QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported
second quarter 2018 financial and operating results and provided an
update on its strategic and financial initiatives (Strategic
Initiatives) announced in February.
- Delivered record quarterly oil and condensate production of 6.6
MMbbls, including a record 3.2 MMbbls in the Permian Basin, a 32%
and 49% quarter-over-quarter increase, respectively
- Delivered 20% quarter-over-quarter increase in Williston Basin
production driven by strong well results from our drilling and
refracs programs on South Antelope
- Increased quarterly production in Haynesville/Cotton Valley to
314 MMcfed, a 71% year-over-year increase, driven by strong well
results from our drilling and refrac programs
- Decreased Permian Basin lease operating expense (LOE) to $5.10
per Boe, a 24% year-over-year decrease
- Increased 2018 oil and condensate production guidance to
reflect improved efficiencies in the Permian Basin and better than
forecasted results in the Williston Basin
"Our record Permian Basin oil production performance in the
second quarter demonstrates the quality of our assets and
underscores the continued success of our 'tank-style' completions,"
commented Chuck Stanley, Chairman, President and CEO of QEP. "We
continue to put more wells on production than originally forecast
in the Permian Basin due to operational efficiencies, such as
faster drill times and a 33% quarter-over-quarter increase in the
number of frac stages completed per crew per month. These
efficiency gains have enabled us to drive down gross completed well
costs by over five percent since the fourth quarter 2017, while
bringing a similar number of wells in the basin onto production,
operating fewer drilling rigs and utilizing fewer frac crews than
originally planned for the year."
"For the remainder of 2018 we will continue to focus on
balancing capital investments with cash flow and will be allocating
the vast majority of capital to the Permian Basin. We expect to put
approximately 31 wells on production in the Permian Basin in the
second half of 2018, with more than 50% of these wells having
lateral lengths of 9,000 feet or greater. We expect the addition of
these long laterals, along with our current drilling rig and frac
crew level, to support our production profile in 2018 and lay the
foundation for oil production growth in the Permian Basin in
2019."
"We continue to make progress on our Strategic Initiatives. In
early July, we announced the execution of a definitive agreement to
sell our Uinta Basin assets for a purchase price of $155 million
(Uinta Basin Divestiture), with an anticipated closing in
September. During the second quarter, we received bids for our
Williston Basin assets, which we believe did not reflect the value
of the underlying quality and economics of the assets. Our decision
not to accept the current bids for our Williston Basin assets is
reflective of our duty to maximize the value of our company and its
assets for all of our shareholders. We continue to engage in
discussions with several potential buyers regarding the sale of
all, or a portion of, our Williston Basin assets."
"While our transition to a pure play Permian Basin company
may take longer than we originally anticipated, QEP’s Board and
management remain committed to the Strategic Initiatives,"
concluded Stanley.
The Company has posted to its website www.qepres.com a
presentation that supplements the information provided in this
release.
QEP Second Quarter 2018 Financial Results
The Company reported a net loss of $336.0 million, or $1.42 per
diluted share, for the second quarter 2018 compared with net income
of $45.4 million, or $0.19 per diluted share, for the second
quarter 2017. The net loss in the second quarter 2018 includes
$403.7 million of impairment expense primarily related to the
announced sale of the Uinta Basin assets.
Net income or loss includes non-cash gains and losses associated
with the change in the fair value of derivative instruments, gains
and losses from asset sales, asset impairments and certain other
items. Excluding these items, the Company’s second quarter 2018
Adjusted Net Income (a non-GAAP measure) was $13.8 million, or
$0.06 per diluted share, compared with an Adjusted Net Loss of
$30.2 million, or $0.12 per diluted share, for the second quarter
2017.
Adjusted EBITDA (a non-GAAP measure) for the second quarter 2018
was $282.6 million compared with $177.2 million for the second
quarter 2017, primarily due to an increase in oil and condensate
production, mainly from the Permian Basin, an increase in average
net realized oil prices and increased gas production in
Haynesville/Cotton Valley. These changes were partially offset by
an increase in realized derivative losses, a decrease in gas sales
primarily due to the Pinedale divestiture, which occurred in the
third quarter 2017 (Pinedale Divestiture) and a reduction in
average net realized gas prices.
The definitions and reconciliations of Adjusted Net Income
(Loss) and Adjusted EBITDA to net income (loss) are provided within
Non-GAAP Measures at the end of this release.
Production
Oil equivalent production was 14.1 MMboe for the second quarter
2018 compared with 13.9 MMboe for the second quarter 2017, a 2%
increase. Oil and condensate production increased 35%, while
natural gas and NGL production decreased 16% and 15%, respectively.
Second quarter 2018 equivalent production was positively impacted
by increased drilling and completion activity in the Permian and
Williston basins and Haynesville/Cotton Valley. These increases
were partially offset by the loss of 3.3 MMboe of production in
Pinedale as a result of the Pinedale Divestiture.
Operating Expenses
During the second quarter 2018, LOE was $66.5 million, a
decrease of 5% compared with the second quarter 2017. The decrease
in total LOE was primarily due to the Pinedale Divestiture,
partially offset by an increase in the Permian Basin due to the
2017 acquisition of oil and gas properties in the Permian Basin
(the 2017 Permian Basin Acquisition), and increased maintenance and
repairs, power and fuel and chemical expense.
During the second quarter 2018, LOE was $4.71 per Boe, a
decrease of 7% compared with the second quarter 2017. The decrease
in LOE per Boe was primarily due to lower cost production from the
recent horizontal well completions in the Permian Basin and
Haynesville/Cotton Valley partially offset by the loss of lower LOE
per Boe production due to the Pinedale Divestiture.
Adjusted transportation and processing (T&P) costs (a
non-GAAP measure) were $43.6 million during the second quarter
2018, a decrease of 40% compared with the second quarter 2017,
primarily due to the Pinedale Divestiture.
During the second quarter 2018, Adjusted T&P costs were
$3.09 per Boe, a decrease of 41% compared with the second quarter
2017, primarily due to the Pinedale Divestiture, which had higher
T&P costs per Boe. Excluding the Pinedale Divestiture, Adjusted
T&P costs per Boe were down 28% due to decreases in both
Haynesville/Cotton Valley and Permian Basin. The Adjusted T&P
cost per Boe decreased in Haynesville/Cotton Valley due to
increased production, which increased utilization of the Company's
firm transportation commitments on interstate pipelines. The
decrease in T&P costs per Boe in the Permian Basin was driven
by increased production and associated throughput under lower cost
T&P contracts. The definition and reconciliation of Adjusted
T&P costs to the T&P costs presented in QEP's Condensed
Consolidated Statements of Operations are provided within Non-GAAP
Measures at the end of this release.
General and administrative expense was $55.8 million, or $3.95
per Boe, during the second quarter 2018, an increase of 78%
compared with the second quarter 2017. The increase in the second
quarter 2018 was primarily due to an increase in restructuring
costs associated with the implementation of our Strategic
Initiatives. In addition to these restructuring costs, QEP
recognized an increase in share-based compensation and changes in
the mark-to-market value of the Deferred Compensation Wrap Plan and
an increase related to reduced overhead recoveries, primarily
associated with our Pinedale Divestiture.
