Pioneer Natural Resources Company Reports Third 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 September 30, 2017.
Pioneer reported a third quarter net loss attributable to common
stockholders of $23 million, or $0.13 per diluted share. Without the
effect of noncash mark-to-market derivative losses of $103 million after
tax, or $0.61 per diluted share, adjusted results for the third quarter
were earnings of $80 million after tax, or $0.48 per diluted share.
Third quarter financial, production and other recent highlights included:
-
producing 276 thousand barrels oil equivalent per day (MBOEPD), an
increase of 17 MBOEPD, or 6%, compared to the second quarter of 2017;
third quarter production was negatively impacted by 3,500 barrels oil
equivalent per day (BOEPD) due to Hurricane Harvey and unplanned
downtime at a third-party gas processing facility; production would
have been at the top end of Pioneer’s third quarter guidance range of
274 MBOEPD to 279 MBOEPD without these negative impacts; third quarter
production growth was driven by the Company’s Spraberry/Wolfcamp
horizontal drilling program;
-
producing 162 thousand barrels per day (MBPD) of oil, an increase of
15 MBPD, or 10%, compared to the second quarter of 2017;
-
increasing Spraberry/Wolfcamp horizontal production by 22 MBOEPD, or
13%, compared to the second quarter of 2017; horizontal oil production
increased by 17 MBPD, or 15% quarter over quarter; internal rates of
return (IRRs) from the Spraberry/Wolfcamp drilling program continue to
be strong;
-
reducing production costs (excluding taxes) to $6.01 per barrel oil
equivalent (BOE) compared to $6.19 per BOE in the second quarter of
2017 and $6.79 per BOE in 2016; third quarter production costs
benefited from continuing low horizontal Spraberry/Wolfcamp production
costs of $1.85 per BOE (excluding taxes);
-
adding 2018 derivatives for 59 MBPD of oil and 83 million cubic feet
per day (MMCFPD) of gas; Pioneer’s 2018 derivative positions now cover
more than 80% of forecasted oil production and more than 35% of
forecasted gas production;
-
continuing to maintain a strong balance sheet with cash on hand at the
end of the third quarter of $2.1 billion (includes liquid
investments); net debt to forecasted 2017 operating cash flow was 0.3
times at the end of the third quarter and net debt-to-book
capitalization was 5%; and
-
exporting 1.4 million barrels of Pioneer’s Midland Basin oil
production during the third quarter and expecting to export over 2.3
million barrels during the fourth quarter; customers are located in
Asia and Europe.
Pioneer’s third quarter drilling update and other recent operations
activity included:
-
adding two rigs recently in the Spraberry/Wolfcamp to improve
operational flexibility by increasing Pioneer’s inventory of wells
that have been drilled and are awaiting completion (DUCs); once an
adequate DUC inventory is built in the second half of 2018, the
Company expects to use these two rigs to achieve longer-term
production growth targets, which is consistent with the Company’s
previously discussed plans to add drilling rigs in the second half of
2018; the Company is now operating 20 rigs in the Spraberry/Wolfcamp,
with 16 of these rigs in the northern area and 4 rigs in the southern
Wolfcamp joint venture area where Pioneer holds a working interest of
60%; the 2017 capital budget is being increased by $50 million,
primarily to reflect the capital associated with the two additional
Spraberry/Wolfcamp rigs and higher than anticipated completion costs
in the Eagle Ford Shale;
-
utilizing four-string casing design successfully in areas of the
Spraberry/Wolfcamp where this design is necessary;
-
placing 61 horizontal wells on production in the Spraberry/Wolfcamp
during the third quarter; 59 wells were Version 3.0 completions that
continue to outperform Version 2.0 completions; two wells were
completed in the Jo Mill interval; early production results from both
Jo Mill wells continue to support the successful appraisal of this
interval;
-
continuing to see encouraging results from the 12 Spraberry/Wolfcamp
wells that were placed on production in the second quarter of 2017
with higher intensity completions (referred to as Version 3.0+
completions);
-
expecting to place approximately 70 wells on production in the
Spraberry/Wolfcamp during the fourth quarter of 2017, resulting in
approximately 230 wells being placed on production during 2017; IRRs
for this year’s Spraberry/Wolfcamp 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);
-
drilling and completing 11 new wells and completing nine DUC wells in
the Eagle Ford Shale during 2017 (Pioneer has a 46% working interest);
the objective of this 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 30% to
40%, assuming an oil price of $50 per barrel and a gas price of $3 per
MCF; two new drills and nine DUCs were placed on production in the
Eagle Ford Shale during the second and third quarters; the average
cumulative production per well from the new drills and DUCs after
approximately 80 days and 140 days of production, respectively, is
more than double the average cumulative production per well for the
same time period from all wells placed on production during 2015 and
2016; two additional new drills were placed on production in early
October; and
-
resuming production (approximately 8 MBOEPD) in the West Panhandle
field in late October after volumes were temporarily shut in due to a
fire at a third-party gas processing facility in mid-September;
downtime from the fire impacted third quarter production by
approximately 1,300 BOEPD.
