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 183,036 Boe of average
daily production for the six months ended
June
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 six months ended June 30, 2017 and 2016
included the following highlights:
·
Net income was $
802 m
illion
($5.39
per diluted share) as compared to net loss
of $1.3
billion ($(9.94)
per diluted share) for the first six months of 2017
and 2016, respectively. The increase was primarily due to:
•
no
recorded impairments of long-lived assets during the six months ended June 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;
•
$
712
million change in
(gain) loss on derivatives due to a $495 million gain on derivatives
during
the six months ended June 30, 2017, as compared to a
$217
million loss on derivatives
during 2016;
•
gain
on disposition of assets, net increased $544 million primarily due to our
disposition of Alpha Crude Connector, LLC (“ACC”) which resulted in a gain of
approximately $
655
million during the six months ended June 30, 2017, as compared to a gain of
approximately $110 million during 2016 primarily attributable to our Northern
Delaware Basin divestiture in February 2016;
•
$499
million increase in oil and natural gas revenues as a result of a
36 percent increase in commodity price realizations per Boe
(excluding the effects of derivative activities) and
a
29
percent increase in production
; and
•
$27
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 six months ended June 30, 2017, as compared to a loss before income
taxes during 2016; and
•
$36
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
183,036
Boe
per day during the first six months of 2017 increased 29 percent as compared to
142,319 Boe per day during 2016.
·
Net cash provided by operating activities increased by
approximately $129 million to $805
million
for
the first six months of 2017, as compared to $676
m
illion
in the first six 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 tax expense, (iii) changes related to cash income taxes and (iv)
increased production expense.
·
Cash increased by approximately $609 million during the first six
months of 2017 primarily as a result of proceeds from our February 2017
divestiture of ACC. In July 2017, we paid approximately $540 million in cash as
partial consideration for our Midland Basin acquisition.
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 June 30, 2017 and additional
derivative contracts entered into subsequent to June 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 six months
ended
June 30, 2017
and 2016, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
48.32
|
|
$
|
45.56
|
|
$
|
50.12
|
|
$
|
39.65
|
|
Natural gas
(MMBtu)
|
|
$
|
3.15
|
|
$
|
2.24
|
|
$
|
3.12
|
|
$
|
2.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High and Low
NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
53.40
|
|
$
|
51.23
|
|
$
|
54.45
|
|
$
|
51.23
|
|
|
Low
|
|
$
|
42.53
|
|
$
|
35.70
|
|
$
|
42.53
|
|
$
|
26.21
|
|
Natural
gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
3.42
|
|
$
|
2.92
|
|
$
|
3.72
|
|
$
|
2.92
|
|
|
Low
|
|
$
|
2.89
|
|
$
|
1.90
|
|
$
|
2.56
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $50.17 and $44.23 per Bbl and $3.09 and
$2.79 per MMBtu, respectively, during the period from
July 1, 2017
to July 31, 2017. At July 31, 2017, the NYMEX oil price and NYMEX natural gas
price were $50.17 per Bbl and $2.79 per MMBtu, respectively.
Historically, and during the six months ended
June 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 $21.99 per Bbl and $18.16 per Bbl during the three months ended
June 30, 2017 and 2016, respectively, and $23.09 per Bbl and $16.32 per Bbl
during the six months ended June 30, 2017 and 2016, respectively.
Recent
Events
Midland Basin
acquisition.
In July 2017, we completed an acquisition in the Midland
Basin. As consideration for the acquisition, we paid approximately $600 million
in cash, of which $60 million was held in escrow at June 30, 2017 with the
remaining $540 million paid in July 2017. The acquisition is subject to
customary post-closing adjustments.
Northern Delaware Basin
acquisition.
In April 2017, we closed on the remainder of the acquisition
in the Northern Delaware Basin. As consideration for the entire acquisition, we
paid approximately $159 million in cash and issued to the seller approximately
2.2 million shares of our common stock with an approximate value of $291
million.
Credit Facility amendment.
In April 2017, we amended our credit facility
to extend the maturity date to May 9, 2022. Additionally, we increased our
borrowing base to $3.0 billion and decreased the commitments from our bank
group to $2.0 billion.
Derivative Financial Instruments
Derivative financial instrument exposure.
