QEP Resources, Inc. (NYSE: QEP) (QEP or the Company) today reported
fourth quarter and full year 2018 financial and operating results
and provided initial 2019 guidance and capital investment plan.
FULL YEAR 2018 HIGHLIGHTS
- Delivered record oil and condensate production of 23.9 MMbbls,
including a record of 12.1 MMbbls in the Permian Basin
- Reported year-end total proved reserves in the Permian Basin of
307.8 MMboe, a 13% increase over 2017
- Reported year-end total proved reserves of 658.2 MMboe,
including record proved crude oil and condensate reserves of 339.1
MMbbls
"2018 was a year of transition and transformation for QEP. We
made significant progress on the strategic initiatives we outlined
in February 2018, which were aimed at streamlining our operations,
optimizing our cost structure and rationalizing our asset
portfolio," commented Tim Cutt, President and CEO of QEP. "We enter
2019 with a renewed focus on actively managing and improving our
cost structure, more specifically, reducing our G&A expense and
lowering the capital intensity of the business. We are committed to
aligning our activity and our production profile to the current
commodity price environment and reaching cash-flow neutrality in
2019.
"Earlier today we announced that we have commenced a
comprehensive review of strategic alternatives to maximize
shareholder value, which could result in a merger or sale of the
Company or other transaction involving the Company or its assets.
Our Board and management team are committed to taking all
appropriate and necessary actions to drive value for QEP
shareholders and we believe the best way to accomplish this goal is
to run a broad process designed to identify the potential value of
these strategic alternatives.
"We also announced that we have terminated our agreement with
Vantage Acquisition Operating Company, LLC, to sell our Williston
Basin assets. We now intend to move forward with a paced
development of the remaining high-return Williston inventory to
maximize the value of the asset.
“As we look to supplement cash flows in 2019, we intend to
pursue the monetization of our gas midstream infrastructure in the
Permian Basin in the first half of the year and continue to
evaluate strategic options for our remaining Permian midstream
infrastructure, as well as other non-core properties in our
portfolio.
"QEP has undergone significant, positive changes over the last
12 months and we remain focused on operating our business safely,
delivering best in class capital and operating costs, and
maintaining technical and operating excellence."
The Company has posted to its website www.qepres.com a
presentation that supplements the information provided in this
release.
QEP Fourth Quarter and Full Year 2018 Financial
Results
The Company reported a net loss of $629.3 million for the fourth
quarter 2018, or $2.66 per diluted share, compared with income of
$150.3 million, or $0.62 per diluted share, in the fourth quarter
2017. The net loss in the fourth quarter 2018 includes $1,156.5
million of impairment expense, a result of the signing of a
purchase and sale agreement for the divestiture of the Williston
Basin assets, a $12.3 million increase in general and
administrative expense, primarily due to restructuring costs
related to our 2018 Strategic Initiatives, and a $10.0 million
decrease in net loss from asset sales, inclusive of restructuring
costs. These increases to the net loss were partially offset by a
$469.5 million increase in gain on derivative contracts, a $19.9
million decrease to lease operating expense and a 10% increase in
oil and condensate production.
For the year ended December 31, 2018, QEP reported a net
loss of $1,011.6 million, or $4.25 per diluted share, compared with
net income of $269.3 million, or $1.12 per diluted share, for the
comparable 2017 period.
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 2018
Adjusted Net Loss (a non-GAAP measure) was $29.6 million, or $0.13
per diluted share, compared with an Adjusted Net Income of $274.0
million, or $1.13 per diluted share, in the fourth quarter 2017.
For the year ended December 31, 2018, the Company’s Adjusted
Net Loss was $42.1 million, or $0.17 per diluted share, compared
with an Adjusted Net Income of $185.2 million, or $0.77 per diluted
share, for 2017.
Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2018
was $194.1 million compared to $195.1 million in the fourth quarter
2017. For the year ended December 31, 2018, the Company
reported Adjusted EBITDA of $974.8 million compared to $736.1
million for full year 2017, a 32% increase, primarily due to an 18%
increase in average realized prices, a 30% decrease in Adjusted
Transportation and Processing Costs (a non-GAAP measure) and an 11%
decrease in lease operating expense. These changes were partially
offset by a 17% decrease in gas production due to the Pinedale
divestiture in late 2017 and the Uinta Basin divestiture in
September 2018 (the Uinta Basin Divestiture), a 44% increase in
general and administrative expenses and a 14% increase in
production and property taxes.
The definitions and reconciliations of Adjusted EBITDA, Adjusted
Net Income to Net Income (Loss) and Adjusted Transportation and
Processing Costs are provided within the financial tables of this
release.
Production
Oil equivalent production was 11.6 MMboe for the fourth quarter
2018 compared with 12.1 MMboe for the fourth quarter 2017, a 4%
decrease. Natural gas production decreased 18%, while oil and
condensate and NGL production increased 10% and 4%, respectively.
Fourth quarter 2018 equivalent production was negatively impacted
by decreased oil production in the Williston Basin, decreased gas
production due to lack of new activity in the Haynesville/Cotton
Valley and the Uinta Basin Divestiture, in September 2018, which
contributed 3.9 Bcf in the fourth quarter 2017.
Operating Expenses
During the fourth quarter 2018, lease operating expense (LOE)
was $59.5 million, or $5.11 per Boe, a decrease of 25% compared
with the fourth quarter 2017. The decrease in total LOE was
primarily due to reduced workovers in the Williston Basin and
Haynesville/Cotton Valley and the Uinta Basin Divestiture,
partially offset by increased power and fuel, labor, maintenance
and repair expenses on our Permian Basin properties.
During the fourth quarter 2018, Adjusted Transportation and
Processing (T&P) Costs (a non-GAAP measure) were $38.5 million,
or $3.31 per Boe, a decrease of 10% compared with the fourth
quarter 2017, primarily due to the Uinta Basin divestiture combined
with a decrease in Haynesville/Cotton Valley from lower gas
production. These decreases were partially offset by increases in
the Permian Basin due to higher gas recovery.
During the fourth quarter 2018, general and administrative
expense (G&A) was $57.5 million, or $4.95 per Boe, an increase
of 27% compared with the fourth quarter 2017. The increase in total
G&A expense in the fourth quarter 2018 was primarily due to an
increase in costs associated with the implementation of our 2018
Strategic Initiatives. The increase was partially offset by a
decrease in share-based compensation and in the mark-to-market
value of the deferred compensation wrap plan and a decrease in
outside services.
