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. Our legacy in the Permian Basin provides us a
deep understanding of operating and geological trends. We are also at the
forefront of applying new technologies, such as horizontal drilling and
enhanced completion techniques, throughout our three core operating areas: the
New Mexico Shelf, the Delaware Basin and the Midland Basin. In the New Mexico
Shelf, we primarily target the Yeso formation; in the Delaware Basin, we target
the Bone Spring formation (including the Avalon shale and the Bone Spring
sands) and the Wolfcamp shale formation; and in the Midland Basin, we target
the Wolfcamp and Spraberry formations.
Oil comprised 59 percent of our 623.5 MMBoe of estimated proved
reserves at December 31, 2015 and 61.6 percent of our 40.0 MMBoe of
production for the nine months ended
September
30, 2016
.
We seek to operate the wells in which we own an
interest, and we operated wells that accounted for 93 percent of our proved developed
producing PV-10 and 78.9 percent of our 7,636 gross wells at
December 31, 2015
. 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, 2016 and 2015
included the following highlights:
·
Net loss was $
1.3 b
illion
($(10.18)
per diluted share) as compared to
net income of $66.7
million ($0.56
per diluted share) for the first nine months of
2016 and 2015, respectively. The decrease was primarily due to:
•
$1.5
billion in impairments of long-lived assets during the nine months ended
September 30, 2016, primarily attributable to properties in our New Mexico
Shelf area, as compared to $7.6 million in non-cash impairment charges in
2015
;
•
$556.7 million change in (gain) loss on derivatives due to
a $175.7
million loss on derivatives during the nine months ended
September 30, 2016, as compared to a
$381.1
million gain on derivatives during the nine months ended September 30, 2015;
•
$304.0
million decrease in oil and natural gas revenues as a result of a
23 percent decrease in commodity price realizations per Boe
(excluding the effects of derivative activities), partially
offset by
a 2
percent increase in
production
;
•
$27.7
million loss on extinguishment of debt related to the early redemption of our
7.0% unsecured senior notes due 2021 (the “7.0% Notes”); and
•
$21.9
million increase in exploration and abandonment expense
primarily due to leasehold abandonments during the
nine
months ended
September 30,
2016
as compared to 2015;
partially offset by:
•
$807.7
million change in our income tax provision due to the loss before income taxes during
the nine months ended September 30, 2016, as compared to income before income
taxes during the nine months ended September 30, 2015;
•
$110.8
million increase in (gain) loss on disposition of assets, net primarily due to
our February 2016 asset divestiture;
•
$77.2
million decrease in oil and natural gas production expense, primarily due to a continued
identification and implementation of operational cost efficiencies, an overall
decrease in the cost of goods and services and lower production taxes as a
result of reduced revenues;
•
$19.1
million decrease in general and administrative expense, primarily due to a
general company-wide initiative to reduce general and administrative costs and
an increase in forfeiture estimates; and
•
$11.2
million decrease in depreciation, depletion and amortization expense, primarily
due to slightly lower depletion rate per Boe period over period.
·
Average daily sales volumes of
145,868
Boe
per day during the first nine months of 2016 were up slightly as compared to
143,020 Boe per day during the first nine months of 2015.
·
Net cash provided by operating activities decreased by
approximately $323.3 million to $437.3
million
for
the first nine months of 2016, as compared to $760.6
m
illion
in the first nine months of 2015, primarily due to a decrease in oil and
natural gas revenues and negative variances in working capital changes,
partially offset by decreased production expenses, changes related to cash
income taxes and decreased cash general and administrative costs.
·
Cash increased by approximately $930.4 million during the first
nine months of 2016 primarily as a result of proceeds from our August 2016
equity offering, our divestiture that closed in February 2016 and operating
cash flows, partially offset by the cash consideration paid related to our
asset acquisition that closed in March 2016, cash paid to redeem the 7.0% Notes
in September 2016 and capital expenditures for properties. In October 2016, we
paid approximately $1.2 billion in cash as partial consideration for the asset
acquisition of approximately 40,000 net acres in the Northern Midland Basin (the
“Reliance 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 8 and 16 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, 2016 and additional
derivative contracts entered into subsequent to September 30, 2016,
respectively.
Oil and natural gas prices have been subject to
significant fluctuations during the past several years. In general, the average
oil and natural gas prices were lower during the comparable year-to-date
periods of 2016 measured against 2015; however, the average natural gas prices
were slightly higher during the comparable quarterly periods ended September
30, 2016 measured against 2015. 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, 2016
and 2015, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
45.03
|
|
$
|
46.70
|
|
$
|
41.45
|
|
$
|
51.10
|
|
Natural gas (MMBtu)
|
|
$
|
2.80
|
|
$
|
2.73
|
|
$
|
2.35
|
|
$
|
2.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
48.99
|
|
$
|
56.96
|
|
$
|
51.23
|
|
$
|
61.43
|
|
|
Low
|
|
$
|
39.51
|
|
$
|
38.24
|
|
$
|
26.21
|
|
$
|
38.24
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
3.06
|
|
$
|
2.93
|
|
$
|
3.06
|
|
$
|
3.23
|
|
|
Low
|
|
$
|
2.55
|
|
$
|
2.52
|
|
$
|
1.64
|
|
$
|
2.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $51.60 and $44.07 per Bbl and $3.34 and
$2.73 per MMBtu, respectively, during the period from
October 1, 2016
to November 7, 2016. At November 7, 2016, the NYMEX oil price and NYMEX natural
gas price were $44.07 per Bbl and $2.77 per MMBtu, respectively.
Recent Events
Asset acquisition.
In
October 2016, we completed the Reliance Acquisition. As consideration for the
acquisition, we paid approximately $1.2 billion in cash and issued to the
seller approximately 3.9 million shares of common stock with an approximate
value of $0.5 billion.
