Pioneer Natural Resources Company Reports Second Quarter 2017 Financial and Operating Results
Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the
Company”) today reported financial and operating results for the quarter
ended June 30, 2017.
Pioneer reported second quarter net income attributable to common
stockholders of $233 million, or $1.36 per diluted share. Without the
effect of noncash mark-to-market derivative gains and the gain from the
sale of acreage in Martin County, Texas, adjusted results for the second
quarter were earnings of $38 million after tax, or $0.21 per diluted
share.
Second quarter 2017 and other recent highlights included:
-
producing 259 thousand barrels oil equivalent per day (MBOEPD), of
which 57% was oil; quarterly production grew by 10 MBOEPD, or 4%,
compared to the first quarter of 2017, and was at the top end of
Pioneer’s second quarter production guidance range of 254 MBOEPD to
259 MBOEPD; this was the ninth consecutive quarter of production
growth since the oil price collapse in late 2014; second quarter
production growth was driven by the Company’s Spraberry/Wolfcamp
horizontal drilling program; total Spraberry/Wolfcamp production
increased 12 MBOEPD, or 6%, compared to the first quarter of 2017;
internal rates of return (IRRs) on Spraberry/Wolfcamp drilling
continue to be strong;
-
reducing production costs (excluding taxes) to $6.19 per barrel oil
equivalent (BOE) in the second quarter compared to $6.31 per BOE in
the first quarter of 2017 and $6.79 per BOE in 2016; production costs
benefited from continuing low horizontal Spraberry/Wolfcamp production
costs of $2.23 per BOE for the quarter;
-
adding 51 thousand barrels oil per day (MBOPD) of oil derivatives for
2018; Pioneer’s derivative positions now cover approximately 90% of
forecasted oil production and 80% of forecasted gas production for the
remainder of 2017, 50% of forecasted oil production for 2018 and 15%
of forecasted gas production for 2018;
-
maintaining a strong balance sheet with cash on hand at the end of the
second quarter of $2.4 billion (includes liquid investments); net debt
to forecasted 2017 operating cash flow was 0.2 times at the end of the
second quarter, and net debt to book capitalization was 3%;
-
placing 61 horizontal wells on production in the Spraberry/Wolfcamp
during the second quarter; nine wells utilized higher intensity
completions compared to Version 3.0 wells (referred to as Version 3.0+
completions), with encouraging early results; four wells were
completed in the Jo Mill interval that continue to support the
successful appraisal of this zone; the remaining 48 wells were Version
3.0 completions that continue to outperform Version 2.0 completions;
-
placing four wells on production in the Eagle Ford Shale that were
drilled, but not completed in early 2016, utilizing higher intensity
completions; these wells are outperforming nearby wells with less
intense completions by more than 20% after approximately 50 days of
production; and
-
exporting approximately one million barrels of Pioneer’s Permian oil
during the second quarter to Europe; the Company expects to export
another one million barrels to Europe and Asia during the third
quarter.
Pioneer’s updated 2017 outlook is summarized below:
-
operating 18 horizontal rigs in the Spraberry/Wolfcamp; of these, 14
rigs are in the northern area and four rigs are focused in the
northern portion of the southern Wolfcamp joint venture area (Pioneer
has a 60% working interest in the joint venture); both areas are
utilizing Version 3.0 completions, with some wells testing larger
completions during the year; IRRs on this year’s drilling program are
expected to range from 40% to 75% assuming an oil price of $50 per
barrel and a gas price of $3 per thousand cubic feet (MCF).
-
maintaining efficient operations in the Spraberry/Wolfcamp by not
accelerating activity over the remainder of 2017 to catch up on
completions that were delayed due to unforeseen drilling delays,
especially in light of the current commodity price environment; the
Company now expects to place approximately 230 wells on production
during 2017 compared to a plan of approximately 260 wells, with
associated capital spending expected to be reduced from $2.4 billion
to $2.3 billion;
-
producing increased gas and natural gas liquids (NGLs) from horizontal
proved developed producing (PDP) wells as of year-end 2016 due to
higher average gas-oil ratios (GORs) than forecasted based on current
type curves; the increased gas and NGL production is expected to
result in higher estimated ultimate well recoveries (EURs), positive
reserve revisions and enhanced returns;
-
continuing to meet type curve expectations for Spraberry/Wolfcamp oil
production for horizontal PDP wells and 2017 new drills; oil content
from new drills in the Spraberry/Wolfcamp continues to average 70% to
80% as expected; cumulative oil content for all Spraberry/Wolfcamp
horizontal wells placed on production since 2011 is approximately 70%;
-
drilling and completing 11 new wells and completing nine drilled but
uncompleted wells in the Eagle Ford Shale during 2017 (Pioneer has a
46% working interest); the objective of the limited new well drilling
program is to test longer laterals with wider spacing and
higher-intensity completions; IRRs on this year’s drilling program are
expected to range from 35% to 45% assuming an oil price of $50 per
barrel and a gas price of $3 per MCF; and
-
expecting 2017 production growth for the Company to be 15% to 16%, the
low end of the Company’s forecasted 15% to 18% targeted growth range;
reflects the lost production from the deferral of 30
Spraberry/Wolfcamp completions to 2018, offset by the benefit of
increased gas and NGL production from higher GORs; the Company’s oil
growth rate is also being reduced to a range of 17% to 18% as a result
of the completion deferrals; oil content for 2017 is expected to
average approximately 58%.
President and CEO Timothy L. Dove stated, “The Company delivered another
strong quarter, with solid earnings, production at the top end of our
second quarter guidance range, continued impressive horizontal well
performance in the Spraberry/Wolfcamp and reduced production costs. We
are drilling high-return and highly productive wells primarily as a
result of our successful completion optimization program. In particular,
we are seeing encouraging results from the larger Version 3.0+
completions in the Midland Basin.”
“Operationally, we fell behind on our completions due to unforeseen
drilling delays. To maintain efficient operations, we have chosen not to
accelerate activity in order to catch up in the second half, especially
in light of the current commodity price environment. Our current rig
count remains the same, but we are deferring 30 Spraberry/Wolfcamp
completions that were planned for this year into 2018. This will result
in a reduction in 2017 capital spending of approximately $100 million
and production growth closer to the low end of our guidance range of 15%
to 18% for 2017. This decision is consistent with our longer-term
objective to grow production efficiently by maintaining a steady pace of
activity, spending within cash flow, maintaining a strong balance sheet
and improving corporate returns.”
