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 four core
operating areas: the Northern Delaware Basin, the Southern Delaware Basin, the
Midland Basin and the New Mexico Shelf.
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 three months ended
March 31,
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 three months ended March 31, 2018 and 2017
included the following highlights:
·
Net
income was $
835 m
illion ($5.58
per diluted share) as compared to $650
m
illion ($4.37
per
diluted share) for the first three months of 2018 and 2017, respectively. The
increase was primarily due to:
•
$335 million increase
in oil and natural gas revenues as a result of
a
26
percent increase in production and a
23 percent increase in commodity price realizations per Boe
(excluding the effects of derivative activities);
•
$117 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 three months ended March 31, 2018, as compared to 2017;
•
$97 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
•
$69 million net
increase in gain on disposition of assets due to a gain of approximately $723
million during the three months ended March 31, 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:
•
$
321
million change in (gain) loss on derivatives due to a $35
million loss on derivatives
during the three months ended March 31,
2018, as compared to a
$286 million gain
during
2017;
•
$43 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 nine months of 2017 and first
quarter of 2018 and (iii) increased cost of services;
•
$34 million increase
in depreciation, depletion and amortization expense, primarily due to an
increase in production, partially offset by a decrease in the depletion rate
per Boe; and
•
$22 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 three months of 2018 increased 26 percent as compared to 181 MBoe per
day during 2017.
·
Net
cash provided by operating activities increased by approximately $81 million to
$488
million
for the first three months
of 2018, as compared to $407
m
illion in
the first three 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) negative variances in working capital, (iii) increased
production expense and (iv) 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;
·
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;
·
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;
·
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 cost and availability of products and personnel needed for us
to produce oil and natural gas, including rigs, crews, sand, water and water
disposal;
·
the quality of the oil we produce; and
·
the price and availability of alternative fuels.
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 March 31, 2018 and additional
derivative contracts entered into subsequent to March 31, 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 months
ended
March 31, 2018
and 2017, as well as the
high and low NYMEX prices for the same periods:
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Three
Months Ended
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March
31,
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2018
|
|
2017
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Average NYMEX prices:
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Oil (Bbl)
|
|
$
|
62.96
|
|
$
|
51.95
|
|
Natural gas (MMBtu)
|
|
$
|
2.84
|
|
$
|
3.08
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High and Low NYMEX prices:
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Oil (Bbl):
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High
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$
|
66.14
|
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$
|
54.45
|
|
|
Low
|
|
$
|
59.19
|
|
$
|
47.34
|
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Natural gas (MMBtu):
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|
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High
|
|
$
|
3.63
|
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$
|
3.72
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Low
|
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$
|
2.55
|
|
$
|
2.56
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Further, the NYMEX oil price and NYMEX natural gas price reached highs
and lows of $68.64 and $62.06 per Bbl and $2.82 and $2.66 per MMBtu,
respectively, during the period from
April 1, 2018
to April 30, 2018. At April 30, 2018, the NYMEX oil price
and NYMEX natural gas price were $68.57 per Bbl and $2.76 per MMBtu,
respectively.
Historically, and during the three months ended March 31, 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. The average Mont
Belvieu price for a blended barrel of natural gas liquids was $27.64 per
Bbl and $24.19 per Bbl during the three months ended March 31, 2018 and 2017, respectively.
Recent Events
RSP
Acquisition.
On March 27, 2018, we and RSP Permian, Inc. (“RSP”) entered into an
Agreement and Plan of Merger (the “Acquisition Agreement”) under which we will
acquire RSP through an all-stock transaction (the “RSP Acquisition”). Under the
terms of the Acquisition Agreement, shareholders of RSP will receive 0.320 of a
share of our common stock in exchange for one share of RSP common stock. We
estimate that we will issue up to 51 million shares in connection with the RSP
Acquisition. We expect to complete the RSP Acquisition during the third quarter
of 2018, subject to the approval of both our and RSP’s shareholders, the
satisfaction of certain regulatory approvals and other customary closing
conditions.
Oryx
distribution.
During the three months ended March 31, 2018, we received a cash equity
method investment distribution from Oryx of approximately $157 million. Of this
amount, approximately $54 million fully offset our net investment in Oryx. The
remaining distribution of approximately $103 million was recorded in other
income
on our consolidated statement of operations for the three months
ended March 31, 2018 since the lenders to the term loan do not have recourse
against us, and we have no contractual obligation to repay the distribution.