Redemption of senior notes.
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,
as determined in accordance with the indenture governing the 7.0% Notes. We
also paid accrued and unpaid interest on the 7.0% Notes through September 19,
2016, the redemption date.
We recorded a loss on extinguishment of debt related to the
redemption of the 7.0% Notes of approximately $27.7 million for the three and nine
months ended September 30, 2016. This amount includes $21.0 million
associated with the make-whole premium paid for the early redemption of the
notes and approximately $6.7 million of unamortized deferred loan costs.
Common stock offering.
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. We used a portion of the
net proceeds to finance part of the cash portion of the purchase price for the
Reliance Acquisition and to fund part of the early redemption of the 7.0% Notes,
and the remainder for general corporate purposes.
2017 capital budget.
In November 2016, we announced our 2017 capital budget, excluding
acquisitions, of approximately $1.6 billion with expected capital spending to
range between $1.4 billion and $1.6 billion. Approximately 90 percent of
capital will be directed to drilling and completion activity. Our 2017 capital
program is expected to continue focusing on horizontal drilling in the Delaware
Basin and Midland Basin. Our 2017 capital budget, based on our current
expectations of commodity prices and costs, is expected to be within our cash
flows. Our budget could change depending on numerous factors, including
commodity prices, leverage metrics and industry conditions.
Derivative
Financial Instruments
Derivative financial instrument exposure.
At
September 30, 2016
, the fair value of our financial derivatives was a net
asset
of $
61.8
million. All of our counterparties to these financial
derivatives are parties or affiliates of parties to our credit facility and
have their outstanding debt commitments and derivative exposures collateralized
pursuant to our credit facility. 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. 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 or
its affiliates.
New commodity derivative contracts.
After September 30, 2016, 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 Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,021,470
|
|
989,280
|
|
866,970
|
|
785,580
|
|
3,663,300
|
|
|
Price per Bbl
|
$
|
52.64
|
$
|
52.76
|
$
|
52.90
|
$
|
52.95
|
$
|
52.80
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
665,190
|
|
783,340
|
|
710,310
|
|
648,700
|
|
2,807,540
|
|
|
Price per Bbl
|
$
|
54.46
|
$
|
54.37
|
$
|
54.39
|
$
|
54.42
|
$
|
54.41
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
450,000
|
|
455,000
|
|
644,000
|
|
644,000
|
|
2,193,000
|
|
|
Price per Bbl
|
$
|
(0.60)
|
$
|
(0.60)
|
$
|
(0.60)
|
$
|
(0.60)
|
$
|
(0.60)
|
Natural Gas Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMbtu)
|
|
1,800,000
|
|
1,820,000
|
|
1,840,000
|
|
1,840,000
|
|
7,300,000
|
|
|
Price per MMbtu
|
$
|
3.01
|
$
|
3.01
|
$
|
3.01
|
$
|
3.01
|
$
|
3.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2016
and 2015. Because of normal production
declines, increased or decreased drilling activities, fluctuations in commodity
prices and the effects of acquisitions or divestitures, the historical
information presented below should not be interpreted as being indicative of
future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
8,383
|
|
|
8,945
|
|
|
24,620
|
|
|
26,042
|
|
|
Natural gas (MMcf)
|
|
|
34,096
|
|
|
28,746
|
|
|
92,087
|
|
|
78,014
|
|
|
Total (MBoe)
|
|
|
14,066
|
|
|
13,736
|
|
|
39,968
|
|
|
39,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
91,120
|
|
|
97,228
|
|
|
89,854
|
|
|
95,392
|
|
|
Natural gas (Mcf)
|
|
|
370,609
|
|
|
312,457
|
|
|
336,084
|
|
|
285,766
|
|
|
Total (Boe)
|
|
|
152,888
|
|
|
149,304
|
|
|
145,868
|
|
|
143,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
41.52
|
|
$
|
43.82
|
|
$
|
37.75
|
|
$
|
46.56
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
59.87
|
|
$
|
61.23
|
|
$
|
60.74
|
|
$
|
62.65
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
2.42
|
|
$
|
2.49
|
|
$
|
1.97
|
|
$
|
2.59
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
2.46
|
|
$
|
2.78
|
|
$
|
2.14
|
|
$
|
2.90
|
|
|
Total, without derivatives (Boe)
|
|
$
|
30.61
|
|
$
|
33.74
|
|
$
|
27.78
|
|
$
|
36.23
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
41.65
|
|
$
|
45.68
|
|
$
|
42.35
|
|
$
|
47.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
4.98
|
|
$
|
7.23
|
|
$
|
6.00
|
|
$
|
7.38
|
|
|
Oil and natural gas taxes
|
|
$
|
2.38
|
|
$
|
2.83
|
|
$
|
2.23
|
|
$
|
3.02
|
|
|
Depreciation, depletion and amortization
|
|
$
|
21.27
|
|
$
|
23.99
|
|
$
|
22.27
|
|
$
|
23.09
|
|
|
General and administrative
|
|
$
|
3.80
|
|
$
|
4.37
|
|
$
|
4.02
|
|
$
|
4.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the
effect of net cash receipts from derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
(in thousands)
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
153,823
|
|
$
|
155,732
|
|
$
|
565,918
|
|
$
|
419,047
|
|
|
|
Natural gas derivatives
|
|
|
1,541
|
|
|
8,301
|
|
|
16,125
|
|
|
24,394
|
|
|
|
|
Total
|
|
$
|
155,364
|
|
$
|
164,033
|
|
$
|
582,043
|
|
$
|
443,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation
of average prices with derivatives is a result of including the net cash
receipts from 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, 2016 Compared to Three Months Ended September 30,
2015
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$430.5 million for the three months ended
September 30,
2016
, a decrease of
$33.0 million (7
percent
) from $463.5 million for
2015
.