At
June 30, 2017
, the fair value of our financial derivatives was a net
asset
of $
225
million. At
June 30, 2017
, all of our counterparties have their outstanding debt
commitments and derivative exposures collateralized pursuant to our credit
facility. At
June 30, 2017
, under the terms of our financial derivative instruments
and their collateralization under our credit facility, 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. Under the terms of our credit
facility, certain events could occur that would cause the obligations under our
credit facility to no longer be secured by our oil and natural gas properties. Our
credit facility does not allow us to offset amounts we may owe a lender against
amounts we may be owed related to our financial instruments with such party.
New commodity derivative contracts.
After June 30, 2017, we entered into the following
oil price swaps and oil basis 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)
|
|
|
|
|
|
1,253,000
|
|
1,354,000
|
|
2,607,000
|
|
|
Price per Bbl
|
|
|
|
|
$
|
47.76
|
$
|
47.73
|
$
|
47.74
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,059,000
|
|
869,000
|
|
747,000
|
|
669,000
|
|
3,344,000
|
|
|
Price per Bbl
|
$
|
48.33
|
$
|
48.26
|
$
|
48.20
|
$
|
48.15
|
$
|
48.25
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,002,000
|
|
940,000
|
|
885,000
|
|
845,000
|
|
3,672,000
|
|
|
Price per Bbl
|
$
|
49.26
|
$
|
49.24
|
$
|
49.27
|
$
|
49.26
|
$
|
49.26
|
Oil Basis
Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
|
|
915,000
|
|
1,380,000
|
|
2,295,000
|
|
|
Price per Bbl
|
|
|
|
|
$
|
(1.28)
|
$
|
(1.28)
|
$
|
(1.28)
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
630,000
|
|
637,000
|
|
644,000
|
|
644,000
|
|
2,555,000
|
|
|
Price per Bbl
|
$
|
(1.11)
|
$
|
(1.11)
|
$
|
(1.11)
|
$
|
(1.11)
|
$
|
(1.11)
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
810,000
|
|
819,000
|
|
828,000
|
|
828,000
|
|
3,285,000
|
|
|
Price per Bbl
|
$
|
(1.12)
|
$
|
(1.12)
|
$
|
(1.12)
|
$
|
(1.12)
|
$
|
(1.12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations
The following table sets forth summary
information concerning our production and operating data for the three and six
months ended
June 30, 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
|
|
Six Months Ended
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily
production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
113,220
|
|
|
89,418
|
|
|
113,409
|
|
|
89,214
|
|
|
Natural gas
(Mcf)
|
|
|
428,769
|
|
|
334,440
|
|
|
417,762
|
|
|
318,632
|
|
|
Total (Boe)
|
|
|
184,682
|
|
|
145,158
|
|
|
183,036
|
|
|
142,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
prices per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without
derivatives (Bbl)
|
|
$
|
44.75
|
|
$
|
41.68
|
|
$
|
46.91
|
|
$
|
35.80
|
|
|
Oil, with
derivatives (Bbl) (a)
|
|
$
|
51.60
|
|
$
|
61.46
|
|
$
|
51.86
|
|
$
|
61.18
|
|
|
Natural gas,
without derivatives (Mcf)
|
|
$
|
2.71
|
|
$
|
1.88
|
|
$
|
2.85
|
|
$
|
1.70
|
|
|
Natural gas,
with derivatives (Mcf) (a)
|
|
$
|
2.67
|
|
$
|
2.13
|
|
$
|
2.78
|
|
$
|
1.95
|
|
|
Total, without
derivatives (Boe)
|
|
$
|
33.73
|
|
$
|
30.00
|
|
$
|
35.57
|
|
$
|
26.25
|
|
|
Total, with
derivatives (Boe) (a)
|
|
$
|
37.84
|
|
$
|
42.78
|
|
$
|
38.48
|
|
$
|
42.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural
gas production
|
|
$
|
5.91
|
|
$
|
5.83
|
|
$
|
5.64
|
|
$
|
6.54
|
|
|
Production and
ad valorem taxes
|
|
$
|
2.62
|
|
$
|
2.51
|
|
$
|
2.77
|
|
$
|
2.15
|
|
|
Depreciation,
depletion and amortization
|
|
$
|
16.69
|
|
$
|
21.27
|
|
$
|
17.02
|
|
$
|
22.82
|
|
|
General and
administrative
|
|
$
|
3.70
|
|
$
|
4.04
|
|
$
|
3.54
|
|
$
|
4.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the effect of net cash receipts from (payments on)
derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash
receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
70
|
|
$
|
160
|
|
$
|
101
|
|
$
|
412
|
|
|
|
Natural gas
derivatives
|
|
|
(2)
|
|
|
8
|
|
|
(5)
|
|
|
15
|
|
|
|
|
Total
|
|
$
|
68
|
|
$
|
168
|
|
$
|
96
|
|
$
|