2018 capital budget.
In February
2018, we announced our 2018 capital budget, excluding acquisitions, of
approximately $2.0 billion with expected capital spending to range between $1.9
billion and $2.1 billion. Approximately 93 percent of capital will be directed
to drilling and completion activity. Our 2018 capital program is expected to
continue focusing on large-scale project development. Our 2018 capital budget,
based on our current expectations of commodity prices and costs, is expected to
be within our operating cash flows. Our budget could change depending on
numerous factors, including commodity prices, leverage metrics and industry
conditions.
February
2018 acquisition and divestiture.
In February 2018, we closed on an
acquisition treated as a business combination where we received producing wells
with approximately 5 MBoepd along with approximately 21,000 net acres,
primarily located in the Midland Basin. As consideration for the non-cash
acquisition, we divested of approximately 34,000 net acres, primarily comprised
of approximately 32,000 net acres in the Northern Delaware Basin, with current
production of 3 MBoepd. The business acquired was valued at approximately $755
million as compared to the historical book value of the divested assets of
approximately $180 million, which resulted in a preliminary non-cash gain of
approximately $575 million, subject to customary post-closing adjustments. The approximately
$755 million fair value of assets acquired comprised of approximately $245
million of proved properties, approximately $480 million of unproved properties
and approximately $30 million of other assets. The fair value of the assets
received in the business combination approximated the fair value of assets
disposed.
Southern Delaware Basin divestitures.
In January 2018, we closed on two asset sales transactions of certain
non-core assets in Reeves and Ward Counties 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, which is included in gain on disposition
of assets, net on our consolidated statement of operations for the three months
ended March 31, 2018. The assets divested included proved and unproved oil and
natural gas properties on approximately 20,000 net acres.
These divestitures completed a transaction structured as a reverse
like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of
the Internal Revenue Code of 1986, as amended, that we entered into concurrent
with a July 2017 acquisition in the Midland Basin. In connection with the
Reverse 1031 Exchange, we assigned the ownership of the oil and natural gas
properties acquired to a VIE formed by an exchange accommodation titleholder. We
operated the properties pursuant to a management agreement with the VIE. At
December 31, 2017 and prior to the completion of the reverse like-kind exchange
in January 2018, we were determined to be the primary beneficiary of the VIE,
as we had the ability to control the activities that most significantly impact
the VIE’s economic performance.
Upon completion of the Reverse 1031 Exchange in January 2018, the assets
and liabilities attributable to the acquisition that were held by the VIE were
conveyed to us, and the VIE structure was dissolved.
Nonmonetary
transactions.
During the three months ended March 31, 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 $14 million.
Derivative Financial Instruments
Derivative
financial instrument exposure.
At March 31, 2018, the fair
value of our financial derivatives was a net liability of $302
million. Under the terms of our financial
derivative instruments, we do not have exposure to potential “margin calls” on
our financial derivative instruments. The terms of our credit facility, as
amended and restated (our “Credit Facility”), do not allow us to offset amounts
we may owe a lender against amounts we may be owed related to our financial
instruments with such party.
New commodity derivative contracts.