This decrease was primarily due to the decrease in realized oil and natural gas
prices and a decrease in oil production partially offset by an increase in
natural gas production. Specific factors affecting oil and natural gas revenues
include the following:
·
total oil production was 8,383
MBbl
for the
three months ended
September 30, 2016
, a
decrease
of 562
MBbl
(6.3
percent
) from 8,945
MBbl
for
2015
;
·
average realized oil price (excluding the effects of derivative
activities) was
$41.52
per Bbl during the three months ended
September 30,
2016
, a decrease of 5.2
percent
from
$43.82
per Bbl during
2015
.
For the three
months ended September 30, 2016, our crude oil price differential relative to
NYMEX was $(3.51) per Bbl, or a realization of approximately 92.2 percent, as
compared to a crude oil price differential relative to NYMEX of $(2.88) per
Bbl, or a realization of approximately 93.8 percent, for 2015. We incur fixed
deductions from the posted Midland oil price based on the location of our oil
within the Permian Basin. Additionally, the basis differential between the
location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for
our oil directly impacts our realized oil price. For the three months ended
September 30, 2016 and 2015, the average market basis differential between
WTI-Midland and WTI-Cushing was a price reduction of $
(0.31)
per
Bbl and benefit of $
0.72
per
Bbl, respectively;
·
total natural gas production was 34,096
MMcf
for the three months ended
September 30,
2016
, an
increase
of 5,350
MMcf
(18.6
percent
) from 28,746
MMcf
for
2015
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$2.42
per Mcf during the
three months ended
September 30, 2016
, a decrease of 2.8
percent
from
$2.49
per Mcf during
2015.
For the three months ended September 30, 2016 and 2015, we realized
approximately 86.4 percent and 91.2 percent, respectively, of the average NYMEX
natural gas prices for the respective periods. Factors contributing to the
decrease in our realized gas price (excluding the effects of derivatives) as a
percentage of NYMEX during the three months ended September 30, 2016 as
compared to 2015 include (i) a decrease in the posted regional natural gas
prices on which we are paid while the NYMEX natural gas price increased and
(ii) increased deductions and fees from the natural gas price on which we are
paid, comparatively, partially offset by the average Mont Belvieu price of
$17.82 per Bbl compared to $16.56 per Bbl during the three months ended
September 30, 2016 and 2015, respectively.
Production expenses.
The following table provides the
components of our total oil and natural gas production costs for the three
months ended
September 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
65,173
|
|
$
|
4.63
|
|
$
|
90,232
|
|
$
|
6.57
|
Workover costs
|
|
|
4,908
|
|
|
0.35
|
|
|
9,033
|
|
|
0.66
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
1,886
|
|
|
0.13
|
|
|
5,817
|
|
|
0.42
|
|
Production
|
|
|
31,608
|
|
|
2.25
|
|
|
33,043
|
|
|
2.41
|
|
|
Total oil and natural gas production expenses
|
|
$
|
103,575
|
|
$
|
7.36
|
|
$
|
138,125
|
|
$
|
10.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have
some control over lease operating expenses and workover costs on properties we
operate, but production and ad valorem taxes are related to commodity prices.
Lease operating expenses were $65.2 million ($4.63
per Boe) for the three months ended
September
30, 2016
, which was a decrease of
$25.0 million from $90.2 million ($6.57 per Boe) for the three months ended
September 30, 2015
. The decrease in lease operating expenses during the third
quarter of 2016 as compared to 2015 was primarily due to (i)
continued identification and implementation of operational
cost efficiencies,
(ii) an overall
decrease in the cost of goods and services, including salt water disposal costs
and (iii) credits from interim period estimates of the cost for goods and
services
.
The decrease in lease operating expenses per Boe was primarily due
to
the reduction in lease
operating expenses noted above coupled with a slight increase in production
period over period
.
Workover expenses were approximately
$4.9 million and $9.0 million for the three months ended
September 30, 2016
and 2015, respectively. The decrease was primarily related to
less overall activity during the third quarter of 2016 as compared to 2015.
Production taxes per unit of production were $2.25
per Boe during the three months ended
September
30, 2016
, a decrease of 7 percent
from $2.41 per Boe during
2015
. Over the same period, our revenue per Boe
prices (excluding the effects of derivatives) decreased 9 percent. The decrease
in production taxes per unit of production was directly related to the decrease
in oil and natural gas prices.
Exploration
and abandonments expense.
The following table provides a breakdown of our exploration and abandonments
expense for the three months ended
September
30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
September 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
2,043
|
|
$
|
827
|
Exploratory dry hole costs
|
|
|
93
|
|
|
224
|
Leasehold abandonments
|
|
|
8,000
|
|
|
13,283
|
Other
|
|
|
208
|
|
|
457
|
|
Total exploration and abandonments
|
|
$
|
10,344
|
|
$
|
14,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2016
, we recorded approximately $8.0 million of leasehold
abandonments primarily related to expiring acreage. For the three months ended
September 30, 2015,
our abandonments were primarily related to non-core acreage in our
Delaware Basin area.
Depreciation, depletion and amortization
expense.
