Hires financial advisors to assist with
divestiture of Williston and Uinta basin assets
QEP Resources, Inc. (NYSE:QEP) (QEP or
the Company) today announced strategic initiatives to transition to
a pure-play Permian Basin company, reported fourth quarter and full
year 2017 financial and operating results, and provided initial
2018 guidance and capital investment plan.
2018 Strategic and Financial Initiatives
QEP’s Board of Directors has unanimously approved several
strategic and financial initiatives to transition the Company to a
pure-play Permian Basin company and to address the significant
discount to net asset value reflected in the Company's share
price.
Strategic Initiatives
- Engaged financial advisors to assist with the divestiture of
the Company’s Williston and Uinta basin assets, with data rooms
expected to be opened in late March or early April
- Market remaining non-Permian assets, including the
Haynesville/Cotton Valley (Haynesville), in the second half of
2018
Financial Initiatives
- Use proceeds from asset sales to fund Permian Basin development
program, until the program reaches operating cash flow neutrality
in 2019, reduce debt and return cash to shareholders through share
repurchases
- Authorized a $1.25 billion share repurchase program(1)
- Approved 2018 capital investment plan of approximately $1.075
billion, of which approximately 65% will be directed toward the
Permian Basin
"The strategic initiatives announced today are responsive to
ongoing shareholder feedback and fit with our long-term goal of
becoming a more oil-focused company. The initiatives will allow us
to simplify our portfolio, streamline our operations, and sharpen
our focus on our Permian Basin assets, quickly resulting in QEP
becoming a leading pure-play Permian company. Today our Permian
Basin assets consist of approximately 44,000 net acres in the core
of the northern Midland Basin. The assets delivered 8.2 MMboe of
net production in 2017 with estimated total proved year-end 2017
reserves of 272.7 MMboe,” commented Chuck Stanley, Chairman,
President and CEO of QEP.
____________________________(1)
Subject to available
liquidity, market conditions and proceeds from asset sales.
"We expect to continue to make progress developing our Permian
Basin assets in 2018 utilizing “tank-style” completions. We believe
this approach maximizes the economic recovery of oil through the
simultaneous development of multiple subsurface targets, while
improving capital efficiency through shared surface facilities,
which we believe will reduce per-unit operating costs and result in
expanded operating margins and improve our returns on invested
capital. Based on our current plan, which contemplates running five
to six rigs and assumes commodity prices averaging $55 per barrel
and $3 per MMBtu, we expect the Permian Basin assets will achieve
operating cash flow neutrality in 2019, while delivering peer
leading production growth.”
"We intend to use the proceeds from asset sales to fund the
ongoing development of our core Permian operations, reduce debt,
and return cash to shareholders through a significant share
repurchase program."
"I want to personally thank all of our employees for their
continued commitment to the safe and efficient operation of all of
our assets as we work together to accomplish this transition,”
continued Stanley.
The Company has posted to its website www.qepres.com a
presentation that supplements the information provided in this
release. See slide 3 in the February 2018 QEP Investor Presentation
for a summary of our announced Strategic Initiatives.
Full Year 2017 Highlights
- Net Income of $269.3 million, or $1.12 per fully-diluted
share
- Total oil equivalent production of 53.1 MMboe, of which 37% was
crude oil
- Record Permian Basin oil production of 6.1 MMbbl, a 52%
increase
- Natural gas production of 168.9 Bcf, including 72.9 Bcf in the
Haynesville
- Year-end total proved reserves of 684.7 MMboe, including record
proved oil reserves of 320.5 MMbbl
- Divested Pinedale Anticline natural gas asset for net cash
proceeds of $718.2 million, after purchase price adjustments (the
Pinedale Divestiture)
- Acquired approximately 15,100 net acres in the core of the
northern Midland Basin (2017 Permian Basin Acquisition)
"Our accomplishments in 2017 were significant, including the
divestiture of our Pinedale Anticline natural gas asset and
expansion of our tier one acreage position in the Permian Basin. We
continued to accelerate our development activity while actively
enhancing our drilling and completion designs in the Permian Basin.
We also had success with our refrac programs in both the
Haynesville and the Williston Basin and we successfully completed
our first long-lateral horizontal well utilizing state-of-the-art
completion techniques in the Haynesville. As we begin 2018, the
Company is undertaking a number of strategic initiatives that will
result in QEP becoming a pure-play Permian Basin company,”
concluded Stanley.
QEP Fourth Quarter and Full Year 2017 Financial
Results
The Company reported net income of $150.3 million for the fourth
quarter 2017, or $0.62 per diluted share, compared with a loss of
$133.3 million, or $0.56 per diluted share, in the fourth quarter
2016. For the year ended December 31, 2017, QEP reported net
income of $269.3 million, or $1.12 per diluted share, compared with
a net loss of $1,245.0 million, or $5.62 per diluted share, for the
comparable 2016 period. Net income for the fourth quarter and year
ended December 31, 2017, was positively impacted by a $307.9
million tax benefit, primarily due to a revaluation of the
Company’s net deferred tax liability to reflect the change in the
federal corporate income tax rate from 35% to 21% under the Tax
Cuts and Jobs Act signed into law on December 22, 2017 (Tax Reform
Act).
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 fourth quarter 2017
Adjusted Net Income (a non-GAAP measure) was $274.0 million, or
$1.13 per diluted share, compared with an Adjusted Net Loss of
$36.2 million, or $0.15 per diluted share, in the fourth quarter
2016. For the year ended December 31, 2017, the Company’s
Adjusted Net Income was $185.2 million, or $0.77 per diluted share,
compared with an Adjusted Net Loss of $232.8 million, or $1.05 per
diluted share, for 2016.
Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2017
was $195.1 million, compared to $174.5 million in the fourth
quarter 2016. For the year ended December 31, 2017, the
Company reported Adjusted EBITDA of $736.1 million compared to
$628.1 million for full year 2016, a 17% increase, primarily due to
a 15% increase in average realized prices, a 15% decrease in
transportation and processing costs and a 22% decrease in general
and administrative expenses. These changes were partially offset by
a 5% decrease in oil equivalent production, a 31% increase in lease
operating expense and a 21% increase in production and property
taxes. The definitions and reconciliations of Adjusted EBITDA and
Adjusted Net Income to Net Income (Loss) are provided within the
financial tables of this release.
Production
Oil equivalent production was 12.1 MMboe for the fourth quarter
2017 compared with 13.7 MMboe for the fourth quarter 2016. Oil
production increased 7%, while natural gas and NGL production
decreased 22% and 23%, respectively. Fourth quarter 2017 equivalent
production was impacted by weather-related issues in the Williston
and Permian basins, 33.5 Mboe and 52.0 Mboe respectively, and the
Pinedale Divestiture in September 2017. The decrease was partially
offset by increased production related to ongoing completion
activity in the Permian Basin and Haynesville. For the year ended
December 31, 2017, oil equivalent production was 53.1 MMboe
compared with 55.8 MMboe for the comparable 2016 period, a 5%
decrease. Adjusted for the Pinedale Divestiture, production
increased 22% in the fourth quarter and 8% for the year ended
December 31, 2017.