Mark-to-Market Derivative Gains and Unusual
Items Included in Second Quarter 2017 Earnings
Pioneer’s second quarter earnings included a noncash mark-to-market gain
on derivatives of $71 million after tax, or $0.42 per diluted share.
Earnings also included a gain of $124 million after tax, or $0.73 per
diluted share, from the sale of acreage in Martin County, Texas.
Spraberry/Wolfcamp Operations Update and Outlook
Pioneer is the largest acreage holder in the Spraberry/Wolfcamp, with
approximately 600,000 gross acres in the northern portion of the play
and approximately 200,000 gross acres in the southern Wolfcamp joint
venture area. Pioneer’s contiguous acreage position and substantial
resource potential allow for decades of drilling horizontal wells with
lateral lengths ranging from 7,500 feet to 14,000 feet.
The 2017 plan assumed that approximately 260 horizontal wells would be
placed on production during the year, weighted heavily to the second
half of the year (approximately 150 of these wells). Due to unforeseen
drilling delays in the first half of the year, 11 wells were not placed
on production as planned, and many of the wells during this period were
placed on production later than expected. Moreover, approximately
one-third of the 99 wells that were placed on production in the first
half of the year occurred in June. This resulted in significant lost
production days. The impact of these delays is a reduction to the
full-year Spraberry/Wolfcamp horizontal oil growth forecast of
approximately 8 MBOPD.
The Company is producing increased gas and NGLs from its 770 horizontal
PDP wells (as of year-end 2016) due to higher GORs than forecasted based
on current type curves. As a result, gas and NGL production is above the
Company’s 2017 plan forecast, while the Company’s oil production from
these wells is meeting the plan forecast. The increased gas and NGL
production is expected to result in higher EURs, positive reserve
revisions and enhanced returns.
Gradually increasing GORs over the life of a well has been observed in
the Spraberry/Wolfcamp since the 1950s. It is normal for reservoirs
driven by solution gas to experience increasing GORs over time.
Increasing GORs on horizontal wells is consistent with the long-dated
history of increasing GORs on vertical wells in the Spraberry/Wolfcamp.
However, because horizontal wells contact more surface area and draw
down pressures faster, the GORs on these wells are increasing somewhat
faster than the increase experienced on vertical wells.
The Company implemented a completion optimization program during 2015 in
the Spraberry/Wolfcamp that combines longer laterals with optimized
stage lengths, clusters per stage, fluid volumes and proppant
concentrations. The objective of the program is to improve well
productivity by allowing more rock to be contacted closer to the
horizontal wellbore. In 2013 and 2014, the Company’s initial fracture
stimulation design (Version 1.0) consisted of proppant concentrations of
1,000 pounds per foot, fluid concentrations of 30 barrels per foot,
cluster spacing of 60 feet and stage spacing of 240 feet. Beginning in
mid-2015, the Company enhanced its fracture stimulation design (Version
2.0), which consisted of larger proppant concentrations of 1,400 pounds
per foot, larger fluid concentrations of 36 barrels per foot, tighter
cluster spacing of 30 feet and shorter stage spacing of 150 feet. The
Version 2.0 design increased the cost of a completion by approximately
$500 thousand per well. Beginning in the first quarter of 2016, Pioneer
commenced testing further-enhanced completion designs (Version 3.0),
which included larger proppant concentrations up to 1,700 pounds per
foot, larger fluid concentrations up to 50 barrels per foot, tighter
cluster spacing down to 15 feet and shorter stage spacing down to 100
feet. The cost of this design added $500 thousand to $1 million per well
compared to Version 2.0. The Company placed 48 Version 3.0 wells on
production in the second quarter. These wells and the 154 Version 3.0
wells that were placed on production prior to the second quarter of 2017
are continuing to outperform Version 2.0 completions.
In addition to the 48 Version 3.0 wells that were placed on production
during the second quarter, Pioneer placed nine wells on production that
utilized higher intensity completions compared to Version 3.0 wells.
These are being referred to as Version 3.0+ completions. Six of the
Version 3.0+ wells utilized increased proppant and three utilized
increased proppant and water compared to Version 3.0 wells. Early
production results from all of these wells are outperforming nearby
offset wells with less intense completions. The Company plans to test a
minimum of six additional 3.0+ wells over the remainder of the year.
The Company placed four Jo Mill wells on production during the second
quarter. Nine wells have now been tested as part of the Jo Mill
appraisal program since the fourth quarter of 2014. Of the four second
quarter wells, performance from three of the wells that have at least 60
days of production is encouraging. The fourth well is currently flowing
back. The Jo Mill wells placed on production to date cover a large cross
section of Pioneer’s acreage. The Company plans to place two additional
Jo Mill wells on production in the third quarter. The cost of the Jo
Mill wells in the 2017 program is approximately $7 million per well for
an average lateral length of 10,000 feet.
The expected costs to drill and complete Spraberry/Wolfcamp horizontal
wells in 2017 are: Wolfcamp B – $8.8 million for a 10,000-foot lateral
well; Wolfcamp A – $7.8 million for a 9,500-foot lateral well; and Lower
Spraberry Shale – $7.5 million for a 9,500-foot lateral well. Production
costs (including production and ad valorem taxes) for Pioneer’s
horizontal Spraberry/Wolfcamp wells are expected to continue to range
from $4.00 per BOE to $5.00 per BOE.
As a result of the increased EURs associated with the higher GORs that
are being experienced on horizontal PDP wells, the Company is increasing
the EURs for Wolfcamp interval wells. For the 2017 drilling program, the
Wolfcamp B EUR is being increased from 1.5 million barrels oil
equivalent (MMBOE) to 1.7 MMBOE and the Wolfcamp A EUR is being
increased from 1.2 MMBOE to 1.3 MMBOE. The EUR for Lower Spraberry Shale
wells remains at 1.0 MMBOE since higher GORs than forecasted have not
been experienced in this shallower interval.
The drilling program in the Spraberry/Wolfcamp is expected to deliver
IRRs ranging from 40% to 75%, assuming Version 3.0 completions, an oil
price of $50.00 per barrel and a gas price of $3.00 per MCF. These
returns include tank battery and saltwater disposal facility costs and
the benefit of higher EURs attributable to Wolfcamp interval wells as a
result of the increased GORs.
