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QEP REPORTS FOURTH QUARTER AND FULL YEAR 2019 FINANCIAL AND OPERATING RESULTS AND
PROVIDES INITIAL 2020 GUIDANCE AND CAPITAL INVESTMENT PLAN

DENVER February 26, 2020 — QEP Resources, Inc. (NYSE: QEP) (QEP or the Company) today reported fourth quarter and full year 2019 financial and operating results and provided initial 2020 guidance and capital investment plan.

FULL YEAR 2019 HIGHLIGHTS

Delivered equivalent production 11% above and capital investment 11% below the midpoint of original 2019 guidance
Lowered drilling, completion, and equipment costs in the Permian Basin by $2.0 million per well
Reduced General & Administrative (G&A) expense by approximately 30% from 2018 to 2019
Decreased officer headcount by 54%, which resulted in a $10 million reduction to target officer compensation
Generated $566.9 million of Net Cash Provided from Operating Activities
Retired $66.9 million of debt and ended the year with a $166.3 million cash balance

FULL YEAR 2020 OUTLOOK & OVERVIEW

Plan to deliver 4% oil growth in the Permian Basin, while reducing the Permian capital program by approximately 8%
Completed G&A expense reduction initiatives, which delivers a 40% reduction to G&A expense compared to 2019
Plan to generate approximately $100 million of Free Cash Flow (a non-GAAP measure) at $50 WTI
76% of forecasted 2020 oil production hedged at approximately $58 per barrel
Continue to organically de-lever balance sheet

"2019 was a year of significant change for QEP. We were intensely focused throughout the year on right-sizing our corporate overhead, improving capital efficiency and reducing operating expenses in the field. Our focus resulted in QEP essentially being Free Cash Flow neutral for the full year 2019 as we prioritize profitability and financial discipline over production growth," commented Tim Cutt, President and CEO of QEP.

"Our highly efficient capital investment program in 2020, along with the reduced corporate G&A and operating cost structure, provides us confidence in our ability to generate approximately $100 million of Free Cash Flow at $50 WTI in 2020. Our robust hedge position, 76% of forecasted 2020 oil production at approximately $58 per barrel, creates a solid floor to achieve our financial goals. Through the efforts of our top tier employee base, QEP is in a strong position to build cash in 2020, which supports our corporate goal of organically de-levering our balance sheet and returning capital to shareholders."

1


OPERATIONS UPDATE


For the full year 2019 the Company drilled a total of 76 horizontal wells, including 69 in the Permian Basin and seven in the Williston Basin, and turned 66 operated wells to production, including 59 in the Permian Basin and seven in the Williston Basin. The average lateral length for the wells completed in the Permian Basin in 2019 was 10,205 feet and the average lateral length for the wells completed in the Williston Basin in 2019 was 10,182 feet.

Oil equivalent production in the Permian Basin was 5.1 million barrels of oil equivalent (MMboe) in the fourth quarter 2019, an increase of 17% over the fourth quarter 2018. The increase was a result of putting new wells on production, coupled with
improved well performance, which was attributable to changes in well completion design, accelerated flowback and improved artificial lift, and higher gas capture rates. Total Company oil equivalent production was 8.5 MMboe in the fourth quarter 2019, a decrease of 27% compared with the fourth quarter 2018, primarily driven by the divestiture of our Haynesville assets in January 2019 (Haynesville Divestiture).

Oil and condensate production in the Permian Basin was 3.4 million barrels (MMbbl) in the fourth quarter 2019, an increase of 4% over the fourth quarter 2018. Total Company oil and condensate production was 5.7 MMbbl in the fourth quarter 2019, and was essentially flat compared with the fourth quarter 2018. The relatively flat production was the result of an increase in volumes in the Permian Basin, offset by lower Williston Basin volumes due to reduced activity.

For the full year 2019, oil equivalent production in the Permian Basin was 19.4 MMboe, an increase of 22% compared with the full year 2018. The increase was a result of improved well performance on the 69 wells placed on production in 2019 which was attributable to changes in well completion design, accelerated flowback and improved artificial lift, and higher gas capture rates. For the full year 2019, total Company oil equivalent production was 32.2 MMboe, a decrease of 19.7 MMboe compared with the full year 2018, primarily driven by the Haynesville Divestiture and Uinta Basin divestiture in September 2018.

For the full year 2019, oil and condensate production in the Permian Basin was 13.5 MMbbl, an increase of 1.4 MMbbl, or 11%, compared with 2018. For the full year 2019, total Company oil and condensate production was 21.6 MMbbl, a decrease of 2.4 MMbbl compared with the full year 2018, primarily driven by decreased activity in the Williston Basin and the Uinta Basin divestiture.

FINANCIAL UPDATE


The Company reported a net loss of $110.4 million in the fourth quarter 2019, or $0.46 per diluted share, compared with a loss of $629.3 million, or $2.66 per diluted share, in the fourth quarter 2018. The lower net loss in the fourth quarter 2019 was primarily due to a decrease in impairment expense of $1,156.5 million partially offset by a $448.3 million decrease in gain on derivative contracts and a $212.5 million increase in income tax expense.