Operating Expenses
During the fourth quarter 2017, lease operating expense (LOE)
was $6.58 per Boe, an increase of 47% compared with the fourth
quarter 2016. For the year ended December 31, 2017, LOE was
$5.55 per Boe, an increase of 38% compared with the prior year. The
increase in LOE during the fourth quarter and year ended December
31, 2017 was driven by an increase in workovers in the Williston
and Permian Basins and Haynesville, power and fuel expenses,
services and supplies expenses in the Permian Basin and increased
water disposal expenses in Haynesville.
During the fourth quarter 2017, transportation and processing
costs were $3.54 per Boe, a decrease of 31% compared with the
fourth quarter 2016. For the year ended December 31, 2017,
transportation and processing costs were $4.61 per Boe, a decrease
of 11% compared with the prior year. The decrease in transportation
and processing costs during the fourth quarter and year ended
December 31, 2017 was primarily attributable to decreases in
Pinedale, primarily related to the Pinedale Divestiture and
recovery of historical transportation costs, and in Haynesville
related to the recovery of fees for historical unutilized gathering
and transportation capacity that was charged to QEP by the operator
of wells in which QEP had a working interest.
During the fourth quarter 2017, production and property taxes
were $2.34 per Boe, an increase of 8% compared with the fourth
quarter 2016. For the year ended December 31, 2017, production
and property taxes were $2.15 per Boe, an increase of 26% compared
with the prior year, primarily a result of increased oil and gas
revenues primarily from higher field-level prices partially offset
by lower production.
General and administrative expense for the fourth quarter 2017
was $45.2 million, or $3.75 per Boe, an increase of 33% compared
with the fourth quarter 2016. The increase in fourth quarter 2017
was primarily due to an increase in share-based compensation
expense and an increase in benefits, partially offset by a decrease
in legal expenses. For the year ended December 31, 2017,
general and administrative expense was $153.5 million, or $2.89 per
Boe, a decrease of 18% compared with the prior year. The decrease
for the year ended December 31, 2017, was driven primarily by
a decrease in legal expenses and loss contingencies and a decrease
in share-based compensation expense, partially offset by an
increase in labor, benefits and employee expenses.
Capital Investment
Total capital investment was $1,056.3 million (on an accrual
basis) for the fourth quarter 2017, compared with $714.6 million
for the fourth quarter 2016. Total capital investment for the year
ended December 31, 2017 (on an accrual basis), was $2,035.0
million, up $859.7 million compared with the year ended
December 31, 2016.
Capital investment, excluding property acquisitions was $372.2
million (on an accrual basis) for the fourth quarter 2017, compared
with $145.5 million for the fourth quarter 2016. Capital
investment, excluding property acquisitions, for the year ended
December 31, 2017 (on an accrual basis), was $1,219.8 million,
up $689.7 million compared with the year ended December 31,
2016.
During the year ended December 31, 2017, the Company
invested $815.2 million to acquire various oil and gas properties,
undeveloped leasehold acreage, producing wells and additional
surface acreage, primarily in the Permian Basin.
2017 Permian Basin Acquisition
In October 2017, QEP acquired additional oil and gas
properties in the 2017 Permian Basin Acquisition for an
aggregate purchase price of $720.7 million, subject to post-closing
purchase price adjustments. The 2017 Permian Basin Acquisition
assets consist of approximately 15,100 net acres, mainly in Martin
County, Texas, an increase of approximately 1,300 net acres
compared to the 13,800 net acres originally announced in July 2017.
QEP structured the 2017 Permian Basin Acquisition transaction as a
like-kind exchange under Section 1031 of the Internal Revenue
Service Code and funded the purchase price with the proceeds from
the Pinedale Divestiture.
In the fourth quarter 2017, QEP made offers to various persons
who own additional oil and gas interests in certain properties
included in the 2017 Permian Basin Acquisition on substantially the
same terms and conditions as the original purchase. If all offers
are accepted, the Company now anticipates that the aggregate
purchase price for the additional oil and gas interests will not
exceed $50.0 million. These acquisitions are expected to close in
the first half of 2018. When combined with the acreage from the
2017 Permian Basin Acquisition, the Company expects the total
acquired acreage to be approximately 16,000 net acres.
Asset Divestitures
In addition to the Pinedale Divestiture, as a part of the
Company’s ongoing effort to simplify its portfolio, QEP entered
into agreements to sell, or closed on the sale of several non-core
assets for total proceeds of approximately $18.9 million during the
fourth quarter 2017. For the year ended December 31, 2017, the
Company received total proceeds from asset divestitures of $806.8
million.
Liquidity
During the fourth quarter 2017, the Company issued $500.0
million of 5.625% Senior Notes due in 2026 and used the proceeds to
repay $445.7 million of debt, as follows:
- Redeemed $134.0 million of its outstanding 6.80% Senior Notes
due in 2018;
- Purchased $84.3 million of its 6.80% Senior Notes due in 2020
pursuant to a tender offer; and
- Purchased $227.4 million of its 6.875% Senior Notes due in 2021
pursuant to a tender offer.
2018 Guidance
The following guidance excludes the impacts of our announced
strategic initiatives.
QEP's quarterly and full year 2018 guidance and related
assumptions are shown below. The Company’s guidance assumes an oil
price of $55 per barrel and a natural gas price of $3 per MMBtu and
the following additional assumptions:
Rig Count
- Permian (average of five rigs)
- Williston (average of one-half rig)
- Haynesville (average of one-half rig)
Wells Put on Production / Refracs:
- Permian Basin: approximately 95 net operated wells put on
production
- Company: approximately 111 net operated wells put on
production
- Refracs: approximately 35 net, in the Williston Basin and the
Haynesville
- No property acquisitions or divestitures
- Ethane rejection for the entire year where QEP can make such an
election
The Company anticipates updating guidance as it completes the
contemplated divestitures.
|
2018 Guidance |
|
|
|
2018 |
|
|
|
Oil
production (MMbbl) |
21.0 - 22.5 |
Gas
production (Bcf) |
132.0 - 143.0 |
NGL
production (MMbbl) |
4.7 - 5.2 |
Total oil equivalent production (MMboe) |
47.7 - 51.5 |
|
|
Lease
operating and transportation expense (per Boe) |
$9.00 - $10.00 |
Depletion,
depreciation and amortization (per Boe) |
$17.50 - $18.50 |
Production
and property taxes (% of field-level revenue) |
8.5% |
(in millions) |
General and
administrative expense(1) |
$185 - $205 |
|
|
Capital
investment (excluding property acquisitions) |
|
Drilling, Completion and Equip(2) |
$965 - $1,065 |
Infrastructure |
$50 |
Corporate |
$10 |
Total capital investment (excluding property acquisitions) |
$1,025 - $1,125 |
____________________________(1)
General and administrative
expense includes approximately $25.0 million of non-cash
share-based compensation expense and approximately $20.0 million of
estimated retention program
expense.(2) Approximately
65% of the planned capital investment is focused on projects in the
Permian Basin. Drilling, Completion and Equip includes
approximately $20.0 million of non-operated well completion
costs.
