to the increase in oil and natural gas sales, partially offset by a
higher percentage of our total production originating in Texas, which has a
lower tax rate than New Mexico.
Production taxes fluctuate with the
market value of our production sold, while ad valorem taxes are generally based
on the valuation of our oil and natural gas properties at the beginning of the
year, which vary across the different areas in which we operate.
Gathering, processing and transportation costs.
The following table shows the gathering, processing and
transportation costs for the three months ended
June 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
June 30,
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation costs
|
|
$
|
9
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation costs were $9 million ($0.45 per
Boe) for the three months ended
June 30, 2018
. On
January 1, 2018, we adopted ASC 606, which requires certain amounts related to gathering,
processing and transportation costs to be separately presented on the
consolidated statements of operations. Prior to the adoption of ASC 606, the
majority of these costs were accounted for as a deduction to revenue and
included within total operating revenues on the consolidated statements of
operations. We have elected to use the modified retrospective approach for
adopting ASC 606, and as such, prior period amounts have not been restated.
Exploration and abandonments expense.
The following table provides the components of our exploration and
abandonments expense for the three months ended
June 30, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
June 30,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
2
|
|
$
|
1
|
Leasehold abandonments
|
|
|
4
|
|
|
18
|
Other
|
|
|
2
|
|
|
1
|
|
Total exploration and abandonments
|
|
$
|
8
|
|
$
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the periods presented above
primarily consists of the costs of acquiring and processing geophysical data
and core analysis.
For the three months ended
June 30, 2018 and 2017
, we recorded approximately $4 million and $18 million,
respectively, of leasehold abandonments. For the three months ended
June
30, 2018
, our abandonments were primarily related to
acreage in the Southern Delaware Basin where we had no future plans to drill. For
the three months ended
June 30, 2017
, our
abandonments were primarily related to non-contiguous acreage expiring in the
Southern Delaware Basin.
Our other expense for the periods presented above primarily consists of
surface and title costs on locations we no longer intend to drill, certain
plugging costs and delay rentals.
Depreciation,
depletion and amortization expense.
The following table provides components of our depreciation, depletion
and amortization expense for the three months ended June 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
303
|
|
$
|
14.59
|
|
$
|
274
|
|
$
|
16.34
|
Depreciation of other property and equipment
|
|
|
6
|
|
|
0.25
|
|
|
6
|
|
|
0.33
|
Amortization of intangible assets
|
|
|
1
|
|
|
0.04
|
|
|
1
|
|
|
0.02
|
|
Total depletion, depreciation and amortization
|
|
$
|
310
|
|
$
|
14.88
|
|
$
|
281
|
|
$
|
16.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
54.15
|
|
|
|
|
$
|
45.42
|
|
|
|
Natural gas price used to estimate proved natural gas reserves
at period end
|
$
|
2.92
|
|
|
|
|
$
|
3.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties was $303 million
($14.59 per Boe) for the three months ended
June 30, 2018
, an increase of $29 million (11 percent) from $274 million
($16.34 per Boe) for
2017
. The increase in depletion
expense was primarily due to an increase in production, partially offset by a
lower depletion rate per Boe. The decrease in depletion expense per Boe was
primarily due to (i) lower drilling and completion costs per Boe of proved
developed reserves added since June 30, 2017 and (ii) an overall increase in
proved reserves primarily caused by our successful exploratory drilling
program, acquisitions, higher oil prices and nonmonetary transactions,
partially offset by decreased proved reserves caused by reclassification of proved
undeveloped reserves to unproved reserves because they are no longer expected
to be developed within five years of the date of their initial recognition and
divestitures.
General and administrative expenses.
The following table provides components of our general
and administrative expenses for the three months ended
June 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
59
|
|
$
|
2.71
|
|
$
|
50
|
|
$
|
3.06
|
Less: Operating fee reimbursements
|
|
|
(5)
|
|
|
(0.21)
|
|
|
(4)
|
|
|
(0.25)
|
Non-cash stock-based compensation
|
|
|
18
|
|
|
0.87
|
|
|
14
|
|
|
0.89
|
|
Total general and administrative expenses
|
|
$
|
72
|
|
$
|
3.37
|
|
$
|
60
|
|
$
|
3.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were approximately $72 million ($3.37
per Boe) for the three months ended
June 30, 2018
, an increase of $12 million (20 percent) from $60 million
($3.70 per Boe) for
2017
. The increases in
cash general and administrative and non-cash stock-based compensation expenses
were primarily the result of increased employee headcount. The decrease in
total general and administrative expenses per Boe was primarily the result of increased
production, partially offset by the increase in total general and
administrative expenses noted above.