After March 31, 2018, we entered into the following oil price swaps, oil
basis swaps and natural gas price swaps to hedge additional amounts of our
estimated future production:
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First
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Second
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Third
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Fourth
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Quarter
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Quarter
|
|
Quarter
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|
Quarter
|
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Total
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Oil Price Swaps: (a)
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2018:
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Volume (Bbl)
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|
729,000
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659,000
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|
417,000
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1,805,000
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Price per Bbl
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$
|
64.92
|
$
|
64.76
|
$
|
64.54
|
$
|
64.77
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2019:
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Volume (Bbl)
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443,000
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328,000
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257,000
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217,000
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1,245,000
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Price per Bbl
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$
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59.81
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$
|
59.71
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$
|
59.46
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$
|
59.34
|
$
|
59.63
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2020:
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Volume (Bbl)
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1,244,000
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1,185,000
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1,131,000
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1,104,000
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4,664,000
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Price per Bbl
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$
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56.05
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$
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56.01
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$
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55.95
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$
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55.92
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$
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55.98
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Oil Basis Swaps: (b)
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2019:
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Volume (Bbl)
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630,000
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637,000
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644,000
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|
644,000
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2,555,000
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Price per Bbl
|
$
|
(3.26)
|
$
|
(3.26)
|
$
|
(3.26)
|
$
|
(3.26)
|
$
|
(3.26)
|
Natural Gas Price Swaps: (c)
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2018:
|
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Volume (MMBtu)
|
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|
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1,200,000
|
|
3,680,000
|
|
3,680,000
|
|
8,560,000
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|
Price per MMBtu
|
|
|
$
|
2.88
|
$
|
2.88
|
$
|
2.88
|
$
|
2.88
|
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2019:
|
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Volume (MMBtu)
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2,700,000
|
|
2,730,000
|
|
2,760,000
|
|
2,760,000
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10,950,000
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|
Price per MMBtu
|
$
|
2.75
|
$
|
2.75
|
$
|
2.75
|
$
|
2.75
|
$
|
2.75
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2020:
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Volume (MMBtu)
|
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1,820,000
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1,820,000
|
|
1,840,000
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|
1,840,000
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7,320,000
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Price per MMBtu
|
$
|
2.70
|
$
|
2.70
|
$
|
2.70
|
$
|
2.70
|
$
|
2.70
|
|
|
|
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(a)
|
The index prices for the oil
price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly
average futures price.
|
|
(b)
|
The basis differential price is
between Midland – WTI and Cushing – WTI.
|
(c)
|
The index prices for the
natural gas price swaps are based on the NYMEX – Henry Hub last trading day
futures price.
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Results of Operations
The following table sets forth summary information concerning our
production and operating data for the three months ended
March 31,
2018
and 2017. Because of normal production declines,
increased or decreased drilling activities, fluctuations in commodity prices
and the effects of acquisitions or divestitures, the historical information
presented below should not be interpreted as being indicative of future
results.
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|
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Three
Months Ended
|
|
|
|
|
|
|
March
31,
|
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|
|
|
|
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2018
|
|
2017
|
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|
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Production and operating data:
|
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Net production volumes:
|
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|
|
|
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Oil (MBbl)
|
|
|
12,939
|
|
|
10,224
|
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Natural gas (MMcf)
|
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|
45,448
|
|
|
36,597
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|
Total (MBoe)
|
|
|
20,514
|
|
|
16,324
|
|
|
|
|
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|
Average daily production volumes:
|
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|
|
|
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|
Oil (Bbl)
|
|
|
143,767
|
|
|
113,600
|
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Natural gas (Mcf)
|
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|
504,978
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|
|
406,633
|
|
|
Total (Boe)
|
|
|
227,930
|
|
|
181,372
|
|
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|
|
|
|
|
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|
|
Average prices per unit:
|
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|
|
|
|
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|
|
Oil, without derivatives (Bbl)
|
|
$
|
61.29
|
|
$
|
49.08
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
52.59
|
|
$
|
52.12
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
3.39
|
|
$
|
3.00
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
3.41
|
|
$
|
2.90
|
|
|
Total, without derivatives (Boe)
|
|
$
|
46.17
|
|
$
|
37.47
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
40.71
|
|
$
|
39.15
|
|
|
|
|
|
|
|
|
|
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|
|
Operating costs and expenses per Boe: (b)
|
|
|
|
|
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|
|
Oil and natural gas production
|
|
$
|
6.33
|
|
$
|
5.35
|
|
|
Production and ad valorem taxes
|
|
$
|
3.40
|
|
$
|
2.93
|
|
|
Gathering, processing and transportation
|
|
$
|
0.53
|
|
$
|
-
|
|
|
Depreciation, depletion and amortization
|
|
$
|
15.43
|
|
$
|
17.36
|
|
|
General and administrative
|
|
$
|
3.31
|
|
$
|
3.36
|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
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(a)
|
Includes the effect of net cash
receipts from (payments on) derivatives:
|
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|
|
|
|
|
|
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|
|
Three
Months Ended
|
|
|
|
|
|
|
March
31,
|
|
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(113)
|
|
$
|
31
|
|
|
|
Natural gas derivatives
|
|
|
1
|
|
|
(3)
|
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|
Total
|
|
$
|
(112)
|
|
$
|
28
|
|
|
|
|
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|
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|
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|
|
|
|
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|
|
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 March 31, 2018 Compared to Three Months Ended March 31, 2017
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$947 million for the three months ended
March
31, 2018
, an increase of
$335 million (55
percent
)
from $612 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 12,939 M
Bbl
for the
three months ended
March 31, 2018
, an
increase
of 2,715 M
Bbl
(27
percent
) from 10,224 M
Bbl
for
2017
;
·
average realized oil price (excluding the effects of derivative
activities) was
$61.29
per Bbl during the three months ended
March
31, 2018
, an increase of 25
percent
from
$49.08
per Bbl
during
2017
.