|
2018 Quarterly Production
Guidance |
|
|
1Q 2018 |
2Q 2018 |
3Q 2018 |
4Q 2018 |
2018 |
QEP
Resources |
Current Forecast |
Oil
production (MMbbl) |
4.5 - 4.7 |
4.9 - 5.2 |
5.7 - 6.3 |
5.8 - 6.2 |
21.0 - 22.5 |
Gas
production (Bcf) |
31.7 - 33.6 |
33.9 -
36.8 |
35.9 -
38.9 |
30.5 -
33.7 |
132.0
- 143.0 |
NGL
production (MMbbl) |
1.0 - 1.1 |
1.1 -
1.2 |
1.3 -
1.4 |
1.3 -
1.5 |
4.7 -
5.2 |
Total oil equivalent production (MMboe) |
10.8 - 11.4 |
11.7 - 12.5 |
13.0 - 14.2 |
12.2 - 13.3 |
47.7 - 51.5 |
Total wells put on production (net) |
20 |
46 |
25 |
20 |
111 |
Total refracs put on production (net) |
14 |
13 |
8 |
0 |
35 |
|
|
|
|
|
|
Permian Basin |
|
|
|
|
|
Oil
production (MMbbl) |
2.0 - 2.1 |
2.6 -
2.7 |
2.8 -
3.1 |
3.2 -
3.4 |
10.6 -
11.3 |
Gas
production (Bcf) |
1.6 - 1.8 |
2.0 -
2.2 |
2.3 -
2.5 |
2.4 -
2.6 |
8.3 -
9.1 |
NGL production (MMbbl) |
0.30 - 0.35 |
0.40 - 0.45 |
0.45 - 0.50 |
0.50 - 0.55 |
1.65 - 1.85 |
Permian Basin equivalent production (MMboe) |
2.6 - 2.8 |
3.3 -
3.5 |
3.6 -
4.0 |
4.1 -
4.4 |
13.6
-14.7 |
Permian Basin wells put on production (net) |
18 |
34 |
23 |
20 |
95 |
|
|
|
|
|
|
Production Outlook
At the midpoint of guidance, the Company expects to deliver
year-over-year total oil-equivalent production growth of
approximately 15% in 2018, compared with 2017 volumes after
adjusting for the impact of the Pinedale Divestiture, and Permian
Basin total oil-equivalent Permian Basin production is expected to
grow to 13.6 - 14.7 MMboe, an increase of over 70%, compared with
2017 volumes.
The Company expects to deliver year-over-year crude oil
production growth of approximately 13% in 2018, compared with 2017
volumes, after adjusting for the impact of the 2017 Pinedale
Divestiture, and Permian Basin crude oil volumes are expected to
grow to 10.6 - 11.3 MMbbl.
The Company expects to deliver year-over-year natural gas
production growth of approximately 18%, at the midpoint, in 2018,
compared with 2017 volumes, after adjusting for the 2017 Pinedale
Divestiture, primarily from increased drilling and refrac activity
in the Haynesville.
Operations Summary
Permian Basin
Permian Basin net production averaged approximately 27.8 Mboed
(89% liquids) during the fourth quarter 2017, a Company record for
the Permian Basin and a 9% increase compared with the third quarter
2017, and an 87% increase compared with the fourth quarter
2016.
QEP completed and turned to sales 24 gross-operated horizontal
wells in the fourth quarter 2017 (average working interest 100%),
in two drilling spacing units ("DSU'"), one with eight wells and
the other with 16 wells. Five wells in the eight well DSU targeted
the Spraberry Shale and were completed with an average lateral
length of 7,355 feet and achieved an average peak 24-hour IP rate
of 185 Boed per 1,000 feet (86% oil). In the sixteen well DSU,
three of the wells targeted the Wolfcamp A and five the Wolfcamp B.
The Wolfcamp A wells were completed with an average lateral length
of 7,355 feet and achieved an average peak 24-hour IP rate of 164
Boed per 1,000 feet (83% oil). The Wolfcamp B wells were completed
with an average lateral length of 7,350 feet and achieved an
average peak 24-hour IP rate of 133 Boed per 1,000 feet (82% oil).
None of the wells on either of the pads had reached 30-day peak
rates at the end of the fourth quarter 2017.
At the end of the fourth quarter 2017, the Company had 36
gross-operated horizontal wells waiting on completion (working
interest 100%) and 11 gross-operated horizontal wells being drilled
(average working interest 99%) and an additional 18 wells for which
surface casing has been set (average working interest 95%) as of
December 31, 2017.
Current QEP-operated drilled and completed authorization for
expenditure (AFE) well costs for the Permian Basin are detailed on
slide 23 of the February 2018 Investor Presentation.
At the end of the fourth quarter 2017, the Company had six
operated rigs in the Permian Basin.
Slides 9-15 in the February 2018 Investor Presentation depict
QEP's acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net production averaged approximately 48.7 Mboed
(86% liquids) during the fourth quarter 2017, a 5% increase
compared with the third quarter 2017 and a 9% decrease compared
with the fourth quarter 2016.
The Company completed and turned to sales two gross operated
wells during the fourth quarter 2017, both of which were on Ft.
Berthold (average working interest 90%). The wells were completed
with an average lateral length of 9,928 feet and had an average
peak 24-hour IP of 230 Boed per 1,000 feet (92% oil) and an average
IP 30 rate of 105 Boed per 1,000 feet (92% oil).
The Company also completed nine gross-operated refracs, five on
South Antelope (average working interest 100%) and four on Ft.
Berthold (average working interest 100%) during the fourth quarter.
The five refracs on South Antelope achieved an average per well IP
30 rate increase of 822 Boed/well (74% oil). Pre-refrac, the five
wells averaged 77 Boed/well (64% oil), while post-refrac the five
wells had an average peak 24-hour IP of 1,460 Boed/well (73% oil)
and an average IP 30 of 899 Boed/well (74% oil). The four refracs
on Ft. Berthold were still in the early stages of cleanup as of the
end of the fourth quarter 2017.
At the end of the fourth quarter 2017, QEP had five
gross-operated wells waiting on completion (average working
interest 94%) and two wells being drilled (average working interest
100%), all on South Antelope.
Current QEP-operated drilled and completed AFE well costs and
refrac costs for the Williston Basin are detailed on slide 23 of
the February 2018 Investor Presentation.
At the end of the fourth quarter 2017, the Company had one
operated rig in the Williston Basin, operating on South
Antelope.
Slides 16-18 in the February 2018 Investor Presentation depict
QEP's acreage and activity in the Williston Basin.
Haynesville
Haynesville net production averaged approximately 262.7 MMcfed
(43.8 Mboed) (0% liquids) during fourth quarter 2017, a 21%
increase compared with the third quarter 2017 and an 83% increase
compared with the fourth quarter 2016.
The Company completed and turned to sales two gross operated
wells during the fourth quarter 2017 (average working interest
99%). One of the two wells completed reached peak production during
the quarter. The first well drilled and completed in the quarter
had an IP 24 rate of 21.1 MMcfed and an IP 30 rate of 19.5 MMcfed
(100% gas) with a lateral length of 5,102 feet. The second well
drilled and completed during the quarter was still in the process
of cleaning up at the end of the quarter and had a lateral length
of 10,480 feet. During the quarter, the Company also completed five
QEP-operated refracs, with an average incremental 24-hour rate
increase of 17.4 MMcfed/well (average working interest 99%).
Current QEP-operated drilled and completed AFE well costs and
refrac costs for Haynesville are detailed on slide 23 of the
February 2018 Investor Presentation.
At the end of the fourth quarter, the Company had one operated
rig in Haynesville.
Slides 19-20 in the February 2018 Investor Presentation depict
QEP's acreage and activity in Haynesville.