During the second quarter 2018, production and property taxes
were $37.6 million, an increase of 32% compared with the second
quarter 2017. The increase in production and property taxes was
primarily due to increased oil pricing and increased oil and
condensate production in the Williston and Permian basins and
increased gas production in Haynesville/Cotton Valley, partially
offset by the loss of production resulting from the Pinedale
Divestiture.
Production and property taxes were $2.66 per Boe, during the
second quarter 2018, an increase of 29% compared with the second
quarter 2017, but an increase of 63% excluding the Pinedale
Divestiture. The 63% increase was due to an increase in average
field-level equivalent prices in the Permian and Williston basins
offset by lower rate per Boe in Haynesville/Cotton Valley due to
lower non-operated ad valorem charges and franchise taxes per
Boe.
Capital Investment
Capital investment, excluding property acquisitions, was $365.7
million (on an accrual basis) for the second quarter 2018, compared
with $306.0 million for the second quarter 2017. Approximately
$337.8 million of the capital expenditures was related to the
drilling, completion and equipping of wells and $27.9 million was
related to infrastructure investment. The increase in capital
expenditures was primarily related to increased drilling and
completion activity in the Permian and Williston basins and
Haynesville/Cotton Valley.
During the second quarter 2018, QEP acquired various oil and gas
properties, which primarily included proved and unproved leasehold
acreage in the Permian Basin, for an aggregate purchase price of
$8.8 million.
2018 Share Repurchase Program
During the second quarter 2018, the Company settled and retired
592,310 shares that were repurchased in late March 2018 at a
weighted average price of $9.37 per share, for $5.6 million.
Asset Divestitures
On July 5, 2018, the Company's wholly owned subsidiary, QEP
Energy Company, entered into a definitive agreement to sell natural
gas and oil producing properties, undeveloped acreage and related
assets located in the Uinta Basin for cash proceeds of $155.0
million, subject to customary purchase price adjustments. The
agreement also includes the assumption of certain contractual
obligations associated with gathering and processing contracts. The
transaction is expected to close in September 2018.
QEP closed on the sale of several non-core assets during the
second quarter 2018 for total proceeds of approximately $15.5
million.
During the second quarter 2018, the Company received bids for
its Williston Basin assets. The Company believes that the initial
bids received were below values reflective of the underlying
quality and economics of the assets. The Company continues to
engage in discussions with several potential buyers regarding the
sale of all, or a portion of, the Williston Basin assets.
Additionally, in response to unsolicited inquiries, the Company
has entered into confidentiality agreements and is providing data
to several third parties interested in a transaction involving the
Company's Haynesville assets.
Liquidity
As of June 30, 2018, QEP had $575.0 million of borrowings
outstanding and $0.3 million in letters of credit outstanding under
its revolving credit facility. The Company estimates that, as of
June 30, 2018, it could incur additional indebtedness of
approximately $675.0 million and be in compliance with the
covenants contained in its revolving credit facility.
Updated 2018 Guidance
The Company’s updated guidance includes no adjustment for
property acquisitions or divestitures and assumes that QEP will
elect to reject ethane from its produced gas for the entire year
where QEP has the right to make such an election, except in the
Permian Basin where processing economics support ethane
recovery.
QEP's updated full year 2018 guidance is detailed below.
Rig Count:
- Permian Basin - average of four and one-half rigs (dropped to
four rigs in mid-July 2018 and for balance of year)
- Williston Basin - average of one-quarter rig (rig released
during second quarter 2018)
- Haynesville/Cotton Valley - average of one-half rig (rig
released during second quarter 2018)
Wells Put on Production:
- Company: approximately 114 net operated wells
- Permian Basin: approximately 98 net operated wells
Refracs:
- 27 net refracs in the Williston Basin and Haynesville/Cotton
Valley, all of which have been completed in the first half of
2018
Slide 4 in the July 2018 Investor Presentation provides
additional details on QEP's 2018 Guidance.
|
2018 Guidance |
|
2018 |
2018 |
|
Previous Guidance |
Current Guidance |
Oil & condensate
production (MMbbl) |
21.5 - 23.0 |
23.0 - 24.0 |
Gas production
(Bcf) |
135.0 - 145.0 |
137.0 - 143.0 |
NGL
production (MMbbl) |
4.25 - 4.75 |
4.0 - 4.5 |
Total oil
equivalent production (MMboe) |
48.3 - 51.9 |
49.8 - 52.3 |
|
|
|
Adjusted lease
operating and transportation expense (per Boe)(1) |
$9.00 - $10.00 |
$8.50 - $9.50 |
Depletion, depreciation
and amortization (per Boe) |
$17.00 - $18.00 |
$17.00 - $18.00 |
Production and property
taxes (% of field-level revenue) |
|
8.5% |
|
|
8.5% |
|
(in millions) |
General and
administrative expense(2) |
$195 - $215 |
$205 - $225 |
|
|
|
Capital investment
(excluding property acquisitions) |
|
|
Drilling,
Completion and Equip(3) |
$1,000 - $1,100 |
$1,000 - $1,100 |
Infrastructure |
|
$60 |
|
|
$60 |
|
Corporate |
|
$10 |
|
|
$10 |
|
Total
capital investment (excluding property acquisitions) |
$1,070 - $1,170 |
$1,070 - $1,170 |
|
|
|
____________________________(1)
Adjusted lease operating and transportation expense (per Boe) is a
non-GAAP measure. Refer to Non-GAAP Measures at the end of this
release.(2) General and administrative expense includes
approximately $35.0 million of non-cash share-based compensation
expense and approximately $30.0 million of estimated restructuring
costs.(3) Approximately 70% of the planned capital investment in
Drilling, Completion and Equip is focused on projects in the
Permian Basin. Includes approximately $20.0 million of non-operated
well costs.