We receive fees for the operation of jointly-owned oil and natural gas
properties during the drilling and production phases and record such
reimbursements as reductions to general and administrative expenses on the
consolidated statements of operations. We earned reimbursements of
approximately $5 million and $4 million for the three months ended
June 30,
2018 and 2017
, respectively.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for the
three months ended
June 30, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(128)
|
|
$
|
199
|
|
Natural gas derivatives
|
|
|
(5)
|
|
|
10
|
|
|
Total
|
|
$
|
(133)
|
|
$
|
209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from (payments on) derivatives for the three
months ended June 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
(86)
|
|
$
|
70
|
|
Natural gas derivatives
|
|
|
4
|
|
|
(2)
|
|
|
Total
|
|
$
|
(82)
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in value of our derivatives
portfolio between periods and the related cash settlements of those
derivatives, which could be significant. To the extent the future commodity
price outlook declines between measurement periods, we will have mark-to-market
gains; while to the extent the future commodity price outlook increases between
measurement periods, we will have mark-to-market losses. See Note 7 of the Condensed
Notes to Consolidated Financial Statements included in “Item 1. Consolidated
Financial Statements (Unaudited)” for additional information regarding
significant judgments made in classifying financial instruments in the fair
value hierarchy.
Interest expense.
The following table sets forth interest expense, weighted average
interest rates and weighted average debt balances for the three months ended
June 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
June 30,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
27
|
|
$
|
39
|
Capitalized interest
|
|
|
2
|
|
|
-
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
29
|
|
$
|
39
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
5.3%
|
|
|
-
|
Weighted average interest rate - senior notes
|
|
|
4.3%
|
|
|
5.3%
|
|
Total weighted average interest rate
|
|
|
4.3%
|
|
|
5.3%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
50
|
|
$
|
-
|
Weighted average senior notes balance
|
|
|
2,400
|
|
|
2,750
|
|
Total weighted average debt balance
|
|
$
|
2,450
|
|
$
|
2,750
|
|
|
|
|
|
|
|
|
Our weighted average debt balance decreased for the three months ended
June 30, 2018 as compared to 2017 primarily due to completing a cash tender
offer and the satisfaction and discharge in September 2017 of all of the
outstanding $600 million aggregate principal amount of our 5.5% unsecured
senior notes due 2022 and $1,550 million aggregate principal amount of our 5.5%
unsecured senior notes due 2023, partially offset by (i) the issuance of $1,000
million in aggregate principal amount of 3.75% unsecured senior notes due 2027
and $800 million in aggregate principal amount of 4.875% unsecured senior notes
due 2047 and (ii) an increase in our weighted average credit facility balance.
The decrease in interest expense was due to the decrease in the weighted
average debt balance and weighted average interest rate and an increase in
capitalized interest.
Loss on extinguishment of debt.
We recorded a
loss on extinguishment of debt of approximately $1 million for the three months
ended June 30, 2017, representing the proportional amount of unamortized
deferred loan costs associated with banks that are no longer in the credit
facility syndicate as a result of our April 2017 credit facility amendment.
Income tax provisions.
For the three
months ended
June 30, 2018 and 2017, w
e recorded income
tax expense of $40 million and $93 million, respectively. These amounts include
a discrete income tax benefit of approximately $1 million related to excess tax
benefits on stock-based awards for the three months ended
June 30, 2018
and a discrete income tax expense of approximately $2
million
related to excess tax deficiencies on stock-based
awards for the three months ended
June 30, 2017. The change in our
income tax provision was primarily due to the decrease in the U.S. federal
statutory rate from 35 percent to 21 percent.
The effective income tax rates for the three months ended
June 30,
2018 and 2017
were 23 percent and 38 percent,
respectively.
Six Months Ended June
30, 2018 Compared to Six Months Ended June 30, 2017
Oil and natural gas revenues.
Revenue
from oil and natural gas operations was
$1,892
million for the six months ended
June 30, 2018
,
an increase of
$713 million (60
percent
) from $1,179 million for
2017
. This increase was primarily due to the increase in oil
and natural gas production as well as the increase in realized oil and natural
gas prices (excluding the effects of derivative activities). Additionally, on
January 1, 2018, we adopted Accounting Standards Codification (“ASC”) Topic
606, “Revenue from Contracts with Customers,” (“ASC 606”), which requires
certain costs related to gathering, processing and transportation to be
separately presented on the consolidated statements of operations. Prior to the
adoption of ASC 606, these costs were generally accounted for as a deduction to
revenue and included within total operating revenues on the consolidated
statements of operations. We elected to use the modified retrospective approach
for adopting ASC 606, and as such prior period amounts have not been restated.