Uinta Basin
Uinta Basin net production averaged approximately 54.4 MMcfed
(9.1 Mboed) (23% liquids) during the fourth quarter 2017. This
represents a 7% decrease in production compared with the third
quarter 2017 and a 14% decrease compared with the fourth quarter
2016.
At the end of the fourth quarter, the Company had one drilling
rig in the Uinta Basin.
Estimated Proved Reserves
At December 31, 2017, QEP's estimated proved reserves were
approximately 684.7 MMboe, a 6% decrease compared with 2016,
primarily due to the sale of reserves in-place associated with the
Pinedale Divestiture, which was partially offset by an increase of
proved reserves as a result of extensions and discoveries in the
Permian Basin and the 2017 Permian Basin Acquisition. Williston
Basin proved reserves decreased primarily from under performance of
wells in our high density pilot test areas. Other Northern proved
reserves decreased primarily due to property divestitures in 2017.
Uinta Basin proved reserves decreased primarily due to changing
from a vertical well development plan to a horizontal well
development plan. Haynesville/Cotton Valley's increase of proved
reserves is primarily the result of the successful refracturing
program in 2017. Extensions and discoveries were 86.4 MMboe, were
primarily in the Permian Basin and related to new well completions
and associated new PUD locations. Approximately 56% of total proved
reserves at year-end 2017 and 42% of total proved reserves at
year-end 2016 were crude oil and NGL. Proved developed reserves
were 253.1 MMboe, or 37%, of total estimated proved reserves at
year-end 2017.
A reconciliation of reported quantities of estimated proved
reserves is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Gas |
|
NGL |
|
Total |
|
|
(MMbbl) |
|
(Bcf) |
|
(MMbbl) |
|
(MMboe)(1) |
Balance at December 31,
2016 |
|
238.6 |
|
|
2,553.8 |
|
|
67.2 |
|
|
731.4 |
|
Revisions
of previous estimates |
|
3.7 |
|
|
12.5 |
|
|
(3.1 |
) |
|
2.7 |
|
Extensions and discoveries |
|
59.1 |
|
|
101.9 |
|
|
10.4 |
|
|
86.4 |
|
Purchase
of reserves in place |
|
46.6 |
|
|
125.5 |
|
|
8.7 |
|
|
76.3 |
|
Sale of
reserves in place |
|
(7.9 |
) |
|
(831.2 |
) |
|
(12.6 |
) |
|
(159.0 |
) |
Production |
|
(19.6 |
) |
|
(168.9 |
) |
|
(5.4 |
) |
|
(53.1 |
) |
Balance at
December 31, 2017 |
|
320.5 |
|
|
1,793.6 |
|
|
65.2 |
|
|
684.7 |
|
____________________________(1)
Natural gas is converted to crude
oil equivalent at the ratio of six Mcf of natural gas to one barrel
of crude oil equivalent.
Details on the reported quantities of estimated year-end 2017
and 2016 proved reserves presented by operating area, proved
reserve category and percentage of total estimated proved reserves
composed of crude oil and NGL (liquids) are as follows:
|
|
|
|
|
|
|
|
|
|
|
Total (in MMboe) |
|
% of total |
|
PUD % |
|
liquids % |
For
the year ended December 31, 2017 |
|
|
|
|
|
|
Northern Region |
|
|
|
|
|
|
|
|
Williston Basin |
|
146.9 |
|
|
21 |
% |
|
36 |
% |
|
88 |
% |
Pinedale |
|
— |
|
|
— |
% |
|
— |
% |
|
— |
% |
Uinta Basin |
|
100.8 |
|
|
15 |
% |
|
62 |
% |
|
15 |
% |
Other Northern |
|
4.5 |
|
|
1 |
% |
|
— |
% |
|
13 |
% |
Southern Region |
|
|
|
|
|
|
|
|
Permian Basin |
|
272.7 |
|
|
40 |
% |
|
77 |
% |
|
88 |
% |
Haynesville/Cotton Valley |
|
159.8 |
|
|
23 |
% |
|
— |
% |
|
— |
% |
Other Southern |
|
— |
|
|
— |
% |
|
— |
% |
|
— |
% |
Total proved reserves |
|
684.7 |
|
|
100 |
% |
|
63 |
% |
|
56 |
% |
|
|
|
|
|
|
|
|
|
For
the year ended December 31, 2016 |
|
|
|
|
|
|
Northern Region |
|
|
|
|
|
|
|
|
Williston Basin |
|
160.2 |
|
|
22 |
% |
|
37 |
% |
|
86 |
% |
Pinedale |
|
160.7 |
|
|
22 |
% |
|
14 |
% |
|
13 |
% |
Uinta Basin |
|
106.1 |
|
|
14 |
% |
|
62 |
% |
|
15 |
% |
Other Northern |
|
12.3 |
|
|
2 |
% |
|
— |
% |
|
6 |
% |
Southern Region |
|
|
|
|
|
|
|
|
Permian Basin |
|
147.8 |
|
|
20 |
% |
|
81 |
% |
|
88 |
% |
Haynesville/Cotton Valley |
|
144.3 |
|
|
20 |
% |
|
74 |
% |
|
— |
% |
Other Southern |
|
— |
|
|
— |
% |
|
— |
% |
|
— |
% |
Total proved reserves |
|
731.4 |
|
|
100 |
% |
|
51 |
% |
|
42 |
% |
Fourth Quarter and Full Year 2017 Results Conference
Call
QEP's management will discuss fourth quarter and full year 2017
results in a conference call on Thursday, March 1, 2018,
beginning at 9:00 a.m. EST. 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 March
29, 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 #13675566. In addition, QEP’s slides for the fourth
quarter 2017, 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 focused in two
regions of the United States: the Northern Region (primarily in
North Dakota and Utah) and the Southern Region (primarily Texas and
Louisiana). For more information, visit QEP Resources' 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 and financial
initiatives; timing and divestiture of assets; use of proceeds from
sale of assets; amount and funding for share repurchase program;
simplifying our asset portfolio; streamlining operations; focus on
Permian Basin assets; becoming a leading pure-play Permian Basin
company; utilization of our tank-style completion methodology and
anticipated benefits from this methodology; amount and allocation
of planned capital expenditures and related assumptions; achieving
cash flow neutrality in 2019; delivering peer leading production
growth; the number and location of drilling rigs to be deployed;
forecasted production amounts and growth and related assumptions;
forecasted lease operating and transportation expense, depletion,
depreciation and amortization expense, general and administrative
expense, non-cash share based compensation expense, retention
program expense, production and property taxes and capital
investment for 2018 and related assumptions for such guidance; 2018
quarterly production guidance and assumptions for such guidance;
plans to update guidance; impact of Tax Reform Act; plans to reject
ethane in 2018; estimated reserves; forecasted number of new wells
and the locations of such wells; number of workover wells. 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 our credit rating, our
compliance with loan covenants, the increasing credit pressure on
our 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 (OPEC); 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 Tax Reform Act; actual proceeds from asset sales;
actions of activist shareholders; 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; 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; 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. QEP
Resources 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.