During the fourth quarter 2018, production and property taxes
were $26.9 million, or $2.31 per Boe, a decrease of 5% compared
with the fourth quarter 2017. The decrease in production and
property taxes was primarily due to decreased revenues in the
Williston and Uinta basins and production tax exemptions in
Haynesville/Cotton Valley, partially offset by increased revenues
in the Permian Basin.
Capital Investment
Total capital investment was $205.7 million (on an accrual
basis) for the fourth quarter 2018, compared with $1,056.3 million
for the fourth quarter 2017. Total capital investment for the year
ended December 31, 2018 (on an accrual basis), was $1,242.2
million, down $792.8 million compared with the year ended
December 31, 2017, due to the acquisition of oil and gas
properties in the Permian Basin (the 2017 Permian Basin
Acquisition) in the fourth quarter 2017.
Capital investment, excluding property acquisitions, was $188.4
million (on an accrual basis) for the fourth quarter 2018, compared
with $372.2 million for the fourth quarter 2017, of which $170.7
million related to the drilling, completion and equipping of wells
and $16.8 million was related to infrastructure investment. The
decrease in capital expenditures was primarily related to decreased
drilling and completion activity in the Permian Basin and limited
activity in the Williston Basin and Haynesville/Cotton Valley in
the fourth quarter 2018.
Capital investment, excluding property acquisitions, was
$1,176.6 million (on an accrual basis) for the year ended
December 31, 2018 compared with $1,219.8 million for the year
ended December 31, 2017, of which $1,089.3 million related to
the drilling, completion and equipping of wells and $83.0 million
was related to infrastructure investment. The decrease in capital
expenditures was primarily related to decreased drilling and
completion activity in the Williston Basin and reduced well
refracturing activity in the Haynesville/Cotton Valley, partially
offset by increased drilling and completion activity in the Permian
Basin.
During the year ended December 31, 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 $65.6 million, subject to customary post-closing
adjustments. Of the $65.6 million, $49.1 million was related to
acquisitions from various entities that owned additional oil and
gas interests in certain properties included in the 2017 Permian
Basin Acquisition on substantially the same terms and conditions as
the 2017 Permian Basin Acquisition.
Asset Divestitures
In January 2019, QEP closed its previously announced divestiture
of its oil and gas assets and the gathering system in the
Haynesville/Cotton Valley for net cash proceeds of $605.1 million,
subject to post-closing purchase price adjustments (the Haynesville
Divestiture). As part of this transaction the buyer assumed all
firm gas transportation agreements related to these assets. In
addition, $32.2 million was placed in escrow due to title defects
asserted prior to closing, all or a portion of which QEP expects to
receive pursuant to the purchase and sale agreement's title dispute
resolution procedures.
In November 2018, the Company's wholly owned subsidiary, QEP
Energy Company, entered into a purchase and sale agreement for its
assets in the Williston Basin for a purchase price of $1,725.0
million, subject to purchase price adjustments (the Planned
Williston Basin Divestiture). The purchase price was comprised of
$1,650.0 million in cash and contractual rights to receive $75.0
million of the buyer's common stock if certain conditions were met.
The transaction was subject to certain conditions, including,
approval of buyer's shareholder and regulatory approvals. In
February 2019, the Company agreed with the buyer to terminate the
purchase and sale agreement for its assets in the Williston Basin.
Following the termination, QEP will continue to operate and develop
its assets in the Williston Basin, including the Company's South
Antelope and Fort Berthold leaseholds.
QEP closed on the sale of several non-core assets during the
fourth quarter 2018 for total net cash proceeds of approximately
$26.1 million.
Liquidity
Net Cash Provided by Operating Activities for the fourth quarter
2018 was $141.3 million, compared with $117.4 million for the
fourth quarter 2017. Discretionary Cash Flow (a non-GAAP measure)
was $45.4 million for the fourth quarter 2018, compared with $67.4
million for the fourth quarter 2017.
The definitions and reconciliations of Discretionary Cash Flow
and Discretionary Cash Flow in Excess of Capital Expenditures are
provided within Non-GAAP Measures at the end of this release.
As of December 31, 2018, QEP had $430.0 million of
borrowings and $0.3 million in letters of credit outstanding under
its credit facility. The Company estimates that, as of
December 31, 2018, it could incur additional indebtedness of
approximately $819.7 million and be in compliance with the
covenants contained in its revolving credit facility.
As of February 15, 2019, QEP had no borrowings outstanding
and $0.3 million in letters of credit outstanding under its credit
facility. QEP used the proceeds from the Haynesville Divestiture to
pay off its outstanding balance on its credit facility in January
2019.
2019 Guidance
QEP's first quarter and full year 2019 guidance assumes an oil
price of $55 per barrel and a natural gas price of $2.75 per MMBtu,
assumes that QEP will elect to recover ethane from its produced gas
in the Permian Basin where processing economics support
ethane recovery, and assumes no property acquisitions or
divestitures.
Rig Count
- Permian Basin: average of three rigs for first half of 2019 and
two rigs for the second half of 2019
- Williston Basin: one rig arriving in the second quarter 2019 to
drill seven gross operated wells
Wells Put on Production
- Permian Basin: approximately 47 net operated wells
- Williston Basin: approximately six net operated wells
2019 Guidance |
|
1Q 2019 |
2019 |
|
|
|
Oil & condensate
production (MMbbl) |
4.95 -
5.15 |
20.5 -
21.5 |
Gas production
(Bcf) |
5.85 -
6.35 |
23.0 -
25.0 |
NGL production
(MMbbl) |
0.90 - 1.05 |
3.7 - 4.2 |
Total oil equivalent production (MMboe) |
6.83 -
7.26 |
28.0 -
29.9 |
|
|
|
Lease operating and
Adjusted Transportation and Processing Costs (per Boe)(1) |
|
$9.00
- $10.00 |
Depletion, depreciation
and amortization (per Boe) |
|
$16.75
-$17.75 |
Production and property
taxes (% of field-level revenue) |
|
7.0% |
(in millions) |
General and
administrative expense(2) |
|
$170.0
- $180.0 |
|
|
|
Capital investment
(excluding property acquisitions) |
|
|
Drilling,
Completion and Equip(3) |
|
$540.0 - $590.0 |
Midstream
Infrastructure(4) |
|
$70.0 |
Corporate |
|
$5.0 |
Total
capital investment (excluding property acquisitions) |
|
$615.0 - $665.0 |
|
|
|
Wells put
on production (net) |
9.8 |
53.1 |
____________________________(1) Adjusted
Transportation and Processing Costs (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 $18.0 million of share-based compensation expense and
approximately $54.0 million of estimated expenses related to
restructuring costs, primarily severance and retention agreements
entered into in connection with our strategic initiatives, which
includes approximately $11.0 million of accelerated share-based
compensation expense.(3) Drilling, Completion and Equip
includes approximately $57.0 million of non-operated well
completion costs.(4) Includes capital expenditures in the
Permian Basin associated with (a) water sourcing, gathering,
recycling and disposal and (b) crude oil and natural gas gathering
system.