President and CEO Timothy L. Dove stated, “The Company delivered another
excellent quarter, with solid earnings, significant oil production
growth, strong horizontal well performance in the Spraberry/Wolfcamp and
reduced production costs. Our world-class Spraberry/Wolfcamp asset is
located in the Midland Basin, considered by many to be the top oil shale
play in North America. We are drilling low-cost, highly productive wells
that generate high returns and have industry-leading breakeven oil
prices.”
“Despite the drilling delays that we experienced in the second quarter,
our operations are back on track and we remain committed to our 10-year
plan of drilling high-return wells that will deliver organic compound
annual production growth of 15%+. Achieving this target will result in
oil production of approximately 700 MBPD in 2026 and total production
greater than 1 million barrels oil equivalent per day. This plan will
allow us to maintain a steady pace of activity, spend within cash flow
by 2020 at an oil price of $50 per barrel, maintain a strong balance
sheet and improve corporate returns.”
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 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.
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 Company placed 59 Version 3.0 wells on production in the third
quarter. These wells and the more than 200 Version 3.0 wells that were
placed on production prior to the third quarter of 2017 are continuing
to outperform Version 2.0 completions.
Pioneer placed 12 wells on production during the second quarter that
utilized higher intensity completions compared to Version 3.0 wells.
These are referred to as Version 3.0+ completions. Nine 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
three additional 3.0+ wells over the remainder of the year.
In addition to the 59 Version 3.0 wells that were placed on production
during the third quarter, Pioneer placed two Jo Mill wells on
production. Eleven wells have now been tested as part of the Jo Mill
appraisal program since the fourth quarter of 2014. Performance from all
of these wells is encouraging. The Jo Mill wells placed on production to
date cover a large cross section of Pioneer’s acreage. The Company plans
to drill additional Jo Mill wells during 2018. The cost of a Jo Mill
well is approximately $7 million for a lateral length of 8,500 feet.
The budgeted 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. For the
2017 drilling program, the expected ultimate recoveries (EURs) by
interval are: Wolfcamp B – 1.7 MMBOE, Wolfcamp A – 1.3 MMBOE and the
Lower Spraberry Shale – 1.0 MMBOE.
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.
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.
The Company’s Spraberry/Wolfcamp horizontal drilling program continues
to drive production growth, with Spraberry/Wolfcamp horizontal
production growing by 22 MBOEPD, or 13%, in the third quarter of 2017
compared to the second 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.
In the fourth quarter, the Company expects to place approximately 70
wells on production, which are expected to be weighted evenly across the
quarter.
Eagle Ford Shale Operations
In the liquids-rich area of the Eagle Ford Shale play in South Texas,
Pioneer is completing a limited horizontal drilling and completion
program during 2017 that is focused in Karnes, DeWitt and Live Oak
counties. The 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 being 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 $9.6 million per well. The
Company expects EURs averaging 1.3 MMBOE for the new wells with IRRs
ranging from 30% to 40%, 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.
Two of these wells were placed on production during the third quarter.
Of the remaining nine wells, two wells were placed on production in
October and the remaining seven wells are expected to be placed on
production in mid-November. The nine DUCs were placed on production
during the second and third quarters. The average cumulative production
per well from the new drills and DUCs after approximately 80 days and
140 days of production, respectively, is more than double the average
cumulative production per well for the same time period from all wells
placed on production during 2015 and 2016.
Pioneer’s production from the Eagle Ford Shale averaged 21 MBOEPD in the
third quarter, of which 34% was condensate, 34% was NGLs and 32% 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 35%.
West Panhandle Operations
The West Panhandle field produced 4,500 BOEPD during the third quarter
of 2017, reflecting the impact of multiple downtime events at the
third-party gas processing plant where the liquids-rich gas from the
field is processed into gas and NGLs. Early in the third quarter, field
production was shut in due to a planned turnaround at the third-party
plant. In mid-September, the field had to be shut in again after the
plant incurred significant damage due to a fire. Repairs to the plant
are underway, but it is expected to be several months before the plant
can be placed back into service. As a result, the third party and
Pioneer have made modifications to their respective facilities to enable
field production to resume, with the gas volumes being rerouted to
another gas processing facility operated by the third party. Production
from the field resumed in late October at approximately 8 MBOEPD. The
impact to third quarter production from the unplanned downtime
associated with the fire was approximately 1,300 BOEPD, with most of
this loss being gas and NGLs.