Disclosures regarding non-proved reserves
The Securities and Exchange Commission (SEC) requires oil and
gas companies, in their filings with the SEC, to disclose proved
reserves that a company has demonstrated by actual production or
through reliable technology to be economically and legally
producible at specific prices and existing economic and operating
conditions. The SEC permits optional disclosure of probable and
possible reserves; however, QEP has made no such disclosures in its
filings with the SEC. Estimates of probable and possible reserves
are by their nature more speculative than estimates of proved
reserves and, accordingly, are subject to substantially more risks
of actually being realized. Actual quantities that may be
ultimately recovered from QEP’s interests may differ substantially
from the reserve estimates contained in this release. Investors are
urged to closely consider the disclosures and risk factors about
the Company’s reserves in its Annual Report on Form 10-K for the
year ended December 31, 2017.
Contact
Contact |
|
|
Investors: |
|
Media: |
William I. Kent,
IRC |
|
Brent Rockwood |
Director, Investor
Relations |
|
Director,
Communications |
303-405-6665 |
|
303-672-6999 |
|
|
|
|
|
|
|
|
QEP RESOURCES,
INC. |
|
|
|
CONSOLIDATED
STATEMENTS OF OPERATIONS |
|
|
|
|
Three Months Ended |
|
Year Ended |
|
December 31, |
|
December 31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
REVENUES |
(in millions, except per share amounts) |
Oil
sales |
$ |
283.7 |
|
|
$ |
216 |
|
|
$ |
939.4 |
|
|
$ |
769.1 |
|
Gas
sales |
94.6 |
|
|
129.6 |
|
|
494 |
|
|
417.1 |
|
NGL
sales |
27.9 |
|
|
27.3 |
|
|
111.9 |
|
|
83.5 |
|
Other
revenues |
4.7 |
|
|
1.9 |
|
|
15.0 |
|
|
6.2 |
|
Purchased
oil and gas sales |
18.1 |
|
|
24.9 |
|
|
62.6 |
|
|
101.2 |
|
Total
Revenues |
429.0 |
|
|
399.7 |
|
|
1,622.9 |
|
|
1,377.1 |
|
OPERATING
EXPENSES |
|
|
|
|
|
|
|
Purchased
oil and gas expense |
18.9 |
|
|
24.7 |
|
|
64.3 |
|
|
105.5 |
|
Lease
operating expense |
79.4 |
|
|
61.4 |
|
|
294.8 |
|
|
224.7 |
|
Transportation and processing costs |
42.7 |
|
|
70.3 |
|
|
245.3 |
|
|
289.2 |
|
Gathering
and other expense |
2.3 |
|
|
1.2 |
|
|
7.3 |
|
|
5.0 |
|
General
and administrative |
45.2 |
|
|
38.6 |
|
|
153.5 |
|
|
196.5 |
|
Production and property taxes |
28.2 |
|
|
29.5 |
|
|
114.3 |
|
|
94.8 |
|
Depreciation, depletion and amortization |
194.3 |
|
|
203.6 |
|
|
754.5 |
|
|
871.1 |
|
Exploration expenses |
0.3 |
|
|
0.8 |
|
|
22.0 |
|
|
1.7 |
|
Impairment |
50.5 |
|
|
6.1 |
|
|
78.9 |
|
|
1,194.3 |
|
Total
Operating Expenses |
461.8 |
|
|
436.2 |
|
|
1,734.9 |
|
|
2,982.8 |
|
Net gain (loss) from
asset sales |
8.3 |
|
|
— |
|
|
213.5 |
|
|
5.0 |
|
OPERATING
INCOME (LOSS) |
(24.5 |
) |
|
(36.5 |
) |
|
101.5 |
|
|
(1,600.7 |
) |
Realized and unrealized
gains (losses) on derivative contracts |
(138.8 |
) |
|
(147.9 |
) |
|
24.5 |
|
|
(233.0 |
) |
Interest and other
income (expense) |
(0.9 |
) |
|
18.1 |
|
|
1.6 |
|
|
23.7 |
|
Loss from early
extinguishment of debt |
(32.7 |
) |
|
— |
|
|
(32.7 |
) |
|
— |
|
Interest expense |
(34.7 |
) |
|
(34.0 |
) |
|
(137.8 |
) |
|
(143.2 |
) |
INCOME
(LOSS) BEFORE INCOME TAXES |
(231.6 |
) |
|
(200.3 |
) |
|
(42.9 |
) |
|
(1,953.2 |
) |
Income tax (provision)
benefit |
381.9 |
|
|
67.0 |
|
|
312.2 |
|
|
708.2 |
|
NET
INCOME (LOSS) |
$ |
150.3 |
|
|
$ |
(133.3 |
) |
|
$ |
269.3 |
|
|
$ |
(1,245.0 |
) |
|
|
|
|
|
|
|
|
Earnings (loss) per
common share |
|
|
|
|
|
|
|
Basic |
$ |
0.62 |
|
|
$ |
(0.56 |
) |
|
$ |
1.12 |
|
|
$ |
(5.62 |
) |
Diluted |
$ |
0.62 |
|
|
$ |
(0.56 |
) |
|
$ |
1.12 |
|
|
$ |
(5.62 |
) |
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
|
|
|
Used in
basic calculation |
241.0 |
|
|
239.6 |
|
|
240.6 |
|
|
221.7 |
|
Used in
diluted calculation |
241.0 |
|
|
239.6 |
|
|
240.6 |
|
|
221.7 |
|
Dividends per common
share |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
QEP RESOURCES,
INC. |
|
|
|
CONSOLIDATED
BALANCE SHEETS |
|
|
|
|
|
|
|
|
December 31, |
|
December 31, |
2017 |
2016 |
ASSETS |
(in millions) |
Current Assets |
|
|
|
Cash and
cash equivalents |
$ |
— |
|
|
$ |
443.8 |
|
Accounts
receivable, net |
142.1 |
|
|
155.7 |
|
Income
tax receivable |
4.9 |
|
|
18.6 |
|
Fair
value of derivative contracts |
3.4 |
|
|
— |
|
Hydrocarbon inventories, at lower of average cost or net realizable
value |
3.6 |
|
|
10.4 |
|
Prepaid
expenses |
10.7 |
|
|
11.4 |
|
Other
current assets |
0.7 |
|
|
0.2 |
|
Total
Current Assets |
165.4 |
|
|
640.1 |
|
Property,
Plant and Equipment (successful efforts method for oil and gas
properties) |
|
|
Proved
properties |
12,470.9 |
|
|
14,232.5 |
|
Unproved
properties |
1,095.8 |
|
|
871.5 |
|
Gathering
and other |
319.7 |
|
|
301.8 |
|
Materials
and supplies |
37.8 |
|
|
32.7 |
|
Total
Property, Plant and Equipment |
13,924.2 |
|
|
15,438.5 |
|
Less Accumulated
Depreciation, Depletion and Amortization |
|
|
|
Exploration and production |
6,642.9 |
|
|
8,797.7 |
|
Gathering
and other |
124.3 |
|
|
101.8 |
|
Total