The Company’s Spraberry/Wolfcamp horizontal drilling program continues
to drive production growth, with total Spraberry/Wolfcamp production
growing by 12 MBOEPD, or 6%, in the second quarter of 2017 compared to
the first quarter. Pioneer’s forecasted 2017 production growth rate for
the Spraberry/Wolfcamp ranges from 30% to 32%. This reflects the Company
placing approximately 230 wells on production in 2017. Of these wells,
approximately 190 wells are expected to be in the northern area and 40
wells will be in the southern Wolfcamp joint venture area. Approximately
55% of the wells will be in the Wolfcamp B, 30% in the Wolfcamp A and
15% in the Lower Spraberry Shale. The Company also plans to commence a
limited appraisal program for the Clearfork and Wolfcamp D intervals
late this year.
In the third quarter, the Company expects to place 55 to 60 wells on
production, which are expected to be weighted evenly across the quarter.
The Company assumes that it will continue to reject ethane throughout
2017, based on continuing weak market conditions.
Spraberry/Wolfcamp Oil Pipeline Commitments
Pioneer is currently delivering 60 MBOPD of Spraberry/Wolfcamp oil to
the Gulf Coast under firm pipeline contracts. These contracts provide
domestic and export delivery capability to Corpus Christi, Houston and
Nederland. There is currently approximately seven million barrels per
day of refinery capacity in the Gulf Coast market, with approximately
two million barrels per day of oil export capability.
The Company is finalizing agreements with several midstream companies
that will expand current oil transport commitments to meet the Company’s
expected Spraberry/Wolfcamp volume growth. The Company has a longer-term
target to move 70% to 80% of forecasted net oil production under firm
pipeline contracts to the Gulf Coast in order to increase its access to
international markets and the U.S. refinery market.
Eagle Ford Shale Operations
In the liquids-rich area of the Eagle Ford Shale play in South Texas,
Pioneer has commenced a limited horizontal drilling and completion
program that is focused in Karnes, DeWitt and Live Oak counties. The
2017 program includes completing nine wells that were drilled in late
2015/early 2016 and drilling and completing 11 new wells.
The objective of this drilling and completion program is to test longer
laterals with wider spacing and higher intensity completions in the new
wells. Lateral lengths are being extended to 7,500 feet from the
previous design of 5,200 feet, with cluster spacing reduced from 50 feet
to 30 feet. Proppant concentrations are being increased from 1,200
pounds per foot to 2,000 pounds per foot. The cost of drilling and
completing the new wells is expected to be $8.5 million per well. The
Company expects EURs averaging 1.3 MMBOE for the new wells with IRRs
ranging from 35% to 45%, assuming an oil price of $50.00 per barrel and
a gas price of $3.00 per MCF.
Drilling was completed on the 11 new wells during the second quarter.
Four of the drilled but uncompleted wells (DUCs) were also fracture
stimulated and placed on production during the second quarter. After
approximately 50 days of production, the wells are exhibiting a
productivity improvement of more than 20% above nearby wells with less
intense completions. Completion of the remaining 16 wells (5 DUCs and 11
new drills) is expected by early in the fourth quarter.
Pioneer’s production from the Eagle Ford Shale averaged 19 MBOEPD in the
second quarter, of which 32% was condensate, 34% was NGLs and 34% was
gas. The 2017 drilling program is expected to moderate the production
decline Pioneer has experienced in the field since it stopped drilling
operations in early 2016. The year-over-year decline is forecasted to be
approximately 40%, while the decline from the fourth quarter of 2016 to
the fourth quarter of 2017 is expected to be shallower at 20% since the
production from the 2017 program is heavily weighted to the second half
of the year.
2017 Capital Program
The Company’s capital budget for 2017 is being reduced from $2.8 billion
to $2.7 billion (excluding acquisitions, asset retirement obligations,
capitalized interest, geological and geophysical G&A and IT system
upgrades). The reduction reflects the decision to defer 30
Spraberry/Wolfcamp completions to 2018. The budget includes $2.4 billion
for drilling and completion activities, including tank
batteries/saltwater disposal facilities and gas processing facilities,
and $275 million for water infrastructure, vertical integration and
field facilities.
The following provides a breakdown of the drilling capital budget by
asset:
-
Spraberry/Wolfcamp – $2.3 billion (includes $1.8 billion for the
horizontal drilling and completion program, $265 million for tank
batteries/saltwater disposal facilities, $115 million for gas
processing facilities and $110 million for land, science and other
expenditures);
-
Eagle Ford Shale – $95 million (includes $65 million for the
horizontal drilling and completion program and $30 million for
compression, land and other expenditures); and
-
Other assets – $20 million.
Capital spending for 2017 is expected to be funded from forecasted
operating cash flow of $1.9 billion (assuming average estimated prices
for the second half of 2017 of $47.50 per barrel for oil and $3.00 per
MCF for gas) and cash on hand (including liquid investments). Net debt
to 2017 operating cash flow is forecasted to remain below 1.0 times.
Second Quarter 2017 Financial Review
Sales volumes for the second quarter of 2017 averaged 259 MBOEPD. Oil
sales averaged 147 thousand barrels per day (MBPD), NGL sales averaged
53 MBPD and gas sales averaged 354 million cubic feet per day.
The average realized price for oil was $45.00 per barrel. The average
realized price for NGLs was $16.91 per barrel, and the average realized
price for gas was $2.62 per MCF. These prices exclude the effects of
derivatives.
Production costs including taxes averaged $8.38 per BOE. Depreciation,
depletion and amortization (DD&A) expense averaged $14.46 per BOE.
Exploration and abandonment costs were $26 million, including $8 million
for drilling, acreage and other abandonments, $2 million for seismic
purchases and $16 million for personnel costs. General and
administrative expense totaled $81 million. Interest expense was $35
million. Other expense was $59 million, including (i) $43 million of
charges associated with excess firm gathering and transportation
commitments and (ii) $5 million of losses (principally noncash)
associated with the portion of vertical integration services provided to
nonaffiliated working interest owners, including joint venture partners,
in wells operated by the Company.
Third Quarter 2017 Financial Outlook
The Company’s third quarter 2017 outlook for certain operating and
financial items is provided below.
Production is forecasted to average 274 MBOEPD to 279 MBOEPD.
Production costs are expected to average $7.75 per BOE to $9.75 per BOE.
DD&A expense is expected to average $14.00 per BOE to $16.00 per BOE.