427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2017
Compared to Three Months Ended June 30, 2016
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$567 million for the three months ended
June 30, 2017
, an
increase of
$171 million (43
percent
) from $396 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 113,220
Bbl
for the three months ended
June 30, 2017
, an
increase
of 23,802
Bbl
(27
percent
) from 89,418
Bbl
for
2016
;
·
average realized oil price (excluding the effects of derivative
activities) was
$44.75
per Bbl during the three months ended
June 30, 2017
, an
increase of 7
percent
from
$41.68
per Bbl
during
2016
.
For the three
months ended June 30, 2017, our crude oil price differential relative to NYMEX
was $(3.57) per Bbl, or a realization of approximately 93 percent, as compared
to a crude oil price differential relative to NYMEX of $(3.88) 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 three
months ended June 30, 2017 and 2016, the average market basis differential
between WTI-Midland and WTI-Cushing was a price reduction of $
0.83
per
Bbl and $
0.17
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
June
30, 2017 as compared to 2016
primarily due to more production
transported through pipelines;
·
average daily natural gas production was 428,769
Mcf
for the three months ended
June 30, 2017
, an
increase
of 94,329
Mcf
(28
percent
) from 334,440
Mcf
for
2016
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$2.71
per Mcf during the
three months ended
June 30, 2017
, an increase of 44
percent
from
$1.88
per Mcf during
2016.
For the three months ended June 30, 2017 and 2016, we realized approximately 86
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
three months ended June 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
June 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 $21.99
per Bbl and $18.16 per Bbl during the three months ended June 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
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
|
$
|
96
|
|
$
|
5.66
|
|
$
|
73
|
|
$
|
5.47
|
Workover costs
|
|
|
4
|
|
|
0.25
|
|
|
4
|
|
|
0.36
|
|
|
Total oil and
natural gas production expenses
|
|
$
|
100
|
|
$
|
5.91
|
|
$
|
77
|
|
$
|
5.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $96 million ($5.66
per Boe) for the three months ended
June 30,
2017
, which was an increase of $23
million from $73 million ($5.47 per Boe) for the three months ended
June 30, 2016
.
The increase in lease operating expenses during the second quarter of 2017 as compared
to 2016 was primarily due to increased production associated with our wells
successfully drilled and completed in 2016 and 2017 and our acquisitions during
the second half of 2016 and first half of 2017.
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 second half of 2016
and first half 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
June 30,
2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
40
|
|
$
|
2.41
|
|
$
|
30
|
|
$
|
2.26
|
Ad valorem taxes
|
|
|
4
|
|
|
0.21
|
|
|
3
|
|
|
0.25
|
|
|
Total production
and ad valorem taxes
|
|
$
|
44
|
|
$
|
2.62
|
|
$
|
33
|
|
$
|
2.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $2.41
per Boe during the three months ended
June 30,
2017
, an increase of 7 percent
from $2.26 per Boe during
2016
. Over the same period, our revenue per Boe
(excluding the effects of derivatives) increased 12 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
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Geological and
geophysical
|
|
$
|
1
|
|
$
|
3
|
Exploratory dry
hole costs
|
|
|
-
|
|
|
7
|
Leasehold
abandonments
|
|
|
18
|
|
|
11
|
Other
|
|
|
1
|
|
|
-
|
|
Total
exploration and abandonments
|
|
$
|
20
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 three
months ended June 30, 2016 were primarily related to an uneconomic well in our
Delaware Basin area that was attempting to establish commercial production
through testing of multiple zones. We did not recognize any exploratory dry
hole costs during the three months ended June 30, 2017.