For the three months ended
March 31, 2018, our crude oil price differential relative to NYMEX was $(1.67)
per Bbl, or a realization of approximately 97 percent, as compared to a crude
oil price differential relative to NYMEX of $(2.87) per Bbl, or a realization
of approximately 94 percent, for 2017. We incur fixed deductions from the
posted Midland oil price based on the location of our oil within the Permian
Basin. These fixed deductions were less per Boe during the
three months ended
March 31, 2018 as compared to
2017
primarily due to more production transported
through pipelines and successful renegotiation of fixed deductions for trucked
volumes.
Additionally, the basis 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 March 31,
2018 and 2017, the average market basis differential between WTI-Midland and
WTI-Cushing was a price benefit of $
0.38
per
Bbl and $
0.75
per Bbl, respectively
;
·
total natural gas production was 45,448 M
Mcf
for the three months ended
March 31, 2018
, an
increase
of 8,851
MMcf
(24
percent
) from
36,597 M
Mcf
for
2017
; and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$3.39
per Mcf during the three months ended
March
31, 2018
, an increase of 13
percent
from
$3.00
per Mcf during
2017. For the three months ended March 31, 2018 and 2017, we realized
approximately 119 percent and 97 percent, respectively, of the average NYMEX
natural gas prices for the respective periods. The increase in our realized
natural gas price (excluding the effects of derivatives) as a percentage of
NYMEX during the three months ended March 31, 2018 as compared to 2017 was
primarily 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. The increase in our realized natural gas price was also due to an
increase in the average Mont Belvieu price for a blended barrel of natural gas
liquids during the three months ended March 31, 2018 as compared to 2017.
Historically, and during the
three months ended
March
31, 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. The
average Mont Belvieu price for a blended barrel of natural gas liquids was
$27.64
per Bbl and
$24.19
per
Bbl during the three months ended March 31, 2018 and 2017, respectively.
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
March 31,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
121
|
|
$
|
5.88
|
|
$
|
82
|
|
$
|
5.05
|
Workover costs
|
|
|
9
|
|
|
0.45
|
|
|
5
|
|
|
0.30
|
|
|
Total oil and natural gas production expenses
|
|
$
|
130
|
|
$
|
6.33
|
|
$
|
87
|
|
$
|
5.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $121 million ($5.88 per Boe) for the three
months ended
March 31, 2018
, which was an increase of
$39 million from $82 million ($5.05 per Boe) during
2017
. The increase in lease operating expenses during the first
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 last
nine months of 2017 and first quarter of 2018, particularly our July 2017
Midland Basin acquisition, whose associated properties incur higher lease operating
expense per Boe than our legacy assets, (iii) our February 2018 acquisition and
divestiture, in which we acquired an additional incremental working interest in
the associated properties and (iv) 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 July 2017 Midland Basin acquisition and our February 2018 acquisition
and divestiture, 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
March 31,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
64
|
|
$
|
3.13
|
|
$
|
44
|
|
$
|
2.66
|
Ad valorem taxes
|
|
|
6
|
|
|
0.27
|
|
|
4
|
|
|
0.27
|
|
|
Total production and ad valorem taxes
|
|
$
|
70
|
|
$
|
3.40
|
|
$
|
48
|
|
$
|
2.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $3.13 per Boe during the
three months ended
March 31, 2018
, an increase of 18
percent from $2.66 per Boe during
2017
. Over
the same period, our revenue per Boe (excluding the effects of derivatives)
increased 23 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
March 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
March
31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation costs
|
|
$
|
11
|
|
$
|
0.53
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation costs were $11 million ($0.53
per Boe) for the three months ended
March 31, 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
March 31, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
5
|
|
$
|
6
|
Exploratory dry hole costs
|
|
|
-
|
|
|
-
|
Leasehold abandonments