Total exploration and abandonment expense is forecasted to be $20
million to $30 million.
General and administrative expense is expected to be $80 million to $85
million. Interest expense is expected to be $33 million to $38 million.
Other expense is forecasted to be $60 million to $70 million and is
expected to include (i) $45 million to $50 million of charges associated
with excess firm gathering and transportation commitments and (ii) $5
million to $10 million of losses (principally noncash) associated with
the portion of vertical integration services provided to nonaffiliated
working interest owners, including joint venture partners, in wells
operated by the Company. Accretion of discount on asset retirement
obligations is expected to be $4 million to $7 million.
The Company’s effective income tax rate is expected to range from 35% to
40%. Current income taxes are expected to be less than $5 million.
The Company’s financial and derivative mark-to-market results and open
derivatives positions are outlined on the attached schedules.
Earnings Conference Call
On Wednesday, August 2, 2017, at 9:00 a.m. Central Time, Pioneer will
discuss its financial and operating results for the quarter ended June
30, 2017, with an accompanying presentation. Instructions for listening
to the call and viewing the accompanying presentation are shown below.
Internet: www.pxd.com
Select
“Investors,” then “Earnings & Webcasts” to listen to the discussion,
view the presentation and see other related material.
Telephone: Dial (888) 312-3046 and confirmation code 5070224 five
minutes before the call. View the presentation via Pioneer’s internet
address above.
A replay of the webcast will be archived on Pioneer’s website. A
telephone replay will be available through August 26, 2017. Click
here to register for the call-in audio replay, and enter
confirmation code 5070224.
Pioneer is a large independent oil and gas exploration and production
company, headquartered in Dallas, Texas, with operations in the United
States. For more information, visit www.pxd.com.
Except for historical information contained herein, the statements in
this presentation are forward-looking statements that are made pursuant
to the Safe Harbor Provisions of the Private Securities Litigation
Reform Act of 1995. Forward-looking statements and the business
prospects of Pioneer are subject to a number of risks and uncertainties
that may cause Pioneer’s actual results in future periods to differ
materially from the forward-looking statements. These risks and
uncertainties include, among other things, volatility of commodity
prices, product supply and demand, competition, the ability to obtain
environmental and other permits and the timing thereof, other government
regulation or action, the ability to obtain approvals from third parties
and negotiate agreements with third parties on mutually acceptable
terms, completion of planned divestitures, litigation, the costs and
results of drilling and operations, availability of equipment, services,
resources and personnel required to perform the Company’s drilling and
operating activities, access to and availability of transportation,
processing, fractionation and refining facilities, Pioneer’s ability to
replace reserves, implement its business plans or complete its
development activities as scheduled, access to and cost of capital, the
financial strength of counterparties to Pioneer’s credit facility,
investment instruments and derivative contracts and purchasers of
Pioneer’s oil, natural gas liquids and gas production, uncertainties
about estimates of reserves and resource potential, identification of
drilling locations and the ability to add proved reserves in the future,
the assumptions underlying production forecasts, quality of technical
data, environmental and weather risks, including the possible impacts of
climate change, the risks associated with the ownership and operation of
the Company’s industrial sand mining and oilfield services businesses
and acts of war or terrorism. These and other risks are described in
Pioneer’s Annual Report on Form 10-K for the year ended December 31,
2016, and other filings with the Securities and Exchange Commission. In
addition, Pioneer may be subject to currently unforeseen risks that may
have a materially adverse impact on it. Accordingly, no assurances can
be given that the actual events and results will not be materially
different than the anticipated results described in the forward-looking
statements. Pioneer undertakes no duty to publicly update these
statements except as required by law.
Cautionary Note to U.S. Investors --The SEC prohibits oil and gas
companies, in their filings with the SEC, from disclosing estimates of
oil or gas resources other than “reserves,” as that term is defined by
the SEC. In this presentation, Pioneer includes estimates of
quantities of oil and gas using certain terms, such as “resource
potential,” “net recoverable resource potential,” “recoverable
resource,” “estimated ultimate recovery,” “EUR,” “oil in place” or other
descriptions of volumes of reserves, which terms include quantities of
oil and gas that may not meet the SEC’s definitions of proved, probable
and possible reserves, and which the SEC's guidelines strictly prohibit
Pioneer from including in filings with the SEC. These estimates
are by their nature more speculative than estimates of proved reserves
and, accordingly, are subject to substantially greater risk of being
recovered by Pioneer. U.S. investors are urged to consider
closely the disclosures in the Company’s periodic filings with the SEC.
Such filings are available from the Company at 5205 N. O'Connor
Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations,
and the Company’s website at www.pxd.com.
These filings also can be obtained from the SEC by calling
1-800-SEC-0330.
