QEP Resources : Q2 2020 Investor Presentation Slides

Investor Presentation

July 2020

Forward-Looking Statements & Non-GAAP Financial Measures

This presentation includes forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E 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 statements are not guarantees of future performance. These forward‐looking statements include statements regarding: free cash flow generation; our strong balance sheet and liquidity; creation of long-term shareholder value; expectations regarding utilization of multi-well pads in 2020; expectations regarding drilling, completion and development in the Permian and Williston Basins; updated 2020 guidance and the underlying assumptions; our [2021] economic breakeven point per barrel in the Permian; expected rate of return based on commodity price levels; expected refrac candidates in the Williston Basin; and estimated 2021 capital budget and production and certain assumptions related thereto.

Actual results may differ materially from those included in the forward‐looking statements due to a number of factors, including, but not limited to: the length and severity of the recent outbreak of COVID- 19 and its impact on QEP's business; 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 QEP's Annual Report on Form 10‐K for the year ended December 31, 2019 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 presentation, in other documents, or on its website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves calculated in accordance with SEC guidelines; however, QEP has made no such disclosures in its filings with the SEC. "EURs" or "estimated ultimate recoveries" refer to QEP's internal estimates of hydrocarbon quantities that may be potentially recovered and are not proved, probable or possible reserves within the meaning of the rules of the SEC. Probable and possible reserves and EURs are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially more risks of actually being realized. Actual quantities of natural gas, oil and NGL that may be ultimately recovered from QEP's interests may differ substantially from the estimates contained in this presentation. Factors affecting ultimate recovery include the scope of QEP's drilling program; the availability of capital; oil, gas and NGL prices; drilling and production costs; availability of drilling services and equipment; drilling results; geological and mechanical factors affecting recovery rates; lease expirations; actions of lessors and surface owners; transportation constraints, including gas and crude oil pipeline takeaway capacity; changes in local, regional, national and global demand for natural gas, oil and NGL; changes in, adoption of and compliance with laws and regulations; regulatory approvals; and other factors. Investors are urged to consider carefully the disclosures and risk factors about QEP's reserves in the Form 10-K.

QEP refers to Free Cash Flow, a non‐GAAP financial measure that management believes is a useful tool to assess QEP's operating results. For a definition of this term and a reconciliation to the most directly comparable GAAP measure, see the recent earnings press release and SEC filings at the Company's website at www.qepres.com under "Investor Relations."

2

QEP's World Class Assets

			Williston Basin
	7,973 Mboe	Net Acres: 94,610
	2Q20 Production: 2,515.0 Mboe
Q2 2020 Total Production (1)
	68% Oil		QEP Production Mix
	15% NGL	Permian Basin	2Q20
	17% Gas	Permian Basin Williston Basin
	Net Acres: 49,054
	2Q20 Production Mix	2Q20 Production: 5,453.2 Mboe

145,837

Total Net Acres (2)

Oil		NGL		Gas

(1)	Includes Other Northern and Other Southern production of 4.7 Mboe.	3
(2)	Includes Other Northern and Other Southern acreage of 2,173 net acres.

A Leading North American Independent E&P Company

World Class	•	Focused asset footprint
•	High-quality, contiguous acreage
Assets
•	382.3 MMboe of proved reserves(1)

Differentiated	•	Efficient, low-cost pad development
Well	• Peer leading D&C costs
Development	•	Capital program discipline & flexibility

Creating	• Free cash flow generation
Shareholder	•	Strong balance sheet & liquidity
Value	•	Reducing outstanding debt levels

Well positioned to develop

its portfolio of low-cost,

high-quality resource plays while creating long-term shareholder value

(1) As of December 31, 2019.

4

Committed to Environmental, Social & Governance Performance

We strive to minimize our impact to the environment where we operate, and we focus on the protection of the

health, safety and well-being of our employees, contractors, families, friends and neighbors.

Water	Air
QEP recognizes water is a valuable resource. We have pioneered water	QEP is committed to minimizing its impact on air quality, while
conservation practices in our operating areas, utilizing the latest	continuing to meet the energy demands of our nation. We report
technology and following industry best practices for the responsible use	emissions through the EPA's Greenhouse Gas Reporting Program and air
and protection of water sources. From 2017 through 2019, we recycled	emissions from production activities are carefully monitored, managed,
over 1.1 billion gallons of flow-back and produced water through our	and reported so they remain within prescribed state and federal limits.
company owned water recycling facilities, which have the capacity to
recycle between 180,000 and 200,000 barrels of water per day.

Land	Spill Prevention
QEP has a history of utilizing multi-well pads dating back to 2003,	QEP recognizes that prevention of spills is vital to protection of water,
creating significant reductions in our surface footprint. 100% of our wells	land resources and wildlife. We design, construct, and operate our
will be drilled on multi-well pads in 2020. We are also a pioneer in	facilities in a manner that reduces the potential for spills, and we have
horizontal hydraulic re-fracturing, which allows us to increase production	procedures in place to quickly respond in order to minimize impacts to
from existing wells by utilizing the existing wellbore, pad and production	the environment from releases or spills that may occur.
facility without causing additional surface disturbance.