For the three months ended
June 30, 2017 and 2016
, we recorded approximately $18 million and $11 million,
respectively, of leasehold abandonments. For the three months ended
June 30, 2017
,
our abandonments were primarily related to non-contiguous acreage expiring in
our Southern Delaware Basin core area. For the three months ended
June 30, 2016
,
our abandonments were primarily related to acreage in our Northern Delaware
Basin core area where we identified (i) drilling locations which, based on
multiple factors, are no longer likely to be drilled, (ii) acreage 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 three months ended
June 30, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of
proved oil and natural gas properties
|
|
$
|
274
|
|
$
|
16.34
|
|
$
|
276
|
|
$
|
20.84
|
Depreciation of
other property and equipment
|
|
|
6
|
|
|
0.33
|
|
|
4
|
|
|
0.40
|
Amortization of
intangible assets - operating rights
|
|
|
1
|
|
|
0.02
|
|
|
1
|
|
|
0.03
|
|
Total depletion,
depreciation and amortization
|
|
$
|
281
|
|
$
|
16.69
|
|
$
|
281
|
|
$
|
21.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to
estimate proved oil reserves at period end
|
|
$
|
45.42
|
|
|
|
|
$
|
39.63
|
|
|
|
Natural gas price
used to estimate proved natural gas reserves at period end
|
|
$
|
3.01
|
|
|
|
|
$
|
2.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $274 million ($16.34 per Boe) for the three months ended June
30, 2017 and $276 million ($20.84 per Boe) for 2016. Depletion expense remained
relatively flat period over period due to offsetting factors of increased
production and lower expenses per Boe. The decrease in depletion expense per Boe
period over period was primarily due to (i) 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,
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 and (ii) lower drilling and completion costs per Boe
of proved developed reserves added.
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 June 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 $
45.26
per barrel of oil to a 2024 price of $
53.68
per barrel of oil. Similarly, natural gas prices ranged from a
2017 price of $
3.16
per Mcf of natural gas decreasing to a 2020
price of $
2.83
per Mcf of natural gas partially recovering to
a 2024 price of $
3.03
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 June 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 June 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 $
1.2
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 June 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 $
365
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
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative expenses
|
|
$
|
50
|
|
$
|
3.06
|
|
$
|
45
|
|
$
|
3.37
|
Less: Operating
fee reimbursements
|
|
|
(4)
|
|
|
(0.25)
|
|
|
(4)
|
|
|
(0.27)
|
Non-cash
stock-based compensation
|
|
|
14
|
|
|
0.89
|
|
|
12
|
|
|
0.94
|
|
Total general
and administrative expenses
|
|
$
|
60
|
|
$
|
3.70
|
|
$
|
53
|
|
$
|
4.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $60 million ($3.70 per Boe) for the three months ended
June 30, 2017
,
an increase of $7 million (13 percent) from $53 million ($4.04 per Boe) for
2016
. The
increase in cash general and administrative expenses was primarily a result of
increased compensation expense. The increase in non-cash stock-based compensation
was primarily due to an increase in forfeiture estimates during 2016.
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
$4
million for each of the
three months ended
June 30, 2017 and 2016
.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for
the three months ended
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Gain
(loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
199
|
|
$
|
(281)
|
|
Natural gas
derivatives
|
|
|
10
|
|
|
(17)
|
|
|
Total
|
|
$
|
209
|
|
$
|
(298)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table represents our net cash receipts from
(payments on) derivatives for the three months ended June 30, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash
receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
70
|
|
$
|
160
|
|
Natural gas
derivatives
|
|
|
(2)
|
|
|
8
|
|
|
Total
|
|
$
|
68
|
|
$
|
168
|
|
|
|
|
|
|
|
|
|
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
June 30, 2017 as compared to $
55
million
during 2016. T
he decrease was
primarily due to (i) approximately $11 million for the early redemption of
our $600 million 7.0% unsecured senior notes in September 2016 and (ii)
approximately $3 million, net, for the satisfaction and discharge of our $600
million 6.5% unsecured senior notes in December 2016 and our issuance of $600
million 4.375% unsecured senior notes in December 2016.