See Note 2 of the Condensed Notes to Consolidated Financial Statements included
in “Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding the adoption of ASC 606. Specific factors affecting oil
and natural gas revenues include the following:
·
total oil production was 25,968 MBbl for the six
months ended June 30, 2018, an increase of 5,441 MBbl (27 percent) from
20,527 MBbl for 2017;
·
average realized oil price (excluding the effects of
derivative activities) was
$61.13
per Bbl during the six months
ended
June 30, 2018
, an increase of 30
percent
from
$46.91
per Bbl
during
2017
. For the six months ended June 30,
2018, our crude oil price differential relative to NYMEX was $(4.29) per Bbl,
or a realization of approximately 93 percent, as compared to a crude oil price
differential relative to NYMEX of $(3.21) per Bbl, or a realization of
approximately 94 percent, for 2017. The basis differential (referred to as the
“Mid-Cush differential”) between the location of Midland, Texas and Cushing,
Oklahoma (NYMEX pricing location) for our oil directly impacts our realized oil
price. For the six months ended June 30, 2018 and 2017, the average market Mid-Cush
differentials were price reductions of $(2.39) per Bbl and $(0.09) per Bbl,
respectively. Our crude oil price differential relative to NYMEX excluding the
Mid-Cush differential was $(1.90) per Bbl for the six months ended June 30,
2018, as compared to $(3.12) per Bbl for the six months ended June 30, 2017. These
amounts are comprised of fixed deductions from the posted Midland oil price
based on the location of our oil within the Permian Basin and were less per Boe
during the six months ended June 30, 2018 as compared to 2017 primarily due to
more production transported through pipelines, successful renegotiation of
fixed deductions for trucked volumes and more favorable gathering system rates;
·
total natural gas production was 92,285 MMcf for the
six months ended June 30, 2018, an increase of 16,670 MMcf (22 percent) from
75,615 MMcf for 2017; and
·
average realized natural gas price (excluding the
effects of derivative activities) was
$3.29
per Mcf during the six months ended
June 30, 2018
, an increase of 15
percent
from
$2.85
per Mcf during
2017
. For the six months ended
June 30, 2018 and 2017
, we realized approximately 116 percent and 91 percent,
respectively, of the average NYMEX natural gas prices for the respective
periods.
Historically, and during the
six
months ended June 30, 2018, we derived a significant portion of our total
natural gas revenues from the value of the natural gas liquids contained in our
natural gas, with the remaining portion coming from the value of the dry
natural gas residue. Because of our liquids-rich natural gas stream and the
related value of the natural gas liquids being included in our natural gas
revenues, our realized natural gas price (excluding the effects of derivatives)
reflected a price greater than the related NYMEX natural gas price for the
six months ended
June 30, 2018. The increase in our
realized natural gas price (excluding the effects of derivatives) as a
percentage of NYMEX during the
six
months
ended June 30, 2018 as compared to 2017 was primarily due to an increase in the
average Mont Belvieu price for a blended barrel of natural gas liquids, which
was
$28.68
per Bbl and
$23.09
per Bbl during the six months ended June 30, 2018 and
2017, respectively. The increase in our realized natural gas price was also due
to the adoption of ASC 606, as our natural gas realized price was $0.13 per Mcf
higher than what it would have been under the previous revenue standard.
Oil and natural gas production expenses.
The following table provides the components of our oil and
natural gas production expenses for the six months ended June 30, 2018 and
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
242
|
|
$
|
5.84
|
|
$
|
178
|
|
$
|
5.36
|
Workover costs
|
|
|
18
|
|
|
0.44
|
|
|
9
|
|
|
0.28
|
|
|
Total oil and natural gas production expenses
|
|
$
|
260
|
|
$
|
6.28
|
|
$
|
187
|
|
$
|
5.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $242 million ($5.84 per Boe) for the six
months ended
June 30, 2018
, which was an increase of
$64 million from $178 million ($5.36 per Boe) during
2017
. The increase in lease operating expenses during the six
months ended
June 30, 2018
as compared to 2017
was primarily due to (i) increased production associated with our wells
successfully drilled and completed in 2017 and 2018, (ii) our acquisitions and
nonmonetary transactions during the last half of 2017 and first half of 2018,
particularly our July 2017 Midland Basin acquisition and our February 2018
acquisition and divestiture, whose associated properties incur higher lease
operating expense per Boe than our legacy assets and (iii) increased cost of
services. The increase in lease operating expenses per Boe was primarily due to
the increase in lease operating expenses noted above including higher expenses
per Boe on properties associated with our recent acquisitions, partially offset
by an increase in production.
Workover costs were $18 million ($0.44 per Boe) for the six months ended
June 30,
2018
, which was an increase of $9 million from $9
million ($0.28 per Boe) during
2017
. The
increase in workover costs during the six months ended
June 30,
2018 as compared to 2017 was primarily due to (i)
increased workover activity, (ii) higher expenses on properties associated with
our recent acquisitions and (iii) increased cost of services. The increase in
workover costs per Boe was primarily due to the increase in workover costs
noted above, partially offset by an increase in production.
Production and ad valorem taxes.