Accumulated Depreciation, Depletion and Amortization |
6,767.2 |
|
|
8,899.5 |
|
Net
Property, Plant and Equipment |
7,157.0 |
|
|
6,539.0 |
|
Fair value of
derivative contracts |
0.1 |
|
|
— |
|
Other noncurrent
assets |
72.3 |
|
|
66.3 |
|
TOTAL
ASSETS |
$ |
7,394.8 |
|
|
$ |
7,245.4 |
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
Current
Liabilities |
|
|
|
Checks
outstanding in excess of cash balances |
$ |
44.0 |
|
|
$ |
12.3 |
|
Accounts
payable and accrued expenses |
372.1 |
|
|
269.7 |
|
Production and property taxes |
31.6 |
|
|
30.1 |
|
Interest
payable |
26.0 |
|
|
32.9 |
|
Fair
value of derivative contracts |
103.6 |
|
|
169.8 |
|
Total
Current Liabilities |
577.3 |
|
|
514.8 |
|
Long-term debt |
2,160.8 |
|
|
2,020.9 |
|
Deferred income
taxes |
518.0 |
|
|
825.9 |
|
Asset retirement
obligations |
206.6 |
|
|
225.8 |
|
Fair value of
derivative contracts |
31.8 |
|
|
32.0 |
|
Other long-term
liabilities |
102.4 |
|
|
123.3 |
|
Commitments and
Contingencies |
|
|
|
EQUITY |
|
|
|
Common
stock – par value $0.01 per share; 500.0 million shares
authorized; 243.0 million and 240.7 million shares issued,
respectively |
2.4 |
|
|
2.4 |
|
Treasury
stock – 2.0 million and 1.1 million shares, respectively |
(34.2 |
) |
|
(22.9 |
) |
Additional paid-in capital |
1,398.2 |
|
|
1,366.6 |
|
Retained
earnings |
2,442.6 |
|
|
2,173.3 |
|
Accumulated other comprehensive income (loss) |
(11.1 |
) |
|
(16.7 |
) |
Total
Common Shareholders' Equity |
3,797.9 |
|
|
3,502.7 |
|
TOTAL
LIABILITIES AND EQUITY |
$ |
7,394.8 |
|
|
$ |
7,245.4 |
|
|
|
|
|
|
|
|
|
|
|
QEP RESOURCES,
INC. |
|
CONSOLIDATED
CASH FLOWS |
|
|
|
|
Year Ended December 31, |
|
2017 |
|
2016 |
OPERATING
ACTIVITIES |
(in millions) |
Net income (loss) |
$ |
269.3 |
|
|
$ |
(1,245.0 |
) |
Adjustments
to reconcile net income (loss) to net cash provided by (used in)
operating activities: |
|
|
Depreciation, depletion and amortization |
754.5 |
|
|
871.1 |
|
Deferred
income taxes |
(314.8 |
) |
|
(651.3 |
) |
Impairment |
78.9 |
|
|
1,194.3 |
|
Dry hole
exploratory well expense |
21.3 |
|
|
— |
|
Share-based compensation |
22.4 |
|
|
35.6 |
|
Amortization of debt issuance costs and discounts |
6.2 |
|
|
6.4 |
|
Bargain
purchase gain from acquisitions |
0.4 |
|
|
(22.6 |
) |
Net
(gain) loss from asset sales |
(213.5 |
) |
|
(5.0 |
) |
Loss from
early extinguishment of debt |
32.7 |
|
|
— |
|
Unrealized (gains) losses on marketable securities |
(2.9 |
) |
|
(1.4 |
) |
Unrealized (gains) losses on derivative contracts |
(40.0 |
) |
|
367.0 |
|
Other
non-cash activity |
(9.4 |
) |
|
— |
|
Changes
in operating assets and liabilities |
(6.7 |
) |
|
114.6 |
|
Net Cash
Provided by (Used in) Operating Activities |
598.4 |
|
|
663.7 |
|
INVESTING
ACTIVITIES |
|
|
|
Property
acquisitions |
(815.2 |
) |
|
(639.0 |
) |
Property,
plant and equipment, including exploratory well expense |
(1,159.6 |
) |
|
(569.1 |
) |
Proceeds
from disposition of assets |
806.8 |
|
|
29.0 |
|
Net Cash
Provided by (Used in) Investing Activities |
(1,168.0 |
) |
|
(1,179.1 |
) |
FINANCING
ACTIVITIES |
|
|
|
Checks
outstanding in excess of cash balances |
31.7 |
|
|
(17.5 |
) |
Long-term
debt issued |
500.0 |
|
|
— |
|
Long-term
debt issuance costs paid |
(14.4 |
) |
|
— |
|
Long-term
debt extinguishment costs paid |
(28.1 |
) |
|
— |
|
Long-term
debt repaid |
(445.6 |
) |
|
(176.8 |
) |
Proceeds
from credit facility |
492.0 |
|
|
— |
|
Repayments of credit facility |
(403.0 |
) |
|
— |
|
Treasury
stock repurchases |
(6.8 |
) |
|
(4.1 |
) |
Proceeds
from issuance of common stock, net |
— |
|
|
781.4 |
|
Excess
tax (provision) benefit on share-based compensation |
— |
|
|
0.1 |
|
Net Cash
Provided by (Used in) Financing Activities |
125.8 |
|
|
583.1 |
|
Change in cash and cash
equivalents |
(443.8 |
) |
|
67.7 |
|
Beginning cash and cash
equivalents |
443.8 |
|
|
376.1 |
|
Ending cash and cash
equivalents |
$ |
— |
|
|
$ |
443.8 |
|
|
|
|
|
|
|
|
|
|
|
|
Production by Region |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2017 |
|
2016 |
|
Change |
|
2017 |
|
2016 |
|
Change |
|
(in Mboe) |
Northern
Region |
|
|
|
|
|
|
|
|
|
|
|
Williston
Basin |
4,479.8 |
|
|
4,948.1 |
|
|
(9 |
)% |
|
18,140.0 |
|
|
20,370.0 |
|
|
(11 |
)% |
Pinedale |
29.3 |
|
|
3,820.9 |
|
|
(99 |
)% |
|
9,871.7 |
|
|
15,826.0 |
|
|
(38 |
)% |
Uinta
Basin |
834.8 |
|
|
973.1 |
|
|
(14 |
)% |
|
3,605.4 |
|
|
4,714.3 |
|
|
(24 |
)% |
Other
Northern |
136.8 |
|
|
349.3 |
|
|
(61 |
)% |
|
1,082.4 |
|
|
1,491.7 |
|
|
(27 |
)% |
Total
Northern Region |
5,480.7 |
|
|
10,091.4 |
|
|
(46 |
)% |
|
32,699.5 |
|
|
42,402.0 |
|
|
(23 |
)% |
Southern
Region |
|
|
|
|
|
|
|
|
|
|
|
Permian
Basin |
2,554.3 |
|
|
1,371.5 |
|
|
86 |
% |
|
8,227.2 |
|
|
5,976.7 |
|
|
38 |
% |
Haynesville/Cotton Valley |
4,028.5 |
|
|
2,203.0 |
|
|
83 |
% |
|
12,188.7 |
|
|
7,285.5 |
|
|
67 |
% |
Other
Southern |
6.4 |
|
|
9.8 |
|
|
(35 |
)% |
|
29.5 |
|
|
116.0 |
|
|
(75 |
)% |
Total
Southern Region |
6,589.2 |
|
|
3,584.3 |
|
|
84 |
% |
|
20,445.4 |
|
|
13,378.2 |
|
|
53 |
% |