2017 Capital Program
The Company’s capital budget for 2017 is being increased from $2.7
billion to $2.75 billion (excluding acquisitions, asset retirement
obligations, capitalized interest, geological and geophysical G&A and IT
system upgrades). The increase reflects the recent decision to add two
rigs in the Spraberry/Wolfcamp to improve operational flexibility by
increasing Pioneer’s DUC inventory. Once an adequate DUC inventory is
built in the second half of 2018, the Company expects to use these two
rigs to achieve longer-term production growth targets, which is
consistent with the Company’s previously discussed plans to add drilling
rigs in the second half of 2018 for this purpose. The increased capital
spending also includes higher than anticipated completion costs in the
Eagle Ford Shale.
The budget includes $2.475 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 – $2.35 billion (includes $1.86 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 – $105 million (includes $75 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 2017 of $49.50 per barrel for oil and $3.00 per MCF for gas) and
cash on hand (including liquid investments).
Third Quarter 2017 Financial Review
Sales volumes for the third quarter of 2017 averaged 276 MBOEPD. Oil
sales averaged 162 MBPD, NGL sales averaged 57 MBPD and gas sales
averaged 340 MMCFPD.
The average realized price for oil was $45.35 per barrel. The average
realized price for NGLs was $18.96 per barrel, and the average realized
price for gas was $2.58 per MCF. These prices exclude the effects of
derivatives.
Production costs, including taxes, averaged $8.11 per BOE. Depreciation,
depletion and amortization (DD&A) expense averaged $14.01 per BOE.
Exploration and abandonment costs were $18 million, including $3 million
for seismic purchases and $15 million for personnel costs. General and
administrative expense totaled $81 million. Interest expense was $37
million. Other expense was $58 million, including $45 million of charges
associated with excess firm gathering and transportation commitments.
Fourth Quarter 2017 Financial Outlook
The Company’s fourth quarter 2017 outlook for certain operating and
financial items is provided below.
Production is forecasted to average 292 MBOEPD to 302 MBOEPD.
Production costs are expected to average $7.50 per BOE to $9.50 per BOE.
DD&A expense is expected to average $13.50 per BOE to $15.50 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 $34 million to $39 million.
Other expense is forecasted to be $60 million to $70 million and is
expected to include $45 million to $55 million of charges associated
with excess firm gathering and transportation commitments. 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 Thursday, November 2, 2017, at 9:00 a.m. Central Time, Pioneer will
discuss its financial and operating results for the quarter ended
September 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) 539-3696 and confirmation code 3153325 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. This
replay will be available through November 27, 2017. Click
Here to register for the call-in audio replay, and you will receive
the dial-in information.
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, refining and export 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 liquid 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.
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|
|
|
|
|
|
|
|
|
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|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
|
December 31, 2016
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
636
|
|
|
$
|
1,118
|
Short-term investments
|
|
|
|
