Pioneer Natural Resources Reports Third Quarter 2015 Financial and Operating Results
Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the
Company”) today announced financial and operating results for the
quarter ended September 30, 2015.
Pioneer reported third quarter net income attributable to common
stockholders of $646 million, or $4.27 per diluted share. Without the
effect of noncash derivative mark-to-market gains and other unusual
items, adjusted results for the third quarter were a net loss of $1
million after tax, or $0.01 per diluted share.
Third quarter and other recent highlights included:
-
producing 211 thousand barrels oil equivalent per day (MBOEPD) in the
third quarter, of which 52% was oil; production grew by 7% compared to
the second quarter of 2015 and was above the top end of Pioneer’s
third quarter guidance range of 205 MBOEPD to 210 MBOEPD; third
quarter production growth was driven by the Company’s strong
Spraberry/Wolfcamp horizontal drilling program; Spraberry/Wolfcamp
production increased 15 MBOEPD, or 13%, compared to the second quarter
of 2015, with oil production increasing by 10 thousand barrels per day;
-
updating 2015 full-year production growth forecast to 11% from 10%+,
reflecting an increase in forecasted Spraberry/Wolfcamp production
growth from 22% - 24% to 25% - 26%;
-
realizing significant service cost reductions and efficiency gains
that have resulted in (i) a 25% decrease in drilling and completion
costs compared to 2014, (ii) a 20% reduction in horizontal tank
battery costs compared to 2014 and (iii) an 18% reduction in lease
operating expenses per barrel oil equivalent (BOE) compared to 2014;
the Company expects to achieve additional cost reductions and
efficiency gains by early 2016, with drilling and completion costs and
horizontal tank battery costs expected to decline by more than 30% and
25%, respectively, compared to 2014;
-
reducing the average time to drill, complete and place a three-well
horizontal pad on production (spud-to-POP) to 135 days in the
Spraberry/Wolfcamp, driven primarily by a reduction in the average
drilling time by seven days per well;
-
placing 33 horizontal wells on production during the third quarter in
the northern Spraberry/Wolfcamp; early production results from 30
wells targeting the Wolfcamp B (28 wells) and the Wolfcamp A (two
wells) intervals are on average tracking estimated ultimate recoveries
(EURs) of more than 15% above a type curve that is expected to recover
one million barrels oil equivalent (MMBOE) over the life of the well,
with average 24-hour peak production rates of approximately 1,900
barrels oil equivalent per day (BOEPD) and a 78% oil content; 19 wells
of the 30 wells benefited from completion optimization;
-
continuing to deliver an average EUR of 1 MMBOE from all Wolfcamp B
and Wolfcamp A interval wells drilled in the northern
Spraberry/Wolfcamp since 2013;
-
benefiting from the capital efficiency associated with drilling
horizontal wells with lateral lengths ranging from 7,500 feet to
10,000 feet across Pioneer’s contiguous Spraberry/Wolfcamp acreage
position;
-
closing the sale of Pioneer’s Eagle Ford Shale midstream business in
July for $2.15 billion gross ($1.0 billion net); received net sale
proceeds of $530 million at closing, with an additional $500 million
to be received in July 2016; resulted in a book gain of $778 million
before tax, or a return on Pioneer’s equity investment (approximately
$162 million) of more than seven times in five years, including sales
proceeds and cash distributions received prior to the sale; and
-
maintaining a strong balance sheet, with net debt-to-book
capitalization of 19% at the end of the third quarter and cash on hand
of $581 million.
Pioneer’s latest outlook for the 2015 through 2018 period includes:
-
continuing to protect the Company’s cash flow through the use of
commodity derivatives, with (i) forecasted oil production coverage for
the remainder of 2015 of approximately 90%, with most of the volumes
protected by swaps at $71 per barrel, (ii) forecasted oil production
coverage for 2016 increasing to approximately 85% using a combination
of swaps and three-way collars, (iii) forecasted oil production
coverage for 2017 increasing to 20% using three-way collars and (iv)
forecasted gas production coverage for the remainder of 2015 and for
2016 of approximately 85% and approximately 70%, respectively, using a
combination of swaps and three-way collars in both years;
-
continuing to forecast compound annual production growth of 15%+ (oil
growth of 20%+) over the 2016 through 2018 period; the Company expects
to deliver this forecasted production growth using fewer rigs in the
Spraberry/Wolfcamp than the 28 rigs previously anticipated due to
efficiency gains and drilling higher EUR wells; eight rigs were added
in the northern Spraberry/Wolfcamp between July 1 and late October,
with no further rig additions planned for 2015 (current
Spraberry/Wolfcamp rig count is 18 rigs, of which 14 rigs are
operating in the northern area and four rigs are operating in the
southern Wolfcamp joint venture area);
-
timing of future rig additions in the Spraberry/Wolfcamp over the 2016
through 2018 period will be dependent on numerous factors, including
the pace of incremental efficiency gains, further productivity
improvements and continuing to achieve strong well returns;
-
delivering internal rates of return (IRRs) in the Spraberry/Wolfcamp
ranging from 45% to 60% at current strip commodity prices (includes
capital costs for tank batteries and saltwater disposal facilities);
and
-
operating six horizontal rigs in the Eagle Ford Shale that are
expected to keep production essentially flat over the 2016 through
2018 period compared to the third quarter of 2015.
Scott D. Sheffield, Chairman and CEO, stated, “Despite the weak
commodity price environment, the Company reported a great quarter that
was highlighted by the impressive production growth delivered by our
horizontal drilling program in the Spraberry/Wolfcamp. This drilling
program continues to provide strong returns due to our aggressive
pursuit of cost reductions and efficiency gains, combined with
increasing the EURs of our oil wells. We are putting rigs back to work
and expect to be able to deliver 15%+ compound annual production growth
over the 2016 through 2018 period using fewer rigs than previously
anticipated as a result of improving capital efficiency and well
productivity.”
Mark-To-Market Derivative Gains and Unusual
Items Included in Third Quarter 2015 Earnings
Pioneer’s third quarter earnings included noncash mark-to-market gains
on derivatives of $214 million after tax, or $1.42 per diluted share.