|
|
|
10
|
|
|
6
|
Other
|
|
|
3
|
|
|
3
|
|
Total exploration and abandonments
|
|
$
|
18
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
March 31, 2018 and 2017
, we recorded approximately $10 million and $6 million,
respectively, of leasehold abandonments. For the three months ended
March
31, 2018
, our abandonments were primarily related to
(i) expiring acreage in the Southern Delaware Basin and (ii) acreage in the
Northern Delaware Basin and New Mexico Shelf where we had no future plans to
drill. For the three months ended
March 31, 2017
,
our abandonments were primarily related to (i) acreage in the Northern Delaware
Basin and Midland Basin where we had no future plans to drill and (ii) expiring
acreage primarily located 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 March 31, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
311
|
|
$
|
15.13
|
|
$
|
277
|
|
$
|
16.97
|
Depreciation of other property and equipment
|
|
|
5
|
|
|
0.26
|
|
|
6
|
|
|
0.37
|
Amortization of intangible assets
|
|
|
1
|
|
|
0.04
|
|
|
-
|
|
|
0.02
|
|
Total depletion, depreciation and amortization
|
|
$
|
317
|
|
$
|
15.43
|
|
$
|
283
|
|
$
|
17.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
49.94
|
|
|
|
|
$
|
44.10
|
|
|
|
Natural gas price used to estimate proved natural gas reserves
at period end
|
$
|
3.00
|
|
|
|
|
$
|
2.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties was $311 million
($15.13 per Boe) for the three months ended March 31, 2018 and $277 million
($16.97 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
March 31, 2017 and (ii) an overall increase in proved reserves primarily caused
by our successful exploratory drilling program, acquisitions, nonmonetary
transactions and higher commodity 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.
General and administrative expenses.
The following table provides components of our general
and administrative expenses for the three months ended
March 31,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
52
|
|
$
|
2.68
|
|
$
|
48
|
|
$
|
2.91
|
Less: Operating fee reimbursements
|
|
|
(4)
|
|
|
(0.21)
|
|
|
(4)
|
|
|
(0.24)
|
Non-cash stock-based compensation
|
|
|
17
|
|
|
0.84
|
|
|
12
|
|
|
0.69
|
|
Total general and administrative expenses
|
|
$
|
65
|
|
$
|
3.31
|
|
$
|
56
|
|
$
|
3.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were approximately $65 million ($3.31
per Boe) for the three months ended
March 31, 2018
, an increase of $9 million (16 percent) from $56 million
($3.36 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 $4 million for each of the three months ended
March 31,
2018 and 2017
.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for the
three months ended
March 31, 2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
March
31,
|
(in millions)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(33)
|
|
$
|
266
|
|
Natural gas derivatives
|
|
|
(2)
|
|
|
20
|
|
|
Total
|
|
$
|
(35)
|
|
$
|
286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from (payments on) derivatives for the three
months ended March 31, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
March
31,
|
(in millions)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
(113)
|
|
$
|
31
|
|
Natural gas derivatives
|
|
|
1
|
|
|
(3)
|
|
|
Total
|
|
$
|
(112)
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
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 three months ended
March 31, 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
three months ended March 31, 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 $14 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 $656 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 three months ended
March 31, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
30
|
|
$
|
40
|
Capitalized interest
|
|
|
1
|
|
|
-
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
31
|
|
$
|
40
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
4.3%
|
|
|
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
|
|
$
|
211
|
|
$
|
6
|
Weighted average senior notes balance
|
|
|
2,400
|
|
|
2,750
|
|
Total weighted average debt balance
|
|
$
|
2,611
|
|
$
|
2,756
|
|
|
|
|
|
|
|
|
Our weighted average debt balance decreased for the three months ended
March 31, 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, weighted average interest rate and an increase in
capitalized interest.
Other income, net.