The following table provides the components of our production
and ad valorem tax expenses for the six months ended
June 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
128
|
|
$
|
3.10
|
|
$
|
84
|
|
$
|
2.53
|
Ad valorem taxes
|
|
|
12
|
|
|
0.29
|
|
|
8
|
|
|
0.24
|
|
|
Total production and ad valorem taxes
|
|
$
|
140
|
|
$
|
3.39
|
|
$
|
92
|
|
$
|
2.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $3.10 per Boe during the six
months ended
June 30, 2018
, an increase of 23 percent
from $2.53 per Boe during
2017
. Over the same
period, our revenue per Boe (excluding the effects of derivatives) increased 29
percent. The increase in production taxes per unit of production was directly
related to the increase in oil and natural gas sales, partially offset by a
higher percentage of our total production originating in Texas, which has a
lower tax rate than New Mexico. Production taxes fluctuate with the market
value of our production sold, while ad valorem taxes are generally based on the
valuation of our oil and natural gas properties at the beginning of the year,
which vary across the different areas in which we operate.
Gathering, processing and transportation costs.
The following table shows the gathering, processing and
transportation costs for the six months ended
June 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation costs
|
|
$
|
20
|
|
$
|
0.49
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation costs were $20 million ($0.49
per Boe) for the six months ended
June 30, 2018
. On January 1, 2018, we adopted ASC 606, which requires
certain amounts related to gathering, processing and transportation costs to be
separately presented on the consolidated statements of operations. Prior to the
adoption of ASC 606, the majority of these costs were accounted for as a
deduction to revenue and included within total operating revenues on the
consolidated statements of operations. We have elected to use the modified
retrospective approach for adopting ASC 606, and as such, prior period amounts
have not been restated.
Exploration and abandonments expense.
The following table provides the components of our exploration and
abandonments expense for the
six
months ended
June
30, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June 30,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
7
|
|
$
|
7
|
Leasehold abandonments
|
|
|
14
|
|
|
24
|
Other
|
|
|
5
|
|
|
4
|
|
Total exploration and abandonments
|
|
$
|
26
|
|
$
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the periods presented above
primarily consists of the costs of acquiring and processing geophysical data
and core analysis.
For the
six
months ended June 30, 2018 and 2017, we recorded
approximately $14 million and $24 million, respectively, of leasehold
abandonments. For the
six
months ended June
30, 2018, our abandonments were primarily related to (i) expiring acreage in
the Southern Delaware Basin and (ii) acreage in the Southern Delaware Basin,
Northern Delaware Basin and New Mexico Shelf where we had no future plans to
drill. For the
six
months ended June 30, 2017,
our abandonments were primarily related to (i) non-contiguous acreage expiring
in the Southern Delaware Basin and (ii) acreage in the Northern Delaware Basin
and Midland Basin in locations where we have no future plans to drill.
Our other
expense for the periods presented above primarily consists of surface and title
costs on locations we no longer intend to drill, certain plugging costs and
delay rentals.
Depreciation, depletion
and amortization expense.
The
following table provides components of our depreciation, depletion and
amortization expense for the six months ended
June 30, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
614
|
|
$
|
14.86
|
|
$
|
551
|
|
$
|
16.65
|
Depreciation of other property and equipment
|
|
|
11
|
|
|
0.26
|
|
|
12
|
|
|
0.35
|
Amortization of intangible assets - operating rights
|
|
|
2
|
|
|
0.04
|
|
|
1
|
|
|
0.02
|
|
Total depletion, depreciation and amortization
|
|
$
|
627
|
|
$
|
15.16
|
|
$
|
564
|
|
$
|
17.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties was $614 million
($14.86 per Boe) for the six months ended
June 30, 2018
, an increase of $63 million (11 percent) from $551 million
($16.65 per Boe) for
2017
. The increase in depletion
expense was primarily due to an increase in production, partially offset by a
lower depletion rate per Boe. The decrease in depletion expense per Boe was
primarily due to (i) lower drilling and completion costs per Boe of proved
developed reserves added since June 30, 2017 and (ii) an overall increase in
proved reserves primarily caused by our successful exploratory drilling
program, acquisitions, nonmonetary transactions and higher oil prices,
partially offset by decreased proved reserves caused by reclassification of
proved undeveloped reserves to unproved reserves because they are no longer
expected to be developed within five years of the date of their initial
recognition and divestitures.
General and administrative expenses.
The following table provides components of our general
and administrative expenses for the six months ended
June 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
111
|
|
$
|
2.70
|
|
$
|
98
|
|
$
|
2.99
|
Less: Operating fee reimbursements
|
|
|
(9)
|
|
|
(0.21)
|
|
|
(8)
|
|
|
(0.24)
|
Non-cash stock-based compensation
|
|
|
35
|
|
|
0.86
|
|
|
26
|
|
|
0.79
|
|
Total general and administrative expenses
|
|
$
|
137
|
|
$
|
3.35
|
|
$
|
116
|
|
$
|
3.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were approximately $137 million
($3.35 per Boe) for the six months ended
June 30, 2018
, an increase of $21 million (18 percent) from $116 million
($3.54 per Boe) for
2017
. The increase in cash
general and administrative expenses was primarily driven by increased
compensation expense as a result of increased employee headcount. The increase
in non-cash stock-based compensation was primarily due to lower forfeitures in
2018 coupled with the increase in employee headcount. The decrease in total
general and administrative expenses per Boe was primarily the result of
increased production, partially offset by the increase in total general and
administrative expenses noted above.