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
|
(in millions)
|
|
|
|
|
June 30, 2017
|
|
|
December 31, 2016
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
660
|
|
|
|
$
|
1,118
|
|
Short-term investments
|
|
|
|
1,539
|
|
|
|
|
1,441
|
|
Accounts receivable, net
|
|
|
|
491
|
|
|
|
|
518
|
|
Income taxes receivable
|
|
|
|
1
|
|
|
|
|
3
|
|
Inventories
|
|
|
|
192
|
|
|
|
|
181
|
|
Derivatives
|
|
|
|
156
|
|
|
|
|
14
|
|
Other
|
|
|
|
25
|
|
|
|
|
23
|
|
Total current assets
|
|
|
|
3,064
|
|
|
|
|
3,298
|
|
Property, plant and equipment, at cost:
|
|
|
|
|
|
|
Oil and gas properties, using the successful efforts method of
accounting
|
|
|
|
19,501
|
|
|
|
|
19,052
|
|
Accumulated depletion, depreciation and amortization
|
|
|
|
(8,505
|
)
|
|
|
|
(8,211
|
)
|
Total property, plant and equipment
|
|
|
|
10,996
|
|
|
|
|
10,841
|
|
Long-term investments
|
|
|
|
187
|
|
|
|
|
420
|
|
Goodwill
|
|
|
|
270
|
|
|
|
|
272
|
|
Other property and equipment, net
|
|
|
|
1,622
|
|
|
|
|
1,529
|
|
Derivatives
|
|
|
|
29
|
|
|
|
|
—
|
|
Other assets, net
|
|
|
|
103
|
|
|
|
|
99
|
|
|
|
|
$
|
16,271
|
|
|
|
$
|
16,459
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
|
$
|
944
|
|
|
|
$
|
875
|
|
Interest payable
|
|
|
|
59
|
|
|
|
|
68
|
|
Current portion of long-term debt
|
|
|
|
449
|
|
|
|
|
485
|
|
Derivatives
|
|
|
|
3
|
|
|
|
|
77
|
|
Other
|
|
|
|
103
|
|
|
|
|
61
|
|
Total current liabilities
|
|
|
|
1,558
|
|
|
|
|
1,566
|
|
Long-term debt
|
|
|
|
2,281
|
|
|
|
|
2,728
|
|
Derivatives
|
|
|
|
1
|
|
|
|
|
7
|
|
Deferred income taxes
|
|
|
|
1,487
|
|
|
|
|
1,397
|
|
Other liabilities
|
|
|
|
342
|
|
|
|
|
350
|
|
Equity
|
|
|
|
10,602
|
|
|
|
|
10,411
|
|
|
|
|
$
|
16,271
|
|
|
|
$
|
16,459
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
(in millions, except per share data)
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
|
$
|
768
|
|
|
|
$
|
613
|
|
|
|
$
|
1,577
|
|
|
|
$
|
1,022
|
|
Sales of purchased oil and gas
|
|
|
|
517
|
|
|
|
|
395
|
|
|
|
|
1,001
|
|
|
|
|
618
|
|
Interest and other
|
|
|
|
16
|
|
|
|
|
6
|
|
|
|
|
30
|
|
|
|
|
13
|
|
Derivative gains (losses), net
|
|
|
|
135
|
|
|
|
|
(229
|
)
|
|
|
|
286
|
|
|
|
|
(186
|
)
|
Gain on disposition of assets, net
|
|
|
|
194
|
|
|
|
|
1
|
|
|
|
|
205
|
|
|
|
|
3
|
|
|
|
|
|
1,630
|
|
|
|
|
786
|
|
|
|
|
3,099
|
|
|
|
|
1,470
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
|
147
|
|
|
|
|
141
|
|
|
|
|
288
|
|
|
|
|
297
|
|
Production and ad valorem taxes
|
|
|
|
51
|
|
|
|
|
36
|
|
|
|
|
99
|
|
|
|
|
65
|
|
Depletion, depreciation and amortization
|
|
|
|
341
|
|
|
|
|
384
|
|
|
|
|
678
|
|
|
|
|
737
|
|
Purchased oil and gas
|
|
|
|
531
|
|
|
|
|
410
|
|
|
|
|
1,034
|
|
|
|
|
653
|
|
Impairment of oil and gas properties
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
285
|
|
|
|
|
32
|
|
Exploration and abandonments
|
|
|
|
26
|
|
|
|
|
18
|
|
|
|
|
59
|
|
|
|
|
77
|
|
General and administrative
|
|
|
|
81
|
|
|
|
|
80
|
|
|
|
|
165
|
|
|
|
|
154
|
|
Accretion of discount on asset retirement obligations
|
|
|
|
5
|
|
|
|
|
5
|
|
|
|
|
10
|
|
|
|
|
9
|
|
Interest
|
|
|
|
35
|
|
|
|
|
56
|
|
|
|
|
81
|
|
|
|
|
111
|
|
Other
|
|
|
|
59
|
|
|
|
|
67
|
|
|
|
|
119
|
|
|
|
|
154
|
|
|
|
|
|
1,276
|
|
|
|
|
1,197
|
|
|
|
|
2,818
|
|
|
|
|
2,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
|
354
|
|
|
|
|
(411
|
)
|
|
|
|
281
|
|
|
|
|
(819
|
)
|
Income tax benefit (provision)
|
|
|
|
(121
|
)
|
|
|
|
143
|
|
|
|
|
(90
|
)
|
|
|
|
284
|
|
Net income (loss) attributable to common stockholders
|
|
|
$
|
233
|
|
|
|
$
|
(268
|
)
|
|
|
$
|
191
|
|
|
|
$
|
(535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income (loss) per share attributable to common
stockholders
|
|
|
$
|
1.36
|
|
|
|
$
|
(1.63
|
)
|
|
|
$
|
1.11
|
|
|
|
$
|
(3.28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted weighted average shares outstanding
|
|
|
|
170
|
|
|
|
|
164
|
|
|
|
|
170
|
|
|
|
|
163
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
(in millions)
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
233
|
|
|
|
$
|
(268
|
)
|
|
|
$
|
191
|
|
|
|
$
|
(535
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
|
341
|
|
|
|
|
384
|
|
|
|
|
678
|
|
|
|
|
737
|
|
Impairment of oil and gas properties
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
285
|
|
|
|
|
32
|
|
Impairment of inventory and other property and equipment
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
5
|
|
Exploration expenses, including dry holes
|
|
|
|
8
|
|
|
|
|
—
|
|
|
|
|
18
|
|
|
|
|
40
|
|
Deferred income taxes
|
|
|
|
121
|
|
|
|
|
(143
|
)
|
|
|
|
90
|
|
|
|
|
(284
|
)
|
Gain on disposition of assets, net
|
|
|
|
(194
|
)
|
|
|
|
(1
|
)
|
|
|
|
(205
|
)
|
|
|
|
(3
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
|
5
|
|
|
|
|
5
|
|
|
|
|
10
|
|
|
|
|
9
|
|
Interest expense
|
|
|
|
1
|
|
|
|
|
5
|
|
|
|
|
2
|
|
|
|
|
9
|
|
Derivative related activity
|
|
|
|
(111
|
)
|
|
|
|
361
|
|
|
|
|
(251
|
)
|
|
|
|
535
|
|
Amortization of stock-based compensation
|
|
|
|
21
|
|
|
|
|
23
|
|
|
|
|
43
|
|
|
|
|
44
|
|
Other noncash items
|
|
|
|
10
|
|
|
|
|
13
|
|
|
|
