QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported
third quarter 2019 financial and operating results.
HIGHLIGHTS
- Increased full-year production guidance for crude oil, natural
gas and NGL
- Lowered mid-point of capital expenditure guidance by
approximately $15 million, down $65 million year-to-date
- Reduced G&A expense to 2020 target run-rate, down
approximately 40% from third quarter 2018 to third quarter
2019
- Greater than 60% of projected 2020 oil production hedged at
$58.31 per barrel
- Ended the quarter with $92.4 million of cash and cash
equivalents and no borrowings under credit facility
"Operational performance in the third quarter exceeded
expectations, with our core Permian Basin assets delivering record
oil production. The outperformance of the Permian assets is
directly attributable to the enhanced flowback and artificial lift
strategy, along with improved frac to first production timing that
we implemented earlier in the year. As a result, we have increased
our annual production guidance for crude oil, natural gas and NGL
and lowered the midpoint of CAPEX guidance by approximately $15
million compared to the second quarter," commented Tim Cutt,
President and CEO of QEP.
"Our continued focus on reducing expenses has allowed us to
lower the outlook for Lease Operating and G&A Expense. These
tangible expense savings, coupled with the year-to-date reductions
to drilling, completion and facility cost, resulted in QEP
generating Free Cash Flow in the third quarter and positions the
Company to generate significant Free Cash Flow in the fourth
quarter. Our ability to generate significant Free Cash Flow on an
annual basis going forward is expected to allow us to organically
de-lever our balance sheet and return capital to shareholders."
The Company has posted to its website www.qepres.com a
presentation that supplements the information provided in this
release.
QEP Third Quarter 2019 Financial Results
The Company reported net income of $81.0 million for the third
quarter 2019, or $0.34 per diluted share, compared with net income
of $7.3 million, or $0.03 per diluted share, for the third quarter
2018. The Company's increase in net income in the third quarter of
2019 compared to 2018 was primarily due to an $87.4 million gain on
realized and unrealized derivative contracts in the third quarter
of 2019.
Net income 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 third quarter 2019 Adjusted
Net Income (a non-GAAP measure) was $11.0 million, or $0.05 per
diluted share, compared to Adjusted Net Income of $39.6 million, or
$0.17 per diluted share, for the third quarter 2018.
Adjusted EBITDA (a non-GAAP measure) for the third quarter 2019
was $193.5 million compared with $326.2 million for the third
quarter 2018, primarily due to the Haynesville/Cotton Valley and
Uinta Basin divestitures, lower equivalent production in the
Williston Basin and a 16% decrease in average field-level oil
prices, partially offset by an 18% increase in equivalent
production in the Permian Basin, a $33.5 million decrease in
realized derivative losses and an $18.7 million decrease in general
and administrative expenses.
The definitions and reconciliations of Adjusted Net Income
(Loss) to Net Income (Loss) and Adjusted EBITDA and Free Cash Flow
are provided under the heading Non-GAAP measures at the end of this
release.
Production
Oil equivalent production was 8.4 million barrels of oil
equivalent (MMboe) in the third quarter 2019, a decrease of 42%
compared with the third quarter 2018. The decrease in oil
equivalent production was primarily the result of the loss of 5.2
MMboe (3% liquids) of equivalent production associated with the
assets sold in the Haynesville/Cotton Valley and Uinta Basin
divestitures.
Oil and condensate production in the Permian Basin was 4.0
million barrels (MMbbl) in the third quarter 2019, an increase of
12% compared with the third quarter of 2018, and a Company record.
The production increase was offset by lower volumes in the
Williston Basin due to a reduced level of activity in the third
quarter of 2019 and a loss of volumes as a result of the Uinta
Basin divestiture.
Operating Expenses
During the third quarter 2019, lease operating expense (LOE) was
$38.3 million, a decrease of 41% compared with the third quarter
2018. The decrease is primarily due to the Haynesville/Cotton
Valley and Uinta Basin divestitures. Excluding those divestitures,
LOE decreased $14.1 million, driven by a decrease in maintenance
and repair expenses, labor and water disposal in the Permian and
Williston basins as a result of continuing efforts to reduce
operating expenses.
During the third quarter of 2019, LOE was $4.56 per Boe, an
increase of 2% compared to the third quarter of 2018, primarily due
to the Haynesville/Cotton Valley and Uinta Basin divestitures.
Excluding those divestitures, LOE per Boe decreased by 20% compared
to the third quarter of 2018. The 20% decrease per BOE rate
was related to lower cost production from the recent horizontal
well completions in the Permian Basin, partially offset by
decreased production in the Williston Basin.
During the third quarter 2019, Transportation and Processing
(T&P) Costs were $18.0 million, a decrease of 36% compared with
the third quarter 2018. Adjusted T&P Costs (a non-GAAP measure)
were $32.2 million, a decrease of 26% compared with the third
quarter 2018, primarily due to the Haynesville/Cotton Valley and
Uinta Basin divestitures. Excluding those divestitures, Adjusted
T&P Costs increased $5.2 million, primarily due to the
recognition of $7.7 million of firm transportation expense related
to future obligations in an area in which the Company no longer has
production operations as well as increased production in the
Permian Basin, partially offset by decreased production in the
Williston Basin.
During the third quarter 2019, T&P Costs increased by $0.20
per Boe, or 10%, compared with the third quarter 2018. Adjusted
T&P costs increased $0.79 per Boe, or 26%, during the third
quarter of 2019 compared to the third quarter of 2018. The increase
was primarily due to the recognition of $7.7 million of firm
transportation expense related to future obligations in an area in
which the Company no longer has production operations, partially
offset by the Haynesville/Cotton Valley and Uinta Basin
divestitures, which had higher adjusted transportation and
processing costs per Boe.
The definition and reconciliation of Adjusted Transportation and
Processing Costs is provided under the heading Non-GAAP Measures at
the end of this release.
