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 applying new
technologies, such as extended length lateral drilling, multi-well pad
development and enhanced completion techniques, throughout our four core operating
areas: the Northern Delaware Basin, the Southern Delaware Basin, the Midland
Basin and the New Mexico Shelf. Oil comprised
59 percent of our 720 MMBoe of estimated proved reserves at December
31, 2016 and 62 percent of our 186,449 Boe of average daily production for
the nine months ended
September 30, 2017
.
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 7,858 gross wells at
December 31, 2016
. 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 nine months ended September 30, 2017 and 2016
included the following highlights:
·
Net income was $
689 m
illion
($4.63
per diluted share) as compared to net loss
of $1.3
billion ($(10.18)
per diluted share) for the first nine months of
2017 and 2016, respectively. The increase was primarily due to:
•
no
recorded impairments of long-lived assets during the nine months ended
September 30, 2017, as compared to $1.5 billion in non-cash impairment charges in
2016
,
primarily attributable to properties in
our New Mexico Shelf area;
•
$696
million increase in oil and natural gas revenues as a result of
a
28
percent
increase in production and a 28 percent increase in commodity price
realizations per Boe
(excluding the effects of
derivative activities);
•
gain
on disposition of assets, net increased $558 million due to a gain of
approximately $
667
million during the nine months ended September 30, 2017 primarily due to our
disposition of Alpha Crude Connector, LLC (“ACC”), as compared to a gain of
approximately $109 million during 2016 primarily attributable to our Northern
Delaware Basin divestiture in February 2016;
•
$
465
million change in
(gain) loss on derivatives due to a $289 million gain on derivatives
during
the nine months ended September 30, 2017, as compared to a
$176 million loss on derivatives
during 2016;
and
•
$42
million decrease in depreciation, depletion and amortization expense, primarily
due to a decrease in the depletion rate per Boe period over period, partially
offset by an increase in production;
partially
offset by:
•
$1.2
billion change in our income tax provision due to income before income taxes
during the nine months ended September 30, 2017, as compared to a loss before income
taxes during 2016;
•
$53
million increase in production expense, primarily due to increased production
associated with our wells successfully drilled and completed in 2016 and 2017;
and
•
$51
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
186,449
Boe
per day during the first nine months of 2017 increased 28 percent as compared
to 145,868 Boe per day during 2016.
·
Net cash provided by operating activities increased by
approximately $166 million to $1,185
million
for
the first nine months of 2017, as compared to $1,019
m
illion
in the first nine months of 2016, primarily due to an increase in oil and
natural gas revenues and decreased cash interest expense, partially offset by
(i) a decrease in cash settlements on derivatives, (ii) increased
production expense, (iii) increased production tax expense and (iv) changes
related to cash income taxes.
·
Cash decreased by approximately $53 million during the first nine
months of 2017 primarily as a result of cash paid to tender and extinguish our 5.5%
Notes, as defined below, and cash paid for the Midland Basin and Northern
Delaware Basin acquisitions, partially offset by proceeds from the issuance of
the Notes, as defined below, and proceeds from our February 2017 divestiture of
ACC.
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:
·
continuing economic uncertainty
worldwide;
·
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;
·
domestic and foreign governmental
regulations, including limits on the United States’ ability to export crude
oil, and taxation;
·
the level of global inventories;
·
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;
·
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 quality of the oil we produce;
·
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;
·
political and economic events that
directly or indirectly impact the relative strength or weakness of the United
States dollar, on which oil prices are benchmarked globally, against foreign
currencies;
·
the effect of energy conservation
efforts;
·
the price and availability of
alternative fuels; and
·
overall North American oil, natural gas
and natural gas liquids supply and demand fundamentals, including:
•
the United States economy,
•
weather conditions, and
•
liquefied natural gas deliveries to and
exports from the United States.
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 7 and 14 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 September 30, 2017 and
additional derivative contracts entered into subsequent to September 30, 2017,
respectively.
Oil and natural gas prices have been subject to
significant fluctuations during the past several years. The average oil and
natural gas prices were higher during the comparable periods of 2017 measured
against 2016. The following table sets forth the average New York Mercantile
Exchange (“NYMEX”) oil and natural gas prices for the three and nine months
ended
September 30, 2017
and 2016, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX
prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
48.12
|
|
$
|
45.03
|
|
$
|
49.45
|
|
$
|
41.45
|
|
Natural gas
(MMBtu)
|
|
$
|
2.95
|
|
$
|
2.80
|
|
$
|
3.06
|
|
$
|
2.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High and Low
NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
52.22
|
|
$
|
48.99
|
|
$
|
54.45
|
|
$
|
51.23
|
|
|
Low
|
|
$
|
44.23
|
|
$
|
39.51
|
|
$
|
42.53
|
|
$
|
26.21
|
|
Natural
gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
3.15
|
|
$
|
3.06
|
|
$
|
3.72
|
|
$
|
3.06
|
|
|
Low
|
|
$
|
2.77
|
|
$
|
2.55
|
|
$
|
2.56
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $54.15 and $49.29 per Bbl and $3.01 and
$2.75 per MMBtu, respectively, during the period from
October 1, 2017
to October 30, 2017. At October 30, 2017, the NYMEX oil price and NYMEX natural
gas price were $54.15 per Bbl and $2.97 per MMBtu, respectively.
Historically, and during the nine months ended
September 30, 2017, 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 $25.04 per Bbl and $17.82 per Bbl during the three months
ended September 30, 2017 and 2016, respectively, and $23.74 per Bbl and $16.82 per
Bbl during the nine months ended September 30, 2017 and 2016, respectively.
Recent Events
Senior notes.
In September 2017, we issued $1,800
million in aggregate principal amount of unsecured senior notes, consisting of
$1,000 million in aggregate principal amount of 3.75% unsecured senior notes
due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of
4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with
the 3.75% Notes, the “Notes”). We used the net proceeds of approximately $1,777
million, together with cash on hand and borrowings under the Credit Facility,
as defined below, to fund the cash tender offer (the “Tender Offer”) and the satisfaction
and discharge of the outstanding $600 million aggregate principal amount of our
5.5% unsecured senior notes due 2022 and the outstanding $1,550 million
aggregate principal amount of our 5.5% unsecured senior notes due 2023
(collectively, the “5.5% Notes”). As a result of these transactions, we
recorded a loss on extinguishment of debt related to the 5.5% Notes of
approximately $65 million during each of the three and nine months ended
September 30, 2017.
See Note 8
of the Condensed Notes to Consolidated Financial Statements included in “Item
1. Consolidated Financial Statements (Unaudited)” for additional information
regarding our senior notes.
Investment grade period
.
In September 2017, we elected to enter into an “Investment Grade
Period” under the amended and restated credit facility (the “Credit Facility”),
which had the effect of releasing all collateral formerly securing the Credit Facility.