We receive fees for the operation of jointly-owned oil and natural gas
properties during the drilling and production phases and record such
reimbursements as reductions to general and administrative expenses on the
consolidated statements of operations. We earned reimbursements of
approximately $9 million and $8 million for the six months ended June 30, 2018
and 2017, respectively.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives
for the six months ended
June 30, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(161)
|
|
$
|
465
|
|
Natural gas derivatives
|
|
|
(7)
|
|
|
30
|
|
|
Total
|
|
$
|
(168)
|
|
$
|
495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from (payments on) derivatives for the six
months ended June 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
(199)
|
|
$
|
101
|
|
Natural gas derivatives
|
|
|
5
|
|
|
(5)
|
|
|
Total
|
|
$
|
(194)
|
|
$
|
96
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in value of our derivatives
portfolio between periods and the related cash settlements of those
derivatives, which could be significant. To the extent the future commodity
price outlook declines between measurement periods, we will have mark-to-market
gains, while to the extent the future commodity price outlook increases between
measurement periods, we will have mark-to-market losses. See Note 7 of the
Condensed Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information
regarding significant judgments made in classifying financial instruments in
the fair value hierarchy.
Gain on
disposition of assets, net.
During the six months ended June
30, 2018, we recognized a preliminary non-cash gain of approximately $575
million, subject to customary post-closing adjustments, related to our February
2018 acquisition and divestiture.
In January
2018, we closed on our Southern Delaware Basin divestitures with combined
preliminary proceeds of approximately $280 million, subject to customary
post-closing adjustments. After direct transaction costs, we recorded a pre-tax
gain on disposition of assets of approximately $134 million.
During the
six months ended June 30, 2018, we completed multiple nonmonetary transactions.
These transactions included the exchange of both proved and unproved oil and
natural gas properties. Certain of these transactions were accounted for at
fair value and, as a result, we recorded pre-tax gains of approximately $15
million.
In
February 2017, we closed on the divestiture of our ownership interest in ACC.
After adjustments for debt and working capital, we received cash proceeds from
the sale of approximately $803 million. After direct transaction costs, we
recorded a pre-tax gain on disposition of assets of approximately $655 million.
Our net investment in ACC at the time of closing was approximately $129
million.
Interest expense.
The following table sets forth interest expense, weighted average
interest rates and weighted average debt balances for the six months ended
June 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June 30,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
57
|
|
$
|
79
|
Capitalized interest
|
|
|
3
|
|
|
-
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
60
|
|
$
|
79
|
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
4.5%
|
|
|
4.0%
|
Weighted average interest rate - senior notes
|
|
|
4.3%
|
|
|
5.3%
|
|
Total weighted average interest rate
|
|
|
4.3%
|
|
|
5.3%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
130
|
|
$
|
3
|
Weighted average senior notes balance
|
|
|
2,400
|
|
|
2,750
|
|
Total weighted average debt balance
|
|
$
|
2,530
|
|
$
|
2,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our weighted average debt balance decreased for the six months ended June
30, 2018 as compared to 2017 primarily due to completing a cash tender offer
and the satisfaction and discharge in September 2017 of all of the outstanding
$600 million aggregate principal amount of our 5.5% unsecured senior notes due
2022 and $1,550 million aggregate principal amount of our 5.5% unsecured senior
notes due 2023, partially offset by (i) the issuance of $1,000 million in
aggregate principal amount of 3.75% unsecured senior notes due 2027 and $800
million in aggregate principal amount of 4.875% unsecured senior notes due 2047
and (ii) an increase in our weighted average credit facility balance. The
decrease in interest expense was due to the decrease in the weighted average
debt balance and weighted average interest rate and an increase in capitalized
interest.
Loss on extinguishment of debt.
We recorded a
loss on extinguishment of debt of approximately $1 million for the six months
ended June 30, 2017, representing the proportional amount of unamortized
deferred loan costs associated with banks that are no longer in the credit
facility syndicate as a result of our April 2017 credit facility amendment.
Other income, net.
During the six months ended June
30, 2018, we recorded other income of approximately $89 million primarily
related to a cash distribution received from Oryx. See Note 2 of the Condensed
Notes to Consolidated Financial Statements included in “Item 1. Consolidated
Financial Statements (Unaudited)” for additional information regarding this
distribution.
Income tax provisions.