|
34
|
|
|
|
|
34
|
|
Change in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
|
|
(65
|
)
|
|
|
|
(84
|
)
|
|
|
|
27
|
|
|
|
|
(51
|
)
|
Income taxes receivable
|
|
|
|
2
|
|
|
|
|
(1
|
)
|
|
|
|
2
|
|
|
|
|
39
|
|
Inventories
|
|
|
|
8
|
|
|
|
|
(12
|
)
|
|
|
|
(11
|
)
|
|
|
|
(12
|
)
|
Derivatives
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
Investments
|
|
|
|
(1
|
)
|
|
|
|
—
|
|
|
|
|
3
|
|
|
|
|
—
|
|
Other current assets
|
|
|
|
7
|
|
|
|
|
3
|
|
|
|
|
1
|
|
|
|
|
—
|
|
Accounts payable
|
|
|
|
111
|
|
|
|
|
109
|
|
|
|
|
(42
|
)
|
|
|
|
(60
|
)
|
Interest payable
|
|
|
|
20
|
|
|
|
|
36
|
|
|
|
|
(9
|
)
|
|
|
|
20
|
|
Income taxes payable
|
|
|
|
—
|
|
|
|
|
(2
|
)
|
|
|
|
—
|
|
|
|
|
(2
|
)
|
Other current liabilities
|
|
|
|
(39
|
)
|
|
|
|
(9
|
)
|
|
|
|
(24
|
)
|
|
|
|
(26
|
)
|
Net cash provided by operating activities
|
|
|
|
479
|
|
|
|
|
408
|
|
|
|
|
843
|
|
|
|
|
519
|
|
Net cash used in investing activities
|
|
|
|
(475
|
)
|
|
|
|
(1,125
|
)
|
|
|
|
(773
|
)
|
|
|
|
(2,589
|
)
|
Net cash provided by (used in) financing activities
|
|
|
|
(7
|
)
|
|
|
|
930
|
|
|
|
|
(528
|
)
|
|
|
|
2,504
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
|
(3
|
)
|
|
|
|
213
|
|
|
|
|
(458
|
)
|
|
|
|
434
|
|
Cash and cash equivalents, beginning of period
|
|
|
|
663
|
|
|
|
|
1,612
|
|
|
|
|
1,118
|
|
|
|
|
1,391
|
|
Cash and cash equivalents, end of period
|
|
|
$
|
660
|
|
|
|
$
|
1,825
|
|
|
|
$
|
660
|
|
|
|
$
|
1,825
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
Average Daily Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
|
146,884
|
|
|
|
134,723
|
|
|
|
146,255
|
|
|
|
128,762
|
Natural gas liquids ("NGL") (Bbls)
|
|
|
|
53,268
|
|
|
|
41,223
|
|
|
|
50,066
|
|
|
|
40,227
|
Gas (Mcfs)
|
|
|
|
353,612
|
|
|
|
340,542
|
|
|
|
346,149
|
|
|
|
349,597
|
Total (BOE)
|
|
|
|
259,087
|
|
|
|
232,703
|
|
|
|
254,012
|
|
|
|
227,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
|
$
|
45.00
|
|
|
$
|
41.43
|
|
|
$
|
47.01
|
|
|
$
|
35.07
|
NGL (per Bbl)
|
|
|
$
|
16.91
|
|
|
$
|
14.21
|
|
|
$
|
18.03
|
|
|
$
|
12.32
|
Gas (per Mcf)
|
|
|
$
|
2.62
|
|
|
$
|
1.67
|
|
|
$
|
2.70
|
|
|
$
|
1.73
|
Total (per BOE)
|
|
|
$
|
32.56
|
|
|
$
|
28.95
|
|
|
$
|
34.31
|
|
|
$
|
24.72
|
|
|
|
Three Months Ended June 30, 2017
|
|
|
|
Permian
|
|
|
Permian
|
|
|
|
|
|
|
|
|
|
|
|
|
Horizontals
|
|
|
Verticals
|
|
|
Eagle Ford
|
|
|
Other Assets
|
|
|
Total
|
|
|
|
($ per BOE)
|
Margin Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices
|
|
|
$
|
34.92
|
|
|
|
$
|
33.39
|
|
|
|
$
|
26.66
|
|
|
|
$
|
20.86
|
|
|
|
$
|
32.56
|
|
Production costs
|
|
|
|
(2.23
|
)
|
|
|
|
(15.92
|
)
|
|
|
|
(12.30
|
)
|
|
|
|
(10.26
|
)
|
|
|
|
(6.19
|
)
|
Production and ad valorem taxes
|
|
|
|
(2.44
|
)
|
|
|
|
(2.41
|
)
|
|
|
|
(1.07
|
)
|
|
|
|
(1.01
|
)
|
|
|
|
(2.19
|
)
|
|
|
|
$
|
30.25
|
|
|
|
$
|
15.06
|
|
|
|
$
|
13.29
|
|
|
|
$
|
9.59
|
|
|
|
$
|
24.18
|
|
% Oil
|
|
|
|
66
|
%
|
|
|
|
61
|
%
|
|
|
|
32
|
%
|
|
|
|
12
|
%
|
|
|
|
57
|
%
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION
|
The Company uses the two-class method of calculating basic and diluted
earnings per share. Under the two-class method of calculating earnings
per share, generally acceptable accounting principles ("GAAP") provide
that share-based awards with guaranteed dividend or distribution
participation rights qualify as "participating securities" during their
vesting periods. During the periods in which the Company realizes net
income attributable to common shareholders, the Company's basic net
income per share attributable to common stockholders is computed as
(i) net income attributable to common stockholders, (ii) less
participating share-based basic earnings (iii) divided by weighted
average basic shares outstanding and the Company's diluted net income
per share attributable to common stockholders is computed as (i) basic
net income attributable to common stockholders, (ii) plus the
reallocation of participating earnings, if any, (iii) divided by
weighted average diluted shares outstanding. During periods in which the
Company realizes a loss attributable to common stockholders, securities
or other contracts to issue common stock would be dilutive to loss per
share; therefore, conversion into common stock is assumed not to occur.
The following table is a reconciliation of the Company's net income
(loss) attributable to common stockholders to basic and diluted net
income (loss) attributable to common stockholders for the three and six
months ended June 30, 2017 and 2016:
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common stockholders
|
|
|
$
|
233
|
|
|
|
$
|
(268
|
)
|
|
|
$
|
191
|
|
|
|
$
|
(535
|
)
|
Participating basic earnings
|
|
|
|
(2
|
)
|
|
|
|
—
|
|
|
|
|
(2
|
)
|
|
|
|
—
|
|
Basic and diluted net income (loss) attributable to common
stockholders
|
|
|
$
|
231
|
|
|
|
$
|
(268
|
)
|
|
|
$
|
189
|
|
|
|
$
|
(535
|
)
|
Basic and diluted weighted average common shares outstanding were 170
million for the three and six months ended June 30, 2017, respectively,
and 164 million and 163 million for the same respective periods in 2016.