Net income (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 2019 Adjusted Net Loss (a non-GAAP measure) was $25.9 million, or $0.10 per diluted share, compared with an Adjusted Net Loss of $29.6 million, or $0.13 per diluted share, in the fourth quarter 2018.

Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2019 was $183.8 million compared with $194.1 million in the fourth quarter 2018, a 5% decrease. The decrease was primarily due to the Haynesville Divestiture, partially offset by a $26.1 million decrease in general and administrative expense and a $22.8 million decrease in realized derivative losses.

The definitions and reconciliations of Adjusted Net Income (Loss) and Adjusted EBITDA are provided under the heading Non-GAAP Measures at the end of this release.

Capital Investment


2


Capital investment, excluding property acquisitions, was $105.5 million (on an accrual basis) for the fourth quarter 2019, compared with $188.4 million for the fourth quarter 2018, of which $102.6 million related to the drilling, completion and equipping of wells and $2.9 million related to midstream infrastructure investment. The decrease in capital expenditures was primarily related to a planned decrease in completion activity in the Permian Basin due to a change in our corporate strategy in 2019 to focus on Free Cash Flow generation, partially offset by increased capital expenditures in the Williston Basin as the Company resumed completion activity in the basin.

Total capital investment, excluding property acquisitions, was $571.5 million (on an accrual basis) for the year ended December 31, 2019, compared with $1,053.5 million for the year ended December 31, 2018 (excluding $123.1 million of capital expenditures related to Haynesville and Uinta in 2018), a reduction of $482.0 million. The decrease in capital expenditures was primarily related to decreased drilling and completion activity in the Permian and Williston basins due to a change in our corporate strategy.

Operating Expenses

During the fourth quarter 2019, lease operating expense (LOE) was $47.4 million, a decrease of 20% compared with the fourth quarter 2018. The decrease in LOE was primarily due to the Haynesville Divestiture and a decrease in the Williston Basin related to lower maintenance and repair expenses, labor costs, and power, fuel and chemicals as a result of continuing efforts to reduce operating expenses and decreased production activity.

During the fourth quarter 2019, LOE was $5.60 per Boe, an increase of 10% compared to the fourth quarter 2018, but was down 12% excluding the Haynesville Divestiture. The 12% 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 fourth quarter 2019, Transportation and Processing (T&P) Costs were $9.9 million, a decrease of 59% compared with the fourth quarter 2018. Adjusted T&P costs (a non-GAAP measure) were $24.1 million, a decrease of 37% compared with the fourth quarter 2018. The decrease in Adjusted T&P was primarily due to the Haynesville Divestiture. Excluding the Haynesville Divestiture, Adjusted T&P costs decreased due to lower production in the Williston Basin, partially offset by increased production in the Permian Basin.

During the fourth quarter 2019, T&P costs decreased by $0.93 per Boe, or 44%, compared to the fourth quarter 2018. Adjusted T&P Costs decreased by $0.46 per Boe, or 14%, compared with the fourth quarter 2018 primarily due to the Haynesville divestiture. Excluding the Haynesville divestiture, Adjusted T&P costs per Boe decreased by 10%, primarily due to an increase in production in the Permian Basin.

The definition and reconciliation of Adjusted Transportation and Processing Costs is provided under the heading Non-GAAP Measures at the end of this release.


3


During the fourth quarter 2019, general and administrative (G&A) expense was $31.4 million, a decrease of 45% in the fourth quarter 2019 compared with the fourth quarter 2018. During the fourth quarter 2019 and 2018, QEP incurred $6.9 million and $24.3 million, respectively, in costs associated with the implementation of our strategic initiatives. Excluding these costs, G&A expense decreased $8.8 million, or 26%, primarily due to a $6.7 million decrease in workforce related costs from the reduction in our workforce.

Liquidity

Net Cash Provided by Operating Activities for the fourth quarter 2019 was $224.9 million, compared with $141.1 million for the fourth quarter 2018.

The Company generated Free Cash Flow of $56.2 million for the fourth quarter 2019 compared with Free Cash Flow outspend of $23.6 million in fourth quarter 2018, an improvement of $79.8 million. The improvement was primarily due to an $82.9 million decrease in accrued capital investment, and a $9.4 million decrease in interest expense, excluding amortization of debt issuance costs and discounts, which were partially offset by lower Adjusted EBITDA of $10.3 million.

Net Cash Provided by Operating Activities for the full year 2019 was $566.9 million, compared with $816.2 million for the full year 2018.