The following table provides components of our
depreciation, depletion and amortization expense for the three months ended
September 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
293,753
|
|
$
|
20.88
|
|
$
|
324,517
|
|
$
|
23.63
|
Depreciation of other property and equipment
|
|
|
5,091
|
|
|
0.36
|
|
|
4,585
|
|
|
0.33
|
Amortization of intangible assets - operating rights
|
|
|
365
|
|
|
0.03
|
|
|
365
|
|
|
0.03
|
|
Total depletion, depreciation and amortization
|
|
$
|
299,209
|
|
$
|
21.27
|
|
$
|
329,467
|
|
$
|
23.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period
end
|
|
$
|
38.17
|
|
|
|
|
$
|
55.73
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end
|
|
$
|
2.28
|
|
|
|
|
$
|
3.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $293.8 million ($20.88 per Boe) for the three months ended
September 30, 2016, a decrease of $30.7 million (9 percent) from $324.5
million ($23.63 per Boe) for 2015. The decrease in depletion expense was primarily
due to a lower depletion rate per Boe period over period partially offset by a
slight increase in production. The decrease in depletion expense per Boe period
over period was primarily due to
a
non-cash impairment charge of approximately $1.5 billion recorded in the first
quarter of 2016, partially offset by an overall decrease in proved reserves period
over period caused by (i) lower commodity prices, partially offset by capital
cost reductions and (ii) reclassification of proved reserves to unproven that
are no longer expected to be developed within the five years of their initial
recording as required by SEC rules.
The increase in depreciation expense was primarily
associated with additional other property and equipment related to buildings
and other items.
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 calculate the expected 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, 2016, o
ur estimates of commodity prices for purposes
of determining undiscounted future cash flows are based on the NYMEX strip, which
ranged from a 2016 price of $48.53 per barrel of oil and $3.02 per Mcf of natural
gas to a 2023 price of $58.82 per barrel of oil and $3.23 per Mcf of natural
gas. Commodity prices for this purpose were held flat after 2023.
We calculate the estimated 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.
As a result of the carrying amount of certain
of our long-lived assets and their integrated assets being less than their
expected undiscounted future net cash flows, we recognized a non-cash charge
against earnings of approximately $7.6 million during the three months ended September
30, 2015, which was primarily attributable to properties in our eastern Midland
Basin area. The non-cash charge represented the amount by which the carrying
amount exceeded the estimated fair value of the assets. We did not recognize an
impairment charge during the three months ended September 30, 2016.
It is reasonably possible that the estimate of
undiscounted future net cash flows 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) changes in income and expenses from integrated assets. If the oil and
natural gas prices used in this analysis would have been approximately 10 percent
lower as of September 30, 2016 with no other changes in capital costs,
operating costs, price differentials, or reserve volumes, no impairment would
be indicated.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the three months ended
September 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
45,074
|
|
$
|
3.20
|
|
$
|
49,354
|
|
$
|
3.59
|
Less: Operating fee reimbursements
|
|
|
(6,297)
|
|
|
(0.45)
|
|
|
(5,629)
|
|
|
(0.41)
|
Non-cash stock-based compensation
|
|
|
14,728
|
|
|
1.05
|
|
|
16,327
|
|
|
1.19
|
|
Total general and administrative expenses
|
|
$
|
53,505
|
|
$
|
3.80
|
|
$
|
60,052
|
|
$
|
4.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $53.5 million ($3.80 per Boe) for the three months ended
September 30, 2016
, a decrease of $6.6 million (11 percent) from $60.1 million
($4.37 per Boe) for
2015
. The decrease in cash general and
administrative expenses was primarily a result of a general company-wide
initiative to reduce general and administrative costs, while the decrease in
non-cash stock-based compensation was primarily due to an increase in
forfeiture estimates.
The decrease
in total general and administrative expenses per Boe was primarily due to the
reduction in general and administrative costs noted above coupled with a slight
increase in production period over period.
As the operator of certain oil and natural gas properties
in which we own an interest, we earn overhead reimbursements during the
drilling and production phases of the property.
This
reimbursement is reflected as a reduction of general and administrative
expenses in the consolidated statements of operations.
Gain on derivatives.
The following table sets forth the gain on derivatives for the
three months ended
September 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
September 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Gain on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
35,691
|
|
$
|
404,012
|
|
Natural gas derivatives
|
|
|
5,495
|
|
|
9,118
|
|
|
Total
|
|
$
|
41,186
|
|
$
|
413,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from derivatives for the three months ended
September 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
September 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
153,823
|
|
$
|
155,732
|
|
Natural gas derivatives
|
|
|
1,541
|
|
|
8,301
|
|
|
Total
|
|
$
|
155,364
|
|
$
|
164,033
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in
value of our derivatives portfolio between periods, 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 future
commodity price outlook increases between measurement periods, we will have
mark-to-market losses.
Interest expense.
The following table sets forth interest
expense, weighted average interest rates and weighted average debt balances for
the three months ended September 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
September 30,
|
(dollars in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
52,994
|
|
$
|
53,752
|
Capitalized interest
|
|
|
-
|
|
|
1,437
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
52,994
|
|
$
|
55,189
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
-
|
|
|
2.2%
|
Weighted average interest rate - senior notes
|
|
|
5.9%
|
|
|
5.9%
|
|
Total weighted average interest rate
|
|
|
5.9%
|
|
|
5.6%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
-
|
|
$
|
341,667
|
Weighted average senior notes balance
|
|
|
3,276,667
|
|
|
3,350,000
|
|
Total weighted average debt balance
|
|
$
|
3,276,667
|
|
$
|
3,691,667
|
|
|
|
|
|
|
|
|
The decrease in the weighted average debt balance
for the three months ended September 30, 2016 as compared to 2015 was
due to the repayment of our credit facility using a portion of the
proceeds from our October 2015 equity offering and, to
a
lesser extent, the early redemption of the $600 million outstanding principal
amount of our 7.0% Notes. The decrease in interest expense was
due to a decrease in the weighted average debt balance.
Loss on extinguishment of debt.
We recorded a
loss on extinguishment of debt of $27.7 million for the
three months ended September 30, 2016. This amount includes $21.0 million
associated with the make-whole premium paid for the early redemption of the
7.0% Notes and approximately $6.7 million of unamortized deferred loan costs.