During the three months ended
March 31, 2018, we recorded other income of approximately $97 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 three
months ended
March 31, 2018 and 2017, w
e recorded income
tax expense of $254 million and $371 million, respectively. These amounts
include a discrete income tax benefit of approximately $2 million and $7
million related to excess tax benefits on stock-based awards for the three
months ended
March 31, 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 three months ended
March 31,
2018 and 2017
were 23 percent and 36 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
three
months ended
March 31, 2018
and 2017 totaled $450 million and $393 million, respectively. The increase was
primarily due to our increased drilling and completion activity level during
the first
three
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 February 2018, we
announced our 2018 capital budget, excluding acquisitions, of approximately
$2.0 billion with expected capital spending to range between $1.9 billion and
$2.1 billion. Our 2018 capital budget, based on our current expectations of
commodity prices and costs, is expected to be within our operating cash flows.
After the completion of the RSP Acquisition, which is subject to approval
of both our and RSP’s shareholders, the satisfaction of certain regulatory
approvals and other customary closing conditions, we plan to make the necessary
adjustments to our capital budget to accommodate the incremental activities
associated with the assets acquired.
Other than the customary purchase of leasehold acreage, our capital
budgets are exclusive of acquisitions. We do not have a specific acquisition
budget since the timing and size of acquisitions are difficult to forecast. We
evaluate opportunities to purchase or sell oil and natural gas properties in
the marketplace and could participate as a buyer or seller of properties at
various times. We seek to acquire oil and natural gas properties that provide
opportunities for the addition of reserves and production through a combination
of development, high-potential exploration and control of operations that will
allow us to apply our operating expertise, such as the RSP Acquisition.
Acquisitions.
The following
table reflects o
ur expenditures for acquisitions
of proved and unproved properties for the three months ended March 31, 2018 and
2017:
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Three
Months Ended
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|
|
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March
31,
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(in millions)
|
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2018
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2017
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Property acquisition costs:
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Proved
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$
|
-
|
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$
|
127
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Unproved
|
|
|
13
|
|
|
306
|
|
|
Total property acquisition costs (a)
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$
|
13
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$
|
433
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(a)
|
Included in the property
acquisition costs above are budgeted unproved leasehold acreage acquisitions
of approximately $13 million and $5 million for the three months ended March
31, 2018 and 2017, respectively. For the three months ended March 31, 2017,
our unbudgeted acquisitions are primarily comprised of approximately $393
million of property acquisition costs related to our January 2017 Northern
Delaware Basin acquisition.
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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, the changes in our contractual obligations are not material,
other than our derivative liability position, which decreased by $52 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 three months ended
March 31,
2018
.
In connection with our proposed RSP Acquisition, the Acquisition
Agreement provides us certain termination rights under which we may exercise
and effectively terminate the Acquisition Agreement. Should certain unlikely
events occur under
specified circumstances outlined in
the Acquisition Agreement, we will be required to pay RSP a termination fee of
$350 million. See Note 4
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 February 2018, we announced our 2018
capital budget, excluding acquisitions, of approximately $2.0 billion with
expected capital spending to range between $1.9 billion and $2.1 billion. Our
2018 capital budget, 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 three months ended
March 31, 2018
and
2017:
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Three
Months Ended
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|
|
March
31,
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(in millions)
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
488
|
|
$
|
407
|
Net cash provided by (used in) investing activities
|
|
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(93)
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|
|
330
|
Net cash used in financing activities
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|
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(395)
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(19)
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Net increase in cash and cash equivalents
|
|
$
|
-
|
|
$
|
718
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Cash flow
from operating activities.
The increase in operating cash
flows during the
three
months ended March 31,
2018 as compared to the same period in 2017 was primarily due to an increase in
oil and natural gas revenues of approximately $335 million, partially offset by
(i) a decrease in operating cash flow of approximately $140 million due to
approximately $
112
million
for settlements paid on derivatives during the three months ended March 31,
2018, as compared to approximately $
28
million
in settlements received from derivatives during the comparable period in 2017,
(ii)
approximately $49 million of negative variances in operating assets
and liabilities, (iii) approximately $43 million increase in production expense
and (iv) approximately $22 million increase in production tax expense.
Our net
cash provided by operating activities included a reduction of approximately $51
million and a benefit of approximately $2
million for the
three
months ended March 31, 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 three months ended
March 31, 2018
and 2017, we invested approximately $474 million and $286
million, respectively, for additions to oil and natural gas properties.