Third quarter earnings also included a net gain of $432 million after
tax, or $2.85 per diluted share, related to the following unusual items:
-
a gain of $499 million after tax, or $3.29 per diluted share, related
to the sale of Pioneer’s Eagle Ford Shale midstream business,
-
a charge of $58 million after tax, or $0.38 per diluted share,
associated with the impairment of (i) proved properties in South Texas
(Edwards gas play), (ii) unproved acreage in southeastern Colorado
(Black Fox prospect) and (iii) vertical pipe inventory in the
Spraberry/Wolfcamp;
-
a restructuring charge of $6 million after tax, or $0.04 per diluted
share, related to the closing of Pioneer’s Denver office and the
streamlining of operations in the Raton Basin; and
-
a loss of $2 million after tax, or $0.01 per diluted share, related to
discontinued operations.
Spraberry/Wolfcamp Operations Update and 2015
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. The Company believes it has greater than 10 billion
barrels oil equivalent of net recoverable resource potential from
horizontal drilling across its entire acreage position based on its
extensive geologic data and successful drilling results to date.
Pioneer’s contiguous acreage position allows for decades of drilling
horizontal wells with lateral lengths ranging from 7,500 feet to 10,000
feet, resulting in improved capital efficiency. For example, horizontal
wells drilled in the Wolfcamp B interval with lateral lengths of 10,000
feet generate net present values of approximately $8 million compared to
wells with shorter lateral lengths of 5,000 feet, which generate net
present values of approximately $2.3 million [assuming an oil price of
$60 per barrel and a gas price of $3.25 per thousand cubic feet (MCF)
less applicable differentials]. The longer lateral length wells pay out
in approximately 18 months, which is twice as fast as the shorter
lateral length wells.
In the northern Spraberry/Wolfcamp, the Company placed 33 horizontal
wells on production during the third quarter. Early production from 30
wells targeting the Wolfcamp B (28 wells) and Wolfcamp A (two wells)
intervals are on average tracking more than 15% above a 1 MMBOE EUR type
curve. These wells delivered an average 24-hour peak production rate of
approximately 1,900 BOEPD, with 78% oil content. Nineteen wells of the
30 wells benefited from Pioneer’s completion optimization program (17
Wolfcamp B wells and two Wolfcamp A wells). This program includes
optimizing stage length, clusters per stage, fluid volumes and proppant
concentration.
The remaining wells placed on production in the second quarter were two
Wolfcamp D wells with an average 24-hour peak production rate of
approximately 1,600 BOEPD and one Lower Spraberry Shale well that has
not yet reached its initial 24-hour peak production rate.
Pioneer has successfully placed 107 horizontal Wolfcamp B wells and 30
horizontal Wolfcamp A wells on production since it commenced drilling
horizontal wells in the northern Spraberry/Wolfcamp in 2013. The average
production from these wells is tracking a type curve that is expected to
recover 1 MMBOE over the life of the well.
The Company is currently operating 14 horizontal rigs in the northern
Spraberry/Wolfcamp, of which eight have been added since July. The
drilling program in the northern Spraberry/Wolfcamp continues to deliver
strong EURs and returns as a result of cost reduction efforts, drilling
and completion efficiency gains and rock quality. Well productivity
reflects EURs averaging approximately 1 MMBOE, with IRRs averaging 50%
to 60% at current strip commodity prices. These returns include the cost
for tank battery and saltwater disposal facilities. The current cost to
drill and complete a horizontal well is approximately $8.0 million to
$8.5 million, assuming average lateral lengths of approximately 9,000
feet, a 25% cost reduction compared to 2014. A reduction of
approximately 30 days in the average time between beginning to drill a
three-well pad and placing the pad on production has contributed to the
significant reduction in costs. This primarily reflects a reduction in
drilling days per well from 32 days in the second quarter to 25 days in
the third quarter. The improvement has been driven in large part by rigs
drilling one interval consistently and utilizing a modified three-string
casing design. Pioneer’s best drilling times to date have been 16 days
in the northern area and 13 days in the joint venture area. The 25% cost
reduction has been partially offset by the higher costs associated with
the larger completions that are now being used. Costs are expected to be
reduced by more than 30% by early 2016 compared to 2014 levels as
additional cost reductions and efficiency gains are achieved. Completion
optimization and dissolvable plug technology testing are continuing.
Pioneer expects its well costs in the northern Spraberry/Wolfcamp to
decrease to $7.5 million to $8.0 million per well by early 2016.
Pioneer expects to place approximately 110 new horizontal wells on
production in the northern Spraberry/Wolfcamp during 2015. Of these, 75%
will be Wolfcamp B interval wells and the remainder will be split
between Wolfcamp A, Wolfcamp D and Lower Spraberry Shale interval wells.
Seventy-six wells were placed on production during the first nine months
of 2015. The Company plans to spud approximately 120 new horizontal
wells in 2015 in the northern Spraberry/Wolfcamp utilizing two-well and
three-well pads. Approximately 80% of these new wells will be drilled in
the Wolfcamp B interval and the remaining 20% in the Wolfcamp A and
Lower Spraberry Shale intervals.
In the southern Wolfcamp joint venture area, Pioneer continues to
operate four horizontal rigs. The drilling program in this area
continues to deliver strong EURs and returns as a result of cost
reduction efforts, drilling and completion efficiency gains and drilling
being focused in the northern part of the southern Wolfcamp joint
venture area where the best rock quality is located.
Well performance in the southern Wolfcamp joint venture area reflects
EURs averaging approximately 900 MBOE, with IRRs averaging 45% at
current strip commodity prices. These returns exclude the carry that
Pioneer is currently receiving from Sinochem, but include the cost of
tank batteries and saltwater disposal facilities. The current cost to
drill and complete a horizontal well is approximately $7.5 million to
$8.0 million, assuming average lateral lengths of approximately 9,000
feet and a 25% cost reduction compared to 2014. Costs are expected to be
reduced by more than 30% by early 2016 as additional cost reductions and
efficiency gains are achieved. The joint venture drilling program is
experiencing similar spud-to-POP time reductions and efficiency gains as
in the northern Spraberry/Wolfcamp. The Company expects its well costs
in the southern Wolfcamp joint venture area to decrease to $7.0 million
to $7.5 million per well by early 2016.
In the southern Wolfcamp joint venture area, Pioneer expects to place
approximately 85 horizontal wells on production during 2015. Of these,
75% will be Wolfcamp B interval wells. The remainder will be split
between Wolfcamp A and Wolfcamp D interval wells. Seventy-seven wells
were placed on production during the first nine months of 2015. The
Company plans to spud approximately 55 new wells in 2015 utilizing
two-well and three-well pads. More than 90% of these new wells will be
drilled in the Wolfcamp B interval.