During the third quarter 2019, general and administrative
(G&A) expense was $29.6 million, a decrease of 39% compared to
the third quarter 2018. During the third quarter of 2019 and 2018,
QEP incurred $10.0 million and $14.2 million, respectively, in
costs associated with the implementation of our strategic
initiatives, of which $10.4 million and $12.8 million,
respectively, related to restructuring costs. Excluding these
costs, G&A expense decreased by $14.4 million, or 42%,
primarily due to $12.7 million lower labor, benefits and other
associated costs due to the reduction in our workforce and $3.2
million in lower legal and outside service costs, partially offset
by a $2.2 million decrease in overhead recoveries, primarily
associated with our Haynesville/Cotton Valley and Uinta Basin
divestitures. During the quarter the third quarter 2019, G&A
was $3.52 per BOE.
During the third quarter 2019, production and property taxes
were $20.0 million, a decrease of 47% compared to the third quarter
2018. The decrease in production and property taxes was primarily
due to decreased revenues in the Williston Basin as well as the
Haynesville/Cotton Valley and Uinta Basin divestitures.
During the third quarter of 2019, production and property taxes
were $2.38 per Boe, a decrease of 8% compared to the third quarter
of 2018, but decreased 35% excluding the Haynesville/Cotton Valley
and Uinta Basin divestitures. The 35% decrease was due to a
decrease in average field-level equivalent prices in the Permian
and Williston basins.
Capital Investment
Capital investment, excluding property acquisitions, was $128.9
million (on an accrual basis) for the third quarter 2019, compared
with $203.7 million for the third quarter 2018, of which $122.9
million related to the drilling, completion and equipping of wells
and $6.0 million was related to midstream infrastructure
investment. The decrease in capital expenditures was primarily
related to a decrease in completion activity in the Permian Basin,
partially offset by increased capital expenditures in the Williston
Basin as the Company resumed drilling and completion activity in
the basin.
Asset Divestitures
QEP closed on the sale of several assets during the third
quarter 2019, including the corporate aircraft, for total net cash
proceeds of approximately $9.8 million.
Liquidity
Net Cash Provided by Operating Activities for the third quarter
2019 was $146.3 million, compared with $298.0 million for the third
quarter 2018. Free Cash Flow (a non-GAAP measure) was $17.5 million
for the third quarter 2019, compared with $26.2 million for the
third quarter 2018. Free Cash Flow was negative $66.9 million for
the first three quarters of 2019 compared with negative $375.9
million for the first three quarters of 2018. Although the Company
generated negative Free Cash Flow during the first three quarters
of 2019, $676.5 million of proceeds was raised through the
disposition of assets.
As of September 30, 2019, the Company had $92.4 million in
cash and cash equivalents, no borrowings under its revolving credit
facility and $2.9 million in letters of credit outstanding.
2019 Updated Guidance
QEP's fourth quarter and full year 2019 guidance assumes: (1) an
oil price of $55 per barrel and a natural gas price of $2.50 per
MMBtu, (2) that QEP will elect to recover ethane from its produced
gas in the Permian Basin when processing economics
support it, (3) no additional property acquisitions or
divestitures, other than those already disclosed (4) includes
approximately 10 days of production activity in the
Haynesville/Cotton Valley and (5) includes the impact of lower
flare volume and higher gas and NGL capture in the Permian
Basin.
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 in the first quarter 2019 to drill
seven gross operated wells
Wells Put on Production:
- Permian Basin: 59 net operated wells
- Williston Basin: six net operated wells
2019 Guidance |
|
4Q 2019 |
2019 |
2019 |
|
Guidance |
PreviousGuidance |
UpdatedGuidance |
Oil & condensate
production (MMbbl) |
5.7 - 6.0 |
21.0 - 21.5 |
21.6 - 21.9 |
Gas production (Bcf) |
7.9 - 8.4 |
28.0 - 30.0 |
32.4 - 32.9 |
NGL
production (MMbbl) |
1.3 - 1.5 |
4.25 - 4.50 |
5.0 - 5.2 |
Total oil equivalent production (MMboe) |
8.3 - 8.9 |
29.9 - 31.0 |
32.0 - 32.6 |
|
|
|
|
Lease operating expense and
Adjusted Transportation and Processing Costs (per Boe)(1) |
|
$9.00 - $10.00 |
$8.50 - $9.25 |
Depletion, depreciation and
amortization (per Boe) |
|
$16.75 - $17.75 |
$16.75 - $17.75 |
Production and property taxes (% of field-level revenue) |
|
7.0% |
7.5% |
(in millions) |
Total general and administrative expense(2) |
|
$160.0 - $170.0 |
$155.0 - $165.0 |
Less:
Special general & administrative expense(3) |
|
$54.0 |
$54.0 |
Total General and administrative expense (excluding special general
& administrative expense) |
|
$106.0 - $116.0 |
$101.0 - $111.0 |
|
|
|
|
Capital investment (excluding
property acquisitions) |
|
|
|
Drilling, Completion and Equipment (4) |
|
$520.0 - $540.0 |
$515.0 - $530.0 |
Midstream Infrastructure(5) |
|
$55.0 |
$50.0 |
Corporate |
|
$5.0 |
$2.0 |
Total capital investment (excluding property acquisitions) |
$101.0 - $116.0 |
$580.0 - $600.0 |
$567.0 - $582.0 |
|
|
|
|
Wells put on production (net) |
3 |
65 |
65 |
____________________________(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) The mid-point of G&A expense includes approximately
$26.0 million of expenses related to non-cash, share-based
compensation and other mark-to-market liabilities. Because
these mark-to-market liabilities fluctuate with stock price
changes, the amount of actual expense may vary from the forecasted
amount.(3) Special G&A expense also includes approximately
$54.0 million of estimated expenses associated with our strategic
initiative process, primarily related to severance and retention
programs, and includes approximately $11.0 million of accelerated
shared-based compensation expense that is included in the $26.0
million of expenses related to non-cash, share-based compensation
and other mark-to-market liabilities.(4) Drilling, Completion and
Equipment includes approximately $20.0 million of non-operated well
costs.(5) 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 |
|
|
|
|
|
As of September 30, 2019 |
|
Gross |
|
Net |
|
Gross |
|
Net |
Well
Progress |
|
|
|
|
|
|
|
Drilling |
7 |
|
|
7.0 |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
At total depth - under
drilling rig |
6 |
|
|
6.0 |
|
|
— |
|
|
— |
|
Waiting to be completed |
25 |
|
|
25.0 |
|
|
— |
|
|
— |
|
Completed, awaiting
production |
— |
|
|
— |
|
|
4 |
|
|
3.4 |
|
Waiting on completion |
31 |
|
|
31.0 |
|
|
4 |
|
|
3.4 |
|
|
|
|
|
|
|
|
|
Put on production(1) |
24 |
|
|
24.0 |
|
|
3 |
|
|
3.0 |
|
_______________________(1) Total wells put on production during
the three months ended September 30, 2019.