1,357
|
|
|
|
1,441
|
Accounts receivable, net
|
|
|
|
649
|
|
|
|
518
|
Income taxes receivable
|
|
|
|
1
|
|
|
|
3
|
Inventories
|
|
|
|
187
|
|
|
|
181
|
Derivatives
|
|
|
|
43
|
|
|
|
14
|
Other
|
|
|
|
28
|
|
|
|
23
|
Total current assets
|
|
|
|
2,901
|
|
|
|
3,298
|
Property, plant and equipment, at cost:
|
|
|
|
|
|
|
Oil and gas properties, using the successful efforts method of
accounting
|
|
|
|
20,188
|
|
|
|
19,052
|
Accumulated depletion, depreciation and amortization
|
|
|
|
(8,841)
|
|
|
|
(8,211)
|
Total property, plant and equipment
|
|
|
|
11,347
|
|
|
|
10,841
|
Long-term investments
|
|
|
|
151
|
|
|
|
420
|
Goodwill
|
|
|
|
270
|
|
|
|
272
|
Other property and equipment, net
|
|
|
|
1,683
|
|
|
|
1,529
|
Derivatives
|
|
|
|
7
|
|
|
|
—
|
Other assets, net
|
|
|
|
106
|
|
|
|
99
|
|
|
|
$
|
16,465
|
|
|
$
|
16,459
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
|
$
|
1,105
|
|
|
$
|
875
|
Interest payable
|
|
|
|
38
|
|
|
|
68
|
Current portion of long-term debt
|
|
|
|
449
|
|
|
|
485
|
Derivatives
|
|
|
|
17
|
|
|
|
77
|
Other
|
|
|
|
106
|
|
|
|
61
|
Total current liabilities
|
|
|
|
1,715
|
|
|
|
1,566
|
Long-term debt
|
|
|
|
2,282
|
|
|
|
2,728
|
Derivatives
|
|
|
|
12
|
|
|
|
7
|
Deferred income taxes
|
|
|
|
1,475
|
|
|
|
1,397
|
Other liabilities
|
|
|
|
384
|
|
|
|
350
|
Equity
|
|
|
|
10,597
|
|
|
|
10,411
|
|
|
|
$
|
16,465
|
|
|
$
|
16,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
(in millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
2017
|
|
|
2016
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
|
$
|
855
|
|
|
|
$
|
643
|
|
|
|
|
$
|
2,433
|
|
|
|
$
|
1,665
|
|
Sales of purchased oil and gas
|
|
|
|
721
|
|
|
|
|
444
|
|
|
|
|
|
1,722
|
|
|
|
|
1,062
|
|
Interest and other
|
|
|
|
17
|
|
|
|
|
7
|
|
|
|
|
|
44
|
|
|
|
|
21
|
|
Derivative gains (losses), net
|
|
|
|
(133
|
)
|
|
|
|
91
|
|
|
|
|
|
153
|
|
|
|
|
(95
|
)
|
Gain on disposition of assets, net
|
|
|
|
—
|
|
|
|
|
1
|
|
|
|
|
|
205
|
|
|
|
|
4
|
|
|
|
|
|
1,460
|
|
|
|
|
1,186
|
|
|
|
|
|
4,557
|
|
|
|
|
2,657
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
|
152
|
|
|
|
|
141
|
|
|
|
|
|
440
|
|
|
|
|
438
|
|
Production and ad valorem taxes
|
|
|
|
53
|
|
|
|
|
32
|
|
|
|
|
|
152
|
|
|
|
|
97
|
|
Depletion, depreciation and amortization
|
|
|
|
355
|
|
|
|
|
386
|
|
|
|
|
|
1,033
|
|
|
|
|
1,123
|
|
Purchased oil and gas
|
|
|
|
735
|
|
|
|
|
458
|
|
|
|
|
|
1,769
|
|
|
|
|
1,113
|
|
Impairment of oil and gas properties
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
|
285
|
|
|
|
|
32
|
|
Exploration and abandonments
|
|
|
|
18
|
|
|
|
|
19
|
|
|
|
|
|
78
|
|
|
|
|
96
|
|
General and administrative
|
|
|
|
81
|
|
|
|
|
82
|
|
|
|
|
|
245
|
|
|
|
|
235
|
|
Accretion of discount on asset retirement obligations
|
|
|
|
5
|
|
|
|
|
5
|
|
|
|
|
|
14
|
|
|
|
|
14
|
|
Interest
|
|
|
|
37
|
|
|
|
|
50
|
|
|
|
|
|
118
|
|
|
|
|
161
|
|
Other
|
|
|
|
58
|
|
|
|
|
69
|
|
|
|
|
|
176
|
|
|
|
|
223
|
|
|
|
|
|
1,494
|
|
|
|
|
1,242
|
|
|
|
|
|
4,310
|
|
|
|
|
3,532
|
|
Income (loss) before income taxes
|
|
|
|
(34
|
)
|
|
|
|
(56
|
)
|
|
|
|
|
247
|
|
|
|
|
(875
|
)
|
Income tax benefit (provision)
|
|
|
|
11
|
|
|
|
|
78
|
|
|
|
|
|
(79
|
)
|
|
|
|
362
|
|
Net income (loss) attributable to common stockholders
|
|
|
$
|
(23
|
)
|
|
|
$
|
22
|
|
|
|
|
$
|
168
|
|
|
|
$
|
(513
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income (loss) per share attributable to common
stockholders
|
|
|
$
|
(0.13
|
)
|
|
|
$
|
0.13
|
|
|
|
|
$
|
0.98
|
|
|
|
$
|
(3.10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted weighted average shares outstanding
|
|
|
|
170
|
|
|
|
|
170
|
|
|
|
|
|
170
|