Loss on extinguishment of debt.
In
April 2017, we amended our credit facility. We recorded a loss on
extinguishment of debt of approximately $1 million for the three months ended
June 30, 2017, representing the proportional amount of unamortized deferred
loan costs associated with banks that are no longer in the credit facility
syndicate.
Income tax provisions.
We recorded income tax expense of
$93 million, which includes discrete income tax expense of approximately $2
million related to excess tax deficiencies on stock-based awards, which are
recorded in the income tax provision pursuant to Accounting Standards Update
(“ASU”) No. 2016-09, which was adopted on January 1, 2017, and an income tax benefit
of $158 million for the three months ended
June
30, 2017
and 2016, respectively. The
change in our income tax provision was primarily due to income before income
taxes during the three months ended
June 30,
2017, as compared to a loss before income taxes during 2016
. The effective income tax rates for the three
months ended
June 30, 2017
and 2016 were 37.8 percent and 37.3 percent,
respectively.
Six Months Ended June 30, 2017 Compared to Six Months Ended June
30, 2016
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$1,179 million for the six months ended
June 30, 2017
, an
increase of
$499 million (73
percent
) from $680 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 113,409
Bbl
for the six months ended
June 30, 2017
, an
increase
of 24,195
Bbl
(27
percent
) from 89,214
Bbl
for
2016
;
·
average realized oil price (excluding the effects of derivative
activities) was
$46.91
per Bbl during the six months ended
June 30, 2017
, an
increase of 31
percent
from
$35.80
per Bbl
during
2016
. For
the six months ended June 30, 2017, our crude oil price differential relative
to NYMEX was $(3.21) per Bbl, or a realization of approximately 94 percent, as
compared to a crude oil price differential relative to NYMEX of $(3.85) per
Bbl, or a realization of approximately 90 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 six
months ended June 30, 2017 and 2016, the average market basis differential
between WTI-Midland and WTI-Cushing was a price reduction of $0.09 per Bbl and
$0.01 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 six months ended
June 30, 2017 as compared to 2016 primarily due to (i) more production
transported through pipelines and (ii) successful renegotiation of fixed
deductions for existing production transported through pipelines;
·
average daily natural gas production was 417,762
Mcf
for the six months ended
June 30, 2017
, an
increase
of 99,130
Mcf
(31
percent
) from 318,632
Mcf
for
2016
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$2.85
per Mcf during the
six months ended
June
30, 2017
, an increase of 68
percent
from
$1.70
per Mcf during
2016
.
For the six months ended
June
30, 2017 and 2016
, we realized approximately 91 percent and 80 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
six
months ended
June 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
six
months ended June 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 $23.09 per Bbl and $16.32
per Bbl during the six months ended June 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 six months ended June
30, 2016 by approximately 2.4 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 six months ended June 30, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
|
$
|
178
|
|
$
|
5.36
|
|
$
|
159
|
|
$
|
6.15
|
Workover costs
|
|
|
9
|
|
|
0.28
|
|
|
10
|
|
|
0.39
|
|
|
Total oil and
natural gas production expenses
|
|
$
|
187
|
|
$
|
5.64
|
|
$
|
169
|
|
$
|
6.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $178 million
($5.36 per Boe) for the six months ended
June
30, 2017
, which was an increase of
$19 million from $159 million ($6.15 per Boe) for the six months ended
June 30, 2016
.
The increase in lease operating expenses during the first half of 2017 as
compared to 2016 was primarily due to increased production associated with our
wells successfully drilled and completed in 2016 and 2017, partially offset by
(i) implementation of operational cost efficiencies, including improved
infrastructure around salt water disposals and (ii) an overall decrease in the
cost of goods and services. The decrease in lease operating expenses per Boe
was primarily due to implementation of operational costs efficiencies partially
offset by higher expenses per Boe on properties associated with our recent
acquisitions in the second half of 2016 and first half of 2017.
Production and ad valorem taxes.