Permian Basin
Permian Basin net oil equivalent production averaged a Company
record of approximately 61.5 Mboed (86% liquids) during the third
quarter 2019, a 23% increase compared with the second quarter 2019
and an 18% increase compared with the third quarter 2018. Oil and
condensate production in the Permian Basin was 4.0 MMbbl in the
third quarter 2019, a 12% increase compared with the third quarter
of 2018.
In the third quarter 2019, the Company put on production 24
gross-operated horizontal wells, all on Mustang Springs (average
working interest 100%).
At the end of the third quarter 2019, of the 24 wells put on
production during the quarter, 12 wells had reached peak production
rates and 12 wells were still in the process of cleaning up. The
wells put on production during the third quarter 2019 have an
average lateral length of 8,631 feet.
At the end of the third quarter 2019, the Company had seven
gross-operated horizontal wells in process of being drilled (of
which five had surface casing set, but had no drilling rig present)
(average working interest 100%), six horizontal wells at total
depth under drilling rigs and 25 horizontal wells waiting to be
completed (average working interest 100%).
At the end of the third quarter 2019, the Company had two
operated rigs in the Permian Basin.
Williston Basin
Williston Basin net oil equivalent production averaged
approximately 29.6 Mboed (80% liquids) during the third quarter
2019, a 9% decrease compared with the second quarter 2019 and a 38%
decrease compared with the third quarter 2018, primarily due to a
reduced level of activity.
During the third quarter 2019 the Company completed a seven well
(gross) pad on South Antelope. During the last week of third
quarter 2019 three wells (gross) of the seven wells (gross) were
put on production. The remaining four wells (gross) were put on
production in early October 2019.
At the end of the third quarter 2019, the Company had no
drilling rigs in the Williston Basin.
Third Quarter 2019 Results Conference Call
QEP’s management will discuss third quarter 2019 results in a
conference call tomorrow, October 24, 2019, beginning at 9:00
a.m. ET. 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 November 23, 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 #13695492.
In addition, QEP’s slides for the third quarter 2019 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: ability to generate Free Cash Flow in
the fourth quarter of 2019 and full year 2020; ability to
strengthen our balance sheet; ability to execute on our development
programs and capture opportunities to create shareholder value;
actively managing and improving our cost structure; reducing
G&A expense; plans for development of our Permian Basin and
Williston Basin assets; operating our business safely; 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 expense and 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; fourth quarter and
full year 2019 production guidance and assumptions for such
guidance; plans regarding ethane rejection and recovery; the impact
of lower flare volume and higher gas and NGL capture in the Permian
Basin; 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 (SEC), including the Risk Factors section of
the Company’s Annual Report on Form 10-K for the year ended
December 31, 2018 and in the Company's quarterly and current
reports filed with the SEC subsequent to the Annual Report on Form
10-K. QEP undertakes no obligation to publicly correct or update
the forward-looking statements in this news release, in other
documents, or on the website to reflect future events or
circumstances. All such statements are expressly qualified by this
cautionary statement.
Contact |
Investors/Media: |
William I. Kent, IRC |
Director, Investor
Relations |
303-405-6665 |
QEP RESOURCES, INC.CONDENSED
CONSOLIDATED STATEMENTS OF
OPERATIONS(Unaudited)
|
Three Months Ended |
|
Nine Months Ended |
|
September 30, |
|
September 30, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
REVENUES |
(in millions, except per share amounts) |
Oil and condensate, gas and NGL sales |
$ |
305.6 |
|
|
$ |
544.0 |
|
|
$ |
875.8 |
|
|
$ |
1,474.1 |
|
Other revenues |
1.8 |
|
|
3.8 |
|
|
7.1 |
|
|
11.8 |
|
Purchased oil and gas sales |
0.1 |
|
|
13.0 |
|
|
1.4 |
|
|
36.2 |
|
Total Revenues |
307.5 |
|
|
560.8 |
|
|
884.3 |
|
|
1,522.1 |
|
OPERATING
EXPENSES |
|
|
|
|
|
|
|