For the full year 2019, the Company had Free Cash Flow outspend of $9.8 million, compared with and outspend of $314.9 million during 2018, an improvement of $305.1 million. The improvement was primarily due to a $605.1 million decrease in accrued capital investment, a $21.3 million decrease in interest expense, excluding amortization of debt issuance costs and discounts, and a $10.1 million decrease in non-cash, share-based compensation, which were offset by lower Adjusted EBITDA of $311.2 million.

During the fourth quarter 2019, QEP redeemed all $51.7 million of its outstanding 6.80% Senior Notes due March
2020 and repurchased $15.2 million of its 6.875% Senior Notes due March 2021.

As of December 31, 2019, QEP had $166.3 million in cash and cash equivalents, no borrowings under its revolving credit facility and $2.9 million in letters of credit outstanding under its credit facility. The Company estimates that, as of December 31, 2019, the maximum allowable total debt (sum of senior notes and credit facility) to remain in compliance with the covenants under its credit facility was approximately $2,550 million.

The definition and reconciliation of Free Cash Flow is provided under the heading Non-GAAP Measures at the end of this release.

GUIDANCE


QEP's first quarter and full year 2020 guidance assumes: (i) a WTI NYMEX an oil price of $55 per barrel and a natural gas price of $2.50 per MMBtu at Henry Hub, adjusted for applicable commodity and location differentials, (ii) that QEP will elect to recover ethane from its produced gas in the Permian Basin where processing economics support it, (iii) no property acquisitions or divestitures, and (iv) no impacts from a potential monetization of the Permian Basin water asset.



4


Rig Count

Permian Basin: two rigs for 2020, supported by a smaller rig drilling to intermediate depth for a portion of the year
Williston Basin: one rig arriving in the first quarter 2020 to drill six gross operated wells

Wells Put on Production:

Permian Basin: approximately 65 net operated wells
Williston Basin: approximately four net operated wells and eight net refracs

2020 Guidance
 
 
1Q 2020
2020
 
Guidance
Guidance
Oil & condensate production (MMbbl)
5.0 - 5.1
21.35 - 22.45
Gas production (Bcf)
8.2 - 8.5
31.0 - 34.0
NGL production (MMbbl)
1.3 - 1.4
5.0 - 5.6
Total oil equivalent production (MMboe)
7.6 - 7.9
31.5 - 33.7
 
 
 
Lease operating expense (per Boe)
 
$5.20 - $5.80
Adjusted Transportation and Processing Costs (per Boe)(1)
 
$3.30 - $3.60
Depletion, depreciation and amortization (per Boe)
 
$17.75 - $18.75
Production and property taxes (% of field-level revenue)
 
7.5%
(in millions)
 
General and administrative expense(2)
 
$85.0 - $95.0
 
 
 
Capital investment (excluding property acquisitions)
 
 
Drilling, Completion and Equip(3)
 
$520.0 - $565.0
Midstream infrastructure(4)
 
$20.0 - $25.0
Corporate
 
$5.0
Total capital investment (excluding property acquisitions)
$180 - $195.0
$545.0 - $595.0
 
 
 
Wells put on production (net)
21
69
Refracs put on production (net)
0
8
____________________________
(1)  
Adjusted Transportation and Processing Costs (per Boe) is a non-GAAP measure. Refer to the definitions and reconciliations of
Non-GAAP Measures at the end of this release.
(2) 
The mid-point of general and administrative expense includes approximately $13 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) 
Drilling, Completion and Equipment includes approximately $35 million of non-operated well costs.
(4) 
Includes capital expenditures in the Permian Basin associated with (i) water sourcing, gathering, recycling and disposal and (ii) crude oil and natural gas gathering system.



5


COMMODITY DERIVATIVES


The following tables present QEP's volumes and average prices for its open derivative positions as of
February 14, 2020
:

Production Commodity Derivative Swaps
Year
 
Index
 
Total Volumes
 
Average Swap Price per Unit
 
 
 
 
(in millions)
 
 
Oil sales
 
 
 
(bbls)

 
($/bbl)

2020
 
NYMEX WTI
 
13.0

 
$
57.81

2020
 
Argus WTI Midland
 
1.3

 
$
57.30

2020
 
Argus WTI Houston
 
0.8

 
$
60.06

2021
 
NYMEX WTI
 
1.6

 
$
55.04


Production Commodity Derivative Basis Swaps
Year
 
Index
 
Basis
 
Total Volumes
 
Weighted-Average Differential
 
 
 
 
 
 
(in millions)
 
 
Oil sales
 
 
 
 
 
(bbls)

 
($/bbl)