Operations Summary
|
Permian Basin |
|
Williston Basin |
|
Haynesville/Cotton Valley |
|
As of December 31, 2018 |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Well
Progress |
|
|
|
|
|
|
|
|
|
|
|
Drilling |
13 |
|
|
13.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
At total depth - under
drilling rig |
8 |
|
|
8.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Waiting to be
completed |
17 |
|
|
17.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Undergoing
completion |
5 |
|
|
5.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Completed, awaiting
production |
5 |
|
|
5.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Waiting
on completion |
35 |
|
|
35.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
Put on
production(1) |
17 |
|
|
16.7 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
____________________________(1) Total
operated wells put on production during the three months ended
December 31, 2018.
Permian Basin
Permian Basin net oil equivalent production averaged
approximately 47.5 Mboed (87% liquids) during the fourth quarter
2018, a 9% decrease compared to the third quarter 2018
primarily due to a lower number of wells and the timing of these
wells being put on production, and a 71% increase compared to
the fourth quarter 2017. A portion of the year over year increase
is driven by higher gas capture rates compared to prior quarters as
a result of completion of midstream infrastructure.
In the fourth quarter 2018, the Company put on production 17
gross-operated horizontal wells, six on County Line and 11 on
Mustang Springs (average working interest 98%).
At the end of the fourth quarter 2018, two of the six wells put
on production on County Line were still in the process of cleaning
up. The four wells that cleaned up on County Line reached average
peak 24-hour IP of 138 Boed per 1,000 lateral feet (86% oil) from
an average lateral length of 7,282 feet. On Mustang Springs, six of
the 11 wells put on production were still in the process of
cleaning up. The five wells that cleaned up on Mustang Springs
reached average peak 24-hour IP of 125 Boed per 1,000 lateral feet
(84% oil) from an average lateral length of 9,825 feet.
At the end of the fourth quarter 2018, the Company had 13
gross-operated horizontal wells in process of being drilled (of
which 10 had surface casing set, but had no drilling rig present)
(average working interest 100%), eight horizontal wells at total
depth under drilling rigs (average working interest 100%), 17
horizontal wells waiting to be completed (average working interest
100%), five horizontal wells undergoing completion (average working
interest 100%), and five fully completed horizontal wells awaiting
first production, which were part of a tank "pressure wall"
(average working interest 100%).
At the end of the fourth quarter 2018, the Company had four
operated rigs in the Permian Basin.
Slides 7-8 in the February 2019 Investor Presentation depict
QEP's acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net oil equivalent production averaged
approximately 40.9 Mboed (82% liquids) during the fourth quarter
2018, a 14% decrease compared to the third quarter 2018 and a
16% decrease compared to the fourth quarter 2017, primarily
due to the lack of new well completions and refrac timing.
In the fourth quarter 2018, the Company completed and returned
to production four gross-operated refracs on South Antelope
(average working interest 94%). All four refracs had reached peak
oil rates by the end of the quarter with an average IP24 gross
uplift of 1,366 Boed (78% oil).
At the end of the fourth quarter 2018, the Company had no
drilling rigs in the Williston Basin.
Slides 9-10 in the February 2019 Investor Presentation depict
QEP's acreage and activity in the Williston Basin.
Estimated Proved Reserves
At December 31, 2018, QEP's estimated proved reserves were
approximately 658.2 MMboe, a 4% decrease compared to 2017,
primarily due to the sale of reserves in-place associated with the
Uinta Basin Divestiture, which was partially offset by an increase
of proved reserves as a result of extensions and discoveries in the
Permian Basin. Williston Basin and Haynesville/Cotton Valley proved
reserves increased primarily due to successful refracturing
programs in 2018. Extensions and discoveries were 76.3 MMboe, were
primarily in the Permian Basin and related to new well completions
and associated new PUD locations. Approximately 62% of total proved
reserves at year-end 2018 and 56% of total proved reserves at
year-end 2017 were crude oil and NGL. Proved developed reserves
were 228.9 MMboe, or 35%, of total estimated proved reserves at
year-end 2018.
A reconciliation of reported quantities of estimated proved
reserves is summarized in the table below:
|
Oil and condensate |
|
Gas |
|
NGL |
|
Total |
|
(MMbbl) |
|
(Bcf) |
|
(MMbbl) |
|
(MMboe)(1) |
Balance at December 31,
2017 |
320.5 |
|
|
1,793.6 |
|
|
65.2 |
|
|
684.7 |
|
Revisions
of previous estimates |
2.1 |
|
|
314.0 |
|
|
6.7 |
|
|
61.0 |
|
Extensions and discoveries |
57.1 |
|
|
56.5 |
|
|
9.8 |
|
|
76.3 |
|
Purchase
of reserves in place |
8.2 |
|
|