If the Investment Grade Period under the Credit Facility terminates (whether
automatically due to a downgrade of our credit ratings below certain thresholds
or by our election), the Credit Facility will 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. Additionally, as a result of our
Investment Grade Period election along with amendments to certain International
Swap Dealers Association Master Agreements (“ISDA Agreements”) with our
derivative counterparties, our derivatives are no longer secured.
Midland Basin
acquisition.
In July 2017, we completed an acquisition in the Midland
Basin. As consideration for the acquisition, we paid approximately $595 million
in cash. The acquisition is subject to customary post-closing adjustments.
Concurrent with the acquisition, we
entered into a transaction structured as a reverse like-kind exchange in
accordance with Section 1031 of the Internal Revenue Code of 1986. See Note 4
of the Condensed Notes to Consolidated Financial Statements included in “Item
1. Consolidated Financial Statements (Unaudited)” for additional information
regarding this transaction.
Derivative
Financial Instruments
Derivative financial instrument exposure.
At
September 30, 2017
, the fair value of our financial derivatives was a net
liability
of $
11
million. Under the terms of our financial derivative
instruments, we do not have exposure to potential “margin calls” on our
financial derivative instruments. We currently have no reason to believe that
our counterparties to these commodity derivative contracts are not financially
viable. The terms of 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.
In September
2017, we elected to enter into an Investment Grade Period under the Credit
Facility, which had the effect of releasing all collateral formerly securing
the Credit Facility and derivative obligations. See Note 8 of the Condensed
Notes to Consolidated Financial Statements included in “Item 1. Consolidated
Financial Statements (Unaudited)” for additional information regarding our
Credit Facility.
New commodity derivative contracts.
After September 30, 2017, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Price
Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
|
|
|
|
846,000
|
|
846,000
|
|
|
Price per Bbl
|
|
|
|
|
|
|
$
|
51.29
|
$
|
51.29
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
953,000
|
|
600,000
|
|
407,000
|
|
296,000
|
|
2,256,000
|
|
|
Price per Bbl
|
$
|
51.55
|
$
|
51.39
|
$
|
51.43
|
$
|
51.28
|
$
|
51.45
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,035,000
|
|
1,046,500
|
|
828,000
|
|
828,000
|
|
3,737,500
|
|
|
Price per Bbl
|
$
|
51.25
|
$
|
51.25
|
$
|
51.14
|
$
|
51.14
|
$
|
51.20
|
Oil Basis
Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
|
|
|
|
1,499,000
|
|
1,499,000
|
|
|
Price per Bbl
|
|
|
|
|
|
|
$
|
(0.12)
|
$
|
(0.12)
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
540,000
|
|
546,000
|
|
276,000
|
|
276,000
|
|
1,638,000
|
|
|
Price per Bbl
|
$
|
(0.21)
|
$
|
(0.21)
|
$
|
(0.38)
|
$
|
(0.38)
|
$
|
(0.27)
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,395,000
|
|
1,410,500
|
|
1,426,000
|
|
1,426,000
|
|
5,657,500
|
|
|
Price per Bbl
|
$
|
(0.68)
|
$
|
(0.68)
|
$
|
(0.68)
|
$
|
(0.68)
|
$
|
(0.68)
|
Natural Gas
Price Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
|
|
|
|
3,660,000
|
|
3,660,000
|
|
|
Price per MMBtu
|
|
|
|
|
|
|
$
|
3.02
|
$
|
3.02
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
5,400,000
|
|
5,460,000
|
|
4,600,000
|
|
4,600,000
|
|
20,060,000
|
|
|
Price per MMBtu
|
$
|
3.02
|
$
|
3.02
|
$
|
3.01
|
$
|
3.01
|
$
|
3.02
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
1,800,000
|
|
1,820,000
|
|
1,840,000
|
|
1,840,000
|
|
7,300,000
|
|
|
Price per MMBtu
|
$
|
2.86
|
$
|
2.86
|
$
|
2.86
|
$
|
2.86
|
$
|
2.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations
The following table sets forth summary
information concerning our production and operating data for the three and nine
months ended
September 30, 2017
and 2016.
The
actual historical data in this table excludes results from our acquisition
from Reliance Energy, Inc. (the “Reliance Acquisition”) for periods prior to October
2016.
Because of normal production
declines, increased or decreased drilling activities, fluctuations in commodity
prices and the effects of our acquisitions or divestitures, the historical
information presented below should not be interpreted as being indicative of
future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily
production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
119,565
|
|
|
91,120
|
|
|
115,484
|
|
|
89,854
|
|
|
Natural gas
(Mcf)
|
|
|
441,587
|
|
|
370,609
|
|
|
425,791
|
|
|
336,084
|
|
|
Total (Boe)
|
|
|
193,163
|
|
|
152,888
|
|
|
186,449
|
|
|
145,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
prices per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without
derivatives (Bbl)
|
|
$
|
45.29
|
|
$
|
41.52
|
|
$
|
46.34
|
|
$
|
37.75
|
|
|
Oil, with
derivatives (Bbl) (a)
|
|
$
|
47.81
|
|
$
|
59.87
|
|
$
|
50.45
|
|
$
|
60.74
|
|
|
Natural gas,
without derivatives (Mcf)
|
|
$
|
3.18
|
|
$
|
2.42
|
|
$
|
2.96
|
|
$
|
1.97
|
|
|
Natural gas,
with derivatives (Mcf) (a)
|
|
$
|
3.22
|
|
$
|
2.46
|
|
$
|
2.94
|
|
$
|
2.14
|
|
|
Total, without
derivatives (Boe)
|
|
$
|
35.29
|
|
$
|
30.61
|
|
$
|
35.47
|
|
$
|
27.78
|
|
|
Total, with
derivatives (Boe) (a)
|
|
$
|
36.96
|
|
$
|
41.65
|
|
$
|
37.95
|
|
$
|
42.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural
gas production
|
|
$
|
5.99
|
|
$
|
4.98
|
|
$
|
5.76
|
|
$
|
6.00
|
|
|
Production and
ad valorem taxes
|
|
$
|
2.70
|
|
$
|
2.38
|
|
$
|
2.75
|
|
$
|
2.23
|
|
|
Depreciation,
depletion and amortization
|
|
$
|
16.00
|
|
$
|
21.27
|
|
$
|
16.66
|
|
$
|
22.27
|
|
|
General and
administrative
|
|
$
|
3.60
|
|
$
|
3.80
|
|
$
|
3.56
|
|
$
|
4.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the effect of net cash receipts from (payments on)
derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash
receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
28
|
|
$
|
154
|
|
$
|
129
|
|
$
|
566
|
|
|
|
Natural gas
derivatives
|
|
|
2
|
|
|
1
|
|
|
(3)
|
|
|
16
|
|
|
|
|
Total
|
|
$
|
30
|
|
$
|
155
|
|
$
|
126
|
|
$
|
582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30, 2017 Compared to Three Months Ended September 30,
2016
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$627 million for the three months ended
September 30,
2017
, an increase of
$197 million (46
percent
) from $430 million for
2016
.