Purchased oil and gas expense |
0.1 |
|
|
13.3 |
|
|
1.5 |
|
|
38.6 |
|
Lease operating expense |
38.3 |
|
|
64.6 |
|
|
135.5 |
|
|
203.6 |
|
Transportation and processing costs |
18.0 |
|
|
28.0 |
|
|
38.8 |
|
|
93.2 |
|
Gathering and other expense |
3.1 |
|
|
4.6 |
|
|
9.9 |
|
|
10.8 |
|
General and administrative |
29.6 |
|
|
48.3 |
|
|
124.4 |
|
|
164.2 |
|
Production and property taxes |
20.0 |
|
|
37.4 |
|
|
67.6 |
|
|
103.9 |
|
Depreciation, depletion and amortization |
144.2 |
|
|
234.9 |
|
|
395.5 |
|
|
673.6 |
|
Exploration expenses |
— |
|
|
— |
|
|
— |
|
|
0.1 |
|
Impairment |
— |
|
|
— |
|
|
5.0 |
|
|
404.4 |
|
Total Operating Expenses |
253.3 |
|
|
431.1 |
|
|
778.2 |
|
|
1,692.4 |
|
Net gain (loss) from asset
sales, inclusive of restructuring costs |
(2.1 |
) |
|
27.1 |
|
|
2.5 |
|
|
26.7 |
|
OPERATING INCOME (LOSS) |
52.1 |
|
|
156.8 |
|
|
108.6 |
|
|
(143.6 |
) |
Realized and unrealized gains
(losses) on derivative contracts |
87.4 |
|
|
(108.0 |
) |
|
(55.8 |
) |
|
(240.3 |
) |
Interest and other income
(expense) |
0.9 |
|
|
(0.3 |
) |
|
4.6 |
|
|
(4.1 |
) |
Interest expense |
(32.8 |
) |
|
(38.7 |
) |
|
(100.0 |
) |
|
(111.9 |
) |
INCOME (LOSS) BEFORE INCOME TAXES |
107.6 |
|
|
9.8 |
|
|
(42.6 |
) |
|
(499.9 |
) |
Income tax (provision)
benefit |
(26.6 |
) |
|
(2.5 |
) |
|
55.7 |
|
|
117.6 |
|
NET INCOME (LOSS) |
$ |
81.0 |
|
|
$ |
7.3 |
|
|
$ |
13.1 |
|
|
$ |
(382.3 |
) |
|
|
|
|
|
|
|
|
Earnings (loss) per common
share |
|
|
|
|
|
|
|
Basic |
$ |
0.34 |
|
|
$ |
0.03 |
|
|
$ |
0.06 |
|
|
$ |
(1.60 |
) |
Diluted |
$ |
0.34 |
|
|
$ |
0.03 |
|
|
$ |
0.06 |
|
|
$ |
(1.60 |
) |
|
|
|
|
|
|
|
|
Weighted-average common shares
outstanding |
|
|
|
|
|
|
|
Used in basic calculation |
237.9 |
|
|
236.9 |
|
|
237.7 |
|
|
238.3 |
|
Used in diluted calculation |
237.9 |
|
|
237.0 |
|
|
237.7 |
|
|
238.3 |
|
QEP RESOURCES, INC.CONDENSED
CONSOLIDATED BALANCE
SHEETS(Unaudited)
|
September 30, 2019 |
|
December 31, 2018 |
|
|
|
|
ASSETS |
(in millions) |
Current Assets |
|
|
|
Cash and cash equivalents |
$ |
92.4 |
|
|
$ |
— |
|
Accounts receivable, net |
104.3 |
|
|
104.3 |
|
Income tax receivable |
75.5 |
|
|
75.9 |
|
Fair value of derivative contracts |
69.8 |
|
|
87.5 |
|
Prepaid expenses and other current assets |
8.1 |
|
|
12.9 |
|
Total Current Assets |
350.1 |
|
|
280.6 |
|
Property, Plant and Equipment (successful efforts method for
oil and gas properties) |
|
|
|
Proved properties |
9,416.9 |
|
|
9,096.9 |
|
Unproved properties |
698.3 |
|
|
705.5 |
|
Gathering and other |
162.7 |
|
|
167.7 |
|
Materials and supplies |
19.3 |
|
|
29.9 |
|
Total Property, Plant and Equipment |
10,297.2 |
|
|
10,000.0 |
|
Less Accumulated Depreciation, Depletion and Amortization |
|
|
|
Exploration and production |
5,153.3 |
|
|
4,882.4 |
|
Gathering and other |
58.5 |
|
|
58.1 |
|
Total Accumulated Depreciation, Depletion and Amortization |
5,211.8 |
|
|
4,940.5 |
|
Net Property, Plant and Equipment |
5,085.4 |
|
|
5,059.5 |
|
Fair value of derivative contracts |
23.2 |
|
|
35.4 |
|
Operating lease right-of-use
assets, net |
57.4 |
|
|
— |
|
Other noncurrent assets |
54.5 |
|
|
49.6 |
|
Noncurrent assets held for sale |
— |
|
|
692.7 |
|
TOTAL ASSETS |
$ |
5,570.6 |
|
|
$ |
6,117.8 |
|
LIABILITIES AND EQUITY |
|
|
|
Current Liabilities |
|
|
|
Checks outstanding in excess of cash balances |
$ |
0.7 |
|
|
$ |
14.6 |
|
Accounts payable and accrued expenses |
206.2 |
|
|
258.1 |
|
Production and property taxes |
17.7 |
|
|
24.1 |
|
Current portion of long term debt |
51.7 |
|
|
— |
|
Interest payable |
33.0 |
|
|
32.4 |
|
Fair value of derivative contracts |
0.8 |
|
|
— |
|
Current operating lease liabilities |
18.4 |
|
|
— |
|
Asset retirement obligations |
6.7 |
|
|
5.1 |
|
Total Current Liabilities |
335.2 |
|
|
334.3 |
|
Long-term debt |
2,029.4 |
|
|
2,507.1 |
|
Deferred income taxes |
208.0 |
|
|
269.2 |
|
Asset retirement obligations |
95.5 |
|
|
96.9 |
|
Fair value of derivative contracts |
0.4 |
|
|
0.7 |
|
Operating lease
liabilities |
45.3 |
|
|
— |
|
Other long-term liabilities |
86.8 |
|
|
97.4 |
|
Other long-term liabilities held for sale |
— |
|
|
61.3 |
|
Commitments and contingencies |
|
|
|
EQUITY |
|
|
|
Common stock – par value $0.01 per share; 500.0 million shares
authorized; 242.1 million and 239.8 million shares issued,
respectively |
2.4 |
|
|
2.4 |
|
Treasury stock – 4.3 million and 3.1 million shares,
respectively |
(54.8 |
) |
|
(45.6 |