7.9 |
|
|
1.3 |
|
|
10.9 |
|
Sale of
reserves in place |
(24.9 |
) |
|
(544.8 |
) |
|
(7.1 |
) |
|
(122.8 |
) |
Production |
(23.9 |
) |
|
(139.6 |
) |
|
(4.7 |
) |
|
(51.9 |
) |
Balance at
December 31, 2018 |
339.1 |
|
|
1,487.6 |
|
|
71.2 |
|
|
658.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
____________________________(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 2018
and 2017 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, 2018 |
|
|
|
|
|
|
Northern
Region |
|
|
|
|
|
|
|
Williston Basin |
166.8 |
|
|
25 |
% |
|
42 |
% |
|
85 |
% |
Uinta
Basin |
— |
|
|
— |
% |
|
— |
% |
|
— |
% |
Other
Northern |
0.3 |
|
|
— |
% |
|
— |
% |
|
67 |
% |
Southern
Region |
|
|
|
|
|
|
|
Permian
Basin |
307.8 |
|
|
47 |
% |
|
69 |
% |
|
87 |
% |
Haynesville/Cotton Valley |
183.3 |
|
|
28 |
% |
|
81 |
% |
|
— |
% |
Other
Southern |
— |
|
|
— |
% |
|
— |
% |
|
— |
% |
Total proved reserves |
658.2 |
|
|
100 |
% |
|
65 |
% |
|
62 |
% |
|
|
|
|
|
|
|
|
For
the year ended December 31, 2017 |
|
|
|
|
|
|
Northern
Region |
|
|
|
|
|
|
|
Williston
Basin |
146.9 |
|
|
21 |
% |
|
36 |
% |
|
88 |
% |
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 |
% |
|
66 |
% |
|
— |
% |
Other
Southern |
— |
|
|
— |
% |
|
— |
% |
|
— |
% |
Total proved reserves |
684.7 |
|
|
100 |
% |
|
63 |
% |
|
56 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter and Full Year 2018 Results Conference
Call
QEP's management will discuss fourth quarter and full year 2018
results in a conference call on Thursday, February 21, 2019,
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
21, 2019, 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 #13687037. In addition, QEP’s slides for the fourth
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 focused in two
regions of the United States: the Southern Region (primarily in
Texas) and the Northern Region (primarily in North Dakota). 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: streamlining our operations;
optimizing our cost structure; rationalizing our asset portfolio;
actively managing and improving our cost structure; reducing
G&A expense; lowering the capital intensity of our business;
aligning our activity and our production profile to the current
commodity price environment; reaching cash-flow neutrality in 2019;
goals and potential results of our review of strategic
alternatives; plans for development of our Williston Basin assets;
supplementing cash flows in 2019; monetization of our Permian gas
midstream infrastructure; evaluation of strategic options for our
remaining Permian midstream infrastructure and non-core properties;
operating our business safely; delivering best in class capital and
operating costs; maintaining technical and operating excellence;
receipt of the portion of the purchase price for the Haynesville
Divestiture placed in escrow pursuant to title dispute resolution
procedures; the number and location of drilling rigs to be deployed
and wells to be put on production; forecast production amounts and
related assumptions; forecasted lease operating Adjusted
Transportation and Processing 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 2019 and related
assumptions for such guidance; allocation of capital investment;
first quarter 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; estimated reserves; and usefulness of non-GAAP
measures. Actual results may differ materially from those included
in the forward-looking statements due to a number of factors,
including, but not limited to: 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 and other
oil producing countries such as Russia; 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 Elliott Management Corporation or other activist
shareholders; tariffs on products QEP uses in its operations or on
the products QEP 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, 2018. 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, 2018.
Contact
Investors/Media: |
|
William I. Kent,
IRC |
|
Director, Investor
Relations |
|
303-405-6665 |
|
QEP RESOURCES, INC.CONSOLIDATED
STATEMENTS OF OPERATIONS
|
Three Months Ended |
|
Year Ended |
|
December 31, |
|
December 31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
REVENUES |
(in millions, except per share amounts) |
Oil and condensate, gas
and NGL sales |
$ |
397.2 |
|
|
$ |
406.2 |
|
|
$ |
1,871.3 |
|
|
$ |
1,545.3 |
|
Other
revenues |
0.7 |
|
|
4.7 |
|
|
12.5 |
|
|
15.0 |
|
Purchased
oil and gas sales |
12.6 |
|
|
18.1 |
|
|
48.8 |
|
|
62.6 |
|
Total
Revenues |
410.5 |
|
|
429.0 |
|
|
1,932.6 |
|
|
1,622.9 |
|
OPERATING
EXPENSES |
|
|
|
|
|
|
|
Purchased
oil and gas expense |
12.4 |
|
|
18.9 |
|
|
51.0 |
|
|
64.3 |
|
Lease
operating expense |
59.5 |
|
|
79.4 |
|
|
263.1 |
|
|
294.8 |
|
Transportation and processing costs |
24.4 |
|
|
42.7 |
|
|
117.6 |
|
|
245.3 |
|
Gathering
and other expense |
4.7 |
|
|
2.3 |
|
|
15.5 |
|
|
7.3 |
|
General
and administrative |
57.5 |
|
|
45.2 |
|
|
221.7 |
|
|
153.5 |
|
Production and property taxes |
26.9 |
|
|
28.2 |
|
|
130.8 |
|
|
114.3 |
|
Depreciation, depletion and amortization |
183.5 |
|
|
194.3 |
|
|
857.1 |
|
|
754.5 |
|
Exploration expenses |