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). Specific factors affecting
oil and natural gas revenues include the following:
·
average daily oil production was 119,565
Bbl
for the three months ended
September 30,
2017
, an
increase
of 28,445
Bbl
(31
percent
) from 91,120
Bbl
for
2016
;
·
average realized oil price (excluding the effects of derivative
activities) was
$45.29
per Bbl during the three months ended
September 30,
2017
, an increase of 9
percent
from
$41.52
per Bbl during
2016
.
For the three
months ended September 30, 2017, our crude oil price differential relative to
NYMEX was $(2.83) per Bbl, or a realization of approximately 94 percent, as
compared to a crude oil price differential relative to NYMEX of $(3.51) per
Bbl, or a realization of approximately 92 percent, for 2016. 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 September 30, 2017 and 2016, the average market
basis differential between WTI-Midland and WTI-Cushing was a price reduction of
$
0.75
per
Bbl and $
0.31
per
Bbl, respectively. Additionally, 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
September
30, 2017 as compared to 2016
primarily due to more production
transported through pipelines;
·
average daily natural gas production was 441,587
Mcf
for the three months ended
September 30,
2017
, an
increase
of 70,978
Mcf
(19
percent
) from 370,609
Mcf
for
2016
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$3.18
per Mcf during the
three months ended
September 30, 2017
, an increase of 31
percent
from
$2.42
per Mcf during
2016.
For the three months ended September 30, 2017 and 2016, we realized
approximately 108 percent and 86 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 September 30, 2017 as compared to 2016 was primarily
due to an increase in the average Mont Belvieu price for a blended barrel of
natural gas liquids. Historically, and during the
three
months ended
September
30, 2017, 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
$25.04
per
Bbl and
$17.82
per
Bbl during the three months ended September 30, 2017 and 2016, 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
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
|
$
|
100
|
|
$
|
5.68
|
|
$
|
66
|
|
$
|
4.63
|
Workover costs
|
|
|
6
|
|
|
0.31
|
|
|
5
|
|
|
0.35
|
|
|
Total oil and
natural gas production expenses
|
|
$
|
106
|
|
$
|
5.99
|
|
$
|
71
|
|
$
|
4.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $100 million ($5.68
per Boe) for the three months ended
September
30, 2017
, which was an increase of
$34 million from $66 million ($4.63 per Boe) during
2016
. The increase
in lease operating expenses during the third quarter of 2017 as compared to
2016 was primarily due to (i) increased production associated with our wells
successfully drilled and completed in 2016 and 2017, (ii) our acquisitions
during the fourth quarter of 2016 and first nine months of 2017 and (iii) an
increase in 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 in the fourth quarter of 2016 and first nine months of
2017.
Production and ad valorem
taxes.
The
following table provides the components of our production and ad valorem tax
expenses for the three months ended
September
30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
44
|
|
$
|
2.48
|
|
$
|
31
|
|
$
|
2.25
|
Ad valorem taxes
|
|
|
4
|
|
|
0.22
|
|
|
2
|
|
|
0.13
|
|
|
Total production
and ad valorem taxes
|
|
$
|
48
|
|
$
|
2.70
|
|
$
|
33
|
|
$
|
2.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $2.48
per Boe during the three months ended
September
30, 2017
, an increase of 10
percent from $2.25 per Boe during
2016
. Over the same period, our revenue per Boe
(excluding the effects of derivatives) increased 15 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.
Exploration and abandonments expense.
The following table provides the components of
our exploration and abandonments expense for the three months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
September 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Geological and
geophysical
|
|
$
|
2
|
|
$
|
2
|
Exploratory dry
hole costs
|
|
|
-
|
|
|
-
|
Leasehold
abandonments
|
|
|
5
|
|
|
8
|
Other
|
|
|
-
|
|
|
-
|
|
Total
exploration and abandonments
|
|
$
|
7
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
September 30, 2017 and 2016
, we recorded approximately $5 million and $8 million,
respectively, of leasehold abandonments. For the three months ended
September 30, 2017
, our abandonments were primarily related to drilling locations in
our Northern Delaware Basin and New Mexico Shelf core areas which, based on
multiple factors, are no longer likely to be drilled and acreage in our
Southern Delaware Basin core area where we have no future development plans. For
the three months ended
September 30, 2016
, our abandonments were primarily related to
expiring acreage.
Depreciation, depletion and amortization expense.
The following table provides components of our depreciation,
depletion and amortization expense for the three months ended September 30,
2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of
proved oil and natural gas properties
|
|
$
|
279
|
|
$
|
15.67
|
|
$
|
294
|
|
$
|
20.88
|
Depreciation of
other property and equipment
|
|
|
5
|
|
|
0.31
|
|
|
5
|
|
|
0.36
|
Amortization of
intangible assets - operating rights
|
|
|
-
|
|
|
0.02
|
|
|
-
|
|
|
0.03
|
|
Total depletion,
depreciation and amortization
|
|
$
|
284
|
|
$
|
16.00
|
|
$
|
299
|
|
$
|
21.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to
estimate proved oil reserves at period end
|
|
$
|
46.27
|
|
|
|
|
$
|
38.17
|
|
|
|
Natural gas price
used to estimate proved natural gas reserves at period end
|
|
$
|
3.00
|
|
|
|
|
$
|
2.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $279 million ($15.67 per Boe) for the three months ended
September 30, 2017 and $294 million ($20.88 per Boe) for 2016. The decrease in
depletion expense was primarily due to a lower depletion rate per Boe period
over period partially offset by an increase in production. The decrease in
depletion expense per Boe period over period was primarily due to (i) lower
drilling and completion costs per Boe of proved developed reserves added and
(ii) an overall increase in proved reserves period over period primarily due to
our successful exploratory drilling program, the Reliance Acquisition, the
Northern Delaware Basin acquisition, the Midland Basin acquisition, reductions
in future estimated lease operating expenses and an increase in commodity
prices period over period, 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 their initial
recording.
Impairments of long-lived assets.
We periodically review our long-lived assets to
be held and used, including proved oil and natural gas properties and their
integrated assets, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable, for instance when there are
declines in commodity prices or well performance. We
review
our oil and natural gas properties by depletion base. An impairment loss is
indicated if the sum of the expected undiscounted future net cash flows is less
than the carrying amount of the assets. If the estimated undiscounted future
net cash flows are less than the carrying amount of our assets, we recognize an
impairment loss for the amount by which the carrying amount of the asset
exceeds the estimated fair value of the asset.