Income tax provisions.
We recorded an income tax benefit
of $30.4 million and income tax expense of $91.9 million for the three months
ended
September 30, 2016
and 2015, respectively. The change in our
income tax provision was primarily due to the decrease in income before income
taxes. The effective income tax rates for the three months ended
September 30, 2016
and 2015 were 37.3 percent and 33.8 percent,
respectively.
Nine
Months Ended September 30, 2016 Compared to Nine Months Ended September 30,
2015
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$1,110.4 million for the nine months ended
September 30,
2016
, a decrease of
$304.0 million (21
percent
) from $1,414.4 million for
2015
. This
decrease was primarily due to the decrease in realized oil and natural gas
prices. Specific factors affecting oil and natural gas revenues include the
following:
·
total oil production was 24,620
MBbl
for the nine months ended
September 30, 2016
, a
decrease
of 1,422
MBbl
(5.5
percent
) from 26,042
MBbl
for
2015
;
·
average realized oil price (excluding the effects of derivative
activities) was
$37.75
per Bbl during the nine months ended
September 30,
2016
, a decrease of 18.9
percent
from
$46.56
per Bbl during
2015
. For the nine months ended
September 30, 2016, our crude oil price differential relative to NYMEX was
$(3.70) per Bbl, or a realization of approximately 91.1 percent, as compared to
a crude oil price differential relative to NYMEX of $(4.54) per Bbl, or a
realization of approximately 91.1 percent, for 2015. We incur fixed deductions
from the posted Midland oil price based on the location of our oil within the
Permian Basin. Additionally, the basis differential between the location of
Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil directly
impacts our realized oil price. For the nine months ended September 30, 2016
and 2015, the average market basis differential between WTI-Midland and
WTI-Cushing was a price reduction of $0.11 per Bbl and $0.62 per Bbl,
respectively;
·
total natural gas production was 92,087
MMcf
for the nine months ended
September 30,
2016
, an
increase
of 14,073
MMcf
(18.0
percent
) from 78,014
MMcf
for
2015
; and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$1.97
per Mcf during the
nine months ended
September
30, 2016
, a decrease of 23.9
percent
from
$2.59
per Mcf during
2015
.
For the nine months ended
September 30, 2016 and 2015
, we
realized approximately 83.8 percent and 93.8 percent, respectively, of the
average NYMEX natural gas prices for the respective periods.
Factors
contributing to the decrease in our realized gas price (excluding the effects
of derivatives) as a percentage of NYMEX during the nine months ended September
30, 2016 as compared to 2015 were (i) a decrease in the posted regional natural
gas prices on which we are paid while the NYMEX natural gas price decreased at
a lesser rate, (ii) increased deductions and fees from the regional natural gas
price, comparatively and (iii) the average Mont Belvieu price of $16.82 per Bbl
compared to $18.18 per Bbl during the nine months ended September 30, 2016 and 2015,
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.
Production expenses.
The following table provides the
components of our total oil and natural gas production costs for the nine
months ended September 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
224,507
|
|
$
|
5.62
|
|
$
|
265,949
|
|
$
|
6.81
|
Workover costs
|
|
|
15,081
|
|
|
0.38
|
|
|
22,130
|
|
|
0.57
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
10,766
|
|
|
0.27
|
|
|
17,380
|
|
|
0.45
|
|
Production
|
|
|
78,402
|
|
|
1.96
|
|
|
100,466
|
|
|
2.57
|
|
|
Total oil and natural gas production expenses
|
|
$
|
328,756
|
|
$
|
8.23
|
|
$
|
405,925
|
|
$
|
10.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have
some control over lease operating expenses and workover costs on properties we
operate, but production and ad valorem taxes are related to commodity prices.
Lease operating expenses were $224.5 million
($5.62 per Boe) for the nine months ended
September
30, 2016
, which was a decrease of
$41.4 million from $265.9 million ($6.81 per Boe) for the nine months ended
September 30, 2015
. The decrease in lease operating expenses during the nine months
ended
September 30, 2016
as compared to 2015 was primarily due to (i)
continued identification and implementation of operational
cost efficiencies
and (ii) an
overall decrease in the cost of goods and services. The decrease in lease
operating expenses per Boe was primarily due to the reduction in lease
operating expenses noted above coupled with a slight increase in production period
over period.
Workover expenses were approximately
$15.1 million and $22.1 million for the nine months ended September 30,
2016 and 2015, respectively. The decrease was primarily related to less overall
activity during 2016 as compared to 2015.
Production taxes per unit of production were
$1.96 per Boe during the nine months ended
September
30, 2016
, a decrease of 24 percent
from $2.57 per Boe during
2015
. The decrease was directly related to the
decrease in oil and natural gas prices. Over the same period, our revenue per
Boe prices (excluding the effects of derivatives) decreased 23 percent.
Exploration
and abandonments expense.
The following table provides a breakdown of our exploration and abandonments
expense for the
nine
months ended
September
30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
6,545
|
|
$
|
4,313
|
Exploratory dry hole costs
|
|
|
6,794
|
|
|
9,213
|
Leasehold abandonments
|
|
|
39,849
|
|
|
16,646
|
Other
|
|
|
1,290
|
|
|
2,394
|
|
Total exploration and abandonments
|
|
$
|
54,478
|
|
$
|
32,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 (i) an
uneconomic well in our Delaware Basin area that was attempting to establish commercial
production through testing of multiple zones. Our exploratory dry hole costs
during the
nine
months ended September 30, 2015 were primarily
related to (i) an uneconomic well in our Delaware Basin area that was
attempting to establish production in a zone not previously producing in the
general area and (ii) expensing an unsuccessful well, which we did not operate,
that was located in our New Mexico Shelf area.