0.2 |
|
|
0.3 |
|
|
0.3 |
|
|
22.0 |
|
Impairment |
1,156.5 |
|
|
50.5 |
|
|
1,560.9 |
|
|
78.9 |
|
Total
Operating Expenses |
1,525.6 |
|
|
461.8 |
|
|
3,218.0 |
|
|
1,734.9 |
|
Net gain (loss) from
asset sales, inclusive of restructuring costs |
(1.7 |
) |
|
8.3 |
|
|
25.0 |
|
|
213.5 |
|
OPERATING
INCOME (LOSS) |
(1,116.8 |
) |
|
(24.5 |
) |
|
(1,260.4 |
) |
|
101.5 |
|
Realized and unrealized
gains (losses) on derivative contracts |
330.7 |
|
|
(138.8 |
) |
|
90.4 |
|
|
24.5 |
|
Interest and other
income (expense) |
(5.5 |
) |
|
(0.9 |
) |
|
(9.6 |
) |
|
1.6 |
|
Loss from early
extinguishment of debt |
— |
|
|
(32.7 |
) |
|
— |
|
|
(32.7 |
) |
Interest expense |
(37.5 |
) |
|
(34.7 |
) |
|
(149.4 |
) |
|
(137.8 |
) |
INCOME
(LOSS) BEFORE INCOME TAXES |
(829.1 |
) |
|
(231.6 |
) |
|
(1,329.0 |
) |
|
(42.9 |
) |
Income tax (provision)
benefit |
199.8 |
|
|
381.9 |
|
|
317.4 |
|
|
312.2 |
|
NET
INCOME (LOSS) |
$ |
(629.3 |
) |
|
$ |
150.3 |
|
|
$ |
(1,011.6 |
) |
|
$ |
269.3 |
|
|
|
|
|
|
|
|
|
Earnings (loss) per
common share |
|
|
|
|
|
|
|
Basic |
$ |
(2.66 |
) |
|
$ |
0.62 |
|
|
$ |
(4.25 |
) |
|
$ |
1.12 |
|
Diluted |
$ |
(2.66 |
) |
|
$ |
0.62 |
|
|
$ |
(4.25 |
) |
|
$ |
1.12 |
|
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
|
|
|
Used in
basic calculation |
236.7 |
|
|
241.0 |
|
|
237.9 |
|
|
240.6 |
|
Used in
diluted calculation |
236.7 |
|
|
241.0 |
|
|
237.9 |
|
|
240.6 |
|
QEP RESOURCES, INC.CONSOLIDATED BALANCE
SHEETS
|
December 31, 2018 |
|
December 31, 2017 |
ASSETS |
(in millions) |
Current Assets |
|
|
|
Cash and cash
equivalents |
$ |
— |
|
|
$ |
— |
|
Accounts
receivable, net |
104.3 |
|
|
140.0 |
|
Income
tax receivable |
75.9 |
|
|
4.9 |
|
Fair
value of derivative contracts |
87.5 |
|
|
3.4 |
|
Prepaid
expenses |
12.7 |
|
|
10.1 |
|
Other
current assets |
0.2 |
|
|
3.6 |
|
Total
Current Assets |
280.6 |
|
|
162.0 |
|
Property,
Plant and Equipment (successful efforts method for oil and gas
properties) |
|
|
Proved
properties |
9,096.9 |
|
|
8,081.0 |
|
Unproved
properties |
705.5 |
|
|
1,028.5 |
|
Gathering
and other |
167.7 |
|
|
111.0 |
|
Materials
and supplies |
29.9 |
|
|
24.8 |
|
Total
Property, Plant and Equipment |
10,000.0 |
|
|
9,245.3 |
|
Less Accumulated
Depreciation, Depletion and Amortization |
|
|
|
Exploration and production |
4,882.4 |
|
|
3,315.2 |
|
Gathering
and other |
58.1 |
|
|
63.4 |
|
Total
Accumulated Depreciation, Depletion and Amortization |
4,940.5 |
|
|
3,378.6 |
|
Net
Property, Plant and Equipment |
5,059.5 |
|
|
5,866.7 |
|
Fair value of
derivative contracts |
35.4 |
|
|
0.1 |
|
Other noncurrent
assets |
49.6 |
|
|
45.1 |
|
Noncurrent assets held
for sale |
692.7 |
|
|
1,320.9 |
|
TOTAL
ASSETS |
$ |
6,117.8 |
|
|
$ |
7,394.8 |
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
Current
Liabilities |
|
|
|
Checks
outstanding in excess of cash balances |
$ |
14.6 |
|
|
$ |
44.0 |
|
Accounts
payable and accrued expenses |
258.1 |
|
|
360.1 |
|
Production and property taxes |
24.1 |
|
|
31.6 |
|
Interest
payable |
32.4 |
|
|
26.0 |
|
Fair
value of derivative contracts |
— |
|
|
103.6 |
|
Asset
retirement obligations |
5.1 |
|
|
2.8 |
|
Total
Current Liabilities |
334.3 |
|
|
568.1 |
|
Long-term debt |
2,507.1 |
|
|
2,160.8 |
|
Deferred income
taxes |
269.2 |
|
|
518.0 |
|
Asset retirement
obligations |
96.9 |
|
|
104.1 |
|
Fair value of
derivative contracts |
0.7 |
|
|
34.8 |
|
Other long-term
liabilities |
97.4 |
|
|
101.9 |
|
Other long-term
liabilities held for sale |
61.3 |
|
|
109.2 |
|
Commitments and
Contingencies |
|
|
|
EQUITY |
|
|
|
Common
stock - par value $0.01 per share; 500.0 million shares
authorized; 239.8 million and 243.0 million shares issued,
respectively |
2.4 |
|
|
2.4 |
|
Treasury
stock - 3.1 million and 2.0 million shares, respectively |
(45.6 |
) |
|
(34.2 |
) |
Additional paid-in capital |
1,431.9 |
|
|
1,398.2 |
|
Retained
earnings |
1,376.5 |
|
|
2,442.6 |
|
Accumulated other comprehensive income (loss) |
(14.3 |
) |
|
(11.1 |
) |
Total
Common Shareholders' Equity |
2,750.9 |
|
|
3,797.9 |
|
TOTAL
LIABILITIES AND EQUITY |
$ |
6,117.8 |
|
|
$ |
7,394.8 |
|
|
|
|
|
|
|
|
|
QEP RESOURCES, INC.CONSOLIDATED CASH
FLOWS
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
OPERATING
ACTIVITIES |
(in millions) |
Net income (loss) |
$ |
(629.3 |
) |
|
$ |
150.3 |
|
|
$ |
(1,011.6 |
) |
|
$ |
269.3 |
|
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities: |
Depreciation, depletion and amortization |
183.5 |
|
|
194.3 |
|
|
857.1 |
|
|
754.5 |
|
Deferred
income taxes |
(128.0 |
) |
|
(383.3 |
) |
|
(247.6 |
) |
|
(314.8 |
) |
Impairment |
1,156.5 |
|
|
50.5 |
|
|
1,560.9 |
|
|
78.9 |
|
Dry hole
exploratory well expense |
— |
|
|
0.1 |
|
|
— |
|
|
21.3 |
|
Share-based compensation |
10.8 |
|
|
8.9 |
|
|
39.1 |
|
|
22.4 |
|
Amortization of debt issuance costs and discounts |
1.4 |
|
|
1.4 |
|
|
5.4 |
|
|
6.2 |
|
Bargain
purchase gain from acquisitions |
— |
|
|
— |
|
|
— |
|
|
0.4 |
|
Net
(gain) loss from asset sales, inclusive of restructuring costs |
1.7 |
|
|
(8.3 |
) |
|
(25.0 |
) |
|
(213.5 |
) |
Loss from
early extinguishment of debt |
— |
|
|
32.7 |
|
|
— |
|
|
32.7 |
|