We estimate undiscounted future net cash flows
of our long-lived assets and their integrated assets using management’s
assumptions and expectations of (i) commodity prices, which are based on the
NYMEX strip, (ii) pricing adjustments for differentials, (iii) production
costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved
reserves and risk-adjusted probable and possible reserves, and (vii) prevailing
market rates of income and expenses from integrated assets. At September 30,
2017, our estimates of commodity prices for purposes of determining
undiscounted future cash flows, which are based on the NYMEX strip, ranged from
a 2017 price of $
52.29
per barrel of oil decreasing to a 2021 price
of $50.77 per barrel of oil partially recovering to a 2024 price of $
52.01
per barrel of oil. Similarly, natural gas prices ranged from a
2017 price of $
3.14
per Mcf of natural gas decreasing to a 2020
price of $
2.85
per Mcf of natural gas partially recovering to
a 2024 price of $
2.88
per Mcf of natural gas. Commodity prices for
this purpose were held flat after 2024.
We estimate fair values of our long-lived
assets and their integrated assets using a discounted future cash flow model.
Fair value assumptions associated with the calculation of discounted future net
cash flows include (i) market estimates of commodity prices, (ii) pricing
adjustments for differentials, (iii) production costs, (iv) capital
expenditures, (v) production volumes, (vi) estimated proved reserves and
risk-adjusted probable and possible reserves, (vii) prevailing market rates of
income and expenses from integrated assets and (viii) discount rate. The
expected future net cash flows were discounted using an annual rate of 10 percent
to determine fair value. We did not recognize an impairment charge during the
three months ended September 30, 2017 or 2016.
It is reasonably possible that the estimate of
undiscounted future net cash flows of our long-lived assets may change in the
future resulting in the need to impair carrying values. The primary factors
that may affect estimates of future net cash flows are (i) commodity futures
prices, (ii) increases or decreases in production and capital costs, (iii)
future reserve volume adjustments, both positive and negative, to proved
reserves and appropriate risk-adjusted probable and possible reserves, (iv)
results of future drilling activities and (v) prevailing market rates of income
and expenses from integrated assets.
Based on economic factors at September 30, 2017,
we determined that undiscounted future cash flows attributable to our North
Basin Bone Spring (“NBBS”) field located in the Northern Delaware Basin with a
net book value of approximately $
1.1
billion indicated that its carrying amount was
expected to be recovered; however, it may be at risk for impairment if
management’s estimates of future cash flows decline, including as a result of
further declines in projected commodity prices (and the resulting impact of
future cash flows). We estimate that if the future oil and natural gas prices used
in this analysis, and noted above, would have been approximately 10 percent
lower at September 30, 2017 with no other changes in capital costs, operating
costs, price differentials, or reserve performance curves, we could have
recognized a non-cash impairment in that period of approximately $470 million
related to our NBBS field. Other assumptions such as operating costs, well and
reservoir performance, severance and ad valorem taxes, and operating and
development plans would likely change given a change in oil and natural gas
prices. However, we did not estimate the correlation between these assumptions
and any estimated commodity price change, and these and other assumptions may worsen
or partially mitigate some of the effects of a reduction in commodity prices,
including the ultimate impact and amount of any potential impairment charge. As
a result, we are unable to predict with certainty whether or not a decline in
commodity prices alone will cause us to recognize an impairment charge in a
particular field or the magnitude of any such impairment charge. We
additionally note that there may be changes to both drilling and completion
designs that affect the volume curves, capital costs estimates, and the amount
of proved undeveloped locations that can be recorded, each of which will affect
management’s estimates of future cash flows.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the three months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative expenses
|
|
$
|
51
|
|
$
|
2.89
|
|
$
|
42
|
|
$
|
3.04
|
Less: Operating
fee reimbursements
|
|
|
(4)
|
|
|
(0.24)
|
|
|
(4)
|
|
|
(0.29)
|
Non-cash
stock-based compensation
|
|
|
17
|
|
|
0.95
|
|
|
15
|
|
|
1.05
|
|
Total general
and administrative expenses
|
|
$
|
64
|
|
$
|
3.60
|
|
$
|
53
|
|
$
|
3.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $64 million ($3.60 per Boe) for the three months ended
September 30, 2017
, an increase of $11 million (21 percent) from $53 million ($3.80
per Boe) for
2016
. 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 the increase in employee
headcount coupled with lower forfeitures in the third quarter of 2017.
The decrease in total general and
administrative expenses per Boe was primarily due to increased production
period over period, partially offset by the increase in general and
administrative costs 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 in the consolidated statements of operations. We earned
reimbursements of approximately
$4
million for each of the
three months ended
September 30, 2017 and 2016
.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for
the three months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
September 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Gain
(loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(205)
|
|
$
|
36
|
|
Natural gas
derivatives
|
|
|
(1)
|
|
|
5
|
|
|
Total
|
|
$
|
(206)
|
|
$
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table represents our net cash receipts from
derivatives for the three months ended September 30, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
September 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash
receipts from derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
28
|
|
$
|
154
|
|
Natural gas
derivatives
|
|
|
2
|
|
|
1
|
|
|
Total
|
|
$
|
30
|
|
$
|
155
|
|
|
|
|
|
|
|
|
|
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 6 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.
Interest expense was $39 million for the three
months ended
September 30, 2017 as compared to
$
53
million during 2016. T
he
decrease was primarily due to (i) approximately $11 million of interest
expense related to our $600 million 7.0% unsecured senior notes due 2021 (the
“7.0% Notes”) that were redeemed in September 2016 and (ii) approximately $10
million of interest expense related to our $600 million 6.5% unsecured senior
notes due 2022 (the “6.5% Notes”) that were satisfied and discharged in
December 2016, partially offset by approximately $7 million of interest expense
related to our $600 million 4.375% unsecured senior notes due 2025 (the “4.375%
Notes”) issued in December 2016.
Loss on extinguishment of debt.
We
recorded a loss on extinguishment of debt of approximately $65 million for the
three months ended September 30, 2017. This amount includes approximately $36
million associated with the premium paid for the Tender Offer, approximately
$25 million associated with the make-whole premium paid for the early
extinguishment of the 5.5% Notes, approximately $21 million of unamortized
deferred loan costs and approximately $2 million of additional interest on the
5.5% Notes to October 13, 2017, which was paid in September 2017, reduced by
approximately $19 million of unamortized premium.
We recorded a loss on extinguishment of debt of
approximately $28 million for the three months ended September 30, 2016. This
amount includes $21 million associated with the make-whole premium paid
for the early redemption of our 7.0% Notes and approximately $7 million of
unamortized deferred loan costs.
Income tax provisions.
We recorded an income tax benefit
of $66 million and $30 million for the three months ended
September 30, 2017
and 2016, respectively. The change in our income tax provision
was primarily due to the increase in our net loss before income taxes. The
effective income tax rates for the three months ended
September 30, 2017
and 2016 were 36.7 percent and 37.3 percent,
respectively.