The Company’s successful horizontal drilling program continues to drive
production growth, with total Spraberry/Wolfcamp production growing 15
MBOEPD in the third quarter to 134 MBOEPD, or 13%, compared to the
second quarter of 2015. Oil production in the third quarter grew 10
thousand barrels per day compared to the second quarter and represented
65% of total third quarter production in this asset. Gas and natural gas
liquids (NGLs) production increased 5 MBOEPD from the second quarter,
benefiting from the improved recovery of field gas as a result of
gathering system upgrades (e.g. field compression and line looping) and
WTG’s (West Texas Gas) new Sale Ranch gas processing plant coming
on-line. A total of 52 horizontal wells were placed on production during
the third quarter. Horizontal production was 75 MBOEPD and vertical
production was 59 MBOEPD, reflecting the first time that horizontal
production has surpassed vertical production. Third quarter production
was negatively impacted by approximately 3 MBOEPD related to the
Company’s continuing decision to reject ethane due to weak market
conditions.
The Company expects to place approximately 40 horizontal wells on
production in the fourth quarter of 2015, a reduction of 12 wells from
the third quarter. As a result of this reduction and the timing of wells
being placed on production, fourth quarter production is expected to be
down slightly compared to the third quarter. Even with this reduction,
Spraberry/Wolfcamp production is now forecasted to grow by 25% to 26% in
2015 compared to the 22% to 24% previously forecasted due to strong
year-to-date horizontal production performance. It also assumes that the
Company will reject 3 MBOEPD of ethane over the remainder of 2015 due to
continuing weak market conditions.
Spraberry/Wolfcamp Infrastructure Plans
Pioneer is focused on optimizing the development of the
Spraberry/Wolfcamp, which includes ensuring that future infrastructure
requirements are constructed. These requirements include the build-out
of horizontal tank batteries and saltwater disposal facilities,
construction of a field-wide water distribution system, construction of
additional gas processing facilities and the expansion of the sand mine
in Brady, Texas.
Forecasted spending for the construction of tank batteries and saltwater
disposal facilities reflects a combination of building new facilities
and expanding existing facilities. The Company expects to spend
approximately $175 million in 2015 for horizontal tank batteries and
saltwater disposal facilities in the northern Spraberry/Wolfcamp and the
southern Wolfcamp joint venture areas. This amount is net of the carry
that Pioneer currently receives from Sinochem. A spending level of
approximately $200 million is expected in 2016.
Pioneer owns a 27% interest in Targa Resources’ (“Targa”) West Texas gas
processing system and a 30% interest in WTG’s Sale Ranch gas processing
system. These investments (i) improve Pioneer’s contract terms for field
gas processing, (ii) ensure the timely hookup of Pioneer’s new
horizontal wells and (iii) provide the Company with opportunities to
benefit from third-party processing revenues. The $70 million that is
being spent in 2015 includes the initial construction costs for Targa’s
new 200 million cubic feet per day (MMCFPD) gas processing plant in
Martin County (Buffalo plant). It also includes gathering system
upgrades (e.g. field compression and line looping) and new connections.
The system upgrades are resulting in the improved recovery of field gas
that results in higher gas and NGL sales volumes. Spending in 2016 is
expected to be approximately $50 million, including capital to complete
the Buffalo plant, which is expected to be placed into service during
the second quarter of 2016. No new plants are expected to be required
after the Buffalo plant is completed until there is a significant
increase in the Midland Basin rig count.
The Company’s long-term plans call for the construction of a field-wide
water distribution system to reduce the cost of water for drilling and
completion activities and to ensure that adequate supplies of
non-potable water are available for use in the development of the
Spraberry/Wolfcamp field. The system is expected to be built out based
on the timing of adding new rigs and the economics associated with
adding new water sources. The 2015 budget includes $130 million for the
water distribution system, with a similar amount expected to be spent in
2016. The 2015 program includes engineering, right-of-way acquisition,
pipeline installation and connecting a third-party Santa Rosa brackish
water source. It also includes the construction of a delivery line for
100 thousand barrels per day of effluent water that will be purchased
from the City of Odessa. The line is targeted for completion by the end
of 2015. Several subsystems and frac ponds to efficiently distribute the
Odessa water to Pioneer drilling locations will also be constructed and
are targeted for completion during 2016. The Company continues to pursue
a long-term agreement to purchase effluent water from the City of
Midland.
Pioneer’s sand mine in Brady, Texas, which is strategically located
within close proximity (~190 miles) of the Spraberry/Wolfcamp field,
provides a low-cost sand source for the Company’s horizontal drilling
program. Engineering work and site preparation for the expansion of the
mine from 750 thousand tons to 2.1 million tons was completed during the
first half of 2015 at a cost of approximately $25 million. The timing
for completing the expansion, which is expected to cost approximately
$75 million, will depend on the timing of future horizontal rig
additions by Pioneer.
Eagle Ford Shale Operations Update and 2015
Outlook
In the liquids-rich area of the Eagle Ford Shale play in South Texas,
Pioneer’s horizontal rig count was reduced from nine rigs in 2014 to six
rigs in early 2015. Drilling activity is focused in Karnes and DeWitt
counties. The Company placed 36 wells on production in the Eagle Ford
Shale during the third quarter, of which 21 wells were in Upper targets
and 15 wells were in Lower targets.
Pioneer’s third quarter production from the Eagle Ford Shale averaged 43
MBOEPD, of which 40% was condensate. Production for the third quarter
was negatively impacted by well performance issues resulting from well
completion design changes (primarily reduced fluid level concentrations)
that were made early in 2015 to reduce costs. Future completions will
use higher fluid level concentrations in an effort to return well
performance to historical levels. The Company plans to also test higher
proppant concentrations, shorter stage lengths and tighter cluster
spacing. Third quarter production was also negatively impacted by
unplanned facilities downtime and approximately 2 MBOEPD related to the
Company’s continuing decision to reject ethane due to weak market
conditions.
The Company placed 85 wells on production during the first nine months
of 2015 and is targeting placing approximately 100 wells on production
for full-year 2015. Eagle Ford Shale production is forecasted to average
45 MBOEPD in 2015, essentially flat compared to 2014. This forecast
assumes that the Company will reject 2 MBOEPD of ethane over the
remainder of 2015 due to continuing weak market conditions.