2020
 
NYMEX WTI
 
Argus WTI Midland
 
6.2

 
$
0.19

2020
 
NYMEX WTI
 
Argus WTI Houston
 
0.3

 
$
3.75

2021
 
NYMEX WTI
 
Argus WTI Midland
 
4.4

 
$
0.99



6


ESTIMATED PROVED RESERVES
At December 31, 2019, QEP's estimated proved reserves were approximately 382.3 MMboe, a 42% decrease compared with 2018, primarily due to the Haynesville Divestiture and a $992.2 million reduction in future estimated capital expenditures over the next five years in the Permian and Williston basins. The reduction in capital expenditures is due to QEP’s change in corporate strategy in 2019 to focus on Free Cash Flow generation through a reduced capital program and a renewed focus on capital efficiency. The change in development plan, including the updated development sequencing, along with the reduced capital program and lower oil prices, were the primary causes of the 107.3 MMboe negative revisions to previous estimates in reserves. The 107.3 MMboe negative revision is partially offset by extensions and discoveries of 47.6 MMboe, primarily related to new PUD locations from the change in our development sequence to maximize capital efficiency. The majority of the locations that were removed are economic at current prices and are technically consistent with our PUDs; however, they no longer conform to the SEC’s definition of proved reserves under the five year rule and are therefore not reported as PUDs. Approximately 84% of total proved reserves at year-end 2019 and 62% of total proved reserves at year-end 2018 were crude oil and NGL. Proved developed reserves were 190.4 MMboe, or 50%, of total estimated proved reserves at year-end 2019.

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, 2018
339.1

 
1,487.6

 
71.2

 
658.2

Revisions of previous estimates
(94.9
)
 
(23.0
)
 
(8.7
)
 
(107.3
)
Extensions and discoveries
33.6

 
40.0

 
7.4

 
47.6

Purchase of reserves in place
3.6

 
4.0

 
0.7

 
4.9

Sale of reserves in place
(4.9
)
 
(1,102.2
)
 
(0.3
)
 
(188.9
)
Production
(21.6
)
 
(33.1
)
 
(5.1
)
 
(32.2
)
Balance at December 31, 2019
254.9

 
373.3

 
65.2

 
382.3

____________________________
(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.


7


Details on the reported quantities of estimated year-end 2019 and 2018 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, 2019
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
Williston Basin
116.0

 
30
%
 
25
%
 
81
%
Uinta Basin

 
%
 
%
 
%
Other Northern

 
%
 
%
 
%
Southern Region
 
 

 
 
 
 
Permian Basin
266.3

 
70
%
 
61
%
 
85
%
Haynesville/Cotton Valley

 
%
 
%
 
%
Other Southern

 
%
 
%
 
%
Total proved reserves
382.3

 
100
%
 
50
%
 
84
%
 
 
 
 
 
 
 
 
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
%


8


Fourth Quarter and Full Year 2019 Results Conference Call


QEP's management will discuss fourth quarter and full year 2019 results in a conference call on Thursday, February 27, 2020, 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, 2020, 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 #13698628. In addition, QEP’s slides for the fourth 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.


9


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: expected production growth in the Permian Basin, reducing G&A expense, generating free cash flow in 2020, de-levering our balance sheet, returning capital to shareholders, ; underlying assumptions for first quarter and full year 2020 guidance, the number and location of drilling rigs to be deployed and wells to be put on production; first quarter and full year forecasted production amounts and related assumptions; forecasted lease operating expense, Adjusted Transportation and Processing Costs, depletion, depreciation and amortization expense, general and administrative expense, non-cash share-based compensation expense, production and property taxes, and capital investment for 2020 and related assumptions for such guidance; allocation of capital investment; 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, 2019. 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.

Contact
Investors/Media:
 
William I. Kent, IRC
 
Director, Investor Relations
 
303-405-6665
 


10


QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
 
Three Months Ended
 
Year Ended
 
December 31,
 
December 31,
 
2019
 
2018
 
2019
 
2018
REVENUES
(in millions, except per share amounts)
Oil and condensate, gas and NGL sales
$
311.6

 
$
397.2

 
$
1,187.4

 
$
1,871.3

Other revenues
0.8

 
0.7

 
7.9

 
12.5

Purchased oil and gas sales
9.5

 
12.6

 
10.9

 
48.8

Total Revenues
321.9

 
410.5

 
1,206.2

 
1,932.6

OPERATING EXPENSES
 
 
 
 
 
 
 
Purchased oil and gas expense
9.5

 
12.4

 
11.0

 
51.0

Lease operating expense
47.4

 
59.5

 
182.9

 
263.1

Transportation and processing costs
9.9

 
24.4

 
48.7

 
117.6

Gathering and other expense
3.3

 
4.7

 
13.2

 
15.5

General and administrative
31.4

 
57.5

 
155.8

 
221.7

Production and property taxes
28.3

 
26.9

 
95.9

 
130.8

Depreciation, depletion and amortization
144.5

 
183.5

 
540.0

 
857.1

Exploration expenses
0.1

 
0.2

 
0.1

 
0.3

Impairment

 
1,156.5

 
5.0

 
1,560.9

Total Operating Expenses
274.4

 
1,525.6

 
1,052.6

 
3,218.0

Net gain (loss) from asset sales, inclusive of restructuring costs
1.4

 
(1.7
)
 
3.9

 
25.0

OPERATING INCOME (LOSS)
48.9

 
(1,116.8
)
 