|
Updated 2018 Quarterly Production
Guidance |
|
1Q 2018 |
|
2Q 2018 |
2Q 2018 |
|
3Q 2018 |
4Q 2018 |
2018 |
QEP
Resources |
Actuals |
|
Actuals |
Guidance |
|
Current Guidance |
Oil & condensate
production (MMbbl) |
5.0 |
|
6.6 |
5.4 -
5.7 |
|
6.0 - 6.4 |
5.5 - 6.0 |
23.0 - 24.0 |
Gas production
(Bcf) |
35.1 |
|
38.3 |
35.2 -
37.3 |
|
34.9 -
37.5 |
28.2 -
32.1 |
137.0
- 143.0 |
NGL production
(MMbbl) |
0.9 |
|
1.2 |
1.1 -
1.2 |
|
1.1 -
1.2 |
0.9 -
1.3 |
4.0 -
4.5 |
Total oil equivalent production (MMboe) |
11.7 |
|
14.1 |
12.4 - 13.1 |
|
12.9 - 13.9 |
11.1 - 12.6 |
49.8 - 52.3 |
Total
wells put on production (net) |
35.0 |
|
47.2 |
45 |
|
18 |
14 |
114 |
Total
refracs put on production (net) |
14.0 |
|
12.8 |
10 |
|
— |
— |
27 |
|
|
|
|
|
|
|
|
|
Permian
Basin |
|
|
|
|
|
|
|
|
Oil & condensate
production (MMbbl) |
2.2 |
|
3.2 |
2.7 -
2.8 |
|
3.0 -
3.3 |
3.1 -
3.4 |
11.5 -
12.1 |
Gas production
(Bcf) |
1.9 |
|
2.1 |
1.9 -
2.1 |
|
2.4 -
2.6 |
2.4 -
2.6 |
8.8 -
9.2 |
NGL
production (MMbbl) |
0.3 |
|
0.4 |
0.35 -
0.40 |
|
0.40 -
0.45 |
0.35 -
0.40 |
1.44 -
1.54 |
Permian
Basin equivalent production (MMboe) |
2.8 |
|
4.0 |
3.4 - 3.6 |
|
3.8 - 4.2 |
3.9 - 4.2 |
14.4 -15.1 |
Permian
Basin wells put on production (net) |
31.0 |
|
36.1 |
33 |
|
17 |
14 |
98 |
|
|
|
|
|
|
|
|
|
Operations Summary
|
Permian Basin |
|
Williston Basin |
|
Haynesville/CottonValley |
|
Uinta Basin |
|
As of June 30, 2018 |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Well
Progress |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
25 |
|
|
24.8 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At total depth - under
drilling rig |
2 |
|
|
2.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Waiting to be
completed |
12 |
|
|
11.7 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Undergoing
completion |
5 |
|
|
4.8 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Completed, awaiting
production |
8 |
|
|
8.0 |
|
|
— |
|
|
— |
|
|
1 |
|
|
1.0 |
|
|
— |
|
|
— |
|
Waiting
on completion |
27 |
|
|
26.5 |
|
|
— |
|
|
— |
|
|
1 |
|
|
1.0 |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put on
production(1) |
37 |
|
|
36.1 |
|
|
11 |
|
|
10.1 |
|
|
1 |
|
|
1.0 |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________________________(1)
Total wells put on production during the three months ended
June 30, 2018.
Permian Basin
Permian Basin net oil equivalent production averaged a record of
approximately 44.1 Mboed (91% liquids) during the second quarter
2018, a 43% increase compared with the first quarter 2018 and a
108% increase compared with the second quarter 2017.
In the second quarter 2018, the Company put on production 37
gross-operated horizontal wells (eight on County Line and 29 on
Mustang Springs), four more than originally forecast for the second
quarter 2018 (average working interest 98%). The greater than
planned delivery of wells in the second quarter 2018 was a result
of a continued increase in drilling and completion efficiency.
Since entering the Permian Basin in 2014, the Company has achieved
an almost four-fold increase in the number of frac stages completed
per crew per month, with the two crews working for QEP during the
second quarter 2018 pumping an average of 442 stages per active
crew month.
At the end of the second quarter 2018, five of the eight wells
on County Line put on production during the quarter had cleaned up
and reached average peak 24-hour IP of 164 Boed per 1,000 lateral
feet (84% oil) from an average lateral length of 7,247 feet.
At Mustang Springs, the 29 wells were in four one-half-mile wide
drilling spacing units (DSUs), one with a 14 well density, two with
an 11 well density and one with a ten well density. At the end of
the second quarter 2018, six of the 29 wells on Mustang Springs put
on production during the quarter had cleaned up and achieved
average peak 24-hour IP of 152 Boed per 1,000 feet (84% oil) from
an average lateral length of 7,405 feet.
The Company also provided an update on performance of its
high-density pilot consisting of 22 wells in a one-half mile wide
DSU that was in a very early stage of well cleanup at the end of
the first quarter 2018. Of these 22 wells, five were drilled in the
Middle Spraberry, seven in the Spraberry Shale, one in the Dean,
two in the Wolfcamp A and seven in the Wolfcamp B formations. These
wells achieved an average peak 24-hour IP of 88 Boed per 1,000 feet
(84% oil) and had an average peak IP30 of 75 Boed per 1,000 feet
(83% oil). The performance of these wells met Company expectations
given the relatively high density (effectively 47 wellbores per
mile-wide unit) compared to the surrounding DSU’s and the
performance of these wells has been instrumental in informing the
Company's understanding of tank-style development and future DSU
and target reservoir well density optimization.
During the second quarter 2018 the Company, as part of its risk
management strategy, continued to enter into financial derivatives
and physical sales agreements for oil production from the Permian
Basin. As of the end of quarter approximately 97% of the Company’s
50.0 Mbod of gross field-level Permian oil production was gathered
and transported by pipeline. The Company estimates it has flow
assurance, via sales agreements with refiners and marketers, on
more than 95% of its current and projected gross oil volumes for
the remainder of 2018 and 2019. The Company also has 6.0 MMbbls in
2018 and 7.5 MMbbls in 2019 of its projected Permian net oil
volumes either covered by basis swaps or sold in markets outside of
the Midland Basin. See tables provided at the end of this release
for details regarding the Company’s derivatives.
At the end of the second quarter 2018, the Company had 25
gross-operated horizontal wells in process of being drilled (of
which 13 had surface casing set, but had no drilling rig present),
two horizontal wells at total depth under drilling rigs (average
working interest 100%), 12 horizontal wells waiting to be completed
(average working interest 98%), five horizontal wells undergoing
completion (average working interest 96%), and eight fully
completed horizontal wells awaiting first production, which were
part of a tank "pressure wall" (average working interest 100%).
Current QEP-operated drilled and completed authorization for
expenditure (AFE) well costs for the Permian Basin are detailed on
slide 21 of the July 2018 Investor Presentation.
At the end of the second quarter 2018, the Company had five
operated rigs in the Permian Basin. The Company released one of its
operated rigs during mid-July 2018.
Slides 7-12 in the July 2018 Investor Presentation depict QEP's
acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net oil equivalent production averaged
approximately 49.0 Mboed (86% liquids) during the second quarter
2018, an 18% increase compared with the first quarter 2018 and a 3%
decrease compared with the second quarter 2017.
In the second quarter 2018, the Company put on production 11
gross-operated horizontal wells (average working interest 92%). The
wells were completed with an average lateral length of 10,030 feet
and had an average peak 24-hour IP of 289 Boed per 1,000 feet (80%
oil). Seven of the eleven wells had 30 or more days on production
with an average peak IP 30 of 213 Boed per 1,000 feet (77%
oil).
Current QEP-operated drilled and completed AFE well costs for
the Williston Basin are detailed on slide 21 of the July 2018
Investor Presentation.
The Company also completed and returned to production seven
gross-operated refracs on South Antelope (average working interest
97%) during the second quarter 2018. Three of the seven refracs had
reached peak oil rates by the end of the quarter with an average
IP30 gross uplift of 844 Boed (75% oil). Current average gross
QEP-operated Williston Basin refrac costs are approximately $4.9
million per well.
At the end of the second quarter 2018, the Company had no
drilling rigs in the Williston Basin.
Slides 13-15 in the July 2018 Investor Presentation depict QEP's
acreage and activity in the Williston Basin.
Haynesville/Cotton Valley
Haynesville/Cotton Valley net gas equivalent production averaged
approximately 313.9 MMcfed (52.3 Mboed) (0% liquids) during the
second quarter 2018, a 10% increase compared with the first quarter
2018 and a 70% increase compared with the second quarter 2017.
The Company put on production one gross operated well during the
second quarter 2018 (average working interest 100%). The well was
still in the process of cleaning up at quarter end. The Company
also had one fully completed horizontal well awaiting first
production at the end of the quarter (average working interest
100%).