For the
six months ended June 30, 2018 and 2017, we recorded income tax expense of $294
million and $464 million, respectively. These amounts include a discrete income
tax benefit of approximately $3 million and $6 million related to excess tax
benefits on stock-based awards for the six months ended June 30, 2018 and 2017,
respectively. The change in our income tax provision was primarily due to the
decrease in the U.S. federal statutory rate from 35 percent to 21 percent.
The effective income tax rates for the six months ended June 30, 2018 and
2017 were 23 percent and 37 percent, respectively.
Capital Commitments, Capital
Resources and Liquidity
Capital
commitments.
Our primary needs for cash are development, exploration and
acquisition of oil and natural gas assets, payment of contractual obligations
and working capital obligations. Funding for these cash needs may be provided
by any combination of internally-generated cash flow, financing under our
Credit Facility, proceeds from the disposition of assets or alternative
financing sources, as discussed in “— Capital resources” below.
Oil and natural gas properties.
Our costs
incurred on oil and natural gas properties, excluding acquisitions, during the
six
months ended
June 30, 2018
and 2017 totaled $951 million and $776 million, respectively. The increase was
primarily due to our increased drilling and completion activity level during
the first
six
months of 2018 as compared to
2017. Our intent is to manage our capital spending to be within our operating
cash flow, excluding unbudgeted acquisitions. The primary reason for the
differences in costs incurred and cash flow expenditures was the timing of
payments. Total 2018 expenditures were primarily funded in part from cash flows
from operations and proceeds from our January 2018 Southern Delaware Basin
divestitures.
2018 capital budget.
In July 2018, our
board approved a revised 2018 capital budget up to $2.7 billion. The revised
budget includes capital we plan to invest during the second half of the year on
the acquired RSP assets. We expect our 2018 capital spending to range between
$2.5 billion and $2.6 billion, excluding acquisitions. Our 2018 capital budget,
excluding acquisitions and based on our current expectations of commodity
prices and costs, is expected to be within our operating cash flows.
Other than the customary purchase of leasehold acreage, our capital
budgets are exclusive of acquisitions. We do not have a specific acquisition
budget since the timing and size of acquisitions are difficult to forecast. We
evaluate opportunities to purchase or sell oil and natural gas properties in
the marketplace and could participate as a buyer or seller of properties at
various times. We seek to acquire oil and natural gas properties that provide
opportunities for the addition of reserves and production through a combination
of development, high-potential exploration and control of operations that will
allow us to apply our operating expertise, such as the RSP Acquisition.
Acquisitions.
The following
table reflects o
ur expenditures for acquisitions
of proved and unproved properties for the six months ended June 30, 2018 and
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
$
|
139
|
|
Unproved
|
|
|
18
|
|
|
393
|
|
|
Total property acquisition costs (a)
|
|
$
|
18
|
|
$
|
532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the property
acquisition costs above are budgeted unproved leasehold acreage acquisitions
of approximately $18 million for each of the six months ended June 30, 2018
and 2017. For the six months ended June 30, 2017, our unbudgeted acquisitions
are primarily comprised of approximately $451 million of property acquisition
costs related to our Northern Delaware Basin acquisition.
|
|
|
|
|
|
|
|
|
|
|
|
Contractual obligations.
Our contractual
obligations include long-term debt, cash interest expense on debt, derivative
liabilities, asset retirement obligations, employment agreements with officers,
purchase obligations, operating lease obligations and other obligations. Since
December 31, 2017, there have been no material changes in our contractual
obligations, other than a new throughput commitment contract as described below
and our derivative liability position, which increased by $147 million. See
Note 9 of the Condensed Notes to Consolidated Financial Statements included in
“Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding our long-term debt and “Item 3. Quantitative and
Qualitative Disclosures About Market Risk” for information regarding the
interest on our long-term debt and information on changes in the fair value of
our open derivative obligations during the six months ended
June 30,
2018
.
Throughput commitment contract.
In May 2018, we
entered into a one-year term oil marketing contract with a third-party
purchaser. The contract requires us to deliver not less than seven thousand
barrels per day. Should there be a delivery shortfall in any given month, we
retain an option to deliver the shortfall volume in any two subsequent months;
however, failure
to meet this volume delivery
commitment would result in a penalty equal to the volume shortfall multiplied by
the then market price for oil.
RSP termination fee.
In connection with the RSP
Acquisition, the Acquisition Agreement provided us certain termination rights
under which we could have exercised and effectively terminated the Acquisition
Agreement. Although these events under specified circumstances outlined in the
Acquisition Agreement did not occur, we would have been required to pay RSP a
termination fee of $350 million. See Note 4 and Note 15 of the Condensed Notes
to Consolidated Financial Statements included in “Item 1. Consolidated
Financial Statements (Unaudited)” for additional information regarding the RSP
Acquisition.
Off-balance sheet arrangements.
Currently, we
do not have any material off-balance sheet arrangements.
Capital resources.