2015 Capital Budget
The Company’s capital budget for 2015 remains at $2.2 billion (excluding
acquisitions, asset retirement obligations, capitalized interest and
geological and geophysical G&A). The budget includes $1.95 billion for
drilling-related activities and $250 million related to the development
of the Spraberry/Wolfcamp water infrastructure, vertical integration and
facilities.
The following provides a breakdown of the drilling capital by asset:
-
Northern Spraberry/Wolfcamp - $1.4 billion (includes $1,035 million
for the horizontal drilling program, $20 million for the vertical
drilling program, $275 million for infrastructure additions and land
and $70 million for gas processing facilities)
-
Southern Wolfcamp joint venture area (net of carry) - $120 million
(includes $90 million for the horizontal drilling program and $30
million for infrastructure additions and land)
-
Eagle Ford Shale - $390 million (includes $335 million for the
horizontal drilling program and $55 million for infrastructure
additions and land)
-
Other assets - $40 million
The 2015 capital budget is expected to be funded from forecasted
operating cash flow of $1.5 billion (assuming average 2015 estimated
prices of $50 per barrel for oil and $2.75 per MCF for gas) and cash on
the balance sheet.
Pioneer’s net debt at the end of the third quarter of 2015 was $2.1
billion, with net debt-to-book capitalization of 19%. The Company will
continue to target net debt-to-operating cash flow below 1.5 and net
debt-to-book capitalization below 35%.
Third Quarter 2015 Financial Review
Sales volumes for the third quarter of 2015 averaged 211 MBOEPD. Oil
sales averaged 109 thousand barrels per day (MBPD), NGL sales averaged
42 MBPD and gas sales averaged 360 MMCFPD.
The average realized price for oil was $42.46 per barrel. The average
realized price for NGLs was $12.39 per barrel, and the average realized
price for gas was $2.53 per MCF. These prices exclude the effects of
derivatives.
Production costs averaged $11.62 per BOE. Depreciation, depletion and
amortization (DD&A) expense averaged $18.77 per BOE. Exploration and
abandonment costs were $25 million, principally comprised of $7 million
attributable to drilling, acreage and other abandonments, $3 million for
seismic data and $15 million for personnel costs. General and
administrative expense totaled $81 million. Interest expense was $46
million, and other expense was $60 million, which included $22 million
of stacked drilling rig charges, $12 million of vertical pipe inventory
impairment charges and $9 million of restructuring charges related to
the closing of Pioneer’s Denver office and the streamlining of
operations in the Raton Basin.
Fourth Quarter 2015 Financial Outlook
The Company’s fourth quarter 2015 outlook for certain operating and
financial items is provided below.
Production is forecasted to average 206 MBOEPD to 211 MBOEPD.
Production costs are expected to average $11.00 per BOE to $13.00 per
BOE. DD&A expense is expected to average $18.50 per BOE to $20.50 per
BOE. Total exploration and abandonment expense is forecasted to be $25
million to $35 million.
General and administrative expense is expected to be $80 million to $85
million, interest expense is expected to be $45 million to $50 million
and other expense is expected to be $40 million to $50 million. Other
expense includes $18 million to $20 million for stacked drilling rig
charges. Accretion of discount on asset retirement obligations is
expected to be $3 million to $5 million.
The Company’s effective income tax rate is expected to range from 35% to
40%. Current income taxes are expected to be $10 million to $20 million
and are primarily attributable to alternative minimum taxes that remain
to be recognized as a result of the Eagle Ford Shale midstream sale.
The Company’s financial and derivative mark-to-market results and open
derivatives positions are outlined on the attached schedules.
Earnings Conference Call
On Tuesday, November 3, 2015, at 9:00 a.m. Central Time, Pioneer will
discuss its financial and operating results for the quarter ended
September 30, 2015, with an accompanying presentation. Instructions for
listening to the call and viewing the accompanying presentation are
shown below.
Website: www.pxd.com
Select
“Investors,” then “Earnings & Webcasts” to listen to the discussion,
view the presentation and see other related material.
Telephone: Dial (800) 533-9703 and confirmation code: 7681585 five
minutes before the call. View the presentation via Pioneer’s website
address above.
A replay of the webcast will be archived on Pioneer’s website. A
telephone replay will be available through November 28, 2015, by dialing
(888) 203-1112 and confirmation code: 7681585.
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 news release 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, 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, uncertainties about estimates of reserves
and resource potential and the ability to add proved reserves in the
future, the assumptions underlying production forecasts, quality of
technical data, and 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 10-K and 10-Q Reports and
other filings with the U.S. Securities and Exchange Commission (SEC).