Nine
Months Ended September 30, 2017 Compared to Nine Months Ended September 30,
2016
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$1,806 million for the nine months ended
September 30,
2017
, an increase of
$696 million (63
percent
) from $1,110 million for
2016
. 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). Specific factors affecting oil and natural
gas revenues include the following:
·
average daily oil production was 115,484
Bbl
for the nine months ended
September 30,
2017
, an
increase
of 25,630
Bbl
(29
percent
) from 89,854
Bbl
for
2016
;
·
average realized oil price (excluding the effects of derivative
activities) was
$46.34
per Bbl during the nine months ended
September 30,
2017
, an increase of 23
percent
from
$37.75
per Bbl during
2016
. For the nine months ended
September 30, 2017, our crude oil price differential relative to NYMEX was
$(3.11) per Bbl, or a realization of approximately 94 percent, as compared to a
crude oil price differential relative to NYMEX of $(3.70) per Bbl, or a
realization of approximately 91 percent, for 2016. 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 nine
months ended September 30, 2017 and 2016, the average market basis differential
between WTI-Midland and WTI-Cushing was a price reduction of $0.31 per Bbl and
$0.11 per Bbl, respectively. Additionally, 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 nine months ended
September 30, 2017 as compared to 2016 primarily due to more production transported
through pipelines and successful renegotiation of fixed deductions for trucked
volumes;
·
average daily natural gas production was 425,791
Mcf
for the nine months ended
September 30,
2017
, an
increase
of 89,707
Mcf
(27
percent
) from 336,084
Mcf
for
2016
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$2.96
per Mcf during the
nine months ended
September
30, 2017
, an increase of 50
percent
from
$1.97
per Mcf during
2016
.
For the nine months ended
September 30, 2017 and 2016
, we
realized approximately 97 percent and 84 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
nine
months ended September 30, 2017 as
compared to 2016 was primarily due to an increase in the average Mont Belvieu
price for a blended barrel of natural gas liquids. Historically, and during the
nine
months ended September 30, 2017, 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
$23.74
per
Bbl and
$16.82
per
Bbl during the nine months ended September 30, 2017 and 2016, respectively.
During
December 2015, a third-party natural gas processing plant located in the Northern
Delaware Basin became inoperable following an explosion. We estimate that this
event negatively impacted production for the nine months ended September 30,
2016 by approximately 1.6 MBoepd. The plant became fully operational during
April 2016.
Oil and natural gas production
expenses.
The
following table provides the components of our oil and natural gas production expenses
for the nine months ended September 30, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
|
$
|
278
|
|
$
|
5.47
|
|
$
|
225
|
|
$
|
5.62
|
Workover costs
|
|
|
15
|
|
|
0.29
|
|
|
15
|
|
|
0.38
|
|
|
Total oil and
natural gas production expenses
|
|
$
|
293
|
|
$
|
5.76
|
|
$
|
240
|
|
$
|
6.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $278 million
($5.47 per Boe) for the nine months ended
September
30, 2017
, which was an increase of
$53 million from $225 million ($5.62 per Boe) during
2016
. The increase
in lease operating expenses during the nine months ended
September 30, 2017
as compared to 2016 was primarily due to (i) increased production
associated with our wells successfully drilled and completed in 2016 and 2017,
(ii) our acquisitions during the fourth quarter of 2016 and first nine months
of 2017 and (iii) increased cost of services, partially offset by a decrease in
facility expense. The decrease in lease operating expenses per Boe was
primarily due to increased production during the first nine months of 2017 as
compared to 2016, partially offset by the increase in total lease operating expenses
as noted above.
Production and ad valorem
taxes.
The
following table provides the components of our production and ad valorem tax
expenses for the nine months ended
September
30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
128
|
|
$
|
2.52
|
|
$
|
78
|
|
$
|
1.96
|
Ad valorem taxes
|
|
|
12
|
|
|
0.23
|
|
|
11
|
|
|
0.27
|
|
|
Total production
and ad valorem taxes
|
|
$
|
140
|
|
$
|
2.75
|
|
$
|
89
|
|
$
|
2.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $2.52
per Boe during the nine months ended
September
30, 2017
, an increase of 29
percent from $1.96 per Boe during
2016
. Over the same period, our revenue per Boe
(excluding the effects of derivatives) increased 28 percent. The increase in
production taxes per unit of production was directly related to the increase in
oil and natural gas sales. Additionally, tax credits of approximately $4
million were received during the first quarter of 2016 related to certain wells
in Texas qualifying for reduced severance tax rates.
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.
Exploration and abandonments expense.
The following table provides the components of
our exploration and abandonments expense for the
nine
months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Geological and
geophysical
|
|
$
|
9
|
|
$
|
6
|
Exploratory dry
hole costs
|
|
|
-
|
|
|
7
|
Leasehold
abandonments
|
|
|
29
|
|
|
40
|
Other
|
|
|
4
|
|
|
1
|
|
Total
exploration and abandonments
|
|
$
|
42
|
|
$
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the
periods presented above primarily consists of the costs of acquiring and
processing geophysical data and core analysis.
Our exploratory dry hole costs during the nine
months ended September 30, 2016 were primarily related to an uneconomic well in
our Northern Delaware Basin core area that was attempting to establish
commercial production through testing of multiple zones. We did not recognize
any exploratory dry hole costs during the nine months ended September 30, 2017.
For the
nine
months ended
September 30, 2017 and 2016, we recorded approximately $29 million and $40 million,
respectively, of leasehold abandonments. For the
nine
months ended September 30, 2017, our abandonments were primarily related to (i)
non-contiguous acreage expiring in our Southern Delaware Basin core area and
(ii) acreage in our Northern Delaware Basin and New Mexico Shelf core areas in
locations where we have no future plans to drill. For the
nine
months ended September 30, 2016, our
abandonments were primarily related to (i) drilling locations in our Northern
Delaware Basin and New Mexico Shelf core areas which, based on multiple
factors, are no longer likely to be drilled, (ii) acreage in our Northern
Delaware Basin and New Mexico Shelf core areas where we have no future
development plans and (iii) expiring acreage.
Depreciation, depletion and amortization
expense.
The
following table provides components of our depreciation, depletion and
amortization expense for the nine months ended
September
30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of
proved oil and natural gas properties
|
|
$
|
830
|
|
$
|
16.31
|
|
$
|
874
|
|
$
|
21.86
|
Depreciation of
other property and equipment
|
|
|
17
|
|
|
0.33
|
|
|
15
|
|
|
0.38
|
Amortization of
intangible assets - operating rights
|
|
|
1
|
|
|
0.02
|
|
|
1
|
|
|
0.03
|
|
Total depletion,
depreciation and amortization
|
|
$
|
848
|
|
$
|
16.66
|
|
$
|
890
|
|
$
|
22.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
was $830 million ($16.31 per Boe) for the nine months ended
September 30, 2017
, a decrease of $44 million (5 percent) from $874 million ($21.86
per Boe) for
2016
. The decrease in depletion expense was
primarily due to a lower depletion rate per Boe period over period partially
offset by an increase in production. The decrease in depletion expense per Boe
period over period was primarily due to (i) lower drilling and completion costs
per Boe of proved developed reserves added, (ii) an overall increase in proved
reserves period over period primarily caused by our successful exploratory
drilling program, the Reliance Acquisition, the Northern Delaware Basin
acquisition, the Midland Basin acquisition, reductions in future estimated
lease operating expenses and higher commodity prices period over period,
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 their
initial recording and (iii) a non-cash impairment charge of approximately $1.5
billion recorded in the first quarter of 2016.