Unrealized (gains) losses on marketable securities |
2.3 |
|
|
(0.8 |
) |
|
1.2 |
|
|
(2.9 |
) |
Unrealized (gains) losses on derivative contracts |
(361.7 |
) |
|
121.6 |
|
|
(248.5 |
) |
|
(40.0 |
) |
Other
non-cash activity |
— |
|
|
— |
|
|
— |
|
|
(9.4 |
) |
Changes
in operating assets and liabilities |
(95.9 |
) |
|
(50.0 |
) |
|
(114.8 |
) |
|
(4.9 |
) |
Net Cash
Provided by (Used in) Operating Activities |
141.3 |
|
|
117.4 |
|
|
816.2 |
|
|
600.2 |
|
INVESTING
ACTIVITIES |
|
|
|
|
|
|
|
Property
acquisitions |
(17.3 |
) |
|
(720.7 |
) |
|
(65.6 |
) |
|
(815.2 |
) |
Property,
plant and equipment, including exploratory well expense |
(202.0 |
) |
|
(380.0 |
) |
|
(1,234.1 |
) |
|
(1,159.6 |
) |
Proceeds
from disposition of assets |
26.1 |
|
|
18.9 |
|
|
243.6 |
|
|
806.8 |
|
Net Cash
Provided by (Used in) Investing Activities |
(193.2 |
) |
|
(1,081.8 |
) |
|
(1,056.1 |
) |
|
(1,168.0 |
) |
FINANCING
ACTIVITIES |
|
|
|
|
|
|
|
Checks
outstanding in excess of cash balances |
(0.8 |
) |
|
44.0 |
|
|
(29.5 |
) |
|
31.7 |
|
Long-term
debt issued |
— |
|
|
500.0 |
|
|
— |
|
|
500.0 |
|
Long-term
debt issuance costs paid |
— |
|
|
(13.3 |
) |
|
(0.1 |
) |
|
(14.4 |
) |
Long-term
debt extinguishment costs paid |
— |
|
|
(28.1 |
) |
|
— |
|
|
(28.1 |
) |
Long-term
debt repaid |
— |
|
|
(445.6 |
) |
|
— |
|
|
(445.6 |
) |
Proceeds
from credit facility |
992.0 |
|
|
490.0 |
|
|
3,608.0 |
|
|
492.0 |
|
Repayments of credit facility |
(937.5 |
) |
|
(401.0 |
) |
|
(3,267.0 |
) |
|
(403.0 |
) |
Common
stock repurchased and retired |
— |
|
|
— |
|
|
(58.4 |
) |
|
— |
|
Treasury
stock repurchases |
(0.9 |
) |
|
— |
|
|
(8.7 |
) |
|
(6.8 |
) |
Other
capital contributions |
— |
|
|
— |
|
|
0.3 |
|
|
— |
|
Net Cash
Provided by (Used in) Financing Activities |
52.8 |
|
|
146.0 |
|
|
244.6 |
|
|
125.8 |
|
Change in cash, cash
equivalents and restricted cash |
0.9 |
|
|
(818.4 |
) |
|
4.7 |
|
|
(442.0 |
) |
Beginning cash, cash
equivalents and restricted cash |
27.2 |
|
|
841.8 |
|
|
23.4 |
|
|
465.4 |
|
Ending cash, cash
equivalents and restricted cash |
$ |
28.1 |
|
|
$ |
23.4 |
|
|
$ |
28.1 |
|
|
$ |
23.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production by Region |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
|
(in Mboe) |
Northern
Region |
|
|
|
|
|
|
|
|
|
|
|
Williston Basin |
3,760.8 |
|
|
4,479.8 |
|
|
(16 |
)% |
|
16,331.3 |
|
|
18,140.0 |
|
|
(10 |
)% |
Pinedale |
— |
|
|
29.3 |
|
|
(100 |
)% |
|
0.1 |
|
|
9,871.7 |
|
|
(100 |
)% |
Uinta
Basin |
11.3 |
|
|
834.8 |
|
|
(99 |
)% |
|
2,243.5 |
|
|
3,605.4 |
|
|
(38 |
)% |
Other
Northern |
35.7 |
|
|
136.8 |
|
|
(74 |
)% |
|
247.0 |
|
|
1,082.4 |
|
|
(77 |
)% |
Total
Northern Region |
3,807.8 |
|
|
5,480.7 |
|
|
(31 |
)% |
|
18,821.9 |
|
|
32,699.5 |
|
|
(42 |
)% |
Southern
Region |
|
|
|
|
|
|
|
|
|
|
|
Permian
Basin |
4,368.7 |
|
|
2,554.3 |
|
|
71 |
% |
|
15,960.3 |
|
|
8,227.2 |
|
|
94 |
% |
Haynesville/Cotton Valley |
3,445.9 |
|
|
4,028.5 |
|
|
(14 |
)% |
|
17,050.5 |
|
|
12,188.7 |
|
|
40 |
% |
Other
Southern |
4.8 |
|
|
6.4 |
|
|
(25 |
)% |
|
25.2 |
|
|
29.5 |
|
|
(15 |
)% |
Total
Southern Region |
7,819.4 |
|
|
6,589.2 |
|
|
19 |
% |
|
33,036.0 |
|
|
20,445.4 |
|
|
62 |
% |
Total production |
11,627.2 |
|
|
12,069.9 |
|
|
(4 |
)% |
|
51,857.9 |
|
|
53,144.9 |
|
|
(2 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
Oil and condensate
(Mbbl) |
5,749.9 |
|
|
5,240.6 |
|
|
10 |
% |
|
23,932.0 |
|
|
19,620.7 |
|
|
22 |
% |
Gas
(Bcf) |
28.1 |
|
|
34.1 |
|
|
(18 |
)% |
|
139.6 |
|
|
168.9 |
|
|
(17 |
)% |
NGL
(Mbbl) |
1,188.9 |
|
|
1,140.9 |
|
|
4 |
% |
|
4,661.4 |
|
|
5,367.3 |
|
|
(13 |
)% |
Total
equivalent production (Mboe) |
11,627.2 |
|
|
12,069.9 |
|
|
(4 |
)% |
|
51,857.9 |
|
|
53,144.9 |
|
|
(2 |
)% |
Average
daily production (Mboe) |
126.4 |
|
|
131.2 |
|
|
(4 |
)% |
|
142.1 |
|
|
145.6 |
|
|
(2 |
)% |
|
Prices |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
Oil (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
51.67 |
|
|
$ |
54.14 |
|
|
|
|
$ |
59.43 |
|
|
$ |
47.88 |
|
|
|
Commodity derivative
impact |
(2.69 |
) |
|
(2.84 |
) |
|
|
|
(6.41 |
) |
|
0.34 |
|
|
|
Net realized price |
$ |
48.98 |
|
|
$ |
51.30 |
|
|
(5)% |
|
$ |
53.02 |
|
|
$ |
48.22 |
|
|
10% |
Gas (per
Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
3.25 |
|
|
$ |
2.77 |
|
|
|
|
$ |
2.82 |
|
|
$ |
2.92 |
|
|
|
Commodity derivative
impact |
(0.56 |
) |
|
(0.07 |
) |
|
|
|
(0.04 |
) |
|
(0.13 |
) |
|
|
Net
realized price |
$ |
2.69 |
|
|
$ |
2.70 |
|
|
—% |
|
$ |
2.78 |
|
|
$ |
2.79 |
|
|
—% |
NGL (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
19.12 |
|
|
$ |
24.41 |
|
|
|
|
$ |
23.79 |
|
|
$ |
20.85 |
|
|
|
Commodity derivative
impact |
— |
|
|
— |
|
|
|
|
— |
|
|
— |
|
|
|
Net
realized price |
$ |
19.12 |
|
|
$ |
24.41 |
|
|
(22)% |
|
$ |
23.79 |
|
|
$ |
20.85 |
|
|
14% |
Average net
equivalent price (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level
price |
$ |
35.38 |
|
|
$ |
33.65 |
|
|
|
|
$ |
37.15 |
|
|
$ |
29.08 |
|
|
|
Commodity derivative
impact |
(2.68 |
) |
|
(1.44 |
) |
|
|
|
(3.06 |
) |
|
(0.29 |
) |
|
|
Net
realized price |
$ |
32.70 |
|
|
$ |
32.21 |
|
|
2% |
|
$ |
34.09 |