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
2017
|
|
|
2016
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
(23
|
)
|
|
|
$
|
22
|
|
|
|
|
$
|
168
|
|
|
|
$
|
(513
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
|
355
|
|
|
|
|
386
|
|
|
|
|
|
1,033
|
|
|
|
|
1,123
|
|
Impairment of oil and gas properties
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
|
285
|
|
|
|
|
32
|
|
Impairment of inventory and other property and equipment
|
|
|
|
—
|
|
|
|
|
1
|
|
|
|
|
|
1
|
|
|
|
|
6
|
|
Exploration expenses, including dry holes
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
|
19
|
|
|
|
|
41
|
|
Deferred income taxes
|
|
|
|
(11
|
)
|
|
|
|
(56
|
)
|
|
|
|
|
79
|
|
|
|
|
(340
|
)
|
Gain on disposition of assets, net
|
|
|
|
—
|
|
|
|
|
(1
|
)
|
|
|
|
|
(205
|
)
|
|
|
|
(4
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
|
5
|
|
|
|
|
5
|
|
|
|
|
|
14
|
|
|
|
|
14
|
|
Interest expense
|
|
|
|
1
|
|
|
|
|
2
|
|
|
|
|
|
4
|
|
|
|
|
11
|
|
Derivative related activity
|
|
|
|
161
|
|
|
|
|
93
|
|
|
|
|
|
(91
|
)
|
|
|
|
628
|
|
Amortization of stock-based compensation
|
|
|
|
18
|
|
|
|
|
22
|
|
|
|
|
|
61
|
|
|
|
|
66
|
|
Other noncash items
|
|
|
|
13
|
|
|
|
|
17
|
|
|
|
|
|
48
|
|
|
|
|
50
|
|
Change in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
|
|
(158
|
)
|
|
|
|
(13
|
)
|
|
|
|
|
(131
|
)
|
|
|
|
(64
|
)
|
Income taxes receivable
|
|
|
|
—
|
|
|
|
|
(22
|
)
|
|
|
|
|
2
|
|
|
|
|
17
|
|
Inventories
|
|
|
|
2
|
|
|
|
|
5
|
|
|
|
|
|
(9
|
)
|
|
|
|
(7
|
)
|
Derivatives
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
|
|
|
|
—
|
|
|
|
|
(24
|
)
|
Investments
|
|
|
|
2
|
|
|
|
|
—
|
|
|
|
|
|
5
|
|
|
|
|
—
|
|
Other current assets
|
|
|
|
(5
|
)
|
|
|
|
(3
|
)
|
|
|
|
|
(4
|
)
|
|
|
|
(3
|
)
|
Accounts payable
|
|
|
|
124
|
|
|
|
|
52
|
|
|
|
|
|
82
|
|
|
|
|
(8
|
)
|
Interest payable
|
|
|
|
(21
|
)
|
|
|
|
(46
|
)
|
|
|
|
|
(30
|
)
|
|
|
|
(26
|
)
|
Income taxes payable
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
|
|
(2
|
)
|
Other current liabilities
|
|
|
|
(9
|
)
|
|
|
|
(12
|
)
|
|
|
|
|
(33
|
)
|
|
|
|
(38
|
)
|
Net cash provided by operating activities
|
|
|
|
455
|
|
|
|
|
441
|
|
|
|
|
|
1,298
|
|
|
|
|
959
|
|
Net cash used in investing activities
|
|
|
|
(486
|
)
|
|
|
|
(926
|
)
|
|
|
|
|
(1,259
|
)
|
|
|
|
(3,514
|
)
|
Net cash provided by (used in) financing activities
|
|
|
|
7
|
|
|
|
|
(449
|
)
|
|
|
|
|
(521
|
)
|
|
|
|
2,055
|
|
Net decrease in cash and cash equivalents
|
|
|
|
(24
|
)
|
|
|
|
(934
|
)
|
|
|
|
|
(482
|
)
|
|
|
|
(500
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
|
660
|
|
|
|
|
1,825
|
|
|
|
|
|
1,118
|
|
|
|
|
1,391
|
|
Cash and cash equivalents, end of period
|
|
|
$
|
636
|
|
|
|
$
|
891
|
|
|
|
|
$
|
636
|
|
|
|
$
|
891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
2017
|
|
|
2016
|
Average Daily Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
|
161,634
|
|
|
|
134,240
|
|
|
|
|
151,438
|
|
|
|
130,602
|
Natural gas liquids ("NGL") (Bbls)
|
|
|
|
57,346
|
|
|
|
49,235
|
|
|
|
|
52,519
|
|
|
|
43,252
|
Gas (Mcfs)
|
|
|
|
340,384
|
|
|
|
332,415
|
|
|
|
|
344,206
|
|
|
|
343,828
|
Total (BOEs)
|
|
|
|
275,711
|
|
|
|
238,878
|
|
|
|
|
261,325
|
|
|
|
231,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
|
$
|
45.35
|
|
|
$
|
41.44
|
|
|
|
$
|
46.41
|
|
|
$
|
37.27
|
NGL (per Bbl)
|
|
|
$
|
18.96
|
|
|
$
|
12.46
|
|
|
|
$
|
18.38
|
|
|
$
|
12.37
|
Gas (per Mcf)
|
|
|
$
|
2.58
|
|
|
$
|
2.43
|
|
|
|
$
|
2.66
|
|
|
$
|
1.96
|
Total (per BOE)
|
|
|
$
|
33.72
|
|
|
$
|
29.24
|
|
|
|
$
|
34.10
|
|
|
$
|
26.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
|
|
Permian Horizontals
|
|
|
Permian Verticals
|
|
|
Eagle Ford
|
|