157.5

 
(1,260.4
)
Realized and unrealized gains (losses) on derivative contracts
(117.6
)
 
330.7

 
(173.4
)
 
90.4

Interest and other income (expense)
0.1

 
(5.5
)
 
4.7

 
(9.6
)
Loss from early extinguishment of debt
(1.0
)
 

 
(1.0
)
 

Interest expense
(28.1
)
 
(37.5
)
 
(128.1
)
 
(149.4
)
INCOME (LOSS) BEFORE INCOME TAXES
(97.7
)
 
(829.1
)
 
(140.3
)
 
(1,329.0
)
Income tax (provision) benefit
(12.7
)
 
199.8

 
43.0

 
317.4

NET INCOME (LOSS)
$
(110.4
)
 
$
(629.3
)
 
$
(97.3
)
 
$
(1,011.6
)
 
 
 
 
 
 
 
 
Earnings (loss) per common share
 
 
 
 
 
 
 
Basic
$
(0.46
)
 
$
(2.66
)
 
$
(0.41
)
 
$
(4.25
)
Diluted
$
(0.46
)
 
$
(2.66
)
 
$
(0.41
)
 
$
(4.25
)
 
 
 
 
 
 
 
 
Weighted-average common shares outstanding
 
 
 
 
 
 
 
Used in basic calculation
237.8

 
236.7

 
237.7

 
237.9

Used in diluted calculation
237.8

 
236.7

 
237.7

 
237.9


11


QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
 
December 31,
2019
 
December 31,
2018
ASSETS
(in millions)
Current Assets
 
 
 
Cash and cash equivalents
$
166.3

 
$

Accounts receivable, net
108.4

 
104.3

Income tax receivable
37.4

 
75.9

Fair value of derivative contracts
1.5

 
87.5

Prepaid expenses
11.4

 
12.7

Other current assets
0.2

 
0.2

Total Current Assets
325.2

 
280.6

Property, Plant and Equipment (successful efforts method for oil and gas properties)
 
 

Proved properties
9,574.9

 
9,096.9

Unproved properties
599.1

 
705.5

Gathering and other
164.2

 
167.7

Materials and supplies
15.6

 
29.9

Total Property, Plant and Equipment
10,353.8

 
10,000.0

Less Accumulated Depreciation, Depletion and Amortization
 

 
 

Exploration and production
5,250.5

 
4,882.4

Gathering and other
61.0

 
58.1

Total Accumulated Depreciation, Depletion and Amortization
5,311.5

 
4,940.5

Net Property, Plant and Equipment
5,042.3

 
5,059.5

Fair value of derivative contracts
0.2

 
35.4

Operating lease right-of-use assets, net
56.8

 

Other noncurrent assets
53.3

 
49.6

Noncurrent assets held for sale

 
692.7

TOTAL ASSETS
$
5,477.8

 
$
6,117.8

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
 
 
Checks outstanding in excess of cash balances
$
18.3

 
$
14.6

Accounts payable and accrued expenses
227.2

 
258.1

Production and property taxes
18.9

 
24.1

Interest payable
31.0

 
32.4

Fair value of derivative contracts
18.7

 

Current operating lease liabilities
18.0

 

Asset retirement obligations
6.0

 
5.1

Total Current Liabilities
338.1

 
334.3

Long-term debt
2,015.6

 
2,507.1

Deferred income taxes
274.5

 
269.2

Asset retirement obligations
94.9

 
96.9

Fair value of derivative contracts
0.5

 
0.7

Operating lease liabilities
44.8

 

Other long-term liabilities
48.8

 
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 - 4.4 million and 3.1 million shares, respectively
(55.4
)
 
(45.6
)
Additional paid-in capital
1,456.5

 
1,431.9

Retained earnings
1,269.6

 
1,376.5

Accumulated other comprehensive income (loss)
(12.5
)
 
(14.3
)
Total Common Shareholders' Equity
2,660.6

 
2,750.9

TOTAL LIABILITIES AND EQUITY
$
5,477.8


$
6,117.8


12


QEP RESOURCES, INC.
CONSOLIDATED CASH FLOWS
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2019
 
2018
 
2019
 
2018
OPERATING ACTIVITIES
(in millions)
Net income (loss)
$
(110.4
)
 
$
(629.3
)
 
$
(97.3
)
 
$
(1,011.6
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization
144.5

 
183.5

 
540.0

 
857.1

Deferred income taxes
65.5

 
(128.0
)
 
4.3

 
(247.6
)
Impairment

 
1,156.5

 
5.0

 
1,560.9

Non-cash share-based compensation
4.6

 
6.8

 
20.8

 
30.9

Amortization of debt issuance costs and discounts
1.4

 
1.4

 
5.4

 
5.4

Net (gain) loss from asset sales, inclusive of restructuring costs
(1.4
)
 
1.7

 
(3.9
)
 