) |
Additional paid-in capital |
1,451.9 |
|
|
1,431.9 |
|
Retained earnings |
1,384.8 |
|
|
1,376.5 |
|
Accumulated other comprehensive income (loss) |
(14.3 |
) |
|
(14.3 |
) |
Total Common Shareholders' Equity |
2,770.0 |
|
|
2,750.9 |
|
TOTAL LIABILITIES AND EQUITY |
$ |
5,570.6 |
|
|
$ |
6,117.8 |
|
|
|
|
|
|
|
|
|
QEP RESOURCES, INC.CONDENSED
CONSOLIDATED STATEMENTS OF CASH
FLOWS(Unaudited)
|
Three Months Ended |
|
Nine Months Ended |
|
September 30, |
|
September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES |
(in millions) |
Net income (loss) |
$ |
81.0 |
|
|
$ |
7.3 |
|
|
$ |
13.1 |
|
|
$ |
(382.3 |
) |
Adjustments to reconcile net
income (loss) to net cash provided by (used in) operating
activities: |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
144.2 |
|
|
234.9 |
|
|
395.5 |
|
|
673.6 |
|
Deferred income taxes (benefit) |
26.5 |
|
|
0.9 |
|
|
(61.2 |
) |
|
(119.6 |
) |
Impairment |
— |
|
|
— |
|
|
5.0 |
|
|
404.4 |
|
Non-cash share-based compensation |
5.0 |
|
|
7.7 |
|
|
16.2 |
|
|
24.0 |
|
Amortization of debt issuance costs and discounts |
1.3 |
|
|
1.4 |
|
|
4.0 |
|
|
4.0 |
|
Net (gain) loss from asset sales, inclusive of restructuring
costs |
2.1 |
|
|
(27.1 |
) |
|
(2.5 |
) |
|
(26.7 |
) |
Unrealized (gains) losses on marketable securities |
(0.1 |
) |
|
(0.7 |
) |
|
(2.8 |
) |
|
(1.1 |
) |
Unrealized (gains) losses on derivative contracts |
(92.3 |
) |
|
69.6 |
|
|
29.0 |
|
|
113.2 |
|
Changes in operating assets and liabilities |
(21.4 |
) |
|
4.0 |
|
|
(54.3 |
) |
|
(14.6 |
) |
Net Cash Provided by (Used in) Operating Activities |
146.3 |
|
|
298.0 |
|
|
342.0 |
|
|
674.9 |
|
INVESTING
ACTIVITIES |
|
|
|
|
|
|
|
Property acquisitions |
(1.8 |
) |
|
(3.2 |
) |
|
(3.6 |
) |
|
(48.3 |
) |
Property, plant and equipment,
including exploratory well expense |
(148.4 |
) |
|
(267.8 |
) |
|
(465.2 |
) |
|
(1,032.1 |
) |
Proceeds from disposition of
assets |
9.8 |
|
|
168.7 |
|
|
676.5 |
|
|
217.5 |
|
Net Cash Provided by (Used in) Investing Activities |
(140.4 |
) |
|
(102.3 |
) |
|
207.7 |
|
|
(862.9 |
) |
FINANCING
ACTIVITIES |
|
|
|
|
|
|
|
Checks outstanding in excess
of cash balances |
(4.6 |
) |
|
6.8 |
|
|
(13.9 |
) |
|
(28.7 |
) |
Long-term debt issuance costs
paid |
— |
|
|
(0.1 |
) |
|
— |
|
|
(0.1 |
) |
Proceeds from credit
facility |
— |
|
|
586.5 |
|
|
56.0 |
|
|
2,616.0 |
|
Repayments of credit
facility |
— |
|
|
(786.0 |
) |
|
(486.0 |
) |
|
(2,329.5 |
) |
Common stock repurchased and
retired |
— |
|
|
— |
|
|
— |
|
|
(58.4 |
) |
Treasury stock
repurchases |
(0.7 |
) |
|
(1.9 |
) |
|
(7.0 |
) |
|
(7.8 |
) |
Dividends paid |
(4.8 |
) |
|
— |
|
|
(4.8 |
) |
|
— |
|
Other capital
contributions |
— |
|
|
0.1 |
|
|
— |
|
|
0.3 |
|
Net Cash Provided by (Used in) Financing Activities |
(10.1 |
) |
|
(194.6 |
) |
|
(455.7 |
) |
|
191.8 |
|
Change in cash, cash
equivalents and restricted cash |
(4.2 |
) |
|
1.1 |
|
|
94.0 |
|
|
3.8 |
|
Beginning cash, cash
equivalents and restricted cash |
126.3 |
|
|
26.1 |
|
|
28.1 |
|
|
23.4 |
|
Ending cash, cash equivalents
and restricted cash |
$ |
122.1 |
|
|
$ |
27.2 |
|
|
$ |
122.1 |
|
|
$ |
27.2 |
|
|
Production by Region |
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
2019 |
|
2018 |
|
Change |
|
2019 |
|
2018 |
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
(in Mboe) |
Northern Region |
|
|
|
|
|
|
|
|
|
|
|
Williston Basin |
2,722.5 |
|
|
4,381.1 |
|
|
(38 |
)% |
|
9,061.9 |
|
|
12,570.5 |
|
|
(28 |
)% |
Uinta Basin |
— |
|
|
606.0 |
|
|
(100 |
)% |
|
— |
|
|
2,232.2 |
|
|
(100 |
)% |
Other Northern |
19.4 |
|
|
63.1 |
|
|
(69 |
)% |
|
65.1 |
|
|
211.4 |
|
|
(69 |
)% |
Total Northern Region |
2,741.9 |
|
|
5,050.2 |
|
|
(46 |
)% |
|
9,127.0 |
|
|
15,014.1 |
|
|
(39 |
)% |
Southern Region |
|
|
|
|
|
|
|
|
|
|
|
Permian Basin |
5,658.5 |
|
|
4,792.5 |
|
|
18 |
% |
|
14,293.2 |
|
|
11,591.6 |
|
|
23 |
% |
Haynesville/Cotton Valley |
(0.4 |
) |
|
4,552.8 |
|
|
(100 |
)% |
|
310.5 |
|
|
13,604.6 |
|
|
(98 |
)% |
Other Southern |
4.0 |
|
|
4.5 |
|
|
(11 |
)% |
|
14.3 |
|
|
20.4 |
|
|
(30 |
)% |
Total Southern Region |
5,662.1 |
|
|
9,349.8 |
|
|
(39 |
)% |
|
14,618.0 |
|
|
25,216.6 |
|
|
(42 |
)% |
Total production |
8,404.0 |
|
|
14,400.0 |
|
|
(42 |
)% |
|
23,745.0 |
|
|
40,230.7 |
|
|
(41 |
)% |
|
Total Production |
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
Change |
|
2019 |
|
2018 |
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbl) |