In addition, Pioneer may be subject to currently unforeseen risks
that may have a materially adverse impact on it. 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 news release, Pioneer includes estimates of
quantities of oil and gas using certain terms, such as “resource
potential,” “net recoverable resource potential,” “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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PIONEER NATURAL RESOURCES COMPANY
|
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UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
|
(in millions)
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September 30, 2015
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December 31, 2014
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ASSETS
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Current assets:
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|
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Cash and cash equivalents
|
|
|
$
|
581
|
|
|
|
$
|
1,025
|
|
Accounts receivable, net
|
|
|
|
413
|
|
|
|
|
440
|
|
Income taxes receivable
|
|
|
|
—
|
|
|
|
|
23
|
|
Inventories
|
|
|
|
238
|
|
|
|
|
241
|
|
Prepaid expenses
|
|
|
|
19
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|
|
|
|
15
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|
Notes receivable
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|
|
|
497
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|
|
|
|
—
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Derivatives
|
|
|
|
632
|
|
|
|
|
578
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|
Other
|
|
|
|
23
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|
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|
|
37
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|
Total current assets
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|
|
|
2,403
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|
|
|
|
2,359
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|
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|
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Property, plant and equipment, at cost:
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|
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Oil and gas properties, using the successful efforts method of
accounting
|
|
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|
16,969
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|
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15,821
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Accumulated depletion, depreciation and amortization
|
|
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(6,407
|
)
|
|
|
|
(5,431
|
)
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Total property, plant and equipment
|
|
|
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10,562
|
|
|
|
|
10,390
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|
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|
|
|
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|
Goodwill
|
|
|
|
272
|
|
|
|
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272
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Other property and equipment, net
|
|
|
|
1,480
|
|
|
|
|
1,391
|
|
Investment in unconsolidated affiliate
|
|
|
|
—
|
|
|
|
|
239
|
|
Derivatives
|
|
|
|
147
|
|
|
|
|
181
|
|
Other assets, net
|
|
|
|
101
|
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
$
|
14,965
|
|
|
|
$
|
14,926
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
|
$
|
849
|
|
|
|
$
|
1,320
|
|
Interest payable
|
|
|
|
36
|
|
|
|
|
40
|
|
Income taxes payable
|
|
|
|
27
|
|
|
|
|
1
|
|
Deferred income taxes
|
|
|
|
172
|
|
|
|
|
161
|
|
Derivatives
|
|
|
|
2
|
|
|
|
|
3
|
|
Other
|
|
|
|
61
|
|
|
|
|
55
|
|
Total current liabilities
|
|
|
|
1,147
|
|
|
|
|
1,580
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
|
2,675
|
|
|
|
|
2,665
|
|
Derivatives
|
|
|
|
1
|
|
|
|
|
2
|
|
Deferred income taxes
|
|
|
|
1,925
|
|
|
|
|
1,803
|
|
Other liabilities
|
|
|
|
236
|
|
|
|
|
287
|
|
Equity
|
|
|
|
8,981
|
|
|
|
|
8,589
|
|
|
|
|
|
|
|
|
|
|
|
$
|
14,965
|
|
|
|
$
|
14,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
|
$
|
557
|
|
|
|
$
|
967
|
|
|
|
$
|
1,670
|
|
|
|
$
|
2,795
|
|
Sales of purchased oil and gas
|
|
|
|
326
|
|
|
|
|
202
|
|
|
|
|
665
|
|
|
|
|
554
|
|
Interest and other
|
|
|
|
(17
|
)
|
|
|
|
2
|
|
|
|
|
—
|
|
|
|
|
9
|
|
Derivative gains, net
|
|
|
|
573
|
|
|
|
|
341
|
|
|
|
|
617
|
|
|
|
|
19
|
|
Gain on disposition of assets, net
|
|
|
|
779
|
|
|
|
|
1
|
|
|
|
|
782
|
|
|
|
|
11
|
|
|
|
|
|
2,218
|
|
|
|
|
1,513
|
|
|
|
|
3,734
|
|
|
|
|
3,388
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
|
189
|
|
|
|
|
168
|
|
|
|
|
532
|
|
|
|
|
493
|
|
Production and ad valorem taxes
|
|
|
|
36
|
|
|
|
|
58
|
|
|
|
|
112
|
|
|
|
|
169
|
|
Depletion, depreciation and amortization
|
|
|
|
364
|
|
|
|
|
274
|
|
|
|
|
1,003
|
|
|
|
|
734
|
|
Purchased oil and gas
|
|
|
|
339
|
|
|
|
|
194
|
|
|
|
|
684
|
|
|
|
|
535
|
|
Impairment of oil and gas properties
|
|
|
|
72
|
|
|
|
|
—
|
|
|
|
|
210
|
|
|
|
|
—
|
|
Exploration and abandonments
|
|
|
|
25
|
|
|
|
|
22
|
|
|
|
|
79
|
|
|
|
|
80
|
|
General and administrative
|
|
|
|
81
|
|
|
|
|
81
|
|
|
|
|
246
|
|
|
|
|
244
|
|
Accretion of discount on asset retirement obligations
|
|
|
|
3
|
|
|
|
|
3
|
|
|
|
|
9
|
|
|
|
|
9
|
|
Interest
|
|
|
|
46
|
|
|
|
|
46
|
|
|
|
|
138
|
|
|
|
|
138
|
|
Other
|
|
|
|
60
|
|
|
|
|
20
|
|
|
|
|
170
|
|
|
|
|
55
|
|
|
|
|
|
1,215
|
|
|
|
|
866
|
|
|
|
|
3,183
|
|
|
|
|
2,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
|
1,003
|
|
|
|
|
647
|
|
|
|
|
551
|
|
|
|
|
931
|
|
Income tax provision
|
|
|
|
(355
|
)
|
|
|
|
(236
|
)
|
|
|
|
(195
|
)
|
|
|
|
(319
|
)
|
Income from continuing operations
|
|
|
|
648
|
|
|
|
|
411
|
|
|
|
|
356
|
|
|
|
|
612
|
|