(25.0
)
Loss from early extinguishment of debt
1.0

 

 
1.0

 

Unrealized (gains) losses on marketable securities
(1.1
)
 
2.3

 
(3.9
)
 
1.2

Unrealized (gains) losses on derivative contracts
109.3

 
(361.7
)
 
138.3

 
(248.5
)
Changes in operating assets and liabilities
11.5

 
(92.1
)
 
(42.8
)
 
(106.6
)
Net Cash Provided by (Used in) Operating Activities
224.9


141.1

 
566.9

 
816.2

INVESTING ACTIVITIES
 
 
 
 
 
 
 
Property acquisitions
0.1

 
(17.3
)
 
(3.5
)
 
(65.6
)
Property, plant and equipment
(97.5
)
 
(202.0
)
 
(562.7
)
 
(1,234.1
)
Proceeds from disposition of assets
2.4

 
26.1

 
678.9

 
243.6

Net Cash Provided by (Used in) Investing Activities
(95.0
)
 
(193.2
)
 
112.7

 
(1,056.1
)
FINANCING ACTIVITIES
 
 
 
 
 
 
 

Checks outstanding in excess of cash balances
17.6

 
(0.8
)
 
3.7

 
(29.5
)
Long-term debt issued

 

 

 

Long-term debt issuance costs paid

 

 

 
(0.1
)
Long-term debt extinguishment costs paid
(1.0
)
 

 
(1.0
)
 

Long-term debt repaid
(66.9
)
 

 
(66.9
)
 

Proceeds from credit facility
0.1

 
992.0

 
56.1

 
3,608.0

Repayments of credit facility

 
(937.5
)
 
(486.0
)
 
(3,267.0
)
Common stock repurchased and retired

 

 

 
(58.4
)
Treasury stock repurchases
(0.6
)
 
(0.9
)
 
(7.6
)
 
(8.7
)
Dividends paid
(4.8
)
 

 
(9.6
)
 

Other capital contributions

 

 

 
0.3

Net Cash Provided by (Used in) Financing Activities
(55.6
)
 
52.8

 
(511.3
)
 
244.6

Change in cash, cash equivalents and restricted cash
74.3

 
0.7

 
168.3

 
4.7

Beginning cash, cash equivalents and restricted cash
122.1

 
27.4

 
28.1

 
23.4

Ending cash, cash equivalents and restricted cash
$
196.4

 
$
28.1

 
$
196.4

 
$
28.1



13


 
Production by Region
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2019

2018

Change

2019

2018

Change
 
(in Mboe)
Northern Region
 
 
 
 
 
 
 
 
 
 
 
Williston Basin
3,341.9

 
3,760.8

 
(11
)%
 
12,403.8

 
16,331.3

 
(24
)%
Uinta Basin

 
11.3

 
(100
)%
 

 
2,243.5

 
(100
)%
Other Northern
6.5

 
35.7

 
(82
)%
 
71.6

 
247.1

 
(71
)%
Total Northern Region
3,348.4

 
3,807.8

 
(12
)%
 
12,475.4

 
18,821.9

 
(34
)%
Southern Region
 
 
 
 
 
 
 
 
 
 
 
Permian Basin
5,113.4

 
4,368.7

 
17
 %
 
19,406.6

 
15,960.3

 
22
 %
Haynesville/Cotton Valley

 
3,445.9

 
(100
)%
 
310.5

 
17,050.5

 
(98
)%
Other Southern
3.5

 
4.8

 
(27
)%
 
17.8

 
25.2

 
(29
)%
Total Southern Region
5,116.9

 
7,819.4

 
(35
)%
 
19,734.9

 
33,036.0

 
(40
)%
Total production
8,465.3

 
11,627.2

 
(27
)%
 
32,210.3

 
51,857.9

 
(38
)%

 
Total Production
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Oil and condensate (Mbbl)
5,653.9

 
5,749.9

 
(2
)%
 
21,558.3

 
23,932.0

 
(10
)%
Gas (Bcf)
8.5

 
28.1

 
(70
)%
 
33.1

 
139.6

 
(76
)%
NGL (Mbbl)
1,391.2

 
1,188.9

 
17
 %
 
5,139.0

 
4,661.4

 
10
 %
Total equivalent production (Mboe)
8,465.3

 
11,627.2

 
(27
)%
 
32,210.3

 
51,857.9

 
(38
)%
Average daily production (Mboe)
92.0

 
126.4

 
(27
)%
 
88.2

 
142.1

 
(38
)%

 
Prices
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Oil (per bbl)
 
 
 
 
 
 
 
 
 
 
 
Average field-level price
$
52.83

 
$
51.67

 
 
 
$
52.54

 
$
59.43

 
 
Commodity derivative impact
(1.47
)
 
(2.69
)
 
 
 
(1.50
)
 
(6.41
)
 
 
Net realized price
$
51.36

 
$
48.98

 
5
 %
 
$
51.04

 
$
53.02

 
(4
)%
Gas (per Mcf)
 