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
|
(in millions)
|
EBITDAX and discretionary cash flow ("DCF") (as defined below) are
presented herein, and reconciled to the GAAP measures of net income
(loss) and net cash provided by operating activities, because of their
wide acceptance by the investment community as financial indicators of a
company's ability to internally fund exploration and development
activities and to service or incur debt. The Company also views the
non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of
the Company's financial indicators with those of peer companies that
follow the full cost method of accounting. EBITDAX and DCF should not be
considered as alternatives to net income (loss) or net cash provided by
operating activities, as defined by GAAP.
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
|
|
|
2017
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
233
|
|
|
|
$
|
(268
|
)
|
|
|
$
|
191
|
|
|
|
$
|
(535
|
)
|
Depletion, depreciation and amortization
|
|
|
|
341
|
|
|
|
|
384
|
|
|
|
|
678
|
|
|
|
|
737
|
|
Exploration and abandonments
|
|
|
|
26
|
|
|
|
|
18
|
|
|
|
|
59
|
|
|
|
|
77
|
|
Impairment of oil and gas properties
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
285
|
|
|
|
|
32
|
|
Impairment of inventory and other property and equipment
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
5
|
|
Accretion of discount on asset retirement obligations
|
|
|
|
5
|
|
|
|
|
5
|
|
|
|
|
10
|
|
|
|
|
9
|
|
Interest expense
|
|
|
|
35
|
|
|
|
|
56
|
|
|
|
|
81
|
|
|
|
|
111
|
|
Income tax (benefit) provision
|
|
|
|
121
|
|
|
|
|
(143
|
)
|
|
|
|
90
|
|
|
|
|
(284
|
)
|
Gain on disposition of assets, net
|
|
|
|
(194
|
)
|
|
|
|
(1
|
)
|
|
|
|
(205
|
)
|
|
|
|
(3
|
)
|
Derivative related activity
|
|
|
|
(111
|
)
|
|
|
|
361
|
|
|
|
|
(251
|
)
|
|
|
|
535
|
|
Amortization of stock-based compensation
|
|
|
|
21
|
|
|
|
|
23
|
|
|
|
|
43
|
|
|
|
|
44
|
|
Other
|
|
|
|
10
|
|
|
|
|
13
|
|
|
|
|
34
|
|
|
|
|
34
|
|
EBITDAX (a)
|
|
|
|
488
|
|
|
|
|
449
|
|
|
|
|
1,016
|
|
|
|
|
762
|
|
Cash interest expense
|
|
|
|
(34
|
)
|
|
|
|
(51
|
)
|
|
|
|
(79
|
)
|
|
|
|
(102
|
)
|
Discretionary cash flow (b)
|
|
|
|
454
|
|
|
|
|
398
|
|
|
|
|
937
|
|
|
|
|
660
|
|
Cash exploration expense
|
|
|
|
(18
|
)
|
|
|
|
(18
|
)
|
|
|
|
(41
|
)
|
|
|
|
(37
|
)
|
Changes in operating assets and liabilities
|
|
|
|
43
|
|
|
|
|
28
|
|
|
|
|
(53
|
)
|
|
|
|
(104
|
)
|
Net cash provided by operating activities
|
|
|
$
|
479
|
|
|
|
$
|
408
|
|
|
|
$
|
843
|
|
|
|
$
|
519
|
|
_____________
(a)
|
|
“EBITDAX” represents earnings before depletion, depreciation and
amortization expense; exploration and abandonments; impairment of
oil and gas properties; impairment of inventory and other property
and equipment; accretion of discount on asset retirement
obligations; interest expense; income taxes; net gain on the
disposition of assets; noncash derivative related activity;
amortization of stock-based compensation and other items.
|
(b)
|
|
Discretionary cash flow equals cash flows from operating activities
before changes in operating assets and liabilities and exploration
expense.
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
|
(in millions, except per share data)
|
Net income adjusted for noncash mark-to-market ("MTM") derivative gains,
and adjusted income excluding noncash MTM derivative gains and usual
items, as presented in this press release, are presented and reconciled
to Pioneer's net income attributable to common stockholders (determined
in accordance with GAAP) because Pioneer believes that these non-GAAP
financial measures reflect an additional way of viewing aspects of
Pioneer's business that, when viewed together with its financial results
computed in accordance with GAAP, provide a more complete understanding
of factors and trends affecting its historical financial performance and
future operating results, greater transparency of underlying trends and
greater comparability of results across periods. In addition, management
believes that these non-GAAP financial measures may enhance investors'
ability to assess Pioneer's historical and future financial performance.
These non-GAAP financial measures are not intended to be substitutes for
the comparable GAAP measure and should be read only in conjunction with
Pioneer's consolidated financial statements prepared in accordance with
GAAP. Noncash MTM derivative gains or losses will recur in future
periods; however, the amount and frequency can vary significantly from
period to period. The table below reconciles Pioneer's net income
attributable to common stockholders for the three months ended June 30,
2017, as determined in accordance with GAAP, to adjusted income
excluding noncash MTM derivative gains and adjusted income excluding
noncash MTM derivative gains and unusual items for that quarter.