Loss from discontinued operations, net of tax
|
|
|
|
(2
|
)
|
|
|
|
(37
|
)
|
|
|
|
(6
|
)
|
|
|
|
(113
|
)
|
Net income attributable to common stockholders
|
|
|
$
|
646
|
|
|
|
$
|
374
|
|
|
|
$
|
350
|
|
|
|
$
|
499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share attributable to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
$
|
4.29
|
|
|
|
$
|
2.84
|
|
|
|
$
|
2.36
|
|
|
|
$
|
4.24
|
|
Loss from discontinued operations
|
|
|
|
(0.01
|
)
|
|
|
|
(0.26
|
)
|
|
|
|
(0.04
|
)
|
|
|
|
(0.79
|
)
|
Net income
|
|
|
$
|
4.28
|
|
|
|
$
|
2.58
|
|
|
|
$
|
2.32
|
|
|
|
$
|
3.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share attributable to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
$
|
4.28
|
|
|
|
$
|
2.84
|
|
|
|
$
|
2.36
|
|
|
|
$
|
4.23
|
|
Loss from discontinued operations
|
|
|
|
(0.01
|
)
|
|
|
|
(0.26
|
)
|
|
|
|
(0.04
|
)
|
|
|
|
(0.79
|
)
|
Net income
|
|
|
$
|
4.27
|
|
|
|
$
|
2.58
|
|
|
|
$
|
2.32
|
|
|
|
$
|
3.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
149
|
|
|
|
|
143
|
|
|
|
|
149
|
|
|
|
|
143
|
|
Diluted
|
|
|
|
150
|
|
|
|
|
143
|
|
|
|
|
149
|
|
|
|
|
143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
|
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$
|
646
|
|
|
|
$
|
374
|
|
|
|
$
|
350
|
|
|
|
$
|
499
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
|
364
|
|
|
|
|
274
|
|
|
|
|
1,003
|
|
|
|
|
734
|
|
Impairment of oil and gas properties
|
|
|
|
72
|
|
|
|
|
—
|
|
|
|
|
210
|
|
|
|
|
—
|
|
Impairment of inventory and other property and equipment
|
|
|
|
12
|
|
|
|
|
3
|
|
|
|
|
21
|
|
|
|
|
7
|
|
Exploration expenses, including dry holes
|
|
|
|
7
|
|
|
|
|
1
|
|
|
|
|
22
|
|
|
|
|
11
|
|
Deferred income taxes
|
|
|
|
307
|
|
|
|
|
250
|
|
|
|
|
146
|
|
|
|
|
315
|
|
Gain on disposition of assets, net
|
|
|
|
(779
|
)
|
|
|
|
(1
|
)
|
|
|
|
(782
|
)
|
|
|
|
(11
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
|
3
|
|
|
|
|
3
|
|
|
|
|
9
|
|
|
|
|
9
|
|
Discontinued operations
|
|
|
|
(1
|
)
|
|
|
|
68
|
|
|
|
|
(4
|
)
|
|
|
|
247
|
|
Interest expense
|
|
|
|
5
|
|
|
|
|
4
|
|
|
|
|
14
|
|
|
|
|
13
|
|
Derivative related activity
|
|
|
|
(334
|
)
|
|
|
|
(337
|
)
|
|
|
|
(22
|
)
|
|
|
|
(39
|
)
|
Amortization of stock-based compensation
|
|
|
|
23
|
|
|
|
|
20
|
|
|
|
|
70
|
|
|
|
|
63
|
|
Other
|
|
|
|
20
|
|
|
|
|
16
|
|
|
|
|
13
|
|
|
|
|
42
|
|
Change in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
|
|
(23
|
)
|
|
|
|
(18
|
)
|
|
|
|
26
|
|
|
|
|
(77
|
)
|
Income taxes receivable
|
|
|
|
22
|
|
|
|
|
(15
|
)
|
|
|
|
23
|
|
|
|
|
(17
|
)
|
Inventories
|
|
|
|
15
|
|
|
|
|
(19
|
)
|
|
|
|
(29
|
)
|
|
|
|
(27
|
)
|
Prepaid expenses
|
|
|
|
(2
|
)
|
|
|
|
(13
|
)
|
|
|
|
(3
|
)
|
|
|
|
(11
|
)
|
Other current assets
|
|
|
|
2
|
|
|
|
|
3
|
|
|
|
|
(6
|
)
|
|
|
|
(1
|
)
|
Accounts payable
|
|
|
|
9
|
|
|
|
|
66
|
|
|
|
|
(266
|
)
|
|
|
|
96
|
|
Interest payable
|
|
|
|
(26
|
)
|
|
|
|
(26
|
)
|
|
|
|
(4
|
)
|
|
|
|
(26
|
)
|
Income taxes payable
|
|
|
|
27
|
|
|
|
|
—
|
|
|
|
|
26
|
|
|
|
|
1
|
|
Other current liabilities
|
|
|
|
(11
|
)
|
|
|
|
(37
|
)
|
|
|
|
(28
|
)
|
|
|
|
(30
|
)
|
Net cash provided by operating activities
|
|
|
|
358
|
|
|
|
|
616
|
|
|
|
|
789
|
|
|
|
|
1,798
|
|
Net cash used in investing activities
|
|
|
|
(2
|
)
|
|
|
|
(525
|
)
|
|
|
|
(1,208
|
)
|
|
|
|
(1,628
|
)
|
Net cash provided by (used in) financing activities
|
|
|
|
6
|
|
|
|
|
14
|
|
|
|
|
(25
|
)
|
|
|
|
(13
|
)
|
Net increase (decrease) in cash and cash equivalents
|
|
|
|
362
|
|
|
|
|
105
|
|
|
|
|
(444
|
)
|
|
|
|
157
|
|
Cash and cash equivalents, beginning of period
|
|
|
|
219
|
|
|
|
|
445
|
|
|
|
|
1,025
|
|
|
|
|
393
|
|
Cash and cash equivalents, end of period
|
|
|
$
|
581
|
|
|
|
$
|
550
|
|
|
|
$
|
581
|
|
|
|
$
|
550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
|
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
Average Daily Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
|
109,101
|
|
|
|
88,973
|
|
|
|
102,780
|
|
|
|
82,485
|
Natural gas liquids ("NGL") (Bbls)
|
|
|
|
41,617
|
|
|
|
39,819
|
|
|
|
37,903
|
|
|
|
37,319
|
Gas (Mcf)
|
|
|
|
359,957
|
|
|
|
343,711
|
|
|
|
358,594
|
|
|
|
336,749
|
Total (BOE)
|
|
|
|
210,711
|
|
|
|
186,077
|
|
|
|
200,448
|
|
|
|
175,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
|
$
|
42.46
|
|
|
$
|
90.82
|
|
|
$
|
45.63
|
|
|
$
|
92.94
|
NGL (per Bbl)
|
|
|
$
|
12.39
|
|
|
$
|
28.44
|
|
|
$
|
13.72
|
|
|
$
|
30.36
|
Gas (per Mcf)
|
|
|
$
|
2.53
|
|
|
$
|
3.79
|
|
|
$
|
2.53
|
|
|
$
|
4.28
|
Total (BOE)
|
|
|
$
|
28.75
|
|
|
$
|
56.51
|
|
|
$
|
30.52
|
|
|
$
|
58.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. 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. 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 from continuing
operations attributable to common stockholders, securities or other
contracts to issue common stock would not 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
attributable to common stockholders to basic and diluted net income
attributable to common stockholders for the three and nine months ended
September 30, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
|
$
|
646
|
|
|
|
$
|
374
|
|
|
|
$
|
350
|
|
|
|
$
|
499
|
|
Participating basic earnings
|
|
|
|
(6
|
)
|
|
|
|
(4
|
)
|
|
|
|
(3
|
)
|
|
|
|
(5
|
)
|
Basic and diluted net income attributable to common stockholders
|
|
|
$
|
640
|
|
|
|
$
|
370
|
|
|
|
$
|
347
|
|
|
|
$
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average common shares outstanding were 149 million for
both the three and nine months ended September 30, 2015 and diluted
weighted average common shares outstanding were 150 million and 149
million for the three and nine months ended September 30, 2015,
respectively. Basic and diluted weighted average common shares
outstanding were 143 million for the three and nine months ended
September 30, 2014.