 
 
 
 
 
 
 
 
 
 
Average field-level price
$
1.53

 
$
3.25

 
 
 
$
1.58

 
$
2.82

 
 
Commodity derivative impact

 
(0.56
)
 
 
 
(0.08
)
 
(0.04
)
 
 
Net realized price
$
1.53

 
$
2.69

 
(43
)%
 
$
1.50

 
$
2.78

 
(46
)%
NGL (per bbl)
 
 
 
 
 
 
 
 
 
 
 
Average field-level price
$
10.22

 
$
19.12

 
 
 
$
11.15

 
$
23.79

 
 
Commodity derivative impact

 

 
 
 

 

 
 
Net realized price
$
10.22

 
$
19.12

 
(47
)%
 
$
11.15

 
$
23.79

 
(53
)%
Average net equivalent price (per Boe)
 
 
 
 
 
 
 
 
 
 
 
Average field-level price
$
38.50

 
$
35.38

 
 
 
$
38.57

 
$
37.15

 
 
Commodity derivative impact
(0.98
)
 
(2.68
)
 
 
 
(1.09
)
 
(3.06
)
 
 
Net realized price
$
37.52

 
$
32.70

 
15
 %
 
$
37.48

 
$
34.09

 
10
 %


14


 
Operating Expenses
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
 
(in millions)
Lease operating expense
$
47.4

 
$
59.5

 
(20
)%
 
$
182.9

 
$
263.1

 
(30
)%
Adjusted transportation and processing costs(1)
24.1

 
38.5

 
(37
)%
 
103.6

 
172.6

 
(40
)%
Production and property taxes
28.3

 
26.9

 
5
 %
 
95.9

 
130.8

 
(27
)%
Total production costs
$
99.8

 
$
124.9

 
(20
)%
 
$
382.4

 
$
566.5

 
(32
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
(per Boe)
Lease operating expense
$
5.60

 
$
5.11

 
10
 %
 
$
5.68

 
$
5.07

 
12
 %
Adjusted transportation and processing costs(1)
2.85

 
3.31

 
(14
)%
 
3.22

 
3.33

 
(3
)%
Production and property taxes
3.35

 
2.31

 
45
 %
 
2.98

 
2.52

 
18
 %
Total production costs
$
11.80

 
$
10.73

 
10
 %
 
$
11.88

 
$
10.92

 
9
 %
 ____________________________
(1) 
Adjusted transportation and processing costs is a non-GAAP measure. The definition and reconciliation of adjusted transportation and processing costs to transportation and processing costs, as presented, are provided within Non-GAAP Measures at the end of this release.


15


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,
 
2019
 
2018
 
2019
 
2018

(in millions)
Net income (loss)
$
(110.4
)
 
$
(629.3
)
 
$
(97.3
)
 
$
(1,011.6
)
Interest expense
28.1

 
37.5

 
128.1

 
149.4

Interest and other (income) expense
(0.1
)
 
5.5

 
(4.7
)
 
9.6

Income tax provision (benefit)
12.7

 
(199.8
)
 
(43.0
)
 
(317.4
)
Depreciation, depletion and amortization
144.5

 
183.5

 
540.0

 
857.1

Unrealized (gains) losses on derivative contracts
109.3

 
(361.7
)
 
138.3

 
(248.5
)
Exploration expenses
0.1

 
0.2

 
0.1

 
0.3

Net (gain) loss from asset sales, inclusive of restructuring costs
(1.4
)
 
1.7

 
(3.9
)
 
(25.0
)
Impairment

 
1,156.5

 
5.0

 
1,560.9

Loss from early extinguishment of debt
1.0

 

 
1.0

 

Adjusted EBITDA
$
183.8

 
$
194.1

 
$
663.6

 
$
974.8




16


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 interest expense, excluding amortization of deferred finance costs, and accrued property, plant and equipment capital expenditures. Management believes that this measure is useful to management and investors for analysis of the Company's ability to pay dividends, repay debt, fund acquisitions 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
 
Year Ended
 
December 31,
 
December 31,
 
2019
 
2018
 
2019
 
2018
Cash Flow Information:
 
 
 
 
 
 
 
Net Cash Provided by (Used in) Operating Activities
$
224.9

 
$
141.1

 
$
566.9

 
$
816.2

Net Cash Provided by (Used in) Investing Activities
(95.0
)
 
(193.2
)
 
112.7

 
(1,056.1
)
Net Cash Provided by (Used in) Financing Activities
(55.6
)
 
52.8

 
(511.3
)
 
244.6

 
 
 
 
 
 
 
 
Free Cash Flow
 
 
 
 
 
 
 
Net Cash Provided by (Used in) Operating Activities
$
224.9

 
$
141.1

 
$
566.9

 
$
816.2

Exploration expense
0.1

 
0.2

 
0.1

 
0.3

Amortization of debt issuance costs and discounts
(1.4
)
 