The following table provides the
components of our production and ad valorem tax expenses for the six months
ended
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
84
|
|
$
|
2.53
|
|
$
|
47
|
|
$
|
1.81
|
Ad valorem taxes
|
|
|
8
|
|
|
0.24
|
|
|
9
|
|
|
0.34
|
|
|
Total production
and ad valorem taxes
|
|
$
|
92
|
|
$
|
2.77
|
|
$
|
56
|
|
$
|
2.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $2.53
per Boe during the six months ended
June 30,
2017
, an increase of 40 percent
from $1.81 per Boe during
2016
. Over the same period, our revenue per Boe
(excluding the effects of derivatives) increased 36 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
six
months ended
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Geological and
geophysical
|
|
$
|
7
|
|
$
|
4
|
Exploratory dry
hole costs
|
|
|
-
|
|
|
7
|
Leasehold
abandonments
|
|
|
24
|
|
|
32
|
Other
|
|
|
4
|
|
|
1
|
|
Total
exploration and abandonments
|
|
$
|
35
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 six
months ended June 30, 2016 were primarily related to an uneconomic well in our
Delaware Basin area that was attempting to establish commercial production
through testing of multiple zones. We did not recognize any exploratory dry
hole costs during the six months ended June 30, 2017.
For the
six
months ended
June 30, 2017 and 2016, we recorded approximately $24 million and $32 million,
respectively, of leasehold abandonments. For the
six
months ended June 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 Midland Basin core areas in locations where we
have no future plans to drill. For the
six
months ended June 30, 2016, our abandonments were primarily related to (i)
drilling locations in our Delaware Basin and New Mexico Shelf areas which,
based on multiple factors, are no longer likely to be drilled, (ii) acreage in
our Delaware Basin and New Mexico Shelf 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 six months ended
June
30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of
proved oil and natural gas properties
|
|
$
|
551
|
|
$
|
16.65
|
|
$
|
580
|
|
$
|
22.39
|
Depreciation of
other property and equipment
|
|
|
12
|
|
|
0.35
|
|
|
10
|
|
|
0.40
|
Amortization of
intangible assets - operating rights
|
|
|
1
|
|
|
0.02
|
|
|
1
|
|
|
0.03
|
|
Total depletion,
depreciation and amortization
|
|
$
|
564
|
|
$
|
17.02
|
|
$
|
591
|
|
$
|
22.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
was $551 million ($16.65 per Boe) for the six months ended
June 30, 2017
,
a decrease of $29 million (5 percent) from $580 million ($22.39 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)
a non-cash impairment charge of approximately $1.5 billion recorded in the first
quarter of 2016, (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, 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) lower
drilling and completion costs per Boe of proved developed reserves added.
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 June 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 $
45.26
per barrel of oil to a 2024 price of $
53.68
per barrel of oil. Similarly, natural gas prices ranged from a
2017 price of $
3.16
per Mcf of natural gas decreasing to a 2020
price of $
2.83
per Mcf of natural gas partially recovering to
a 2024 price of $
3.03
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 six months ended June 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 June 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 $
1.2
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 June 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 $
365
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 six months ended
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions,
except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative expenses
|
|
$
|
98
|
|
$
|
2.99
|
|
$
|
87
|
|
$
|
3.35
|
Less: Operating
fee reimbursements
|
|
|
(8)
|
|
|
(0.24)
|
|
|
(8)
|
|
|
(0.31)
|
Non-cash
stock-based compensation
|
|
|
26
|
|
|
0.79
|
|
|
28
|
|
|
1.10
|
|
Total general
and administrative expenses
|
|
$
|
116
|
|
$
|
3.54
|
|
$
|
107
|
|
$
|
4.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $116 million ($3.54 per Boe) for the six months ended
June 30, 2017
,
an increase of $9 million (8 percent) from $107 million ($4.14 per Boe) for
2016
. The
increase in cash general and administrative expenses was primarily a result of
increased compensation expense. The decrease in non-cash stock-based
compensation was partially due to recording forfeitures as they occur rather
than recording forfeiture estimates per the adoption of ASU No. 2016-09 on
January 1, 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 of general and
administrative expenses in the consolidated statements of operations. We earned
reimbursements of approximately $8 million for each of the six months ended
June 30, 2017 and 2016.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for
the six months ended
June 30, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Gain
(loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
465
|
|
$
|
(209)
|
|
Natural gas
derivatives
|
|
|
30
|
|
|
(8)
|
|
|
Total
|
|
$
|
495
|
|
$
|
(217)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table represents our net cash receipts from
(payments on) derivatives for the six months ended June 30, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash
receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
101
|
|
$
|
412
|
|
Natural gas
derivatives
|
|
|
(5)
|
|
|
15
|
|
|
Total
|
|
$
|
96
|
|
$
|
427
|
|
|
|
|
|
|
|
|
|
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 $803
million. After direct transaction costs, we recorded a pre-tax gain on
disposition of assets of approximately $
655
million. Our net investment in ACC at the time of closing
was approximately $129 million.