5,670.5 |
|
|
6,640.5 |
|
|
(15 |
)% |
|
15,904.4 |
|
|
18,182.1 |
|
|
(13 |
)% |
Gas (Bcf) |
8.2 |
|
|
38.1 |
|
|
(78 |
)% |
|
24.6 |
|
|
111.5 |
|
|
(78 |
)% |
NGL (Mbbl) |
1,383.0 |
|
|
1,415.3 |
|
|
(2 |
)% |
|
3,747.8 |
|
|
3,472.5 |
|
|
8 |
% |
Total production (Mboe) |
8,404.0 |
|
|
14,400.0 |
|
|
(42 |
)% |
|
23,745.0 |
|
|
40,230.7 |
|
|
(41 |
)% |
Average daily production (Mboe) |
91.3 |
|
|
156.5 |
|
|
(42 |
)% |
|
87.0 |
|
|
147.4 |
|
|
(41 |
)% |
|
Prices |
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
Change |
|
2019 |
|
2018 |
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level price |
$ |
52.70 |
|
|
$ |
62.65 |
|
|
|
|
$ |
52.44 |
|
|
$ |
61.89 |
|
|
|
Commodity derivative impact |
(0.87 |
) |
|
(6.27 |
) |
|
|
|
(1.50 |
) |
|
(7.59 |
) |
|
|
Net realized price |
$ |
51.83 |
|
|
$ |
56.38 |
|
|
(8 |
)% |
|
$ |
50.94 |
|
|
$ |
54.30 |
|
|
(6 |
)% |
Gas (per
Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level price |
$ |
1.13 |
|
|
$ |
2.67 |
|
|
|
|
$ |
1.61 |
|
|
$ |
2.71 |
|
|
|
Commodity derivative impact |
— |
|
|
0.09 |
|
|
|
|
(0.12 |
) |
|
0.10 |
|
|
|
Net realized price |
$ |
1.13 |
|
|
$ |
2.76 |
|
|
(59 |
)% |
|
$ |
1.49 |
|
|
$ |
2.81 |
|
|
(47 |
)% |
NGL (per
bbl) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level price |
$ |
8.63 |
|
|
$ |
29.65 |
|
|
|
|
$ |
11.50 |
|
|
$ |
25.39 |
|
|
|
Commodity derivative impact |
— |
|
|
— |
|
|
|
|
— |
|
|
— |
|
|
|
Net realized price |
$ |
8.63 |
|
|
$ |
29.65 |
|
|
(71 |
)% |
|
$ |
11.50 |
|
|
$ |
25.39 |
|
|
(55 |
)% |
Average net equivalent
price (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
Average field-level equivalent price |
$ |
38.06 |
|
|
$ |
38.87 |
|
|
|
|
$ |
38.60 |
|
|
$ |
37.66 |
|
|
|
Commodity derivative impact |
(0.59 |
) |
|
(2.66 |
) |
|
|
|
(1.13 |
) |
|
(3.16 |
) |
|
|
Net realized equivalent price |
$ |
37.47 |
|
|
$ |
36.21 |
|
|
3 |
% |
|
$ |
37.47 |
|
|
$ |
34.50 |
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
Change |
|
2019 |
|
2018 |
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
Lease operating expense |
$ |
38.3 |
|
|
$ |
64.6 |
|
|
(41 |
)% |
|
$ |
135.5 |
|
|
$ |
203.6 |
|
|
(33 |
)% |
Adjusted transportation and
processing costs(1) |
32.2 |
|
|
43.8 |
|
|
(26 |
)% |
|
79.5 |
|
|
134.1 |
|
|
(41 |
)% |
Production and property
taxes |
20.0 |
|
|
37.4 |
|
|
(47 |
)% |
|
67.6 |
|
|
103.9 |
|
|
(35 |
)% |
Total production costs |
$ |
90.5 |
|
|
$ |
145.8 |
|
|
(38 |
)% |
|
$ |
282.6 |
|
|
$ |
441.6 |
|
|
(36 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(per Boe) |
Lease operating expense |
$ |
4.56 |
|
|
$ |
4.49 |
|
|
2 |
% |
|
$ |
5.71 |
|
|
$ |
5.06 |
|
|
13 |
% |
Adjusted transportation and
processing costs(1) |
3.83 |
|
|
3.04 |
|
|
26 |
% |
|
3.34 |
|
|
3.34 |
|
|
— |
% |
Production and property
taxes |
2.38 |
|
|
2.60 |
|
|
(8 |
)% |
|
2.85 |
|
|
2.58 |
|
|
10 |
% |
Total production costs |
$ |
10.77 |
|
|
$ |
10.13 |
|
|
6 |
% |
|
$ |
11.90 |
|
|
$ |
10.98 |
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________________________(1) Adjusted
transportation and processing costs is a non-GAAP measure. The
definition and reconciliation of adjusted transportation and
processing costs to transportation and processing costs, as
presented, are provided within Non-GAAP Measures at the end of this
release.
QEP RESOURCES, INC.NON-GAAP
MEASURES(Unaudited)
Adjusted EBITDA
This release contains references to the non-GAAP measure of
Adjusted EBITDA. Management defines Adjusted EBITDA as earnings
before interest, income taxes, depreciation, depletion and
amortization (EBITDA), adjusted to exclude changes in fair value of
derivative contracts, exploration expenses, gains and losses from
asset sales, impairment and certain other items. Management uses
Adjusted EBITDA to evaluate QEP’s financial performance and trends,
make operating decisions and allocate resources. Management
believes the measure is useful supplemental information for
investors because it eliminates the impact of certain nonrecurring,
non-cash and/or other items that management does not consider as
indicative of QEP’s performance from period to period. QEP’s
Adjusted EBITDA may be determined or calculated differently than
similarly titled measures of other companies in our industry, which
would reduce the usefulness of this non-GAAP financial measure when
comparing our performance to that of other companies.