|
Other Assets
(a)
|
|
|
Total
|
|
|
|
($ per BOE)
|
Margin Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices
|
|
|
$
|
36.05
|
|
|
|
$
|
34.14
|
|
|
|
$
|
27.51
|
|
|
|
$
|
19.76
|
|
|
|
$
|
33.72
|
|
Production costs
|
|
|
|
(1.85
|
)
|
|
|
|
(18.08
|
)
|
|
|
|
(11.90
|
)
|
|
|
|
(12.87
|
)
|
|
|
|
(6.01
|
)
|
Production and ad valorem taxes
|
|
|
|
(2.32
|
)
|
|
|
|
(2.04
|
)
|
|
|
|
(1.30
|
)
|
|
|
|
(1.08
|
)
|
|
|
|
(2.10
|
)
|
|
|
|
$
|
31.88
|
|
|
|
$
|
14.02
|
|
|
|
$
|
14.31
|
|
|
|
$
|
5.81
|
|
|
|
$
|
25.61
|
|
% Oil
|
|
|
|
67
|
%
|
|
|
|
61
|
%
|
|
|
|
34
|
%
|
|
|
|
10
|
%
|
|
|
|
59
|
%
|
_____________
|
(a)
|
|
Third quarter production was impacted by unplanned downtime at a
third party gas processing plant, where the liquids-rich gas from
Pioneer’s West Panhandle field in Texas is processed into gas and
NGLs. The impact to third quarter production was approximately 1,300
BOEPD, with most of this loss being gas and NGLs.
|
|
|
|
|
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 net 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 nine
months ended September 30, 2017 and 2016:
|
|
|
Three Months Ended September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
2017
|
|
|
2016
|
|
|
|
(in millions)
|
Net income (loss) attributable to common stockholders
|
|
|
$
|
(23
|
)
|
|
|
$
|
22
|
|
|
|
$
|
168
|
|
|
|
$
|
(513
|
)
|
Participating basic earnings
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(1
|
)
|
|
|
|
—
|
|
Basic and diluted net income (loss) attributable to common
stockholders
|
|
|
$
|
(23
|
)
|
|
|
$
|
22
|
|
|
|
$
|
167
|
|
|
|
$
|
(513
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Both basic and diluted weighted average common shares outstanding were
170 million for the three and nine months ended September 30, 2017,
respectively, and 170 million and 165 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 September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
2017
|
|
|
2016
|
Net income (loss)
|
|
|
$
|
(23
|
)
|
|
|
$
|
22
|
|
|
|
|
$
|
168
|
|
|
|
$
|
(513
|
)
|
Depletion, depreciation and amortization
|
|
|
|
355
|
|
|
|
|
386
|
|
|
|
|
|
1,033
|
|
|
|
|
1,123
|
|
Exploration and abandonments
|
|
|
|
18
|
|
|
|
|
19
|
|
|
|
|
|
78
|
|
|
|
|
96
|
|
Impairment of oil and gas properties
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
|
285
|
|
|
|
|
32
|
|
Impairment of inventory and other property and equipment
|
|
|
|
—
|
|
|
|
|
1
|
|
|
|
|
|
1
|
|
|
|
|
6
|
|
Accretion of discount on asset retirement obligations
|
|
|
|
5
|
|
|
|
|
5
|
|
|
|
|
|
14
|
|
|
|
|
14
|
|
Interest expense
|
|
|
|
37
|
|
|
|
|
50
|
|
|
|
|
|
118
|
|
|
|
|
161
|
|
Income tax (benefit) provision
|
|
|
|
(11
|
)
|
|
|
|
(78
|
)
|
|
|
|
|
79
|
|
|
|
|
(362
|
)
|
Gain on disposition of assets, net
|
|
|
|
—
|
|
|
|
|
(1
|
)
|
|
|
|
|
(205
|
)
|
|
|
|
(4
|
)
|
Derivative related activity
|
|
|
|
161
|
|
|
|
|
93
|
|
|
|
|
|
(91
|
)
|
|
|
|
628
|
|
Amortization of stock-based compensation
|
|
|
|
18
|
|
|
|
|
22
|
|
|
|
|
|
61
|
|
|
|
|
66
|
|
Other
|
|
|
|
13
|
|
|
|
|
17
|
|
|
|
|
|
48
|
|
|
|
|
50
|
|
EBITDAX (a)
|
|
|
|
573
|
|
|
|
|
536
|
|
|
|
|
|
1,589
|
|
|
|
|
1,297
|
|
Cash interest expense
|
|
|
|
(36
|
)
|
|
|
|
(48
|
)
|
|
|
|
|
(114
|
)
|
|
|
|
(150
|
)
|
Current income tax benefit
|
|
|
|
—
|
|
|
|
|
22
|
|
|
|
|
|
—
|
|
|
|
|
22
|
|
Discretionary cash flow (b)
|
|
|
|
537
|
|
|
|
|
510
|
|
|
|
|
|
1,475
|
|
|
|
|
1,169
|
|
Cash exploration expense
|
|
|
|
(17
|
)
|
|
|
|
(18
|
)
|
|
|
|
|
(59
|
)
|
|
|
|
(55
|
)
|
Changes in operating assets and liabilities
|
|
|
|
(65
|
)
|
|
|
|
(51
|
)
|
|
|
|
|
(118
|
)
|
|
|
|
(155
|
)
|
Net cash provided by operating activities