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 $79 million for the six
months ended
June 30, 2017 as compared to $
109
million
during 2016. The decrease was primarily due to (i) approximately $21
million for the early redemption of our $600 million 7.0% unsecured senior
notes in September 2016 and (ii) approximately $5 million, net, for the
satisfaction and discharge of our $600 million 6.5% unsecured senior notes in
December 2016 and our issuance of $600 million 4.375% unsecured senior notes in
December 2016.
Loss on extinguishment of debt.
In
April 2017, we amended our credit facility. We recorded a loss on extinguishment
of debt of approximately $1 million for the six months ended June 30, 2017,
representing the proportional amount of unamortized deferred loan costs
associated with banks that are no longer in the credit facility syndicate.
Income tax provisions.
We recorded income tax expense of
$464 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 $752 million for the six months
ended June 30, 2017 and 2016, respectively. The change in our income tax
provision was primarily due to income before income taxes during the six months
ended June 30, 2017, as compared to a loss before income taxes during
2016. The effective income tax rates for the six months
ended June 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
six
months ended
June
30, 2017
and 2016 totaled $775 million
and $525 million, respectively. The increase was primarily due to our increased
drilling and completion activity level during the first half 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 is expected to continue focusing on extended
length lateral drilling and multi-well pad development. Our 2017 capital
budget, 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 (i) cash on hand, (ii) credit facility and
(iii) 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 six months ended
June 30, 2017
and 2016:
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|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Property
acquisition costs:
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|
|
|
|
|
|
|
Proved
|
|
$
|
139
|
|
$
|
256
|
|
Unproved
|
|
|
393
|
|
|
158
|
|
|
Total property
acquisition costs (a)
|
|
$
|
532
|
|
$
|
414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the property acquisition costs above are budgeted
unproved leasehold acreage acquisitions of $18 million and $23 million for
the six months ended June 30, 2017 and 2016, respectively. For the six months
ended June 30, 2017, our unbudgeted acquisitions are primarily comprised of
approximately $451 million of property acquisition costs related to our
Northern Delaware Basin acquisition. For the six months ended June 30, 2016,
our unbudgeted acquisitions are primarily comprised of approximately $374
million of property acquisition costs related to our Southern 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, 2016, the
changes in our contractual obligations are not material, other than our
derivative liability position, which decreased by $178 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 six months ended
June 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. Approximately 90
percent of capital will be directed to drilling and completion activity. Our
2017 capital program is expected to continue focusing on extended length
lateral drilling and multi-well pad development. Our 2017 capital budget, 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 (i) cash on hand, (ii) credit facility and (iii) 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 six months ended
June 30, 2017
and 2016:
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|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash
provided by operating activities
|
|
$
|
805
|
|
$
|
676
|
Net cash used in
investing activities
|
|
|
(168)
|
|
|
(412)
|
Net cash used in
financing activities
|
|
|
(28)
|
|
|
(12)
|
|
Net increase in
cash and cash equivalents
|
|
$
|
609
|
|
$
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Cash flow from operating activities.
The increase in operating cash flows during the
six
months ended
June
30, 2017
as compared to the same period in
2016 was
primarily due to (i) an increase in
oil and natural gas revenues of approximately $499 million, (ii) a decrease in
cash interest expense of approximately $30 million and (iii) approximately $8 million
of positive variances in operating assets and liabilities, partially offset by
(i)
approximately $
96
million
from settlements on derivatives during the six months ended June 30, 2017, as
compared to $
427
million from settlements on derivatives during the
comparable period in 2016,
(ii) approximately
$36 million increase in production tax expense, (iii) a decrease in operating
cash flow of approximately $22 million due to cash tax expense of approximately
$10 million for the
six
months ended June 30, 2017, as compared to a cash tax
benefit of approximately $12 million during the comparable period in
2016 and (iv)
approximately
$18 million increase in production expense.