Impairments of long-lived assets.
We periodically review our long-lived assets to
be held and used, including proved oil and natural gas properties and their
integrated assets, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable, for instance when there are
declines in commodity prices or well performance. We review our oil and natural
gas properties by depletion base. An impairment loss is indicated if the sum of
the expected undiscounted future net cash flows is less than the carrying
amount of the assets. If the estimated undiscounted future net cash flows are
less than the carrying amount of our assets, we recognize an impairment loss
for the amount by which the carrying amount of the asset exceeds the estimated
fair value of the asset.
We estimate undiscounted future net cash flows
of our long-lived assets and their integrated assets using management’s
assumptions and expectations of (i) commodity prices, which are based on the
NYMEX strip, (ii) pricing adjustments for differentials, (iii) production
costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved
reserves and risk-adjusted probable and possible reserves, and (vii) prevailing
market rates of income and expenses from integrated assets. At September 30,
2017, our estimates of commodity prices for purposes of determining
undiscounted future cash flows, which are based on the NYMEX strip, ranged from
a 2017 price of $
52.29
per barrel of oil decreasing to a 2021 price
of $
50.77
per barrel of oil partially recovering to a
2024 price of $
52.01
per barrel of oil. Similarly, natural gas
prices ranged from a 2017 price of $
3.14
per Mcf of natural gas
decreasing to a 2020 price of $
2.85
per Mcf of natural gas partially recovering to
a 2024 price of $
2.88
per Mcf of natural gas. Commodity prices for
this purpose were held flat after 2024.
We estimate fair values of our long-lived
assets and their integrated assets using a discounted future cash flow model.
Fair value assumptions associated with the calculation of discounted future net
cash flows include (i) market estimates of commodity prices, (ii) pricing
adjustments for differentials, (iii) production costs, (iv) capital
expenditures, (v) production volumes, (vi) estimated proved reserves and
risk-adjusted probable and possible reserves, (vii) prevailing market rates of
income and expenses from integrated assets and (viii) discount rate. The
expected future net cash flows were discounted using an annual rate of 10
percent to determine fair value.
During the three months ended March 31, 2016,
NYMEX strip prices declined as compared to December 31, 2015, and as a result
the carrying amount of our Yeso field in our New Mexico Shelf core area
exceeded the expected undiscounted future net cash flows resulting in a
non-cash charge against earnings of approximately $1.5 billion. The Yeso field,
as compared to our other fields not previously impaired, had significant proved
reserves upon acquisition, which required a higher valuation than a field more
exploratory in nature that has a higher risk factor adjustment in the fair
value estimate. Our estimates of commodity prices for purposes of determining
the estimated fair value at March 31, 2016 ranged from a 2016 price of $41.26
per barrel of oil and $2.26 per Mcf of natural gas to a 2023 price of $66.33
per barrel of oil and $3.56 per Mcf of natural gas. Commodity prices for this
purpose were held flat after 2023. We did not recognize an impairment charge
during the nine months ended September 30, 2017.
It is reasonably possible that the estimate of
undiscounted future net cash flows of our long-lived assets may change in the
future resulting in the need to impair carrying values. The primary factors
that may affect estimates of future net cash flows are (i) commodity futures
prices, (ii) increases or decreases in production and capital costs, (iii)
future reserve volume adjustments, both positive and negative, to proved
reserves and appropriate risk-adjusted probable and possible reserves, (iv)
results of future drilling activities and (v) prevailing market rates of income
and expenses from integrated assets.
Based on economic factors at September 30,
2017, we determined that undiscounted future cash flows attributable to our
NBBS field located in the Northern Delaware Basin with a net book value of
approximately $
1.1
billion indicated that its carrying
amount was expected to be recovered; however, it may be at risk for impairment
if management’s estimates of future cash flows decline, including as a result
of further declines in projected commodity prices (and the resulting impact of
future cash flows). We estimate that if the future oil and natural gas prices
used in this analysis, and noted above, would have been approximately 10
percent lower at September 30, 2017 with no other changes in capital costs,
operating costs, price differentials, or reserve performance curves, we could
have recognized a non-cash impairment in that period of approximately $470 million
related to our NBBS field. Other assumptions such as operating costs, well and
reservoir performance, severance and ad valorem taxes, and operating and
development plans would likely change given a change in oil and natural gas
prices. However, we did not estimate the correlation between these assumptions
and any estimated commodity price change, and these and other assumptions may
worsen or partially mitigate some of the effects of a reduction in commodity
prices, including the ultimate impact and amount of any potential impairment
charge. As a result, we are
unable to predict with
certainty whether or not a decline in commodity prices alone will cause us to
recognize an impairment charge in a particular field or the magnitude of any
such impairment charge. We additionally note that there may be changes to both
drilling and completion designs that affect the volume curves, capital costs
estimates, and the amount of proved undeveloped locations that can be recorded,
each of which will affect management’s estimates of future cash flows.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the nine months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative expenses
|
|
$
|
149
|
|
$
|
2.95
|
|
$
|
129
|
|
$
|
3.24
|
Less: Operating
fee reimbursements
|
|
|
(12)
|
|
|
(0.24)
|
|
|
(12)
|
|
|
(0.30)
|
Non-cash
stock-based compensation
|
|
|
43
|
|
|
0.85
|
|
|
43
|
|
|
1.08
|
|
Total general
and administrative expenses
|
|
$
|
180
|
|
$
|
3.56
|
|
$
|
160
|
|
$
|
4.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $180 million ($3.56 per Boe) for the nine months ended
September 30, 2017
, an increase of $20 million (13 percent) from $160 million ($4.02
per Boe) for
2016
. The increase in cash general and
administrative expenses was primarily a result of increased compensation
expense. The decrease in total general and administrative expenses per Boe was
primarily due to increased production period over period, partially offset by
the increase in general and administrative costs 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 of general and
administrative expenses in the consolidated statements of operations. We earned
reimbursements of approximately $12 million for each of the nine months ended
September 30, 2017 and 2016.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for
the nine months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Gain
(loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
260
|
|
$
|
(173)
|
|
Natural gas
derivatives
|
|
|
29
|
|
|
(3)
|
|
|
Total
|
|
$
|
289
|
|
$
|
(176)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table represents our net cash receipts from
(payments on) derivatives for the nine months ended September 30, 2017 and
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash
receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
129
|
|
$
|
566
|
|
Natural gas
derivatives
|
|
|
(3)
|
|
|
16
|
|
|
Total
|
|
$
|
126
|
|
$
|
582
|
|
|
|
|
|
|
|
|
|
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 6 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.