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 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 or net cash provided by
operating activities, as defined by GAAP.
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$
|
646
|
|
|
|
$
|
374
|
|
|
|
$
|
350
|
|
|
|
$
|
499
|
|
Depletion, depreciation and amortization
|
|
|
|
364
|
|
|
|
|
274
|
|
|
|
|
1,003
|
|
|
|
|
734
|
|
Exploration and abandonments
|
|
|
|
25
|
|
|
|
|
22
|
|
|
|
|
79
|
|
|
|
|
80
|
|
Impairment of oil and gas properties
|
|
|
|
72
|
|
|
|
|
—
|
|
|
|
|
210
|
|
|
|
|
—
|
|
Impairment of inventory and other property and equipment
|
|
|
|
12
|
|
|
|
|
3
|
|
|
|
|
21
|
|
|
|
|
7
|
|
Accretion of discount on asset retirement obligations
|
|
|
|
3
|
|
|
|
|
3
|
|
|
|
|
9
|
|
|
|
|
9
|
|
Interest expense
|
|
|
|
46
|
|
|
|
|
46
|
|
|
|
|
138
|
|
|
|
|
138
|
|
Income tax provision
|
|
|
|
355
|
|
|
|
|
236
|
|
|
|
|
195
|
|
|
|
|
319
|
|
Gain on disposition of assets, net
|
|
|
|
(779
|
)
|
|
|
|
(1
|
)
|
|
|
|
(782
|
)
|
|
|
|
(11
|
)
|
Loss from discontinued operations, net of tax
|
|
|
|
2
|
|
|
|
|
37
|
|
|
|
|
6
|
|
|
|
|
113
|
|
Derivative related activity
|
|
|
|
(334
|
)
|
|
|
|
(337
|
)
|
|
|
|
(22
|
)
|
|
|
|
(39
|
)
|
Amortization of stock-based compensation
|
|
|
|
23
|
|
|
|
|
20
|
|
|
|
|
70
|
|
|
|
|
63
|
|
Other
|
|
|
|
20
|
|
|
|
|
16
|
|
|
|
|
13
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX (a)
|
|
|
|
455
|
|
|
|
|
693
|
|
|
|
|
1,290
|
|
|
|
|
1,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash interest expense
|
|
|
|
(41
|
)
|
|
|
|
(42
|
)
|
|
|
|
(124
|
)
|
|
|
|
(125
|
)
|
Current income tax (provision) benefit
|
|
|
|
(48
|
)
|
|
|
|
14
|
|
|
|
|
(49
|
)
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary cash flow (b)
|
|
|
|
366
|
|
|
|
|
665
|
|
|
|
|
1,117
|
|
|
|
|
1,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations cash activity
|
|
|
|
(3
|
)
|
|
|
|
31
|
|
|
|
|
(10
|
)
|
|
|
|
134
|
|
Cash exploration expense
|
|
|
|
(18
|
)
|
|
|
|
(21
|
)
|
|
|
|
(57
|
)
|
|
|
|
(69
|
)
|
Changes in operating assets and liabilities
|
|
|
|
13
|
|
|
|
|
(59
|
)
|
|
|
|
(261
|
)
|
|
|
|
(92
|
)
|
Net cash provided by operating activities
|
|
|
$
|
358
|
|
|
|
$
|
616
|
|
|
|
$
|
789
|
|
|
|
$
|
1,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_____________
(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; loss from discontinued operations, net of
tax; noncash derivative related activity; amortization of
stock-based compensation and other noncash items.
|
(b)
|
|
|
Discretionary cash flow equals cash flows from operating activities
before changes in operating assets and liabilities and cash activity
reflected in discontinued operations 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 loss excluding noncash MTM derivative gains and unusual
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, 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 these non-GAAP 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 and losses and unusual items 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 September 30, 2015, as determined in accordance with GAAP,
to adjusted income excluding noncash MTM derivative gains and adjusted
loss excluding noncash MTM derivative gains and unusual items for that
quarter.
|
|
|
|
|
|
|
|
|
|
After-tax Amounts
|
|
|
Amounts Per Share
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
|
$
|
646
|
|
|
|
$
|
4.27
|
|
Noncash MTM derivative gains
|
|
|
|
(214
|
)
|
|
|
|
(1.42
|
)
|
Adjusted income excluding noncash MTM derivative gains
|
|
|
|
432
|
|
|
|
|
2.85
|
|
|
|
|
|
|
|
|
Gain on sale of Eagle Ford Shale midstream business
|
|
|
|
(499
|
)
|
|
|
|
(3.29
|
)
|
Impairment of South Texas proved properties, southeast Colorado
unproved acreage and vertical pipe inventory
|
|
|
|
58
|
|
|
|
|
0.38
|
|
Raton restructuring, including closure of the Denver office
|
|
|
|
6
|
|
|
|
|
0.04
|
|
Loss from discontinued operations
|
|
|
|
2
|
|
|
|
|
0.01
|
|
Adjusted loss excluding noncash MTM derivative gains and unusual
items
|
|
|
$
|
(1
|
)
|
|
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
|
|
SUPPLEMENTAL INFORMATION
|
|
Open Commodity Derivative Positions as of October 30, 2015
|
(Volumes are average daily amounts)
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
Year Ending December 31,
|
|
|
|
Fourth Quarter
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
Average Daily Oil Production Associated with Derivatives (Bbl):
|
|
|
|
|
|
|
|
|
|
Swap contracts:
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
82,000
|
|
|
|
|
4,475
|
|
|
|
|
—
|
|
NYMEX price
|
|
|
$
|
71.18
|
|
|
|
$
|
59.00
|
|
|
|
$
|
—
|
|
Collar contracts with short puts (a):
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
15,000
|
|
|
|
|
101,806
|
|
|
|
|
34,000
|
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
97.69
|
|
|
|
$
|
75.93
|
|
|
|
$
|
70.42
|
|
Floor
|
|
|
$
|
82.97
|
|
|
|
$
|
65.30
|
|
|
|
$
|
57.65
|
|
Short put
|
|
|
$
|
69.67
|
|
|
|
$
|
46.08
|
|
|
|
$
|
47.65
|
|
Rollfactor swap contracts:
|
|
|
|
|
|
|
|
|
|
Volume (b)
|
|
|
|
37,000
|
|
|
|
|
—
|
|
|
|
|
—
|
|
NYMEX roll price
|
|
|
$
|
0.06
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Average Daily NGL Production Associated with Derivatives (Bbl):