During the quarter the Company completed and returned to
production six QEP-operated refracs, four of which were high
density tests, with an average incremental 24-hour rate increase of
13.0 MMcfed (average working interest 99%).
Current average gross QEP-operated Haynesville refrac costs are
approximately $4.9 million per well.
At the end of the second quarter, the Company had no drilling
rigs in Haynesville/Cotton Valley.
Slides 16-17 in the July 2018 Investor Presentation depict QEP's
acreage and activity in Haynesville/Cotton Valley.
Uinta Basin
Uinta Basin net production averaged approximately 54.2 MMcfed
(9.0 Mboed) (25% liquids) during the second quarter 2018, a 1%
increase compared with the first quarter 2018 and a 9% decrease
compared with the second quarter 2017.
At the end of the second quarter, the Company had no drilling
rigs in the Uinta Basin.
Second Quarter 2018 Results Conference Call
QEP’s management will discuss second quarter 2018 results in a
conference call on Thursday, July 26, 2018, beginning at 9:00
a.m. EDT. The conference call can be accessed at www.qepres.com.
You may also participate in the conference call by dialing (877)
869-3847 in the U.S. or Canada and (201) 689-8261 for international
calls. A replay of the teleconference will be available on the
website immediately after the call through August 26, 2018, or by
dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for
international calls, and then entering the conference ID #
13681534. In addition, QEP’s slides for the second quarter 2018,
with updated maps showing QEP’s leasehold and current activity for
key operating areas discussed in this release, can be found on the
Company’s website.
About QEP Resources, Inc.
QEP Resources, Inc. (NYSE:QEP) is an independent crude oil and
natural gas exploration and production company with operations in
two regions of the United States: the Northern Region (primarily in
North Dakota and Utah) and the Southern Region (primarily in Texas
and Louisiana). For more information, visit QEP's website at:
www.qepres.com.
Forward-Looking Statements
This release includes forward-looking statements within the
meaning of Section 27(a) of the Securities Act of 1933, as amended,
and Section 21(e) of the Securities Exchange Act of 1934, as
amended. Forward-looking statements can be identified by words such
as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,”
“expects,” “should,” “will” or other similar expressions. Such
statements are based on management’s current expectations,
estimates and projections, which are subject to a wide range of
uncertainties and business risks. These forward-looking statements
include statements regarding: planned Strategic Initiatives;
planned asset divestitures and timing of such divestitures; use of
proceeds from sale of assets; transitioning to a
pure-play Permian Basin company and the timing of such
transition; utilization of QEP’s tank-style completion methodology
and anticipated benefits from this methodology; balancing capital
investments with cash flow; allocating the vast majority of capital
to the Permian Basin; anticipated closing date for the sale of the
Uinta Basin assets and novation of derivatives entered into in
conjunction with the execution of the purchase and sale agreement
for such assets; the number and location of drilling rigs to be
deployed, wells to be put on production and refracs; number of new
wells having lateral lengths of 9,000 feet or greater; quality of
initial bids received for QEP’s Williston Basin assets; forecast
production amounts and growth and related assumptions; forecast
lease operating and transportation expense, depletion, depreciation
and amortization expense, general and administrative expense,
non-cash share-based compensation expense, restructuring costs,
production and property taxes, and capital investment for 2018 and
related assumptions for such guidance; allocation of capital
expenditures; quarterly production guidance and assumptions for
such guidance; plans regarding ethane rejection and recovery; the
amount of additional indebtedness QEP could incur and be compliance
with loan covenants; and flow assurance for 95% of QEP’s current
and projected oil volumes for the remainder of 2018 and 2019.
Actual results may differ materially from those included in the
forward-looking statements due to a number of factors, including,
but not limited to: timing and amount of asset divestitures and
share repurchases; changes in oil, gas and NGL prices; liquidity
constraints, including those resulting from the cost or
unavailability of financing due to debt and equity capital and
credit market conditions, changes in QEP’s credit rating, QEP’s
compliance with loan covenants, the increasing credit pressure on
QEP’s industry or demands for cash collateral by counterparties to
derivative and other contracts; market conditions; global
geopolitical and macroeconomic factors; the activities of
the Organization of Petroleum Exporting Countries; general
economic conditions, including interest rates; changes in local,
regional, national and global demand for natural oil, gas and NGL;
impact of new laws and regulations, including the use of hydraulic
fracture stimulation; impact of U.S. dollar exchange rates on oil,
gas and NGL prices; elimination of federal income tax deductions
for oil and gas exploration and development; guidance for
implementation of the Tax Cuts and Jobs Act; actual proceeds from
asset sales; actions of activist shareholders; tariffs on products
QEP uses in its operations or sells; drilling results; shortages of
oilfield equipment, services and personnel; the availability of
storage and refining capacity; operating risks such as unexpected
drilling conditions; transportation constraints, including gas and
crude oil pipeline takeaway capacity in the Permian Basin; weather
conditions; changes in maintenance, service and construction costs;
permitting delays; outcome of contingencies such as legal
proceedings; inadequate supplies of water and/or lack of water
disposal sources; credit worthiness of counterparties to
agreements; and the other risks discussed in the Company’s periodic
filings with the Securities and Exchange Commission, including
the Risk Factors section of the Company’s Annual Report on Form
10-K for the year ended December 31, 2017, and Quarterly
Reports on Form 10-Q filed in 2018. QEP undertakes no
obligation to publicly correct or update the forward-looking
statements in this news release, in other documents, or on the
website to reflect future events or circumstances. All such
statements are expressly qualified by this cautionary
statement.