|
|
$ |
28.79 |
|
|
18% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
|
(in millions) |
Lease operating
expense |
$ |
59.5 |
|
|
$ |
79.4 |
|
|
(25 |
)% |
|
$ |
263.1 |
|
|
$ |
294.8 |
|
|
(11 |
)% |
Adjusted transportation
and processing costs(1) |
38.5 |
|
|
42.7 |
|
|
(10 |
)% |
|
172.6 |
|
|
245.3 |
|
|
(30 |
)% |
Production and property
taxes |
26.9 |
|
|
28.2 |
|
|
(5 |
)% |
|
130.8 |
|
|
114.3 |
|
|
14 |
% |
Total
production costs |
$ |
124.9 |
|
|
$ |
150.3 |
|
|
(17 |
)% |
|
$ |
566.5 |
|
|
$ |
654.4 |
|
|
(13 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(per Boe) |
Lease operating
expense |
$ |
5.11 |
|
|
$ |
6.58 |
|
|
(22 |
)% |
|
$ |
5.07 |
|
|
$ |
5.55 |
|
|
(9 |
)% |
Adjusted transportation
and processing costs(1) |
3.31 |
|
|
3.54 |
|
|
(6 |
)% |
|
3.33 |
|
|
4.61 |
|
|
(28 |
)% |
Production and property
taxes |
2.31 |
|
|
2.34 |
|
|
(1 |
)% |
|
2.52 |
|
|
2.15 |
|
|
17 |
% |
Total
production costs |
$ |
10.73 |
|
|
$ |
12.46 |
|
|
(14 |
)% |
|
$ |
10.92 |
|
|
$ |
12.31 |
|
|
(11 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________________________(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, 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, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
(in millions) |
Net income (loss) |
$ |
(629.3 |
) |
|
$ |
150.3 |
|
|
$ |
(1,011.6 |
) |
|
$ |
269.3 |
|
Interest expense |
37.5 |
|
|
34.7 |
|
|
149.4 |
|
|
137.8 |
|
Interest and other
(income) expense |
5.5 |
|
|
0.9 |
|
|
9.6 |
|
|
(1.6 |
) |
Income tax provision
(benefit) |
(199.8 |
) |
|
(381.9 |
) |
|
(317.4 |
) |
|
(312.2 |
) |
Depreciation, depletion
and amortization |
183.5 |
|
|
194.3 |
|
|
857.1 |
|
|
754.5 |
|
Unrealized (gains)
losses on derivative contracts |
(361.7 |
) |
|
121.6 |
|
|
(248.5 |
) |
|
(40.0 |
) |
Exploration
expenses |
0.2 |
|
|
0.3 |
|
|
0.3 |
|
|
22.0 |
|
Net (gain) loss from
asset sales, inclusive of restructuring costs |
1.7 |
|
|
(8.3 |
) |
|
(25.0 |
) |
|
(213.5 |
) |
Impairment |
1,156.5 |
|
|
50.5 |
|
|
1,560.9 |
|
|
78.9 |
|
Loss from early
extinguishment of debt |
— |
|
|
32.7 |
|
|
— |
|
|
32.7 |
|
Other(1) |
— |
|
|
— |
|
|
— |
|
|
8.2 |
|
Adjusted
EBITDA |
$ |
194.1 |
|
|
$ |
195.1 |
|
|
$ |
974.8 |
|
|
$ |
736.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________________________(1) Reflects
legal expenses and loss contingencies incurred during the year
ended December 31, 2017. 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, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
(in millions, except earnings per share amounts) |
Net income
(loss)(1) |
$ |
(629.3 |
) |
|
$ |
150.3 |
|
|
$ |
(1,011.6 |
) |
|
$ |
269.3 |
|
Adjustments to net
income (loss) |
|
|
|
|
|
|
|
Unrealized (gains) losses on derivative contracts |
(361.7 |
) |
|
121.6 |
|
|
(248.5 |
) |
|
(40.0 |
) |
Income
taxes on unrealized (gains) losses on derivative contracts(2) |
89.3 |
|
|
(45.1 |
) |
|
61.4 |
|
|
14.8 |
|
Net gain
(loss) from asset sales, inclusive of restructuring costs |
1.7 |
|
|
(8.3 |
) |
|
(25.0 |
) |
|
(213.5 |
) |
Income
taxes on net (gain) loss from asset sales, inclusive of
restructuring costs(2) |
(0.4 |
) |
|
3.1 |
|
|
6.2 |
|
|
79.2 |
|
Impairment |
1,156.5 |
|
|
50.5 |
|
|
1,560.9 |
|
|
78.9 |
|
Income
taxes on impairment(2) |
(285.7 |
) |
|
(18.7 |
) |
|
(385.5 |
) |
|
(29.3 |
) |
Loss from
early extinguishment of debt |
— |
|
|
32.7 |
|
|
— |
|
|
32.7 |
|
Income
taxes on loss from early extinguishment of debt(2) |
— |
|
|
(12.1 |
) |
|
— |
|
|
(12.1 |
) |
Other(3) |
— |
|
|
— |
|
|
— |
|
|
8.2 |
|
Income
taxes on other(2) |
— |
|
|
— |
|
|
— |
|
|
(3.0 |
) |
Total after-tax
adjustments to net income |
599.7 |
|
|
123.7 |
|
|
969.5 |
|
|
(84.1 |
) |
Adjusted Net Income
(Loss) |
$ |
(29.6 |
) |
|
$ |
274.0 |
|
|
$ |
(42.1 |
) |
|
$ |
185.2 |
|
|
|
|
|
|
|
|
|
Earnings (Loss) per
Common Share |
|
|
|
|
|
|
|
Diluted
earnings per share |
$ |
(2.66 |
) |
|
$ |
0.62 |
|
|
$ |
(4.25 |
) |
|
$ |
1.12 |
|
Diluted
after-tax adjustments to net income (loss) per share |
2.53 |
|
|
0.51 |
|
|
4.08 |
|
|
(0.35 |
) |
Diluted
Adjusted Net Income per share |
$ |
(0.13 |
) |
|
$ |
1.13 |
|
|
$ |
(0.17 |
) |
|
$ |
0.77 |
|
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
|
|
|
Diluted |
236.7 |
|
|
241.0 |
|
|
237.9 |
|
|
240.6 |
|
________________________(1) 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.(2) Income tax impact of adjustments is
calculated using QEP’s statutory rate of 24.7% and 37.1% for the
three and twelve months ended December 31, 2018 and
2017.(3) Reflects legal expenses and loss contingencies
incurred during the year ended December 31, 2017. 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 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 transportation and processing
costs associated with QEP's production. Management believes that
Adjusted Transportation and Processing Costs is useful supplemental
information for investors as this non-GAAP measure, collectively
with the Company’s lease operating expenses and production and
severance taxes, more completely reflect the Company’s total
production costs required to operate the wells for the period.