Our primary sources of
liquidity have been cash flows generated from (i) operating activities, (ii)
borrowings under our Credit Facility, (iii) proceeds from bond and equity
offerings and (iv) asset dispositions. In July 2018, our board approved a
revised 2018 capital budget up to $2.7 billion. The revised budget includes
capital we plan to invest during the second half of the year on the acquired
RSP assets. We expect our 2018 capital spending to range between $2.5 billion
and $2.6 billion, excluding acquisitions. Our 2018 capital budget, excluding
acquisitions and based on our current expectations of commodity prices and
costs, is expected to be within our operating cash flows.
The following table summarizes our changes in cash and cash equivalents
for the six months ended
June 30, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
1,090
|
|
$
|
805
|
Net cash used in investing activities
|
|
|
(565)
|
|
|
(168)
|
Net cash used in financing activities
|
|
|
(470)
|
|
|
(28)
|
|
Net increase in cash and cash equivalents
|
|
$
|
55
|
|
$
|
609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow
from operating activities.
The increase in operating cash
flows during the
six
months ended June 30,
2018 as compared to the same period in 2017 was primarily due to an increase in
oil and natural gas revenues of approximately $713 million, partially offset by
(i) a decrease in operating cash flow of approximately $290 million due to
approximately $
194
million
for settlements paid on derivatives during the six months ended June 30, 2018,
as compared to approximately $
96
million in
settlements received from derivatives during the comparable period in 2017,
(ii)
approximately $73 million increase in production expense and (iii)
approximately $48 million increase in production tax expense.
Our net
cash provided by operating activities included a reduction of approximately $11
million and $18
million
for the
six
months ended June 30, 2018 and
2017, respectively, associated with changes in working capital items. Changes
in working capital items adjust for the timing of receipts and payments of
actual cash.
Cash flow from investing activities.
During the six months ended
June 30, 2018
and 2017, we invested approximately $941 million and $624
million, respectively, for additions to oil and natural gas properties.
Additionally, we completed acquisitions of oil and natural gas properties of
approximately $19 million and $239 million during the six months ended
June
30, 2018 and 2017, respectively
. We received
approximately $261 million related to proceeds from the disposition of assets during
the six months ended
June 30, 2018,
as
compared to $
803
million during the comparable
period of 2017. Finally, we received an equity method investment distribution from
Oryx of approximately $157 million during the six months ended
June 30,
2018. Of this amount, approximately $9 million represented cumulative Oryx earnings
and was classified as cash flow from operating activities, while the remaining
amount of approximately $148 million was classified as cash flow from investing
activities.
Cash flow
from financing activities.
Net cash
used in financing activities was approximately $470 million and $28 million for
the
six
months ended June 30, 2018 and 2017,
respectively.
We had net payments on our Credit Facility of $322
million for the six months ended
June 30, 2018, as compared to no
outstanding borrowings during the comparable period of
2017.
During the six months ended
June 30, 2018, we decreased our bank
overdrafts by approximately $116 million.
Advances on our Credit Facility bear interest, at our option, based on
(i) an alternative base rate, which is equal to the highest of (a) the prime
rate of JPMorgan Chase Bank (5.0 percent at June 30, 2018), (b) the federal
funds effective rate plus 0.5 percent and (c) the London Interbank Offered Rate
(“LIBOR”) plus 1.0 percent or (ii) LIBOR. Our Credit Facility’s interest
rates and commitment fees on the unused portion of the
available commitment vary depending on our credit ratings from Moody’s
Investors Service, Inc. (“Moody’s”) and S&P Global Ratings (“S&P”). At our
current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear
interest margins of 150 basis points and 50 basis points per annum,
respectively, and commitment fees on the unused portion of the available
commitment are 25 basis points per annum.
In
conducting our business, we may utilize various financing sources, including
the issuance of (i) fixed and floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock and (v) other securities.
Historically, we have demonstrated our use of the capital
markets by issuing common stock and senior unsecured debt. There are no
assurances that we can access the capital markets to obtain additional funding,
if needed, and at cost and terms that are favorable to us. In July 2018, we
issued $1,600 million in aggregate principal amount of unsecured senior notes,
consisting of $1,000 million in aggregate principal amount of 4.3% unsecured
senior notes due 2028 and $600 million in aggregate principal amount of 4.85%
unsecured senior notes due 2048. See Note 15 of the Condensed Notes to
Consolidated Financial Statements included in “Item 1. Consolidated Financial
Statements (Unaudited)” for additional information.
We may also sell
assets and issue securities in exchange for oil and natural gas assets or
interests in energy companies. Additional securities may be of a class senior
to common stock with respect to such matters as dividends and liquidation
rights and may also have other rights and preferences as determined from time
to time. Utilization of some of these financing sources may require approval
from the lenders under our Credit Facility.
Liquidity.