(1.4
)
 
(5.4
)
 
(5.4
)
Interest expense
28.1

 
37.5

 
128.1

 
149.4

Unrealized (gains) losses on marketable securities
1.1

 
(2.3
)
 
3.9

 
(1.2
)
Interest and other income (expense)
(0.1
)
 
5.5

 
(4.7
)
 
9.6

Deferred income taxes (benefit)
(65.5
)
 
128.0

 
(4.3
)
 
247.6

Income tax (provision) benefit
12.7

 
(199.8
)
 
(43.0
)
 
(317.4
)
Non-cash share-based compensation
(4.6
)
 
(6.8
)
 
(20.8
)
 
(30.9
)
Changes in operating assets and liabilities
(11.5
)
 
92.1

 
42.8

 
106.6

Adjusted EBITDA
$
183.8

 
$
194.1

 
$
663.6

 
$
974.8

Non-cash share-based compensation
4.6

 
6.8

 
20.8

 
30.9

Interest expense, excluding amortization of debt issuance costs and discounts
(26.7
)
 
(36.1
)
 
(122.7
)
 
(144.0
)
Accrued property, plant and equipment capital expenditures
(105.5
)
 
(188.4
)
 
(571.5
)
 
(1,176.6
)
Free Cash Flow
$
56.2

 
(23.6
)
 
$
(9.8
)
 
(314.9
)

This release includes a Free Cash Flow estimate for 2020. We are unable, however, to provide 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.











17


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,
 
2019
 
2018
 
2019
 
2018
 
(in millions, except earnings per share amounts)
Net income (loss)
$
(110.4
)
 
$
(629.3
)
 
$
(97.3
)
 
$
(1,011.6
)
Adjustments to net income (loss)
 
 
 
 
 
 
 
Unrealized (gains) losses on derivative contracts
109.3

 
(361.7
)
 
138.3

 
(248.5
)
Income taxes on unrealized (gains) losses on derivative contracts(1)
(24.5
)
 
89.3

 
(42.3
)
 
61.4

Net gain (loss) from asset sales, inclusive of restructuring costs
(1.4
)
 
1.7

 
(3.9
)
 
(25.0
)
Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs(1)
0.3

 
(0.4
)
 
1.2

 
6.2

Impairment

 
1,156.5

 
5.0

 
1,560.9

Income taxes on impairment(1)

 
(285.7
)
 
(1.5
)
 
(385.5
)
Loss from early extinguishment of debt
1.0

 

 
1.0

 

Income taxes on loss from early extinguishment of debt(1)
(0.2
)
 

 
(0.3
)
 

Total after-tax adjustments to net income
84.5

 
599.7

 
97.5

 
969.5

Adjusted Net Income (Loss)
$
(25.9
)
 
$
(29.6
)
 
$
0.2

 
$
(42.1
)

 
 
 
 
 
 
 
Earnings (Loss) per Common Share
 
 
 
 
 
 
 
Diluted earnings per share
$
(0.46
)
 
$
(2.66
)
 
$
(0.41
)
 
$
(4.25
)
Diluted after-tax adjustments to net income (loss) per share
0.36

 
2.53

 
0.41

 
4.08

Diluted Adjusted Net Income per share
$
(0.10
)
 
$
(0.13
)
 
$

 
$
(0.17
)
 
 
 
 
 
 
 
 
Weighted-average common shares outstanding

 
 
 
 
 
 
Diluted
237.8

 
236.7

 
237.7

 
237.9

________________________
(1) 
Income tax impact of adjustments is calculated using QEP’s statutory rate of 22.4% and 24.7% for the three months ended and December 31, 2019 and 2018, respectively, and 30.6% and 24.7% for the year ended December 31, 2019 and 2018, respectively.


18


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 Consolidated Statements of Operations and transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the 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,
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
 
(in millions)
Transportation and processing costs, as presented
$
9.9

 
$
24.4

 
$
(14.5
)
 
$
48.7

 
$
117.6

 
$
(68.9
)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
14.2

 
14.1

 
0.1

 
54.9

 
55.0

 
(0.1
)
Adjusted transportation and processing costs
$
24.1

 
$
38.5

 
$
(14.4
)
 
$
103.6

 
$
172.6

 
$
(69.0
)
 
 
 
 
 
 
 
 
 
 
 
 
 
(per Boe)
Transportation and processing costs, as presented
$
1.17

 
$
2.10

 
$
(0.93
)
 
$
1.51

 
$
2.27

 
$
(0.76
)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
1.68

 
1.21

 
0.47

 
1.70

 
1.06

 
0.64

Adjusted transportation and processing costs
$
2.85

 
$
3.31

 
$
(0.46
)
 
$
3.21

 
$
3.33

 
$
(0.12
)

This release includes estimated 2020 guidance for Adjusted Transportation and Processing Costs. We are unable, however, to provide 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.


19

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