For the
nine
months ended
September 30, 2016 and 2015, we recorded approximately $39.8 million and
$16.6 million, respectively, of leasehold abandonments.
For the nine months ended
September 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. For the
nine
months ended September 30, 2015, our abandonments were
primarily related to non-core acreage in our Delaware Basin area.
Depreciation, depletion and amortization
expense.
The
following table provides components of our depreciation, depletion and
amortization expense for the nine months ended
September
30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
873,797
|
|
$
|
21.86
|
|
$
|
886,609
|
|
$
|
22.71
|
Depreciation of other property and equipment
|
|
|
15,364
|
|
|
0.38
|
|
|
13,769
|
|
|
0.35
|
Amortization of intangible assets - operating rights
|
|
|
1,096
|
|
|
0.03
|
|
|
1,096
|
|
|
0.03
|
|
Total depletion, depreciation and amortization
|
|
$
|
890,257
|
|
$
|
22.27
|
|
$
|
901,474
|
|
$
|
23.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
was $873.8 million ($21.86 per Boe) for the nine months ended
September 30, 2016
, a decrease of $12.8 million (1 percent) from $886.6 million
($22.71 per Boe) for
2015
. The decrease in depletion expense was
primarily due to a slightly lower depletion rate per Boe period over period
partially offset by a slight increase in production. The decrease in depletion
expense per Boe period over period was primarily due to a non-cash impairment
charge of approximately $1.5 billion recorded in the first quarter of 2016,
partially offset by an overall decrease in proved reserves period over period caused
by (i) lower commodity prices, partially offset by capital cost reductions and
(ii) reclassification of proved reserves to unproven that are no longer
expected to be developed within the five years of their initial recording as
required by SEC rules.
The increase in depreciation expense was
primarily associated with additional other property and equipment related to
buildings and other items.
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 calculate the expected 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, 2016, o
ur estimates of commodity prices for purposes
of determining undiscounted future cash flows are based on the NYMEX strip,
which ranged from a 2016 price of $48.53 per barrel of oil and $3.02 per Mcf of
natural gas to a 2023 price of $58.82 per barrel of oil and $3.23 per Mcf of natural
gas. Commodity prices for this purpose were held flat after 2023.
We calculate the estimated 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 area exceeded the expected
undiscounted future net cash flows resulting in a non-cash charge against
earnings of approximately $1.5 billion. As a result of the carrying amount of
certain of our long-lived assets and their integrated assets being less than
their expected undiscounted future net cash flows, we recognized a non-cash
charge against earnings of approximately $7.6 million during the nine months
ended
September 30, 2015
, which was primarily attributable to
properties in our eastern Midland Basin area. Both of these non-cash charges
represented the amount by which the carrying amount exceeded the estimated fair
value of the assets.
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. If the oil and natural gas prices used in
this analysis would have been approximately 10 percent lower as of
September 30, 2016
with no other changes in capital costs, operating costs, price
differentials, or reserve volumes, no impairment would be indicated.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the nine months ended
September 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
136,225
|
|
$
|
3.41
|
|
$
|
150,871
|
|
$
|
3.86
|
Less: Operating fee reimbursements
|
|
|
(18,769)
|
|
|
(0.47)
|
|
|
(18,367)
|
|
|
(0.47)
|
Non-cash stock-based compensation
|
|
|
43,201
|
|
|
1.08
|
|
|
47,272
|
|
|
1.21
|
|
Total general and administrative expenses
|
|
$
|
160,657
|
|
$
|
4.02
|
|
$
|
179,776
|
|
$
|
4.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $160.7 million ($4.02 per Boe) for the nine months ended
September 30, 2016
, a decrease of $19.1 million (11 percent) from $179.8 million
($4.60 per Boe) for
2015
. The decrease in cash general and
administrative expenses was primarily a result of a general company-wide
initiative to reduce general and administrative costs, while the decrease in
non-cash stock-based compensation was primarily due to an increase in
forfeiture estimates.
The decrease
in total general and administrative expenses per Boe was primarily due to the
reduction in general and administrative costs noted above coupled with a slight
increase in production period over period.
As the operator of certain oil and natural gas properties
in which we own an interest, we earn overhead reimbursements during the
drilling and production phases of the property.
This
reimbursement is reflected as a reduction of general and administrative
expenses in the consolidated statements of operations.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for
the nine months ended
September 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(172,974)
|
|
$
|
367,743
|
|
Natural gas derivatives
|
|
|
(2,692)
|
|
|
13,328
|
|
|
Total
|
|
$
|
(175,666)
|
|
$
|
381,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from derivatives for the nine months ended
September 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
565,918
|
|
$
|
419,047
|
|
Natural gas derivatives
|
|
|
16,125
|
|
|
24,394
|
|
|
Total
|
|
$
|
582,043
|
|
$
|
443,441
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in
value of our derivatives portfolio between periods, 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 future
commodity price outlook increases between measurement periods, we will have
mark-to-market losses.
Gain on disposition of assets, net.
In February 2016, we sold certain assets in the northern
Delaware Basin for proceeds of approximately $292.0 million, and recognized a
pre-tax gain of approximately $110.1 million.
Interest expense.