Contact |
Investors/Media: |
William I. Kent,
IRC |
Director, Investor
Relations |
303-405-6665 |
QEP RESOURCES, INC.CONDENSED
CONSOLIDATED STATEMENTS OF
OPERATIONS(Unaudited)
|
Three Months Ended |
|
Six Months Ended |
|
June 30, |
|
June 30, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
REVENUES |
(in millions, except per share amounts) |
Oil and
condensate, gas and NGL sales |
$ |
520.3 |
|
|
$ |
373.0 |
|
|
$ |
930.1 |
|
|
$ |
758.2 |
|
Other
revenue |
3.0 |
|
|
2.7 |
|
|
8.0 |
|
|
6.7 |
|
Purchased
oil and gas sales |
9.1 |
|
|
8.0 |
|
|
23.2 |
|
|
38.9 |
|
Total
Revenues |
532.4 |
|
|
383.7 |
|
|
961.3 |
|
|
803.8 |
|
OPERATING
EXPENSES |
|
|
|
|
|
|
|
Purchased
oil and gas expense |
9.8 |
|
|
9.1 |
|
|
25.3 |
|
|
38.5 |
|
Lease
operating expense |
66.5 |
|
|
70.0 |
|
|
139.0 |
|
|
139.2 |
|
Transportation and processing costs |
31.2 |
|
|
72.2 |
|
|
65.2 |
|
|
142.4 |
|
Gathering
and other expense |
3.4 |
|
|
1.8 |
|
|
6.2 |
|
|
3.3 |
|
General
and administrative |
55.8 |
|
|
31.3 |
|
|
115.9 |
|
|
64.9 |
|
Production and property taxes |
37.6 |
|
|
28.5 |
|
|
66.5 |
|
|
57.6 |
|
Depreciation, depletion and amortization |
242.2 |
|
|
191.5 |
|
|
438.7 |
|
|
383.3 |
|
Exploration expenses |
0.1 |
|
|
— |
|
|
0.1 |
|
|
0.4 |
|
Impairment |
403.7 |
|
|
— |
|
|
404.4 |
|
|
0.1 |
|
Total
Operating Expenses |
850.3 |
|
|
404.4 |
|
|
1,261.3 |
|
|
829.7 |
|
Net gain (loss) from
asset sales, inclusive of restructuring costs |
(3.9 |
) |
|
19.8 |
|
|
(0.4 |
) |
|
19.8 |
|
OPERATING
INCOME (LOSS) |
(321.8 |
) |
|
(0.9 |
) |
|
(300.4 |
) |
|
(6.1 |
) |
Realized and unrealized
gains (losses) on derivative contracts |
(79.1 |
) |
|
106.7 |
|
|
(132.3 |
) |
|
267.6 |
|
Interest and other
income (expense) |
(3.1 |
) |
|
1.8 |
|
|
(3.8 |
) |
|
2.4 |
|
Interest expense |
(38.2 |
) |
|
(34.9 |
) |
|
(73.2 |
) |
|
(68.7 |
) |
INCOME
(LOSS) BEFORE INCOME TAXES |
(442.2 |
) |
|
72.7 |
|
|
(509.7 |
) |
|
195.2 |
|
Income tax (provision)
benefit |
106.2 |
|
|
(27.3 |
) |
|
120.1 |
|
|
(72.9 |
) |
NET
INCOME (LOSS) |
$ |
(336.0 |
) |
|
$ |
45.4 |
|
|
$ |
(389.6 |
) |
|
$ |
122.3 |
|
|
|
|
|
|
|
|
|
Earnings (loss) per
common share |
|
|
|
|
|
|
|
Basic |
$ |
(1.42 |
) |
|
$ |
0.19 |
|
|
$ |
(1.63 |
) |
|
$ |
0.51 |
|
Diluted |
$ |
(1.42 |
) |
|
$ |
0.19 |
|
|
$ |
(1.63 |
) |
|
$ |
0.51 |
|
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
|
|
|
Used in
basic calculation |
237.0 |
|
|
240.5 |
|
|
238.9 |
|
|
240.4 |
|
Used in
diluted calculation |
237.0 |
|
|
240.6 |
|
|
238.9 |
|
|
240.5 |
|
Dividends per common
share |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
QEP RESOURCES, INC.CONDENSED
CONSOLIDATED BALANCE
SHEETS(Unaudited)
|
June 30, 2018 |
|
December 31, 2017 |
ASSETS |
(in millions) |
Current Assets |
|
|
|
Cash and
cash equivalents |
$ |
— |
|
|
$ |
— |
|
Accounts
receivable, net |
175.0 |
|
|
141.8 |
|
Income
tax receivable |
5.3 |
|
|
4.9 |
|
Fair
value of derivative contracts |
23.7 |
|
|
3.4 |
|
Prepaid
expenses |
9.8 |
|
|
10.1 |
|
Other
current assets |
0.3 |
|
|
4.3 |
|
Total
Current Assets |
214.1 |
|
|
164.5 |
|
Property, Plant and
Equipment (successful efforts method for oil and gas
properties) |
|
|
|
Proved
properties |
12,852.3 |
|
|
11,873.6 |
|
Unproved
properties |
1,041.0 |
|
|
1,086.4 |
|
Gathering
and other |
359.7 |
|
|
318.7 |
|
Materials
and supplies |
32.2 |
|
|
32.9 |
|
Total
Property, Plant and Equipment |
14,285.2 |
|
|
13,311.6 |
|
Less Accumulated
Depreciation, Depletion and Amortization |
|
|
|
Exploration and production |
7,267.1 |
|
|
6,642.9 |
|
Gathering
and other |
116.2 |
|
|
124.3 |
|
Total
Accumulated Depreciation, Depletion and Amortization |
7,383.3 |
|
|
6,767.2 |
|
Net
Property, Plant and Equipment |
6,901.9 |
|
|
6,544.4 |
|
Fair value of
derivative contracts |
5.4 |
|
|
0.1 |
|
Other noncurrent
assets |
56.5 |
|
|
53.0 |
|
Noncurrent assets held
for sale |
211.8 |
|
|
$ |
632.8 |
|
TOTAL
ASSETS |
$ |
7,389.7 |
|
|
$ |
7,394.8 |
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
Current
Liabilities |
|
|
|
Checks
outstanding in excess of cash balances |
$ |
8.5 |
|
|
$ |
44.0 |
|
Accounts
payable and accrued expenses |
388.0 |
|
|
363.8 |
|
Production and property taxes |
36.3 |
|
|
31.6 |
|
Interest
payable |
32.7 |
|
|
26.0 |
|
Fair
value of derivative contracts |
155.2 |
|
|
103.6 |
|
Asset
retirement obligations |
6.0 |
|
|
3.5 |
|
Total
Current Liabilities |
626.7 |
|
|
572.5 |
|
Long-term debt |
2,649.4 |
|
|
2,160.8 |
|
Deferred income
taxes |
397.7 |
|
|
518.0 |
|
Asset retirement
obligations |
154.6 |
|
|
159.0 |
|
Fair value of
derivative contracts |
49.3 |
|
|
31.8 |
|
Other long-term
liabilities |
97.8 |
|
|
102.2 |
|
Other long-term
liabilities held for sale |
52.8 |
|
|
52.6 |
|
Commitments and
contingencies |
|
|
|
EQUITY |
|
|
|
Common
stock – par value $0.01 per share; 500.0 million shares
authorized; 239.7 million and 243.0 million shares issued,
respectively |
2.4 |
|
|
2.4 |
|
Treasury
stock – 2.7 million and 2.0 million shares, respectively |
(41.2 |
) |
|
(34.2 |
) |
Additional paid-in capital |
1,415.7 |
|
|
1,398.2 |
|
Retained
earnings |
1,994.7 |
|
|
2,442.6 |
|
Accumulated other comprehensive income (loss) |
(10.2 |
) |
|
(11.1 |
) |
Total
Common Shareholders' Equity |
3,361.4 |
|
|
3,797.9 |
|
TOTAL
LIABILITIES AND EQUITY |
$ |
7,389.7 |
|
|
$ |
7,394.8 |
|
|
|
|
|
|
|
|
|
QEP RESOURCES, INC.CONDENSED
CONSOLIDATED STATEMENTS OF CASH
FLOWS(Unaudited)
|
Six Months Ended |
|
June 30, |
|
2018 |
|
2017 |
OPERATING
ACTIVITIES |
(in millions) |
Net income (loss) |
$ |
(389.6 |
) |
|
$ |
122.3 |
|
Adjustments to
reconcile net income (loss) to net cash provided by (used in)
operating activities: |
|
|
|
Depreciation, depletion and amortization |
438.7 |
|
|
383.3 |
|
Deferred
income taxes (benefit) |
(120.5 |
) |
|
67.2 |
|
Impairment |
404.4 |
|
|
0.1 |
|
Share-based compensation |
23.4 |
|
|
7.7 |
|
Amortization of debt issuance costs and discounts |
2.6 |
|
|
3.1 |
|
Bargain