Total production |
12,069.9 |
|
|
13,675.7 |
|
|
(12 |
)% |
|
53,144.9 |
|
|
55,780.2 |
|
|
(5 |
)% |
|
|
|
Total Production |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2017 |
|
2016 |
|
Change |
|
2017 |
|
2016 |
|
Change |
Oil
(Mbbl) |
5,240.6 |
|
|
4,882.8 |
|
|
7 |
% |
|
19,620.7 |
|
|
20,293.8 |
|
|
(3 |
)% |
Gas
(Bcf) |
34.1 |
|
|
43.9 |
|
|
(22 |
)% |
|
168.9 |
|
|
177.0 |
|
|
(5 |
)% |
NGL
(Mbbl) |
1,140.9 |
|
|
1,476.0 |
|
|
(23 |
)% |
|
5,367.3 |
|
|
5,978.8 |
|
|
(10 |
)% |
Total
equivalent production (Mboe) |
12,069.9 |
|
|
13,675.7 |
|
|
(12 |
)% |
|
53,144.9 |
|
|
55,780.2 |
|
|
(5 |
)% |
Average
daily production (Mboe) |
131.2 |
|
|
148.6 |
|
|
(12 |
)% |
|
145.6 |
|
|
152.4 |
|
|
(4 |
)% |
|
|
|
Prices |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2017 |
|
2016 |
|
Change |
|
2017 |
|
2016 |
|
Change |
Oil (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
54.14 |
|
|
$ |
44.24 |
|
|
|
|
$ |
47.88 |
|
|
$ |
37.90 |
|
|
|
Commodity derivative
impact |
(2.84 |
) |
|
1.34 |
|
|
|
|
0.34 |
|
|
4.25 |
|
|
|
Net
realized price |
$ |
51.30 |
|
|
$ |
45.58 |
|
|
13 |
% |
|
$ |
48.22 |
|
|
$ |
42.15 |
|
|
14 |
% |
Gas (per
Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
2.77 |
|
|
$ |
2.95 |
|
|
|
|
$ |
2.92 |
|
|
$ |
2.36 |
|
|
|
Commodity derivative
impact |
(0.07 |
) |
|
(0.14 |
) |
|
|
|
(0.13 |
) |
|
0.25 |
|
|
|
Net
realized price |
$ |
2.70 |
|
|
$ |
2.81 |
|
|
(4 |
)% |
|
$ |
2.79 |
|
|
$ |
2.61 |
|
|
7 |
% |
NGL (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
24.41 |
|
|
$ |
18.49 |
|
|
|
|
$ |
20.85 |
|
|
$ |
13.97 |
|
|
|
Commodity derivative
impact |
— |
|
|
— |
|
|
|
|
— |
|
|
— |
|
|
|
Net
realized price |
$ |
24.41 |
|
|
$ |
18.49 |
|
|
32 |
% |
|
$ |
20.85 |
|
|
$ |
13.97 |
|
|
49 |
% |
Average net
equivalent price (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
33.65 |
|
|
$ |
27.27 |
|
|
|
|
$ |
29.08 |
|
|
$ |
22.76 |
|
|
|
Commodity derivative
impact |
(1.44 |
) |
|
0.04 |
|
|
|
|
(0.29 |
) |
|
2.35 |
|
|
|
Net
realized price |
$ |
32.21 |
|
|
$ |
27.31 |
|
|
18 |
% |
|
$ |
28.79 |
|
|
$ |
25.11 |
|
|
15 |
% |
|
|
|
Operating Expenses |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2017 |
|
2016 |
|
Change |
|
2017 |
|
2016 |
|
Change |
|
(per Boe) |
Lease operating
expense |
$ |
6.58 |
|
|
$ |
4.49 |
|
|
47 |
% |
|
$ |
5.55 |
|
|
$ |
4.03 |
|
|
38 |
% |
Transportation and
processing costs |
3.54 |
|
|
5.14 |
|
|
(31 |
)% |
|
4.61 |
|
|
5.18 |
|
|
(11 |
)% |
Production and property
taxes |
2.34 |
|
|
2.16 |
|
|
8 |
% |
|
2.15 |
|
|
1.70 |
|
|
26 |
% |
Total
production costs |
$ |
12.46 |
|
|
$ |
11.79 |
|
|
6 |
% |
|
$ |
12.31 |
|
|
$ |
10.91 |
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
QEP RESOURCES, INC.NON-GAAP
MEASURES
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, loss from early extinguishment of debt 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 December 31, |
|
Year Ended December 31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
(in millions) |
Net income (loss) |
$ |
150.3 |
|
|
$ |
(133.3 |
) |
|
$ |
269.3 |
|
|
$ |
(1,245.0 |
) |
Interest expense |
34.7 |
|
|
34.0 |
|
|
137.8 |
|
|
143.2 |
|
Interest and other
(income) expense(1) |
0.9 |
|
|
(18.1 |
) |
|
(1.6 |
) |
|
(23.7 |
) |
Income tax provision
(benefit) |
(381.9 |
) |
|
(67.0 |
) |
|
(312.2 |
) |
|
(708.2 |
) |
Depreciation, depletion
and amortization |
194.3 |
|
|
203.6 |
|
|
754.5 |
|
|
871.1 |
|
Unrealized (gains)
losses on derivative contracts |
121.6 |
|
|
148.4 |
|
|
(40.0 |
) |
|
367.0 |
|
Exploration
expenses |
0.3 |
|
|
0.8 |
|
|
22.0 |
|
|
1.7 |
|
Net (gain) loss from
asset sales |
(8.3 |
) |
|
— |
|
|
(213.5 |
) |
|
(5.0 |
) |
Impairment |
50.5 |
|
|
6.1 |
|
|
78.9 |
|
|
1,194.3 |
|
Loss from early
extinguishment of debt |
32.7 |
|
|
— |
|
|
32.7 |
|
|
— |
|
Other(2) |
— |
|
|
— |
|
|
8.2 |
|
|
32.7 |
|
Adjusted
EBITDA |
$ |
195.1 |
|
|
$ |
174.5 |
|
|
$ |
736.1 |
|
|
$ |
628.1 |
|
____________________________(1)
In the first quarter of 2017, QEP early adopted ASU No. 2017-07,
Compensation – Retirement Benefits (Topic 715): Improving the
presentation of net periodic pension cost and net periodic
postretirement benefit cost, which is effective retrospectively. As
a result, the Company recast "Interest and other (income) expense"
for all prior periods shown. The Company recognizes service costs
related to SERP and Medical Plan benefits within "General and
administrative" expense on the Consolidated Statements of
Operations and all other expenses related to the Pension Plan, SERP
and Medical Plan benefits are recognized within "Interest and other
income (expense)" on the Consolidated Statements of
Operations(2) Reflects legal expenses and loss
contingencies incurred during the years ended December 31,
2017 and 2016. The Company believes that these amounts do not
reflect expected future operating performance or provide meaningful
comparisons to past operating performance and therefore has
excluded these amounts from the calculation of Adjusted EBITDA.