The following table sets forth interest expense, weighted average
interest rates and weighted average debt balances for the nine months ended
September 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
(dollars in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
161,634
|
|
$
|
160,803
|
Capitalized interest
|
|
|
252
|
|
|
3,826
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
161,886
|
|
$
|
164,629
|
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
-
|
|
|
2.4%
|
Weighted average interest rate - senior notes
|
|
|
5.9%
|
|
|
5.9%
|
|
Total weighted average interest rate
|
|
|
5.9%
|
|
|
5.7%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
-
|
|
$
|
250,505
|
Weighted average senior notes balance
|
|
|
3,325,556
|
|
|
3,350,000
|
|
Total weighted average debt balance
|
|
$
|
3,325,556
|
|
$
|
3,600,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in the weighted average debt
balance for the nine months ended September 30, 2016
as compared to 2015 was due to the
repayment of our credit facility using a portion of the proceeds from our
October 2015 equity offering and, to a lesser extent, the early redemption of
the $600 million outstanding principal amount of our 7.0% Notes. The increase in
interest expense was due to a reduction in capitalized interest period
over period, partially offset by an overall decrease in the weighted average
debt balance.
Loss on extinguishment of debt.
We
recorded a loss on extinguishment of debt of $27.7 million for the nine months
ended September 30, 2016. This amount includes $21.0 million associated
with the make-whole premium paid for the early redemption of the 7.0% Notes and
approximately $6.7 million of unamortized deferred loan costs.
Income tax provisions.
We recorded an income tax benefit of
$782.4 million and income tax expense of $25.3 million for the nine months
ended
September 30, 2016
and 2015, respectively. The change in our
income tax provision was primarily due to the decrease in income before income
taxes. The effective income tax rates for the nine months ended
September 30, 2016
and 2015 were 36.9 percent and 27.5 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 ventures 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 and asset retirement obligations, during the
nine
months ended
September 30, 2016
and 2015 totaled $798.8 million and $1.6 billion, respectively. The
decrease was primarily due to our reduced drilling and completion activity
level during the first nine months of 2016 as compared to 2015. The decrease is
primarily related to our intent to adjust our capital spending to be within our
cash flow, excluding unbudgeted acquisitions. The primary reason for the
differences in the costs incurred and cash flow expenditures was our issuance
of approximately 2.2 million shares of common stock related to our March 2016
acquisition and timing of payments. The 2016 expenditures were primarily funded
in part from (i) cash flows from operations, (ii) proceeds from our February
2016 divestiture and (iii) our issuance of approximately 2.2 million shares of
common stock related to our March 2016 acquisition.
2016 capital budget
.
Based on current commodity prices and costs, we
expect our capital plan for 2016, excluding acquisitions, to be approximately
$1.3 billion, within our guidance range of $1.1 billion to $1.3 billion, and
intend to manage our capital spending to be within our cash flows.
2017 capital budget.
In November 2016, we announced our 2017 capital
budget, excluding acquisitions, of approximately $1.6 billion with expected
capital spending to range between $1.4 billion and $1.6 billion. Approximately
90 percent of capital will be directed to drilling and completion activity. Our
2017 capital program is expected to continue focusing on horizontal drilling in
the Delaware Basin and Midland Basin. 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 nine months ended
September 30, 2016
and
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
256,655
|
|
$
|
58,879
|
|
Unproved
|
|
|
172,486
|
|
|
195,971
|
|
|
Total property acquisition costs (a)
|
|
$
|
429,141
|
|
$
|
254,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the property
acquisition costs above are budgeted unproved leasehold acreage acquisitions
of $26.0 million and $63.1 million for the nine months ended September 30,
2016 and 2015, respectively. For the nine months ended September 30, 2016,
our unbudgeted acquisitions are primarily comprised of approximately $374.9
million of property acquisition costs related to our March 2016 acquisition.
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Contractual obligations.
Our contractual obligations include long-term
debt, cash interest expense on debt, operating lease obligations, purchase
obligations, employment agreements with officers, derivative liabilities,
investment contributions
related to Alpha Crude
Connecter, LLC, our other midstream entity in the southern Delaware Basin and
other obligations. With the exception of the early redemption of our 7.0%
Notes, since December 31, 2015, the changes in our contractual obligations are
not material. See Note 9 of the Condensed Notes to Consolidated Financial
Statements included in “Item 1. Consolidated Financial Statements (Unaudited)”
for additional information regarding our long-term debt and “Item 3.
Quantitative and Qualitative Disclosures About Market Risk” for information
regarding the interest on our long-term debt and information on changes in the
fair value of our open derivative obligations during the nine months ended
September 30, 2016
.
Off-balance sheet arrangements.
Currently, we do not have any material
off-balance sheet arrangements.
Capital resources.
Historically, our primary sources of
liquidity have been cash flows generated from (i) operating activities and
cash settlements received from derivatives
, (ii) borrowings under our credit facility, (iii) proceeds
from bond and equity offerings and (iv) proceeds from the sale of assets.
During the remainder of 2016, our intent is to manage our capital spending to
be within our cash flows, excluding acquisitions. Based on current commodity
prices and costs, our capital plan for the full year 2016, excluding
acquisitions, is estimated to be approximately $1.3 billion. However, if
we were to outspend our cash flows, we believe we could use our (i) cash on
hand, (ii) credit facility and (iii) other financing sources to fund any cash
flow deficits.
The following table summarizes our changes in
cash and cash equivalents for the nine months ended
September 30, 2016
and 2015:
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Nine Months Ended
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September 30,
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(in thousands)
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2016
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2015
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Net cash provided by operating activities
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$
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437,301
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$
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760,593
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Net cash used in investing activities
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(201,226)
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(1,823,828)
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Net cash provided by financing activities
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694,314
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1,063,234
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Net increase (decrease) in cash and cash equivalents
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$
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930,389
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$
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(1)
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Cash flow from
operating activities.
The decrease in operating cash flows during the
nine
months ended September 30, 2016 as compared to
the same period in 2015 was primarily due to (i) a decrease in oil and natural
gas revenues of approximately $304.0 million and (ii) approximately $143.5
million of negative variances in operating assets and liabilities, partially
offset by (i) approximately $77.2 million decrease in cash production expense,
(ii) an increase in operating cash flow of approximately $33.5 million due to a
cash tax benefit of approximately $18.8 million for the
nine
months ended
September 30, 2016 compared to cash tax expense of approximately $14.8 million
during 2015
and
(iii) a cash decrease in general and administrative expense of approximately
$15.0 million.