purchase gain from acquisition |
— |
|
|
0.4 |
|
Net
(gain) loss from asset sales, inclusive of restructuring costs |
0.4 |
|
|
(19.8 |
) |
Unrealized (gains) losses on marketable securities |
(0.4 |
) |
|
(1.4 |
) |
Unrealized (gains) losses on derivative contracts |
43.6 |
|
|
(277.6 |
) |
Changes in operating
assets and liabilities |
(25.7 |
) |
|
10.7 |
|
Net Cash
Provided by (Used in) Operating Activities |
376.9 |
|
|
296.0 |
|
INVESTING
ACTIVITIES |
|
|
|
Property
acquisitions |
(45.1 |
) |
|
(76.6 |
) |
Property, plant and
equipment, including exploratory well expense |
(764.3 |
) |
|
(477.9 |
) |
Proceeds from
disposition of assets |
48.8 |
|
|
2.3 |
|
Net Cash
Provided by (Used in) Investing Activities |
(760.6 |
) |
|
(552.2 |
) |
FINANCING
ACTIVITIES |
|
|
|
Checks outstanding in
excess of cash balances |
(35.5 |
) |
|
(0.5 |
) |
Long-term debt issuance
costs paid |
— |
|
|
(1.1 |
) |
Proceeds from credit
facility |
2,029.5 |
|
|
— |
|
Repayments of credit
facility |
(1,543.5 |
) |
|
— |
|
Common stock
repurchased and retired |
(58.4 |
) |
|
— |
|
Treasury stock
repurchases |
(5.9 |
) |
|
(6.4 |
) |
Other capital
contributions |
0.2 |
|
|
— |
|
Net Cash
Provided by (Used in) Financing Activities |
386.4 |
|
|
(8.0 |
) |
Change in cash, cash
equivalents and restricted cash |
2.7 |
|
|
(264.2 |
) |
Beginning cash, cash
equivalents and restricted cash |
23.4 |
|
|
465.4 |
|
Ending cash, cash
equivalents and restricted cash |
$ |
26.1 |
|
|
$ |
201.2 |
|
|
|
|
|
|
|
|
|
|
Production by Region |
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
|
(in Mboe) |
Northern
Region |
|
|
|
|
|
|
|
|
|
|
|
Williston
Basin |
4,459.7 |
|
|
4,573.9 |
|
|
(2 |
)% |
|
8,189.4 |
|
|
9,407.9 |
|
|
(13 |
)% |
Pinedale |
— |
|
|
3,316.7 |
|
|
(100 |
)% |
|
0.1 |
|
|
6,831.6 |
|
|
(100 |
)% |
Uinta
Basin |
821.7 |
|
|
897.0 |
|
|
(8 |
)% |
|
1,626.2 |
|
|
1,865.3 |
|
|
(13 |
)% |
Other
Northern |
42.8 |
|
|
337.1 |
|
|
(87 |
)% |
|
148.2 |
|
|
667.5 |
|
|
(78 |
)% |
Total
Northern Region |
5,324.2 |
|
|
9,124.7 |
|
|
(42 |
)% |
|
9,963.9 |
|
|
18,772.3 |
|
|
(47 |
)% |
Southern
Region |
|
|
|
|
|
|
|
|
|
|
|
Permian
Basin |
4,016.2 |
|
|
1,932.1 |
|
|
108 |
% |
|
6,799.1 |
|
|
3,321.6 |
|
|
105 |
% |
Haynesville/Cotton Valley |
4,761.3 |
|
|
2,792.3 |
|
|
71 |
% |
|
9,051.8 |
|
|
4,839.0 |
|
|
87 |
% |
Other
Southern |
4.4 |
|
|
11.5 |
|
|
(62 |
)% |
|
15.9 |
|
|
18.0 |
|
|
(12 |
)% |
Total
Southern Region |
8,781.9 |
|
|
4,735.9 |
|
|
85 |
% |
|
15,866.8 |
|
|
8,178.6 |
|
|
94 |
% |
Total production |
14,106.1 |
|
|
13,860.6 |
|
|
2 |
% |
|
25,830.7 |
|
|
26,950.9 |
|
|
(4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
Oil and
condensate (Mbbl) |
6,567.6 |
|
|
4,870.3 |
|
|
35 |
% |
|
11,541.6 |
|
|
9,553.0 |
|
|
21 |
% |
Gas
(Bcf) |
38.3 |
|
|
45.8 |
|
|
(16 |
)% |
|
73.4 |
|
|
88.1 |
|
|
(17 |
)% |
NGL
(Mbbl) |
1,152.8 |
|
|
1,354.9 |
|
|
(15 |
)% |
|
2,057.2 |
|
|
2,710.3 |
|
|
(24 |
)% |
Total
production (Mboe) |
14,106.1 |
|
|
13,860.6 |
|
|
2 |
% |
|
25,830.7 |
|
|
26,950.9 |
|
|
(4 |
)% |
Average
daily production (Mboe) |
155.0 |
|
|
152.3 |
|
|
2 |
% |
|
142.7 |
|
|
148.9 |
|
|
(4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices |
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
Oil (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average
field-level price |
$ |
62.21 |
|
|
$ |
44.35 |
|
|
|
|
$ |
61.45 |
|
|
$ |
45.82 |
|
|
|
Commodity
derivative impact |
(7.91 |
) |
|
2.37 |
|
|
|
|
(8.34 |
) |
|
0.99 |
|
|
|
Net
realized price |
$ |
54.30 |
|
|
$ |
46.72 |
|
|
16 |
% |
|
$ |
53.11 |
|
|
$ |
46.81 |
|
|
13 |
% |
Gas (per
Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Average
field-level price |
$ |
2.55 |
|
|
$ |
2.93 |
|
|
|
|
$ |
2.72 |
|
|
$ |
3.05 |
|
|
|
Commodity
derivative impact |
0.17 |
|
|
(0.11 |
) |
|
|
|
0.10 |
|
|
(0.22 |
) |
|
|
Net
realized price |
$ |
2.72 |
|
|
$ |
2.82 |
|
|
(4 |
)% |
|
$ |
2.82 |
|
|
$ |
2.83 |
|
|
— |
% |
NGL (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average
field-level price |
$ |
22.84 |
|
|
$ |
16.86 |
|
|
|
|
$ |
22.47 |
|
|
$ |
19.11 |
|
|
|
Commodity
derivative impact |
— |
|
|
— |
|
|
|
|
— |
|
|
— |
|
|
|
Net
realized price |
$ |
22.84 |
|
|
$ |
16.86 |
|
|
35 |
% |
|
$ |
22.47 |
|
|
$ |
19.11 |
|
|
18 |
% |
Average net
equivalent price (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
Average
field-level price |
$ |
37.77 |
|
|
$ |
26.91 |
|
|
|
|
$ |
36.98 |
|
|
$ |
28.13 |
|
|
|
Commodity
derivative impact |
(3.23 |
) |
|
0.46 |
|
|
|
|
(3.45 |
) |
|
(0.36 |
) |
|
|
Net
realized price |
$ |
34.54 |
|
|
$ |
27.37 |
|
|
26 |
% |
|
$ |
33.53 |
|
|
$ |
27.77 |
|
|
21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
|
(in millions) |
Lease operating
expense |
$ |
66.5 |
|
|
$ |
70.0 |
|
|
(5 |
)% |
|
$ |
139.0 |
|
|
$ |
139.2 |
|
|
— |
% |
Adjusted transportation
and processing costs(1) |
43.6 |
|
|
72.2 |
|
|
(40 |
)% |
|
90.3 |
|
|
142.4 |
|
|
(37 |
)% |
Production and property
taxes |
37.6 |
|
|
28.5 |
|
|
32 |
% |
|
66.5 |
|
|
57.6 |
|
|
15 |
% |
|
$ |
147.7 |
|
|
$ |
170.7 |
|
|
(13 |
)% |
|
$ |
295.8 |
|
|
$ |
339.2 |
|
|
(13 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(per Boe) |
Lease operating
expense |
$ |
4.71 |
|
|
$ |
5.05 |
|
|
(7 |
)% |
|
$ |
5.38 |
|
|
$ |
5.17 |
|
|
4 |
% |
Adjusted transportation
and processing costs(1) |
3.09 |
|
|
5.21 |
|
|
(41 |
)% |
|
3.49 |
|
|
5.28 |
|
|
(34 |
)% |
Production and property
taxes |
2.66 |
|
|
2.06 |
|
|
29 |
% |
|
2.57 |
|
|
2.14 |
|
|
20 |
% |
Total production
costs |
$ |
10.46 |
|
|
$ |
12.32 |
|
|
(15 |
)% |
|
$ |
11.44 |
|
|
$ |
12.59 |
|
|
(9 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________________________(1) Adjusted
transportation and processing costs is a non-GAAP measure. The
definition and reconciliation of adjusted transportation and
processing costs to transportation and processing costs, as
presented, are provided within Non-GAAP Measures at the end of this
release.