|
|
|
$
|
455
|
|
|
|
$
|
441
|
|
|
|
|
$
|
1,298
|
|
|
|
$
|
959
|
|
_____________
|
(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 cash
exploration expense.
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
|
(in millions, except per share data)
|
|
Income adjusted for noncash mark-to-market ("MTM") derivative losses, as
presented in this press release, is presented and reconciled to
Pioneer's net loss attributable to common stockholders (determined in
accordance with GAAP) because Pioneer believes that this non-GAAP
financial measure reflects an additional way of viewing aspects of
Pioneer's business that, when viewed together with its financial results
computed in accordance with GAAP, provides 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 this non-GAAP financial measure may enhance investors'
ability to assess Pioneer's historical and future financial performance.
This non-GAAP financial measure is not intended to be a substitute 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 loss
attributable to common stockholders for the three months ended September
30, 2017, as determined in accordance with GAAP, to adjusted income
excluding noncash MTM derivative losses.
|
|
|
After-tax Amounts
|
|
|
Amounts Per Share
|
Net loss attributable to common stockholders
|
|
|
$
|
(23
|
)
|
|
|
$
|
(0.13
|
)
|
Noncash MTM derivative losses, net ($161 million pretax)
|
|
|
|
103
|
|
|
|
|
0.61
|
|
Adjusted income excluding noncash MTM derivative losses
|
|
|
$
|
80
|
|
|
|
$
|
0.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
SUPPLEMENTAL INFORMATION
|
|
Open Commodity Derivative Positions as of October 31, 2017
|
(Volumes are average daily amounts)
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
Year Ending December 31,
|
|
|
|
Fourth Quarter
|
|
|
|
2018
|
|
|
2019
|
Average Daily Oil Production Associated with Derivatives (Bbl):
|
|
|
|
|
|
|
|
|
|
|
Collar contracts:
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
6,000
|
|
|
|
|
|
3,000
|
|
|
|
—
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
70.40
|
|
|
|
|
$
|
58.05
|
|
|
$
|
—
|
Floor
|
|
|
$
|
50.00
|
|
|
|
|
$
|
45.00
|
|
|
$
|
—
|
Collar contracts with short puts:
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
155,000
|
|
|
|
|
|
152,781
|
|
|
|
—
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
62.12
|
|
|
|
|
$
|
57.72
|
|
|
$
|
—
|
Floor
|
|
|
$
|
49.82
|
|
|
|
|
$
|
47.36
|
|
|
$
|
—
|
Short put
|
|
|
$
|
41.02
|
|
|
|
|
$
|
37.32
|
|
|
$
|
—
|
Basis swap contracts (a):
|
|
|
|
|
|
|
|
|
|
|
Midland-Cushing index swap volume
|
|
|
$
|
6,630
|
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Price differential ($/Bbl)
|
|
|
$
|
(1.09
|
)
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Average Daily NGL Production Associated with Derivatives:
|
|
|
|
|
|
|
|
|
|
|
Propane swap contracts (b):
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
$
|
1,658
|
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Price
|
|
|
$
|
37.80
|
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Ethane collar contracts (c):
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
3,000
|
|
|
|
|
|
—
|
|
|
|
—
|
Index price:
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
11.83
|
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Floor
|
|
|
$
|
8.68
|
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Ethane basis swap contracts (d):
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
6,920
|
|
|
|
|
|
6,920
|
|
|
|
6,920
|
Price differential
|
|
|
$
|
1.60
|
|
|
|
|
$
|
1.60
|
|
|
$
|
1.60
|
Average Daily Gas Production Associated with Derivatives (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