Our
principal sources of liquidity are cash on hand and available borrowing capacity
under our Credit Facility. At
June 30, 2018
,
we had approximately $55 million of cash on hand.
At
June 30, 2018, our commitments from our bank group were $2.0 billion. In July
2018, our cash position was impacted as a result of receiving cash proceeds
from the issuance of the Notes.
We used
proceeds from our Notes issuance along with borrowings on our Credit Facility
to fully extinguish the RSP Notes and repay the amounts outstanding under RSP’s
credit facility.
Debt ratings.
We receive debt
credit ratings from S&P, Moody’s and Fitch Ratings, which are subject to regular
reviews. In determining our ratings, the agencies consider a number of
qualitative and quantitative factors including, but not limited to: the
industry in which we operate, production growth opportunities, liquidity, debt
levels and asset and reserve mix.
A downgrade in our credit ratings could (i) negatively impact our costs
of capital and our ability to effectively execute aspects of our strategy, (ii)
affect our ability to raise debt in the public debt markets, and the cost of
any new debt could be much higher than our outstanding debt and (iii) negatively
affect our ability to obtain additional financing or the interest rate, fees
and other terms associated with such additional financing. Further, if we are
unable to maintain credit ratings of “Ba2” or better from Moody’s and “BB” or
better from S&P, the investment grade period under our Credit Facility will
automatically terminate and cause our Credit Facility to once again be secured
by a first lien on substantially all of our oil and natural gas properties and
by a pledge of the equity interests in our subsidiaries. These and other
impacts of a downgrade in our credit ratings could have a material adverse
effect on our business, financial condition and results of operations.
In June 2018, our long-term debt rating by Moody’s was raised to an
investment grade rating, and in July 2018, Fitch increased our long-term debt
rating. We cannot be assured that our credit ratings will not be downgraded in
the future.
Book capitalization and current ratio
.
Our net book
capitalization at June 30, 2018 was $12.2
billion,
consisting of $0.1 billion of cash and cash equivalents, debt of $
2.4 b
illion and stockholders’ equity of $
9.9
billion. Our net book capitalization at December
31, 2017 was $11.6 billion, consisting of debt of $2.7 billion and
stockholders’ equity of $8.9 billion. Our ratio of net debt to net book
capitalization was 19
percent and
23
percent
at June 30, 2018 and December 31, 2017,
respectively. Our ratio of current assets to current liabilities was 0.76
to 1.0 at June 30, 2018 as compared to 0.51 to 1.0
at December 31, 2017. Both our ratio of net debt to net book capitalization and
our ratio of current assets to current liabilities were impacted subsequent to June
30, 2018 by the closing of the RSP Acquisition.
Inflation
and changes in prices.
Our revenues, the value of our assets and
our ability to obtain bank financing or additional capital on attractive terms
have been and will continue to be affected by changes in commodity prices and
the costs to produce our reserves. Commodity prices are subject to significant
fluctuations that are beyond our ability to control or predict. During the six
months ended June 30, 2018, we received an average of $61.13
per Bbl of oil and $3.29
per
Mcf of natural gas before consideration of commodity derivative contracts
compared to $46.91
per Bbl of oil and $2.85
per Mcf of natural gas in the six months ended June
30, 2017. Although certain of our costs are affected by general inflation,
inflation does not normally have a significant effect on our business.
Critical Accounting Policies, Practices and Estimates
Our
historical consolidated financial statements and related notes to consolidated
financial statements contain information that is pertinent to our management’s
discussion and analysis of financial condition and results of operations.
Preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires that our management make
estimates, judgments and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses, and the disclosure of contingent
assets and liabilities. However, the accounting principles used by us generally
do not change our reported cash flows or liquidity. Interpretation of the
existing rules must be done and judgments made on how the specifics of a given
rule apply to us.
In
management’s opinion, the more significant reporting areas impacted by
management’s judgments and estimates are the choice of accounting method for
oil and natural gas activities, oil and natural gas reserve estimation, asset
retirement obligations, impairment of long-lived assets, valuation of
stock-based compensation, valuation of business combinations, accounting and
valuation of nonmonetary transactions, valuation of financial derivative
instruments and income taxes. Management’s judgments and estimates in these
areas are based on information available from both internal and external
sources, including engineers, geologists and historical experience in similar
matters. Actual results could differ from the estimates as additional
information becomes known.
There have
been no material changes in our critical accounting policies and procedures
during the six months ended June 30, 2018. See our disclosure of critical
accounting policies in “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and “Item 8. Financial
Statements and Supplementary Data” of our Annual Report on Form 10-K for the
year ended December 31, 2017, filed with the SEC on February 21, 2018.
New accounting pronouncements
issued but not yet adopted.
See Note 2 of the Condensed
Notes to Consolidated Financial Statements included in
“Item 1. Consolidated Financial Statements (Unaudited)” for
information regarding new accounting pronouncements issued but not yet adopted.