QEP RESOURCES, INC.NON-GAAP
MEASURES(Unaudited)
Adjusted EBITDA
This release contains references to the non-GAAP measure of
Adjusted EBITDA. Management defines Adjusted EBITDA as earnings
before interest, income taxes, depreciation, depletion and
amortization (EBITDA), adjusted to exclude changes in fair value of
derivative contracts, exploration expenses, gains and losses from
asset sales, impairment and certain other items. Management uses
Adjusted EBITDA to evaluate QEP's financial performance and trends,
make operating decisions and allocate resources. Management
believes the measure is useful supplemental information for
investors because it eliminates the impact of certain nonrecurring,
non-cash and/or other items that management does not consider as
indicative of QEP's performance from period to period. QEP's
Adjusted EBITDA may be determined or calculated differently than
similarly titled measures of other companies in our industry, which
would reduce the usefulness of this non-GAAP financial measure when
comparing our performance to that of other companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure)
to Adjusted EBITDA. This non-GAAP measure should be considered by
the reader in addition to, but not instead of, the financial
statements prepared in accordance with GAAP.
|
Three Months Ended |
|
Six Months Ended |
|
June 30, |
|
June 30, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
(in millions) |
Net income (loss) |
$ |
(336.0 |
) |
|
$ |
45.4 |
|
|
$ |
(389.6 |
) |
|
$ |
122.3 |
|
Interest expense |
38.2 |
|
|
34.9 |
|
|
73.2 |
|
|
68.7 |
|
Interest and other
(income) expense |
3.1 |
|
|
(1.8 |
) |
|
3.8 |
|
|
(2.4 |
) |
Income tax provision
(benefit) |
(106.2 |
) |
|
27.3 |
|
|
(120.1 |
) |
|
72.9 |
|
Depreciation, depletion
and amortization |
242.2 |
|
|
191.5 |
|
|
438.7 |
|
|
383.3 |
|
Unrealized (gains)
losses on derivative contracts |
33.6 |
|
|
(100.3 |
) |
|
43.6 |
|
|
(277.6 |
) |
Exploration
expenses |
0.1 |
|
|
— |
|
|
0.1 |
|
|
0.4 |
|
Net (gain) loss from
asset sales, inclusive of restructuring costs |
3.9 |
|
|
(19.8 |
) |
|
0.4 |
|
|
(19.8 |
) |
Impairment |
403.7 |
|
|
— |
|
|
404.4 |
|
|
0.1 |
|
Adjusted
EBITDA |
$ |
282.6 |
|
|
$ |
177.2 |
|
|
$ |
454.5 |
|
|
$ |
347.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income (Loss)
This release contains references to the non-GAAP measure of
Adjusted Net Income (Loss). Management defines Adjusted Net Income
(Loss) as earnings excluding gains and losses from asset sales,
unrealized gains and losses on derivative contracts, asset
impairments and certain other items. Management uses Adjusted Net
Income (Loss) to evaluate QEP’s financial performance and trends,
make operating decisions, and allocate resources. Management
believes the measure is useful supplemental information for
investors because it eliminates the impact of certain nonrecurring,
non-cash and/or other items that management does not consider as
indicative of QEP’s performance from period to period. QEP’s
Adjusted Net Income (Loss) may be determined or calculated
differently than similarly titled measures of other companies in
our industry, which would reduce the usefulness of this non-GAAP
financial measure when comparing our performance to that of other
companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure)
to Adjusted Net Income (Loss). This non-GAAP measure should be
considered by the reader in addition to, but not instead of, the
financial statements prepared in accordance with GAAP.
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
(in millions, except earnings per share) |
Net income (loss) |
$ |
(336.0 |
) |
|
$ |
45.4 |
|
|
$ |
(389.6 |
) |
|
$ |
122.3 |
|
Adjustments to net
income (loss) |
|
|
|
|
|
|
|
Unrealized (gains) losses on derivative contracts |
33.6 |
|
|
(100.3 |
) |
|
43.6 |
|
|
(277.6 |
) |
Income
taxes on unrealized (gains) losses on derivative contracts(1) |
(7.0 |
) |
|
37.2 |
|
|
(10.3 |
) |
|
103.5 |
|
Net
(gain) loss from asset sales, inclusive of restructuring costs |
3.9 |
|
|
(19.8 |
) |
|
0.4 |
|
|
(19.8 |
) |
Income
taxes on net (gain) loss from asset sales, inclusive of
restructuring costs(1) |
(0.8 |
) |
|
7.3 |
|
|
(0.1 |
) |
|
7.4 |
|
Impairment |
403.7 |
|
|
— |
|
|
404.4 |
|
|
0.1 |
|
Income
taxes on impairment(1) |
(83.6 |
) |
|
— |
|
|
(95.4 |
) |
|
— |
|
Total after tax
adjustments to net income |
349.8 |
|
|
(75.6 |
) |
|
342.6 |
|
|
(186.4 |
) |
Adjusted Net Income
(Loss) |
$ |
13.8 |
|
|
$ |
(30.2 |
) |
|
$ |
(47.0 |
) |
|
$ |
(64.1 |
) |
|
|
|
|
|
|
|
|
Earnings (Loss) per
Common Share |
|
|
|
|
|
|
|
Diluted
earnings per share |
$ |
(1.42 |
) |
|
$ |
0.19 |
|
|
$ |
(1.63 |
) |
|
$ |
0.51 |
|
Diluted
after-tax adjustments to net income (loss) per share |
1.48 |
|
|
(0.31 |
) |
|
1.43 |
|
|
(0.78 |
) |
Diluted
Adjusted Net Income per share |
$ |
0.06 |
|
|
$ |
(0.12 |
) |
|
$ |
(0.20 |
) |
|
$ |
(0.27 |
) |
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
|
|
|
Diluted |
237.0 |
|
|
240.6 |
|
|
238.9 |
|
|
240.5 |
|
____________________________(1) Income tax
impact of adjustments is calculated using QEP’s statutory rate of
20.7% and 37.1% for the three months ended June 30, 2018 and
2017, respectively and QEP's effective tax rate of 23.6% and 37.3%
for the six months ended June 30, 2018 and 2017,
respectively.Adjusted Transportation and Processing
Costs
This release contains references to the non-GAAP measure of
adjusted transportation and processing costs. Management defines
adjusted transportation and processing costs as transportation and
processing costs presented on the Condensed Consolidated Statements
of Operations and transportation and processing costs that are
included as part of "Oil and condensate, gas and NGL sales" on the
Condensed Consolidated Statements of Operations. These costs are
added together to reflect the total operating costs associated with
QEP's production. Management believes that this non-GAAP measure is
useful supplemental information for investors as it reflects the
total production costs required to operate the wells for the period
and is a more comparable measure to the operating costs of its
peers.