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 December 31, |
|
Year Ended December 31, |
|
2018 |
|
2017 |
|
Change |
|
2018 |
|
2017 |
|
Change |
|
(in millions) |
Transportation and
processing costs, as presented |
$ |
24.4 |
|
|
$ |
42.7 |
|
|
$ |
(18.3 |
) |
|
$ |
117.6 |
|
|
$ |
245.3 |
|
|
$ |
(127.7 |
) |
Transportation and
processing costs deducted from oil and condensate, gas and NGL
sales |
14.1 |
|
|
— |
|
|
14.1 |
|
|
55.0 |
|
|
— |
|
|
55.0 |
|
Adjusted
transportation and processing costs |
$ |
38.5 |
|
|
$ |
42.7 |
|
|
$ |
(4.2 |
) |
|
$ |
172.6 |
|
|
$ |
245.3 |
|
|
$ |
(72.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(per Boe) |
Transportation and
processing costs, as presented |
$ |
2.10 |
|
|
$ |
3.54 |
|
|
$ |
(1.44 |
) |
|
$ |
2.27 |
|
|
$ |
4.61 |
|
|
$ |
(2.34 |
) |
Transportation and
processing costs deducted from oil and condensate, gas and NGL
sales |
1.21 |
|
|
— |
|
|
1.21 |
|
|
1.06 |
|
|
— |
|
|
1.06 |
|
Adjusted
transportation and processing costs |
$ |
3.31 |
|
|
$ |
3.54 |
|
|
$ |
(0.23 |
) |
|
$ |
3.33 |
|
|
$ |
4.61 |
|
|
$ |
(1.28 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash Flow and Discretionary Cash Flow in
Excess of Capital Expenditures
This release contains references to the non-GAAP measures of
Discretionary Cash Flow and Discretionary Cash Flow in Excess of
Capital Expenditures.
The Company defines Discretionary Cash Flow as net cash provided
by (used in) operating activities less the changes in operating
assets and liabilities. Management believes that this measure is
useful to management and investors as a measure of the Company's
ability to internally fund its capital expenditures and to service
or incur additional debt.
The Company defines Discretionary Cash Flow in Excess of Capital
Expenditures as Discretionary Cash Flow (defined above) less
property acquisitions and property, plant equipment, including
exploratory well expense. Management believes that this measure is
useful to management and investors for analysis of the Company's
ability to internally fund acquisitions, exploration and
development.
Below is a reconciliation of Net Cash Provided by (Used in)
Operating Activities (a GAAP measure) to Discretionary Cash Flow
and Discretionary Cash Flow in Excess of Capital Expenditures.
These non-GAAP measures 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, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
(in millions) |
Cash Flow
Information: |
|
|
|
|
|
|
|
Net Cash Provided by
(Used in) Operating Activities |
$ |
141.3 |
|
|
$ |
117.4 |
|
|
$ |
816.2 |
|
|
$ |
600.2 |
|
Net Cash Provided by
(Used in) Investing Activities |
(193.2 |
) |
|
(1,081.8 |
) |
|
(1,056.1 |
) |
|
(1,168.0 |
) |
Net Cash Provided by
(Used in) Financing Activities |
52.8 |
|
|
146.0 |
|
|
244.6 |
|
|
125.8 |
|
|
|
|
|
|
|
|
|
Discretionary
Cash Flow: |
|
|
|
|
|
|
|
Net Cash Provided by
(Used in) Operating Activities |
$ |
141.3 |
|
|
$ |
117.4 |
|
|
$ |
816.2 |
|
|
$ |
600.2 |
|
Changes in operating
assets and liabilities |
(95.9 |
) |
|
(50.0 |
) |
|
(114.8 |
) |
|
(4.9 |
) |
Discretionary Cash Flow |
45.4 |
|
|
67.4 |
|
|
701.4 |
|
|
595.3 |
|
Property
acquisitions |
(17.3 |
) |
|
(720.7 |
) |
|
(65.6 |
) |
|
(815.2 |
) |
Property, plant and
equipment, including exploratory well expense |
(202.0 |
) |
|
(380.0 |
) |
|
(1,234.1 |
) |
|
(1,159.6 |
) |
Discretionary Cash Flow in Excess of Capital Expenditures |
$ |
(173.9 |
) |
|
$ |
(1,033.3 |
) |
|
$ |
(598.3 |
) |
|
$ |
(1,379.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables present QEP's volumes and average prices
for its open derivative positions as of February 15, 2019:
Production Commodity Derivative
Swaps |
Year |
|
Index |
|
Total Volumes |
|
Average Swap Priceper Unit |
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2019 |
|
NYMEX
WTI |
|
10.6 |
|
|
$ |
54.61 |
|
2020 |
|
NYMEX
WTI |
|
4.4 |
|
|
$ |
60.22 |
|
Production Commodity Derivative Basis
Swaps |
Year |
|
Index |
|
Basis |
|
Total Volumes |
|
Weighted-Average Differential |
|
|
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2019 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
6.0 |
|
|
$ |
(2.22 |
) |
2019 |
|
NYMEX
WTI |
|
Argus
WTI Houston |
|
0.7 |
|
|
$ |
3.80 |
|
2020 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
1.8 |
|
|
$ |
(0.80 |
) |
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