Below is a reconciliation of Net Income (Loss) (the most
comparable GAAP measure) to Adjusted EBITDA. This non-GAAP measure
should be considered by the reader in addition to, but not instead
of, the financial measure prepared in accordance with GAAP.
|
Three Months Ended |
|
Nine Months Ended |
|
September 30, |
|
September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
Net income (loss) |
$ |
81.0 |
|
|
$ |
7.3 |
|
|
$ |
13.1 |
|
|
$ |
(382.3 |
) |
Interest expense |
32.8 |
|
|
38.7 |
|
|
100.0 |
|
|
111.9 |
|
Interest and other (income)
expense |
(0.9 |
) |
|
0.3 |
|
|
(4.6 |
) |
|
4.1 |
|
Income tax provision
(benefit) |
26.6 |
|
|
2.5 |
|
|
(55.7 |
) |
|
(117.6 |
) |
Depreciation, depletion and
amortization |
144.2 |
|
|
234.9 |
|
|
395.5 |
|
|
673.6 |
|
Unrealized (gains) losses on
derivative contracts |
(92.3 |
) |
|
69.6 |
|
|
29.0 |
|
|
113.2 |
|
Exploration expenses |
— |
|
|
— |
|
|
— |
|
|
0.1 |
|
Net (gain) loss from asset
sales, inclusive of restructuring costs |
2.1 |
|
|
(27.1 |
) |
|
(2.5 |
) |
|
(26.7 |
) |
Impairment |
— |
|
|
— |
|
|
5.0 |
|
|
404.4 |
|
Adjusted EBITDA |
$ |
193.5 |
|
|
$ |
326.2 |
|
|
$ |
479.8 |
|
|
$ |
780.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash Flow
This release contains references to non-GAAP measure of Free
Cash Flow.
The Company defines Free Cash Flow as Adjusted EBITDA plus
non-cash share-based compensation less cash interest expense,
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 pay dividends, repay debt or repurchase stock.
Below is a reconciliation of Net Cash Provided by (Used in)
Operating Activities (the most comparable GAAP measure) to Free
Cash Flow. 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 |
|
Nine Months
Ended |
|
September 30, |
|
September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
Cash
Flow Information: |
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities |
$ |
146.3 |
|
|
$ |
298.0 |
|
|
$ |
342.0 |
|
|
$ |
674.9 |
|
Net Cash
Provided by (Used in) Investing Activities |
(140.4 |
) |
|
(102.3 |
) |
|
207.7 |
|
|
(862.9 |
) |
Net Cash
Provided by (Used in) Financing Activities |
(10.1 |
) |
|
(194.6 |
) |
|
(455.7 |
) |
|
191.8 |
|
|
|
|
|
|
|
|
|
Free
Cash Flow |
|
|
|
|
|
|
|
Net Cash
Provided by (Used in) Operating Activities |
$ |
146.3 |
|
|
$ |
298.0 |
|
|
$ |
342.0 |
|
|
$ |
674.9 |
|
Amortization
of debt issuance costs and discounts |
(1.3 |
) |
|
(1.4 |
) |
|
(4.0 |
) |
|
(4.0 |
) |
Interest
expense |
32.8 |
|
|
38.7 |
|
|
100.0 |
|
|
111.9 |
|
Unrealized
gains (losses) on marketable securities |
0.1 |
|
|
0.7 |
|
|
2.8 |
|
|
1.1 |
|
Interest and
other (income) expense |
(0.9 |
) |
|
0.3 |
|
|
(4.6 |
) |
|
4.1 |
|
Deferred
income taxes |
(26.5 |
) |
|
(0.9 |
) |
|
61.2 |
|
|
119.6 |
|
Income tax
provision (benefit) |
26.6 |
|
|
2.5 |
|
|
(55.7 |
) |
|
(117.6 |
) |
Non-cash
share-based compensation |
(5.0 |
) |
|
(7.7 |
) |
|
(16.2 |
) |
|
(24.0 |
) |
Changes in
operating assets and liabilities |
21.4 |
|
|
(4.0 |
) |
|
54.3 |
|
|
14.7 |
|
Adjusted EBITDA |
193.5 |
|
|
326.2 |
|
|
479.8 |
|
|
780.7 |
|
Non-cash
share-based compensation |
5.0 |
|
|
7.7 |
|
|
16.2 |
|
|
24.0 |
|
Cash
interest expense |
(30.8 |
) |
|
(36.7 |
) |
|
(94.1 |
) |
|
(100.2 |
) |
Property
acquisitions |
(1.8 |
) |
|
(3.2 |
) |
|
(3.6 |
) |
|
(48.3 |
) |
Property,
plant and equipment, including exploratory well expense |
(148.4 |
) |
|
(267.8 |
) |
|
(465.2 |
) |
|
(1,032.1 |
) |
Free Cash Flow |
$ |
17.5 |
|
|
$ |
26.2 |
|
|
$ |
(66.9 |
) |
|
$ |
(375.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Slide 13 of our October 2019 Investor Presentation includes a
Free Cash Flow estimate for 2020 and relative sensitivity analysis.
We are unable, however, to prove a quantitative reconciliation of
the forward-looking non-GAAP measure to its most directly
comparable forward-looking GAAP measure because management cannot
reliably quantify certain of the necessary components of such
forward-looking GAAP measure. The reconciling items in future
periods could be significant.