Below is a reconciliation of adjusted transportation and
processing costs to transportation and processing costs as
presented on the Condensed Consolidated Statements of Operations (a
GAAP measure). This non-GAAP measure should be considered by the
reader in addition to but not instead of, the financial statements
prepared in accordance with GAAP.
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
|
(in millions) |
Adjusted transportation
and processing costs |
$ |
43.6 |
|
|
$ |
72.2 |
|
|
$ |
(28.6 |
) |
|
$ |
90.3 |
|
|
$ |
142.4 |
|
|
$ |
(52.1 |
) |
Transportation and
processing costs deducted from oil and condensate, gas and NGL
sales |
(12.4 |
) |
|
— |
|
|
(12.4 |
) |
|
(25.1 |
) |
|
— |
|
|
(25.1 |
) |
Transportation and processing costs, as presented |
$ |
31.2 |
|
|
$ |
72.2 |
|
|
$ |
(41.0 |
) |
|
$ |
65.2 |
|
|
$ |
142.4 |
|
|
$ |
(77.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(per Boe) |
Adjusted transportation
and processing costs |
$ |
3.09 |
|
|
$ |
5.21 |
|
|
$ |
(2.12 |
) |
|
$ |
3.49 |
|
|
$ |
5.28 |
|
|
$ |
(1.79 |
) |
Transportation and
processing costs deducted from oil and condensate, gas and NGL
sales |
(0.88 |
) |
|
— |
|
|
(0.88 |
) |
|
(0.97 |
) |
|
— |
|
|
(0.97 |
) |
Transportation and processing costs, as presented |
$ |
2.21 |
|
|
$ |
5.21 |
|
|
$ |
(3.00 |
) |
|
$ |
2.52 |
|
|
$ |
5.28 |
|
|
$ |
(2.76 |
) |
The following tables present QEP's volumes and average prices
for its open derivative positions as of July 20, 2018:
Production Commodity Derivative
Swaps |
Year |
|
Index |
|
Total Volumes |
|
Average Swap Priceper Unit |
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2018 |
|
NYMEX
WTI |
|
8.3 |
|
|
$ |
52.46 |
|
2019 |
|
NYMEX
WTI |
|
9.5 |
|
|
$ |
52.66 |
|
2020 |
|
NYMEX
WTI |
|
1.8 |
|
|
$ |
60.77 |
|
Gas
sales |
|
|
|
(MMBtu) |
|
|
|
($/MMBtu) |
|
2018 |
|
NYMEX
HH |
|
44.1 |
|
|
$ |
3.00 |
|
2019 |
|
NYMEX
HH |
|
43.8 |
|
|
$ |
2.86 |
|
Production Commodity Derivative Basis
Swaps |
Year |
|
Index |
|
Basis |
|
Total Volumes |
|
Weighted-AverageDifferential |
|
|
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2018 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
4.6 |
|
|
$ |
(0.99 |
) |
2018 |
|
NYMEX
WTI |
|
Argus
WTI Houston(1) |
|
0.2 |
|
|
$ |
6.30 |
|
2019 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
4.7 |
|
|
$ |
(0.77 |
) |
2019 |
|
NYMEX
WTI |
|
Argus
WTI Houston(1) |
|
0.4 |
|
|
$ |
4.35 |
|
2020 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
1.5 |
|
|
$ |
(1.01 |
) |
Gas
sales |
|
|
|
|
|
(MMBtu) |
|
|
|
($/MMBtu) |
|
2018 |
|
NYMEX
HH |
|
IFNPCR |
|
3.1 |
|
|
$ |
(0.16 |
) |
____________________________(1)
Argus WTI Houston is an index price reflecting the
weighted average price of WTI at Magellan's East Houston crude oil
terminal.
In conjunction with the execution of the purchase and sale
agreement for the Uinta Basin Divestiture, QEP, at the request of
the buyer, entered into the derivative contracts listed below. Upon
the closing of the sale in the third quarter of 2018, the
derivative contracts will be novated to the buyer. The following
tables present QEP's volumes and average prices for the Uinta Basin
Divestiture derivative positions as of July 20, 2018.
Uinta Basin Divestiture Commodity Derivative
Swaps |
Year |
|
Index |
|
Total Volumes |
|
Average Swap Price per Unit |
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2018 |
|
NYMEX
WTI |
|
0.1 |
|
|
$ |
68.55 |
|
2019 |
|
NYMEX
WTI |
|
0.5 |
|
|
$ |
65.30 |
|
2020 |
|
NYMEX
WTI |
|
0.6 |
|
|
$ |
61.20 |
|
2021 |
|
NYMEX
WTI |
|
0.6 |
|
|
$ |
58.50 |
|
2022 |
|
NYMEX
WTI |
|
0.4 |
|
|
$ |
56.15 |
|
2023 |
|
NYMEX
WTI |
|
0.2 |
|
|
$ |
55.00 |
|
Gas
sales |
|
|
|
(MMBtu) |
|
|
|
($/MMBtu) |
|
2018 |
|
NYMEX
HH |
|
2.9 |
|
|
$ |
2.86 |
|
2019 |
|
NYMEX
HH |
|
13.4 |
|
|
$ |
2.74 |
|
2020 |
|
NYMEX
HH |
|
20.2 |
|
|
$ |
2.63 |
|
2021 |
|
NYMEX
HH |
|
19.3 |
|
|
$ |
2.59 |
|
2022 |
|
NYMEX
HH |
|
8.7 |
|
|
$ |
2.61 |
|
2023 |
|
NYMEX
HH |
|
5.4 |
|
|
$ |
2.68 |
|
Uinta Basin Divestiture Commodity Derivative
Basis Swaps |
Year |
|
Index |
|
Basis |
|
Total Volumes |
|
Weighted-Average Differential |
Gas
sales |
|
|
|
|
|
(MMBtu) |
|
|
|
($/MMBtu) |
|
2018 |
|
NYMEX
HH |
|
IFNPCR |
|
2.9 |
|
|
$ |
(0.63 |
) |
2019 |
|
NYMEX
HH |
|
IFNPCR |
|
13.4 |
|
|
$ |
(0.77 |
) |
2020 |
|
NYMEX
HH |
|
IFNPCR |
|
20.2 |
|
|
$ |
(0.77 |
) |
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