Additionally, we completed acquisitions of oil and natural gas properties of
approximately $13 million and $171 million during the three months ended
March
31, 2018 and 2017, respectively
. We received
approximately $255 million related to proceeds from the disposition of assets during
the three months ended
March 31, 2018,
as
compared to $
806
million during the comparable
period of 2017. Finally, we received an equity method investment distribution from
Oryx of approximately $157 million during the three months ended
March
31, 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 $395 million and $19 million for
the
three
months ended March 31, 2018 and 2017,
respectively.
We had net payments on our Credit Facility of $322
million for the three months ended
March 31, 2018, as compared to no
outstanding borrowings during the comparable period of
2017.
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 (4.75 percent at March 31, 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.
We may also
sell assets and issue securities in exchange for oil and natural gas assets or
interests in energy companies, such as in the RSP Acquisition. 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 source of liquidity is available borrowing capacity under our Credit
Facility.
At March 31, 2018, our commitments from our
bank group were $2.0 billion.
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.
As of the filing of this Quarterly Report, no changes in our credit
ratings have occurred since
March 31, 2018
; however, 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 March 31, 2018 was $12.1
billion,
consisting of debt of $
2.4 b
illion and
stockholders’ equity of $
9.7
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 20
percent and
23
percent
at March 31, 2018 and December 31, 2017,
respectively. Our ratio of current assets to current liabilities was 0.65
to 1.0 at March 31, 2018 as compared to 0.51 to 1.0
at December 31, 2017.
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
three months ended March 31, 2018, we received an average of $61.29
per Bbl of oil and $3.39
per
Mcf of natural gas before consideration of commodity derivative contracts
compared to $49.08
per Bbl of oil and $3.00
per Mcf of natural gas in the three months ended
March 31, 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 three months ended March 31, 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.
In February 2016, the FASB
issued ASU No. 2016-02, “Leases (Topic 842),” (“ASU 2016-02”) which supersedes
current lease guidance. The new lease standard requires all leases with a term
greater than one year to be recognized on the balance sheet while maintaining
substantially similar classifications for financing and operating leases. Lease
expense recognition on the consolidated statements of operations will be
effectively unchanged. This guidance is effective for reporting periods
beginning after December 15, 2018, and early adoption is permitted. We do not
plan to early adopt the standard. We enter into lease agreements to support our
operations. These agreements are for leases on assets such as office space,
vehicles, field services, well equipment and drilling rigs. We are substantially
complete with the process of reviewing and determining the contracts to which
this new guidance applies. We are currently enhancing our accounting systems in
order to track and calculate additional information necessary for adoption of
this standard. We believe this new guidance will have a moderate impact to our
consolidated balance sheets due to the recognition of right-of-use assets and
lease liabilities that are not recognized under currently applicable guidance.
In January 2018, the FASB issued ASU No. 2018-01, “Land Easement
Practical Expedient for Transition to Topic 842,” which provides an optional
practical expedient to not evaluate land easements that existed or expired
before the adoption of ASU 2016-02 and that were not previously accounted for
as leases under the original “Leases (Topic 840)” accounting standard (“Topic
840”). We enter into land easements on a routine basis as part of our ongoing
operations and have many such agreements currently in place; however, we do not
currently account for any land easements under Topic 840. As this guidance
serves as an amendment to ASU 2016-02, we will elect this practical expedient,
which becomes effective upon the date of adoption of ASU 2016-02. After the
adoption of ASU 2016-02, we will assess any new land easements to determine
whether the arrangement should be accounted for as a lease.
In June 2016, the FASB issued ASU No. 2016-13, “Financial
Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on
Financial Instruments,” which replaces the current “incurred loss” methodology
for recognizing credit losses with an “expected loss” methodology. This new
methodology requires that a financial asset measured at amortized cost be
presented at the net amount expected to be collected. This standard is intended
to provide more timely decision-useful information about the expected credit
losses on financial instruments. This guidance is effective for fiscal years
beginning after December 15, 2019, and early adoption is allowed as early as
fiscal years beginning after December 15, 2018. We do not believe this new
guidance will have a material impact on our consolidated financial statements.