In February 2017, we closed on our previously announced
divestiture of our ownership interest in ACC. After adjustments for debt and
working capital, we received cash proceeds from the sale of approximately $801 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.
In February 2016, we sold certain assets in the Northern
Delaware Basin for proceeds of approximately $292 million and recognized a pre-tax
gain of approximately $110 million.
Interest expense.
Interest expense was $118 million for the nine
months ended
September 30, 2017 as compared to
$
162
million during 2016. The decrease was primarily due to (i)
approximately $32 million of interest expense related to our $600 million 7.0% Notes
that were redeemed in September 2016 and (ii) approximately $29 million of
interest expense related to our $600 million 6.5% Notes that were satisfied and
discharged in December 2016, partially offset by approximately $20 million of
interest expense related to our $600 million 4.375% Notes issued in December
2016.
Loss on extinguishment of debt.
We recorded a loss on extinguishment of debt of
approximately $66 million for the nine months ended September 30, 2017. This
amount includes (i) approximately $36 million associated with the premium paid
for the Tender Offer, approximately $25 million associated with the make-whole
premium paid for the early extinguishment of the 5.5% Notes, approximately $21
million of unamortized deferred loan costs and approximately $2 million of
additional interest on the 5.5% Notes to October 13, 2017, which was paid in
September 2017, reduced by approximately $19 million of unamortized premium;
and (ii) approximately $1 million 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 the April 2017 credit facility
amendment.
We recorded a loss on extinguishment of debt of approximately
$28 million for the nine months ended
September 30, 2016. This amount includes $21 million associated with the
make-whole premium paid for the early redemption of the 7.0% Notes and
approximately $7 million of unamortized deferred loan costs.
Income tax provisions.
We recorded income tax expense of
$398 million, which includes a discrete income tax benefit of approximately $6
million related to excess tax benefits on stock-based awards, which are recorded
in the income tax provision pursuant to ASU No. 2016-09, which was adopted on
January 1, 2017, and an income tax benefit of $782 million for the nine months
ended September 30, 2017 and 2016, respectively. The change in our income tax
provision was primarily due to income before income taxes during the nine
months ended September 30, 2017, as compared to a loss before income taxes
during 2016. The effective income tax rates for the nine months ended September
30, 2017 and 2016 were 36.6 percent and 36.9 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, midstream joint venture and other capital
commitments, 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
nine
months ended
September
30, 2017
and 2016 totaled $1.2 billion
and $800 million, respectively. The increase was primarily due to our increased
drilling and completion activity level during the first nine months of 2017 as
compared to 2016. Our intent is to manage our capital spending to be within our
cash flow, excluding unbudgeted acquisitions. The primary reason for the
differences in costs incurred and cash flow expenditures was our issuance of
approximately 2.2 million shares of common stock related to our Northern
Delaware Basin acquisition and timing of payments. Total 2017 expenditures were
primarily funded in part from (i) cash flows from operations, (ii) our issuance
of approximately 2.2 million shares of common stock related to our Northern
Delaware Basin acquisition and to a lesser extent (iii) proceeds from our
February 2017 divestiture of ACC.
2017 capital budget.
In February 2017, we announced our updated 2017
capital budget, excluding acquisitions, of approximately $1.8 billion with
expected capital spending to range between $1.6 billion and $1.8 billion.
Approximately 90 percent of capital will be directed to drilling and completion
activity. Our 2017 capital program, based on our current expectations of commodity
prices and costs, is expected to be within our cash flows. However, if we were
to outspend our cash flows, we believe we could use our credit facility and other
financing sources to fund any cash flow deficits. The actual amount and timing
of our expenditures may differ materially from our estimates as a result of,
among other things, actual drilling results, the timing of expenditures by
third parties on projects that we do not operate, the costs of drilling rigs
and other services and equipment, regulatory, technological and competitive
developments, commodity prices, leverage metrics and industry conditions. In
addition, under certain circumstances, we may consider increasing, decreasing
or reallocating our capital spending plans.
Acquisitions.
The
following table reflects o
ur expenditures for
acquisitions of proved and unproved properties for the nine months ended
September 30, 2017
and
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Property
acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
301
|
|
$
|
257
|
|
Unproved
|
|
|
865
|
|
|
172
|
|
|
Total property
acquisition costs (a)
|
|
$
|
1,166
|
|
$
|
429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the property acquisition costs above are budgeted
unproved leasehold acreage acquisitions of approximately $26 million for each
of the nine months ended September 30, 2017 and 2016. For the nine months
ended September 30, 2017, our unbudgeted acquisitions are primarily comprised
of approximately $603 million and $452 million of property acquisition costs
related to our Midland Basin and Northern Delaware Basin acquisitions,
respectively. For the nine months ended September 30, 2016, our unbudgeted
acquisitions are primarily comprised of approximately $375 million of
property acquisition costs related to our Southern 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, 2016, the
changes in our contractual obligations are not material, other than our cash
interest expense on debt and our derivative liability position. Cash interest
expense on debt increased by $854 million due to the issuance of the Notes
which have maturity dates of 2027 and 2047, as compared to the retired 5.5%
Notes
which had maturity dates of 2022 and 2023. Our
derivative liability position decreased from December 31, 2016 by $135 million.
See Note 8 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 nine months ended
September 30, 2017
.
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 2017, we announced our updated 2017 capital budget,
excluding acquisitions, of approximately $1.8 billion with expected capital
spending to range between $1.6 billion and $1.8 billion. Our 2017 capital program,
based on our current expectations of commodity prices and costs, is expected to
be within our cash flows. However, if we were to outspend our cash flows, we
believe we could use our credit facility and other financing sources to fund
any cash flow deficits. The actual amount and timing of our expenditures may
differ materially from our estimates as a result of, among other things, actual
drilling results, the timing of expenditures by third parties on projects that
we do not operate, the costs of drilling rigs and other services and equipment,
regulatory, technological and competitive developments, commodity prices,
leverage metrics and industry conditions. In addition, under certain
circumstances, we may consider increasing, decreasing or reallocating our
capital spending plans.
The following table summarizes our changes in
cash and cash equivalents for the nine months ended
September 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash
provided by operating activities
|
|
$
|
1,185
|
|
$
|
1,019
|
Net cash used in
investing activities
|
|
|
(1,207)
|
|
|
(783)
|
Net cash
provided by (used in) financing activities
|
|
|
(31)
|
|
|
694
|
|
Net increase
(decrease) in cash and cash equivalents
|
|
$
|
(53)
|
|
$
|
930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from
operating activities.