Our net cash provided by operating
activities included a reduction of approximately $72.8
million and a benefit of approximately $70.7
million
for the
nine
months ended September 30,
2016
and 2015, 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 used in investing activities.
During the nine months ended
September
30, 2016
and 2015, we invested approximately $0.9 billion and $2.2 billion,
respectively, for capital expenditures on oil and natural gas properties. Additionally,
we received approximately $296.3 million related to proceeds from the
disposition of assets and approximately $582.0 million from settlements on
derivatives during the nine months ended September 30, 2016 as compared to
$443.4 million from settlements on derivatives during the comparable period in
2015. During the nine months ended September 30, 2016, we had a cash outflow for
funds held in escrow of approximately $81.3 million related to the Reliance
Acquisition. In October 2016 we closed on the Reliance Acquisition and, as
partial consideration, paid approximately $1.2 billion in cash.
Cash flow from
financing activities.
Net cash provided by financing
activities was approximately $694.3 million and $1,063.2 million for the
nine
months ended
September 30, 2016 and 2015, respectively. Below is a description of our
significant financing activities:
·
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 $21.0 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.
·
In March 2015, we issued shares of our common stock in a public
offering and received net proceeds of approximately $741.5 million. We
used a portion of the net proceeds from this offering to repay all outstanding
borrowings under our credit facility and the remainder for general corporate
purposes.
·
During the first nine months of 2016, we had no outstanding
borrowings under our credit facility.
·
During the first nine months of 2015, we had net borrowings on our
credit facility of $307.0 million.
Subsequent
to
September
30, 2016, as partial consideration for the Reliance Acquisition, we issued to
the seller approximately 3.9 million shares of common stock with an approximate
value of $0.5 billion.
At
September 30,
2016,
we had unused commitments on our credit facility of
$2.5
billion. The maturity date of the credit facility is
May 9, 2019.
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”) or (ii) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). The
credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate
advances varied, with interest margins ranging from 125 to 225 basis points and
25 to 125 basis points, respectively, 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 September
30, 2016,
we had approximately $1.2
billion
of cash
on hand. Approximately $1.2 billion of this amount was utilized as partial
consideration for the Reliance Acquisition in October 2016.
At September 30, 2016, our
commitments from our bank group were $2.5 billion. We expect we will maintain
our $2.5 billion in commitments until our next scheduled redetermination in May
2017. At September 30, 2016, our borrowing base was $2.8 billion.
There is no assurance that our borrowing base will not be
reduced, which could affect our liquidity. Upon
a subsequent redetermination, our borrowing base could be substantially
reduced.
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 Standard & Poor’s Ratings Group, Inc. (“S&P”) and
Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular
reviews. S&P’s corporate rating for us is “BB+” with an outlook that was
raised from stable to positive in August 2016. Moody’s corporate rating for us
is “Ba1” with a stable outlook. 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 September 30, 2016;
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, 2016
was $8.7
billion, consisting of $1.2 billion
of cash and cash equivalents, debt of $
2.7 b
illion
and stockholders’ equity of $
7.2
billion. Our ratio
of net debt to net book capitalization was 18
percent
and
31
percent
at September 30,
2016
and December 31, 2015, respectively. Our ratio of current assets to current
liabilities was 3.00
to 1.0 at September 30,
2016
as compared to 2.20 to 1.0 at December 31, 2015. Both our ratio of net debt to
net book capitalization and our ratio of current assets to current liabilities
were impacted subsequent to September 30, 2016 by the Reliance Acquisition.
Inflation and changes in prices.
Our revenues,
the value of our assets, and our ability to obtain bank financing or additional
capital on attractive terms have been and will continue to be affected by
changes in commodity prices and the costs to produce our reserves. Commodity
prices are subject to significant fluctuations that are beyond our ability to
control or predict. During the nine months ended September 30, 2016, we received an
average of $37.75
per Bbl of oil and $1.97
per Mcf of natural gas before consideration of
commodity derivative contracts compared to $46.56
per
Bbl of oil and $2.59
per Mcf of natural gas in
the nine months ended September
30, 2015.
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,
2016. 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, 2015, filed with the
United States Securities and Exchange Commission (the “SEC”) on February 25,
2016.
Recent
accounting pronouncements.
In May
2014, the Financial Accounting Standards Board (“the FASB”) issued Accounting
Standards Update (“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 2014-09 by one
year. That new standard is now effective for annual reporting periods beginning
after December 15, 2017. An entity can apply ASU 2014-09 using either a full
retrospective method, meaning the standard is applied to all of the periods
presented, or a modified retrospective method, meaning the cumulative effect of
initially applying the standard is recognized in the most current period
presented in the financial statements. We are evaluating the impact that this
new guidance will have on our consolidated financial statements.
In February 2016, 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 March 2016, the FASB issued ASU
No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements
to Employee Share-based Payment Accounting,” which changes the accounting and
presentation for share-based payment arrangements in the following areas: (i)
recognition in the statement of operations of excess tax benefits and
deficiencies; (ii) cash flow presentation of excess tax benefits and
deficiencies; (iii) minimum statutory withholding thresholds and the
classification on the cash flow statement of the withheld amounts; and (iv) an
accounting policy election to recognize forfeitures as they occur. This
guidance is effective for reporting periods beginning after December 15, 2016
and early adoption is permitted. We do not plan on early adopting this
standard. Once adopted, we expect increased volatility in earnings and in the
effective tax rate due to the excess tax benefits and deficiencies being
recognized in the statement of operations.