|
|
|
|
|
|
|
|
|
|
Ethane swap contracts (c):
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
6,000
|
|
|
|
|
5,000
|
|
|
|
|
—
|
|
Index price
|
|
|
$
|
7.80
|
|
|
|
$
|
11.61
|
|
|
|
$
|
—
|
|
Propane swap contracts (c):
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
11,000
|
|
|
|
|
7,500
|
|
|
|
|
—
|
|
Index price
|
|
|
$
|
21.62
|
|
|
|
$
|
21.57
|
|
|
|
$
|
—
|
|
Average Daily Gas Production Associated with Derivatives (MMBtu):
|
|
|
|
|
|
|
|
|
|
Swap contracts:
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
20,000
|
|
|
|
|
70,000
|
|
|
|
|
—
|
|
NYMEX price
|
|
|
$
|
4.31
|
|
|
|
$
|
4.06
|
|
|
|
$
|
—
|
|
Collar contracts with short puts:
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
|
285,000
|
|
|
|
|
180,000
|
|
|
|
|
—
|
|
NYMEX price:
|
|
|
|
|
|
|
|
|
|
Ceiling
|
|
|
$
|
5.07
|
|
|
|
$
|
4.01
|
|
|
|
$
|
—
|
|
Floor
|
|
|
$
|
4.00
|
|
|
|
$
|
3.24
|
|
|
|
$
|
—
|
|
Short put
|
|
|
$
|
3.00
|
|
|
|
$
|
2.78
|
|
|
|
$
|
—
|
|
Basis swap contracts:
|
|
|
|
|
|
|
|
|
|
Gulf Coast index swap volume (d)
|
|
|
|
20,000
|
|
|
|
|
10,000
|
|
|
|
|
—
|
|
Price differential ($/MMBtu)
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Mid-Continent index swap volume (d)
|
|
|
|
95,000
|
|
|
|
|
15,000
|
|
|
|
|
45,000
|
|
Price differential ($/MMBtu)
|
|
|
$
|
(0.24
|
)
|
|
|
$
|
(0.32
|
)
|
|
|
$
|
(0.32
|
)
|
Permian Basin index swap volume (d)
|
|
|
|
10,000
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Price differential ($/MMBtu)
|
|
|
$
|
(0.13
|
)
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Permian Basin index swap volume (e)
|
|
|
|
30,000
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Price differential ($/MMBtu)
|
|
|
$
|
0.19
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
_____________
(a)
|
|
|
Counterparties have the option to extend 5,000 Bbls per day of 2015
collar contracts with short puts for an additional year with a
ceiling price of $100.08 per Bbl, a floor price of $90.00 per Bbl
and a short put price of $80.00 per Bbl. The option to extend is
exercisable by the counterparties on December 31, 2015.
|
(b)
|
|
|
Represent swaps that fix the difference between (i) each day's price
per Bbl of West Texas Intermediate oil ("WTI") for the first nearby
month less (ii) the price per Bbl of WTI for the second nearby NYMEX
month, multiplied by .6667; plus (iii) each day's price per Bbl of
WTI for the first nearby month less (iv) the price per Bbl of WTI
for the third nearby NYMEX month, multiplied by .3333.
|
(c)
|
|
|
Represent swaps that reduce the price volatility of forecasted
ethane and propane sales by the Company at Mont Belvieu, Texas and
Conway, Kansas-posted prices.
|
(d)
|
|
|
Represent swaps that fix the basis differentials between the index
prices at which the Company sells its Gulf Coast, Mid-Continent and
Permian Basin gas, respectively, and the NYMEX Henry Hub index price
used in gas swap and collar contracts.
|
(e)
|
|
|
Represent swaps 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.
|
|
|
|
|
Interest rate derivatives. As of October 30, 2015, the
Company was party to interest rate derivative contracts whereby the
Company will receive (i) the 10-year Treasury rate in exchange for
paying average fixed rates of 2.15 percent on a notional amount of $100
million on December 15, 2015 and 2.24 percent on a notional amount of
$100 million on March 15, 2016 and (ii) the three-month LIBOR rate for
the 10-year period from March 2016 through March 2026 in exchange for
paying a fixed interest rate of 2.15 percent on a notional amount of
$100 million on March 15, 2016.
Marketing and basis transfer 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 to mitigate price
risk. As of October 30, 2015, the Company had oil index swap contracts
totaling 10,000 Bbl per day for the remainder of 2015 with a price
differential of $2.99 per Bbl between Cushing WTI and Louisiana Light
Sweet oil.
Derivative Gains, Net
(in millions)
The following table summarizes net derivative gains and losses that the
Company has recorded in earnings for the three and nine months ended
September 30, 2015:
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2015
|
|
|
Nine Months Ended September 30, 2015
|
Noncash changes in fair value:
|
|
|
|
|
|
|
Oil derivative gains
|
|
|
$
|
334
|
|
|
|
$
|
46
|
|
NGL derivative gains
|
|
|
|
5
|
|
|
|
|
7
|
|
Gas derivative losses
|
|
|
|
(1
|
)
|
|
|
|
(29
|
)
|
Marketing derivative losses
|
|
|
|
(1
|
)
|
|
|
|
(3
|
)
|
Interest rate derivative gains (losses)
|
|
|
|
(2
|
)
|
|
|
|
1
|
|
Total noncash derivative gains, net
|
|
|
|
335
|
|
|
|
|
22
|
|
|
|
|
|
|
|
|
Net cash receipts (payments) on settled derivative instruments:
|
|
|
|
|
|
|
Oil derivative receipts
|
|
|
|
205
|
|
|
|
|
505
|
|
NGL derivative receipts
|
|
|
|
5
|
|
|
|
|
7
|
|
Gas derivative receipts
|
|
|
|
29
|
|
|
|
|
85
|
|
Marketing derivative payments
|
|
|
|
(1
|
)
|
|
|
|
(4
|
)
|
Interest rate derivative receipts
|
|
|
|
—
|
|
|
|
|
2
|
|
Total cash derivative receipts, net
|
|
|
|
238
|
|
|
|
|
595
|
|
Total derivative gains, net
|
|
|
$
|
573
|
|
|
|
$
|
617
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20151102006727/en/
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