The increase in operating cash flows during the
nine
months ended September 30, 2017 as compared to
the same period in 2016 was primarily due to an increase in oil and natural gas
revenues of approximately $696 million and a decrease in cash interest expense
of approximately $42 million, partially offset by (i)
approximately
$
126
million from settlements on derivatives during the nine months ended September
30, 2017, as compared to $
582
million from settlements on derivatives
during the comparable period in 2016,
(ii) approximately $53 million increase in
production expense, (iii) approximately $51 million increase in production tax
expense and (iv) a decrease in operating cash flow of approximately $20 million
due to cash tax expense of approximately $6 million for the
nine
months ended
September 30, 2017, as compared to a cash tax benefit of approximately $14
million during the comparable period in 2016.
Our net cash provided by operating
activities included a reduction of approximately $59
million
and $73
million for the
nine
months ended September 30, 2017 and 2016,
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 nine months ended
September
30, 2017
and 2016, we invested approximately $1,958 million and $927 million,
respectively, for capital expenditures on oil and natural gas properties. Additionally,
we received approximately $
803
million related to proceeds from the
disposition of assets during the nine months ended
September 30,
2017,
as compared to $
296
million during the comparable period of
2016.
Cash
flow from financing activities.
Net cash used in financing activities
was approximately $31 million for the
nine
months ended
September 30, 2017 while net cash provided by financing activities was approximately
$694 million for the
nine
months ended September 30, 2016. Below is a description of our significant
financing activities:
·
In
September 2017, we issued $1,800 million in aggregate principal amount of the
Notes, for which we received net proceeds of approximately
$1,777
million. We used the net proceeds from the offering, together with cash on hand
and borrowings under our credit facility, to fund the (i) Tender Offer of $1,232
million principal amount of our 5.5% Notes at a price equal to 102.934 percent
of par and (ii) satisfaction and discharge of our remaining obligations of $918
million principal amount under the indentures of the 5.5% Notes at a price
equal to 102.75 percent of par. The early extinguishment price included
approximately $36 million associated with the premium paid for the Tender
Offer, approximately $25 million for the make-whole premium paid for the early
extinguishment of the 5.5% Notes and approximately $2 million for prepaid
interest as part of the satisfaction and discharge.
·
In
September 2016, we redeemed the $600 million outstanding principal amount of
our 7.0% Notes at a price equal to 103.5 percent of par. The redemption price
included the make-whole premium for the early redemption of $21 million.
·
In
August 2016, we issued approximately 10.4 million shares of our common stock in
a public offering at $130.90 per share and received net proceeds of
approximately $1.3 billion.
·
During the first nine months of
2017
, we
borrowed $368 million on our credit facility.
·
During the first nine months of
2016
, we
had no outstanding borrowings under our credit facility.
In April 2017,
we amended our credit facility to decrease our unused lender commitments.
At
September 30,
2017,
we had unused commitments on our credit facility of approximately
$1.6
billion.
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 (4.25 percent at September 30, 2017), (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. The 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
September 2017, we elected to enter into an Investment Grade Period under our
credit facility, which had the effect of releasing all collateral formerly
securing the credit facility. If the Investment Grade Period under the credit facility
terminates (whether automatically or by our election), the credit facility will
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.
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. 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
September 30, 2017, 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 (“Fitch”), which are subject to regular reviews. In August 2017, our
long-term debt was assigned a first-time investment grade rating by Fitch, and
our rating by S&P was raised to an investment grade rating. 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. An explanation of the significance of each
rating may be obtained from the applicable rating agency.
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 will automatically terminate and cause the 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
September 30, 2017; 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 September
30, 2017
was $11.3
billion, consisting of debt of $
2.7 b
illion and stockholders’ equity of $
8.6
billion. Our net book capitalization at December
31, 2016 was $10.2 billion, consisting of $0.1 billion of cash and cash
equivalents, debt of $2.7 billion and stockholders’ equity of $7.6 billion. Our
ratio of net debt to net book capitalization was 24
percent
and
26
percent
at September 30,
2017
and December 31, 2016, respectively. Our ratio of current assets to current
liabilities was 0.66
to 1.0 at September 30,
2017
as compared to 0.73 to 1.0 at December 31, 2016.
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 nine months ended September 30, 2017, we received an
average of $46.34
per Bbl of oil and $2.96
per Mcf of natural gas before consideration of
commodity derivative contracts compared to $37.75
per
Bbl of oil and $1.97
per Mcf of natural gas in
the nine months ended September
30, 2016.
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
condensed 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 business combinations, valuation of nonmonetary exchanges,
valuation of financial derivative instruments, valuation of stock-based
compensation 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
nine
months ended September 30,
2017. 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, 2016, filed with the United States
Securities and Exchange Commission (the “SEC”) on February 22, 2017.
New
accounting pronouncements issued but not yet adopted.
In
May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No.
2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a
new, single comprehensive model for entities to use in accounting for revenue
arising from contracts with customers and supersedes most current revenue
recognition guidance, including industry-specific guidance. This new revenue
recognition model provides a five-step analysis in determining when and how
revenue is recognized. The new model will require revenue recognition to depict
the transfer of promised goods or services to customers in an amount that
reflects the consideration a company expects to receive in exchange for those
goods or services.
In August 2015, the FASB issued ASU
No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of
the Effective Date,” which deferred the effective date of ASU No. 2014-09 by
one year. That new standard is now effective for annual reporting periods
beginning after December 15, 2017. We expect to use the modified retrospective
method to adopt the standard, meaning the cumulative effect of initially
applying the standard will be recognized with an adjustment to retained
earnings on January 1, 2018. We have substantially completed our internal
evaluation of the adoption of this standard, which included a review of all
revenue-related contracts with customers and the application of the new revenue
recognition model against those contracts. We are also updating our revenue
recognition policy to conform to the new standard. We also expect to expand our
revenue recognition related disclosure. Including those changes previously
discussed, we do not expect this new guidance will have a material impact on our
consolidated financial statements.
In February 2016, the Financial
Accounting Standards Board (the “FASB”) issued ASU No. 2016-02, “Leases
(Topic 842),” 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
finance and operating leases. Lease expense recognition on the income statement
will be effectively unchanged. This guidance is effective for reporting periods
beginning after December 15, 2018 and early adoption is permitted. We are
evaluating the impact that this new guidance will have on our consolidated financial
statements.
In January 2017, the FASB issued
ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition
of a Business,” with the objective of adding guidance to assist in evaluating
whether transactions should be accounted for as asset acquisitions or as
business combinations. The guidance provides a screen to determine when an
integrated set of assets and activities is not a business. The screen requires
that when substantially all of the fair value of the acquired assets is
concentrated in a single asset or a group of similar assets, the set is not a
business. If the screen is not met, to be considered a business, the set must
include an input and a substantive process that together significantly
contribute to the ability to create
output. This new
guidance is effective for annual periods beginning after December 15, 2017, and
early adoption is allowed. We are evaluating the impact this new guidance will
have on our consolidated financial statements.