Adjusted Net Income (Loss)
This release also contains references to the non-GAAP measure of
Adjusted Net Income (Loss). Management defines Adjusted Net Income
(Loss) as earnings excluding changes in fair value of derivative
contracts, gains and losses from asset sales, impairment, loss on
early extinguishment of debt 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 December 31, |
|
Year Ended December 31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
(in millions, except earnings per share amounts) |
Net income
(loss)(3) |
$ |
150.3 |
|
|
$ |
(133.3 |
) |
|
$ |
269.3 |
|
|
$ |
(1,245.0 |
) |
Adjustments to net
income |
|
|
|
|
|
|
|
Unrealized losses (gains) on derivative contracts |
121.6 |
|
|
148.4 |
|
|
(40.0 |
) |
|
367.0 |
|
Income
taxes on unrealized loss (gain) on derivative contracts (1) |
(45.1 |
) |
|
(55.1 |
) |
|
14.8 |
|
|
(133.2 |
) |
Net gain
(loss) from asset sales |
(8.3 |
) |
|
— |
|
|
(213.5 |
) |
|
(5.0 |
) |
Income
taxes on net gain on asset sales (1) |
3.1 |
|
|
— |
|
|
79.2 |
|
|
1.8 |
|
Impairment |
50.5 |
|
|
6.1 |
|
|
78.9 |
|
|
1,194.3 |
|
Income
taxes on impairment (1) |
(18.7 |
) |
|
(2.3 |
) |
|
(29.3 |
) |
|
(433.5 |
) |
Loss from
early extinguishment of debt |
32.7 |
|
|
— |
|
|
32.7 |
|
|
— |
|
Income
taxes on loss from early extinguishment of debt (1) |
(12.1 |
) |
|
— |
|
|
(12.1 |
) |
|
— |
|
Other
(2) |
— |
|
|
— |
|
|
8.2 |
|
|
32.7 |
|
Income
taxes on other (1) |
— |
|
|
— |
|
|
(3.0 |
) |
|
(11.9 |
) |
Total after-tax
adjustments to net income |
123.7 |
|
|
97.1 |
|
|
(84.1 |
) |
|
1,012.2 |
|
Adjusted Net Income
(Loss) |
$ |
274.0 |
|
|
$ |
(36.2 |
) |
|
$ |
185.2 |
|
|
$ |
(232.8 |
) |
|
|
|
|
|
|
|
|
Earnings (Loss) per
Common Share |
|
|
|
|
|
|
|
Diluted
earnings per share |
$ |
0.62 |
|
|
$ |
(0.56 |
) |
|
$ |
1.12 |
|
|
$ |
(5.62 |
) |
Diluted
after-tax adjustments to net income (loss) per share |
0.51 |
|
|
0.41 |
|
|
(0.35 |
) |
|
4.57 |
|
Diluted
Adjusted Net Income per share |
$ |
1.13 |
|
|
$ |
(0.15 |
) |
|
$ |
0.77 |
|
|
$ |
(1.05 |
) |
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
|
|
|
Diluted |
241.0 |
|
|
239.6 |
|
|
240.6 |
|
|
221.7 |
|
________________________(1)
Income tax impact of adjustments is calculated using QEP’s
statutory rate of 37.1% for the three months ended
December 31, 2017 and 2016 and 37.1% and 36.3% for the twelve
months ended December 31, 2017 and
2016.(2)
Reflects legal expenses and loss contingencies incurred during the
years ended December 31, 2017 and 2016. The Company believes
that these amounts do not reflect expected future operating
performance or provide meaningful comparisons to past operating
performance and therefore has excluded these amounts from the
calculation of Adjusted
EBITDA.(3)
Net income during the year ended December 31, 2017, was also
positively impacted by a $307.9 million tax benefit, primarily due
to a revaluation of our net deferred tax liability to reflect the
federal rate change resulting from 35% to 21% under the new tax
legislation.
Reserves Replacement Ratio and Finding and Development
Cost (F&D Cost)
This release refers to Reserve Replacement Ratio and F&D
Cost, which are non-GAAP measures. QEP believes these metrics are
widely used in its industry, as well as, by analysts and investors.
Management believes Reserve Replacement Ratio provides investors
with useful insight concerning QEP's ability to maintain and grow
proved reserves in spite of depletion and F&D Cost is useful to
investors to measure and evaluate the cost of replacing annual
production.
Management defines Reserve Replacement Ratio as net proved
reserve additions, including purchase of reserves in place, divided
by annual production. Management defines F&D Cost as total
costs incurred (an unaudited GAAP measure) divided by the sum of
revisions of previous reserve estimates, extensions and discoveries
and purchases of reserves in place. QEP's definition of these
non-GAAP measures may differ from similarly titled measures
provided by other companies and, as a result, may not be
comparable. There are no directly comparable financial measures
presented in accordance with GAAP for Reserve Replacement Ratio and
F&D Cost; therefore, reconciliations to GAAP are not
practicable.
Reserve Replacement Ratio and F&D Cost for 2017 are
calculated as follows:
|
|
|
|
|
Year Ended |
|
|
December 31, 2017 |
Revisions of previous
estimates (MMboe) |
|
2.7 |
|
Extensions and
discoveries (MMboe) |
|
86.4 |
|
Purchase of reserves in
place (MMboe) |
|
76.3 |
|
Net
proved reserve additions (MMboe) |
|
165.4 |
|
|
|
|
Proved property
acquisitions (in millions) |
|
269.6 |
|
Unproved property
acquisitions (in millions) |
|
532.4 |
|
Other acquisitions (in
millions) |
|
13.2 |
|
Exploration costs
(capitalized and expensed) (in millions) |
|
32.7 |
|
Development costs(1)
(in millions) |
|
1,189.3 |
|
Total
costs incurred (in millions) |
|
$ |
2,037.2 |
|
|
|
|
Production (MMboe) |
|
53.1 |
|
|
|
|
Reserve Replacement
Ratio |
|
311 |
% |
F&D Cost
($/Boe) |
|
$ |
12.32 |
|
________________________(1)
Development costs are net of the
change in accrued capital costs of $60.6 million and additions and
revisions to asset retirement obligations of $32.0 million during
the year ended December 31, 2017.
QEP RESOURCES, INC.DERIVATIVE
POSITIONS
The following tables present QEP's volumes and average prices
for its open derivative positions as of February 23, 2018:
|
Production Commodity Derivative
Swaps |
|
|
|
|
|
|
|
Year |
|
Index |
|
Total Volumes |
|
Average Swap Price per Unit |
|
|
|
|
(in
millions) |
|
|
Oil
sales |
|
|
|
(bbls) |
|
($/bbl) |
2018 |
|
NYMEX
WTI |
|
15.4 |
|
$ |
52.48 |
2019 |
|
NYMEX
WTI |
|
9.1 |
|
$ |
52.45 |
Gas
sales |
|
|
|
(MMBtu) |
|
|
($/MMBtu) |
2018
(Full Year) |
|
NYMEX
HH |
|
91.8 |
|
$ |
2.99 |
2018
(July through December) |
|
NYMEX
HH |
|
1.8 |
|
$ |
3.01 |
2019 |
|
NYMEX
HH |
|
43.8 |
|
$ |
2.86 |
|
Production Commodity Derivative Basis
Swaps |
|
|
|
|
|
|
|
|
|
Year |
|
Index Less Differential |
|
Index |
|
Total Volumes |
|
Weighted-Average Differential |
|
|
|
|
|
|
(in
millions) |
|
|
Oil
sales |
|
|
|
|
|
(bbls) |
|
|
($/bbl) |
2018
(Full Year) |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
6.7 |
|
$ |
(1.06) |
2018
(July through December) |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
0.9 |
|
$ |
(0.71) |
2019 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
4.7 |
|
$ |
(0.77) |
Gas
sales |
|
|
|
|
|
(MMBtu) |
|
|
($/MMBtu) |
2018 |
|
NYMEX
HH |
|
IFNPCR |
|
6.1 |
|
$ |
(0.16) |
|
|
|
|
|
|
|
|
|
|
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