|
|
|
After-tax
|
|
|
Amounts
|
|
|
|
Amounts
|
|
|
Per Share
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
|
$
|
233
|
|
|
|
$
|
1.36
|
|
Noncash MTM derivative gains, net ($111 million pretax)
|
|
|
|
(71
|
)
|
|
|
|
(0.42
|
)
|
Adjusted income excluding noncash MTM derivative gains
|
|
|
|
162
|
|
|
|
|
0.94
|
|
Gain on sale of Martin County acreage ($194 million pretax)
|
|
|
|
(124
|
)
|
|
|
|
(0.73
|
)
|
Adjusted income excluding noncash MTM derivative gains and unusual
items
|
|
|
$
|
38
|
|
|
|
$
|
0.21
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
SUPPLEMENTAL INFORMATION
|
|
Open Commodity Derivative Positions as of July 28, 2017
|
(Volumes are average daily amounts)
|
|
|
|
|
2017
|
|
|
Year Ending December 31,
|
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
2018
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Oil Production Associated with Derivatives (Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
6,000
|
|
|
|
|
6,000
|
|
|
|
|
—
|
|
|
|
—
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
70.40
|
|
|
|
$
|
70.40
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Floor
|
|
|
$
|
50.00
|
|
|
|
$
|
50.00
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Collar contracts with short puts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
147,000
|
|
|
|
|
155,000
|
|
|
|
|
97,000
|
|
|
|
—
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
62.03
|
|
|
|
$
|
62.12
|
|
|
|
$
|
58.94
|
|
|
$
|
—
|
Floor
|
|
|
$
|
49.81
|
|
|
|
$
|
49.82
|
|
|
|
$
|
48.71
|
|
|
$
|
—
|
Short put
|
|
|
$
|
41.07
|
|
|
|
$
|
41.02
|
|
|
|
$
|
38.66
|
|
|
$
|
—
|
Average Daily NGL Production Associated with Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Butane collar contracts with short puts (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
2,000
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
Index price:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
36.12
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Floor
|
|
|
$
|
29.25
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Short put
|
|
|
$
|
23.40
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Ethane collar contracts (b):
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
3,000
|
|
|
|
|
3,000
|
|
|
|
|
—
|
|
|
|
—
|
Index price:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
11.83
|
|
|
|
$
|
11.83
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Floor
|
|
|
$
|
8.68
|
|
|
|
$
|
8.68
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Ethane basis swap contracts (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
6,920
|
|
|
|
|
6,920
|
|
|
|
|
6,920
|
|
|
|
6,920
|
Price differential
|
|
|
$
|
1.60
|
|
|
|
$
|
1.60
|
|
|
|
$
|
1.60
|
|
|
$
|
1.60
|
Average Daily Gas Production Associated with Derivatives (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts with short puts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
290,000
|
|
|
|
|
300,000
|
|
|
|
|
62,329
|
|
|
|
—
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
3.57
|
|
|
|
$
|
3.60
|
|
|
|
$
|
3.56
|
|
|
$
|
—
|
Floor
|
|
|
$
|
2.95
|
|
|
|
$
|
2.96
|
|
|
|
$
|
2.91
|
|
|
$
|
—
|
Short put
|
|
|
$
|
2.47
|
|
|
|
$
|
2.47
|
|
|
|
$
|
2.37
|
|
|
$
|
—
|
Basis swap contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent index swap volume (d)
|
|
|
|
45,000
|
|
|
|
|
45,000
|
|
|
|
|
—
|
|
|
|
—
|
Price differential ($/MMBtu)
|
|
|
$
|
(0.32
|
)
|
|
|
$
|
(0.32
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
Permian Basin index swap volume (e)
|
|
|
|
6,739
|
|
|
|
|
26,522
|
|
|
|
|
51,671
|
|
|
|
—
|
Price differential ($/MMBtu)
|
|
|
$
|
0.26
|
|
|
|
$
|
0.30
|
|
|
|
$
|
0.30
|
|
|
$
|
—
|
_____________
(a)
|
|
Represent collar contracts with short puts that reduce the price
volatility of butane forecasted for sale by the Company at Mont
Belvieu, Texas-posted prices.
|
(b)
|
|
Represent collar contracts that reduce the price volatility of
ethane forecasted for sale by the Company at Mont Belvieu,
Texas-posted prices.
|
(c)
|
|
Represent basis swap contracts that reduce the price volatility of
ethane forecasted for sale by the Company at Mont Belvieu,
Texas-posted prices. The basis swap contracts fix the basis
differential on a NYMEX Henry Hub MMBtu equivalent basis. The
Company will receive the Henry Hub price plus the price differential
on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of
ethane.
|
(d)
|
|
Represent swap contracts that fix the basis differentials between
the index price at which the Company sells its Mid-Continent gas and
the NYMEX Henry Hub index price used in collar contracts with short
puts.
|
(e)
|
|
Represent swap contracts that fix the basis differentials between
Permian Basin index prices and southern California index prices for
Permian Basin gas forecasted for sale in southern California.
|
|
|
|
Diesel derivatives. Periodically, the Company enters into diesel
derivative swap contracts to mitigate fuel price risk. The diesel
derivative swap contracts are priced at an index that is highly
correlated to the prices that the Company incurs to fuel drilling rigs
and its fracture stimulation fleet equipment. As of July 28, 2017, the
Company was party to diesel derivative swap contracts for 1,000 Bbls per
day for the remainder of July 2017 at an average per Bbl fixed price of
$63.00. In July 2017, the Company terminated its diesel derivative swap
contracts for August through December 2017 for cash proceeds of $321
thousand.
Interest rate derivatives. As of July 28, 2017, the Company was
party to interest rate derivative contracts whereby the Company will
receive the three-month LIBOR rate for the 10-year period from December
2017 through December 2027 in exchange for paying a fixed interest rate
of 1.81 percent on a notional amount of $100 million on December 15,
2017.
|
|
Derivative Gains, Net
|
(in millions)
|
The following table summarizes net derivative gains that the Company
recorded in earnings for the three and six months ended June 30, 2017:
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30, 2017
|
|
|
June 30, 2017
|
Noncash changes in fair value:
|
|
|
|
|
|
|
Oil derivative gains
|
|
|
$
|
103
|
|
|
|
$
|
220
|
|
NGL derivative gains
|
|
|
|
—
|
|
|
|
|
3
|
|
Gas derivative gains
|
|
|
|
10
|
|
|
|
|
29
|
|
Diesel derivative losses
|
|
|
|
(1
|
)
|
|
|
|
—
|
|
Interest rate derivative losses
|
|
|
|
(1
|
)
|
|
|
|
(1
|
)
|
Total noncash derivative gains, net
|
|
|
|
111
|
|
|
|
|
251
|
|
|
|
|
|
|
|
|
Net cash receipts on settled derivative instruments:
|
|
|
|
|
|
|
Oil derivative receipts
|
|
|
|
21
|
|
|
|
|
33
|
|
NGL derivative receipts
|
|
|
|
1
|
|
|
|
|
1
|
|
Gas derivative receipts
|
|
|
|
1
|
|
|
|
|
—
|
|
Diesel derivative receipts
|
|
|
|
1
|
|
|
|
|
1
|
|
Total cash receipts on settled derivative instruments, net
|
|
|
|
24
|
|
|
|
|
35
|
|
Total derivative gains, net
|
|
|
$
|
135
|
|
|
|
$
|
286
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20170801006492/en/
Copyright Business Wire 2017