—
|
|
|
|
|
|
82,740
|
|
|
|
—
|
NYMEX price
|
|
|
$
|
—
|
|
|
|
|
$
|
3.03
|
|
|
$
|
—
|
Collar contracts with short puts:
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
300,000
|
|
|
|
|
|
62,329
|
|
|
|
—
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
3.60
|
|
|
|
|
$
|
3.56
|
|
|
$
|
—
|
Floor
|
|
|
$
|
2.96
|
|
|
|
|
$
|
2.91
|
|
|
$
|
—
|
Short put
|
|
|
$
|
2.47
|
|
|
|
|
$
|
2.37
|
|
|
$
|
—
|
Basis swap contracts:
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent index swap volume (e)
|
|
|
|
45,000
|
|
|
|
|
|
—
|
|
|
|
—
|
Price differential ($/MMBtu)
|
|
|
$
|
(0.32
|
)
|
|
|
|
$
|
—
|
|
|
$
|
—
|
Permian Basin index swap volume (f)
|
|
|
|
39,783
|
|
|
|
|
|
56,603
|
|
|
|
80,000
|
Price differential ($/MMBtu)
|
|
|
$
|
0.36
|
|
|
|
|
$
|
0.32
|
|
|
$
|
0.31
|
_____________
|
(a)
|
|
Represent swap contracts that fix the basis differential between
Midland, Texas oil prices and West Texas Intermediate ("WTI") oil
prices at Cushing, Oklahoma.
|
(b)
|
|
Represent swap contracts that reduce the price volatility of propane
forecasted for sale by the Company at Mont Belvieu, Texas-posted
prices.
|
(c)
|
|
Represent collar contracts that reduce the price volatility of
ethane forecasted for sale by the Company at Mont Belvieu,
Texas-posted prices.
|
(d)
|
|
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.
|
(e)
|
|
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.
|
(f)
|
|
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.
|
|
|
|
Marketing derivatives. Periodically, the Company enters into buy
and sell marketing arrangements to fulfill firm pipeline transportation
commitments. Associated with these marketing arrangements, the Company
may enter into index swaps that mitigate price risk. As of September 30,
2017, the Company was party to (i) oil index swap contracts for 10,000
Bbls per day of November and December 2017 transportation commitments
with a price differential of $4.18 per Bbl between NYMEX WTI and
Louisiana Light Sweet oil ("LLS") and (ii) oil index swap contracts for
10,000 Bbls per day of January through August 2018 transportation
commitments with a price differential of $3.18 per Bbl between NYMEX WTI
and LLS.
Interest rate derivatives. As of September 30, 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. In October 2017, the Company liquidated its interest rate
derivative contracts for cash proceeds of $5 million.
|
|
PIONEER NATURAL RESOURCES COMPANY
|
SUPPLEMENTAL INFORMATION (continued)
|
|
Derivative Gains (Losses), Net
|
(in millions)
|
|
The following table summarizes net derivative gains (losses) that the
Company recorded in earnings for the three and nine months ended
September 30, 2017:
|
|
|
Three Months Ended September 30, 2017
|
|
|
Nine Months Ended September 30, 2017
|
Noncash changes in fair value:
|
|
|
|
|
|
|
Oil derivative gains (losses)
|
|
|
$
|
(160
|
)
|
|
|
$
|
61
|
|
NGL derivative gains
|
|
|
|
—
|
|
|
|
|
2
|
|
Gas derivative gains (losses)
|
|
|
|
(1
|
)
|
|
|
|
29
|
|
Interest rate derivative losses
|
|
|
|
—
|
|
|
|
|
(1
|
)
|
Total noncash derivative gains (losses), net
|
|
|
|
(161
|
)
|
|
|
|
91
|
|
|
|
|
|
|
|
|
Net cash receipts on settled derivative instruments:
|
|
|
|
|
|
|
Oil derivative receipts
|
|
|
|
29
|
|
|
|
|
61
|
|
NGL derivative payments
|
|
|
|
(2
|
)
|
|
|
|
(1
|
)
|
Gas derivative receipts
|
|
|
|
1
|
|
|
|
|
1
|
|
Diesel derivative receipts
|
|
|
|
—
|
|
|
|
|
1
|
|
Total cash receipts on settled derivative instruments, net
|
|
|
|
28
|
|
|
|
|
62
|
|
Total derivative gains (losses), net
|
|
|
$
|
(133
|
)
|
|
|
$
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20171101006696/en/
Copyright Business Wire 2017