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 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) (the most
comparable 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 measure prepared in accordance
with GAAP.
|
Three Months EndedSeptember 30, |
|
Nine Months EndedSeptember 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except
earnings per share) |
Net income (loss) |
$ |
81.0 |
|
|
$ |
7.3 |
|
|
$ |
13.1 |
|
|
$ |
(382.3 |
) |
Adjustments
to net income (loss) |
|
|
|
|
|
|
|
Unrealized (gains) losses on derivative contracts |
(92.3 |
) |
|
69.6 |
|
|
29.0 |
|
|
113.2 |
|
Income taxes on unrealized (gains) losses on derivative
contracts(1) |
20.7 |
|
|
(16.6 |
) |
|
(37.9 |
) |
|
(26.6 |
) |
Net (gain) loss from asset sales, inclusive of restructuring
costs |
2.1 |
|
|
(27.1 |
) |
|
(2.5 |
) |
|
(26.7 |
) |
Income taxes on net (gain) loss from asset sales, inclusive of
restructuring costs(1) |
(0.5 |
) |
|
6.4 |
|
|
3.3 |
|
|
6.3 |
|
Impairment |
— |
|
|
— |
|
|
5 |
|
|
404.4 |
|
Income taxes on impairment(1) |
— |
|
|
— |
|
|
(6.5 |
) |
|
(95.0 |
) |
Total after
tax adjustments to net income |
(70.0 |
) |
|
32.3 |
|
|
(9.6 |
) |
|
375.6 |
|
Adjusted Net
Income (Loss) |
$ |
11.0 |
|
|
$ |
39.6 |
|
|
$ |
3.5 |
|
|
$ |
(6.7 |
) |
|
|
|
|
|
|
|
|
Earnings
(Loss) per Common Share |
|
|
|
|
|
|
|
Diluted earnings per share |
$ |
0.34 |
|
|
$ |
0.03 |
|
|
$ |
0.06 |
|
|
$ |
(1.60 |
) |
Diluted after-tax adjustments to net income (loss) per share |
(0.29 |
) |
|
0.14 |
|
|
(0.04 |
) |
|
1.58 |
|
Diluted Adjusted Net Income per share |
$ |
0.05 |
|
|
$ |
0.17 |
|
|
$ |
0.02 |
|
|
$ |
(0.02 |
) |
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
|
|
|
|
|
Diluted |
237.9 |
|
|
237.0 |
|
|
237.7 |
|
|
238.3 |
|
____________________________
(1) Income tax impact of adjustments is
calculated using QEP’s statutory rate of 22.4% and 23.8% for the
three months ended September 30, 2019 and 2018, respectively
and QEP's effective tax rate of 130.8% and 23.5% for the nine
months ended September 30, 2019 and 2018, respectively.
Adjusted Transportation and Processing
Costs
This release contains references to the non-GAAP measure of
Adjusted Transportation and Processing Costs. Management defines
Adjusted Transportation and Processing Costs as transportation and
processing costs presented on the Condensed Consolidated Statements
of Operations and transportation and processing costs that are
included as part of "Oil and condensate, gas and NGL sales" on the
Condensed Consolidated Statements of Operations. These costs are
added together to reflect the total 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
(the most comparable 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 September 30, |
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
Change |
|
2019 |
|
2018 |
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
Transportation and processing costs, as presented |
$ |
18.0 |
|
|
$ |
28.0 |
|
|
$ |
(10.0 |
) |
|
$ |
38.8 |
|
|
$ |
93.2 |
|
|
$ |
(54.4 |
) |
Transportation and processing costs deducted from oil and
condensate, gas and NGL sales |
14.2 |
|
|
15.8 |
|
|
(1.6 |
) |
|
40.7 |
|
|
40.9 |
|
|
(0.2 |
) |
Adjusted transportation and processing costs |
$ |
32.2 |
|
|
$ |
43.8 |
|
|
$ |
(11.6 |
) |
|
$ |
79.5 |
|
|
$ |
134.1 |
|
|
$ |
(54.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(per Boe) |
Transportation and processing costs, as presented |
$ |
2.14 |
|
|
$ |
1.94 |
|
|
$ |
0.2 |
|
|
$ |
1.63 |
|
|
$ |
2.32 |
|
|
$ |
(0.69 |
) |
Transportation and processing costs deducted from oil and
condensate, gas and NGL sales |
1.69 |
|
|
1.1 |
|
|
0.59 |
|
|
1.71 |
|
|
1.02 |
|
|
0.69 |
|
Adjusted transportation and processing costs |
$ |
3.83 |
|
|
$ |
3.04 |
|
|
$ |
0.79 |
|
|
$ |
3.34 |
|
|
$ |
3.34 |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 Updated Guidance includes a Lease operating expense and
Adjusted Transportation and Processing Costs estimate for 2019. We
are unable, however, to prove a quantitative reconciliation of the
Adjusted Transportation and Processing Costs forward-looking
non-GAAP measure to its most directly comparable forward-looking
GAAP measure because management cannot reliably quantify certain of
the necessary components of such forward-looking GAAP measure. The
reconciling items in future periods could be significant.
The following tables present QEP's volumes and average prices
for its open derivative positions as of October 18, 2019:
Production
Commodity Derivative Swaps |
Year |
|
Index |
|
Total Volumes |
|
Average Swap Priceper Unit |
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2019 |
|
NYMEX WTI |
|
3.6 |
|
|
$ |
55.44 |
|
2019 |
|
ICE
Brent |
|
0.5 |
|
|
$ |
66.73 |
|
2019 |
|
Argus WTI
Midland |
|
0.2 |
|
|
$ |
54.6 |
|
2019 |
|
Argus WTI
Houston |
|
0.1 |
|
|
$ |
65.7 |
|
2020 |
|
NYMEX
WTI |
|
11.3 |
|
|
$ |
58.29 |
|
2020 |
|
Argus WTI
Midland |
|
1.5 |
|
|
$ |
57.3 |
|
2020 (January - June) |
|
Argus WTI
Houston |
|
1.0 |
|
|
$ |
60.06 |
|
Production
Commodity Derivative Basis Swaps |
Year |
|
Index |
|
Basis |
|
Total Volumes |
|
Weighted-AverageDifferential |
|
|
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
|
|
(bbls) |
|
|
|
($/bbl) |
|
2019 |
|
NYMEX WTI |
|
Argus WTI Midland |
|
1.7 |
|
|
$ |
(2.22 |
) |
2019 |
|
NYMEX
WTI |
|
Argus WTI
Houston |
|
0.5 |
|
|
$ |
3.69 |
|
2020 |
|
NYMEX
WTI |
|
Argus WTI
Midland |
|
6.6 |
|
|
$ |
0.17 |
|
2020 (January - June) |
|
NYMEX
WTI |
|
Argus WTI
Houston |
|
0.4 |
|
|
$ |
3.75 |
|
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