Our net cash provided by operating activities included a
reduction of approximately $18
million and $26
million for the
six
months ended
June 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 six months ended
June 30, 2017
and 2016, we invested approximately $863 million and $651 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 six months ended
June 30, 2017,
as compared to $294 million during the comparable period of 2016.
Cash flow from financing
activities.
Net cash used in financing activities was approximately $28
million and $12 million for the
six
months ended June 30, 2017 and 2016, respectively. In
April 2017, we amended our credit facility to decrease our unused lender
commitments and increase our borrowing base.
At
June 30, 2017,
we had unused commitments on our credit
facility of $2.0 billion and a borrowing base of
$3.0
billion.
Advances on our amended and restated credit
facility bear interest, at our option, based on (i) the prime rate of JPMorgan
Chase Bank (“JPM Prime Rate”) (4.25 percent at
June
30, 2017)
or (ii) the London
Interbank Offered Rate (“LIBOR”). The credit facility’s interest rates vary,
with interest margins ranging from 125 to 225 basis points (LIBOR Rate Loans)
and 25 to 125 basis points (Alternate Base Rate Loans) per annum depending on
the utilization of the borrowing base. We pay commitment fees on the unused
portion of the available commitment ranging from 30.0 to 37.5 basis points per
annum, depending on utilization of the borrowing base. Subject to certain
restrictions, with respect to our public debt ratings, the collateral securing
the facility may be released.
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 sources of liquidity are cash on hand and available borrowing
capacity under our credit facility. At
June
30, 2017
, we had approximately $662
million
of cash on hand. In July 2017, we paid
approximately $540 million in cash as consideration for our Midland Basin
acquisition in addition to the $60 million of cash held in escrow at June 30,
2017.
During April 2017, we amended our credit
facility to extend the maturity date to May 9, 2022. Additionally, we increased
our borrowing base to $3.0 billion and decreased our commitments from bank
groups to $2.0 billion.
Upon a subsequent
redetermination, there
is no
assurance that our borrowing base will not be reduced, which could affect our
liquidity
.
We may from time to time seek to retire or
purchase our outstanding debt through cash purchases and/or exchanges for other
debt or equity securities, in open market purchases, privately negotiated
transactions or otherwise. Such repurchases or exchanges, if any, will depend
on prevailing market conditions, our liquidity requirements, contractual
restrictions and other factors. The amounts involved may be material.
Debt ratings
.
We receive debt credit ratings from S&P Global Ratings
(“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject
to regular reviews. S&P and Moody’s consider many factors in determining
our ratings including: the industry in which we operate, production growth
opportunities, liquidity, debt levels and asset and reserve mix. A reduction in
our debt ratings could negatively affect our ability to obtain additional
financing or the interest rate, fees and other terms associated with such
additional financing.
A downgrade in our credit ratings could negatively impact
our costs of capital and our ability to effectively execute aspects of our
strategy. Further, a downgrade in our credit ratings could 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. 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 June 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
June 30, 2017
was $10.7
billion, consisting of $0.7 billion of cash and
cash equivalents, debt of $
2.7 b
illion and
stockholders’ equity of $
8.7
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 19
percent and
26
percent
at
June 30,
2017
and December 31, 2016, respectively. Our ratio of current
assets to current liabilities was 1.70
to 1.0
at
June 30, 2017
as compared to 0.73 to 1.0 at December 31, 2016. Both our ratio of net
debt to net book capitalization and our ratio of current assets to current
liabilities were impacted subsequent to
June
30, 2017
by the Midland Basin acquisition in
July 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 six months ended
June 30, 2017
, we received
an average of $46.91
per Bbl of oil and $2.85
per Mcf of natural gas before consideration of
commodity derivative contracts compared to $35.80
per
Bbl of oil and $1.70
per Mcf of natural gas in
the six months ended
June 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
six
months ended June 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
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. The new guidance could result in more
acquisitions of oil and natural gas properties being accounted for as asset
acquisitions instead of business combinations.