Governance Highlights

•	ISS Corporate Governance Score is 1 (highest score possible)	•	Recent Board refreshment with less than five year tenure for over half the Board
•	Two female directors with leadership positions (Independent Chair of	•	Increased oversight of ESG matters by the Board through the Governance and
	the Board and Chair of the Audit Committee)		Social Responsibility Committee

5

Second Quarter Results Driven by Strong Execution

Generated Net Cash Provided by Operating Activities of $72.5 million and reported a $184.4 million Net Loss for the second quarter 2020

$95.3MM

Free Cash Flow (1)

$157.3 MM	$36.6 MM
Adjusted EBITDA (2)	Capital Expenditures (accrued)

5,458.5 Mbbl	$3.62 per Boe	$26.3 MM
Oil Production	Lease Operating Expense	G&A (3)

(1)	Free Cash Flow is a non-GAAP measure. See slide 26 for a reconciliation of Free Cash Flow.
(2)	Adjusted EBITDA is a non-GAAP measure. See slide 25 for a reconciliation of Adjusted EBITDA.	6
(3)	Includes share-based compensation and deferred compensation expense of $8.2 MM. See slide 24 for additional detail.

Updated 2020 Business Plan

In response to the continued market volatility, QEP has adjusted activity across its operations to improve cash flow and preserve liquidity

Updated

2020

Plan

Permian Basin (1)

• Plan to increase rig count from one to two rigs in September
• Plan to resume completion operations in November

Williston Basin

• All operated development activity completed for the year

Expected

2020

Outcomes

• Capital spend of $360 million
• Produce 19.3 million barrels of oil
• Generate more than $150 million of Free Cash Flow (2) at strip prices
• Permian LOE of $3.48/Boe, a 16% decrease compared with 2019
• G&A expense of $87.5 million, a 44% decrease compared with 2019

(1) Current plans to increase and resume activity based upon the recent improvement in commodity prices.

(2) Free Cash Flow is a non-GAAP measure. See slide 26 for a reconciliation of Free Cash Flow.

7

Updated 2020 Guidance

	Original 2020 Guidance (1)	Updated 2020 Guidance
Oil & Condensate Production (MMbbl)	21.35	- 22.45	19.0	- 19.5
Gas Production (Bcf)	31.0	- 34.0	30.0	- 33.0
NGL Production (MMbbl)	5.0	- 5.6	4.1	- 4.6
Total oil equivalent production (MMboe)	31.5	- 33.7	28.1	- 29.6
Lease operating expense (per Boe)	$5.20	- $5.80	$5.00	- $5.30
Adjusted Transportation and Processing Costs (per Boe) (2)	$3.30	- $3.60	$3.60	- $3.90
Depletion, depreciation and amortization (per Boe)	$17.75	- $18.75	$17.75	- $18.75
Production and property taxes (% of field-level revenue)	7.5%	8.5%
(in millions)
G&A expense (3)	$85.0 -$95.0	$85.0 -$90.0
Capital investment (excluding property acquisitions)
Drilling, Completion and Equip (4)	$520.0	- $565.0	$325.0	- $360.0
Midstream Infrastructure (5)	$20.0	- $25.0	$12.0	- $15.0
Corporate	$5.0	$3.0	- $5.0
Total Capital Investment (excluding property acquisitions)	$545.0	- $595.0	$340.0	- $380.0
Wells put on production (net)	69	44
Refracs put on production (net)		8		5

As of July 29, 2020 - QEP's updated 2020 guidance assumes: (i) a WTI NYMEX oil price of $40 per barrel and a natural gas price of $2.00 per MMBtu at Henry Hub, both adjusted for applicable commodity and location differentials, (ii) that QEP
will elect to reject ethane from its produced gas in the Permian Basin where processing economics support it, and (iii) no property acquisitions or divestitures, other than those already disclosed.
(1)	Original guidance as of February 26, 2020.
(2)	Adjusted Transportation and Processing Costs (per Boe) is a non-GAAP measure. Refer to the definitions and reconciliations of Non-GAAP Measures in our press release dated July 29, 2020.
(3)	The mid-point of G&A expense includes approximately $12.0 million of expenses related to cash and non-cashshare-based compensation and our deferred compensation plan mark-to-market. Because our cash share-based
	compensation and our deferred compensation plan liabilities fluctuate with stock price changes, the amount of actual expense may vary from the forecasted amount.
(4)	Drilling, Completion and Equipment includes approximately $30.0 million of non-operated well costs.	8
(5)	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.

2020 Capital & Production Guidance

Capital Program

• Reduced capital program in response to market conditions
• Plan to resume completion activity in the Permian in 4Q20
• Only non-op spending remaining in the Williston in 2020

Capital

	$200
	$180
	$160
millions	$140
$120
$ in	$100
$80
	$60
	$40

$20 $0

1Q20		2Q20		3Q20F	4Q20F
		Permian		Williston

Production

• Peaked in 2Q20 as plan was adjusted in response to market conditions
• Exit Rate expected to be approximately 45 MBopd

Oil Production

6,000

4,000

MBbls

2,000

0

1Q20		2Q20		3Q20F	4Q20F
		Permian		Williston

9

Permian Basin - University 0312E/W

0312W	0312E
½ mile	½ mile
	-- Middle Spraberry
	-- Lower Spraberry
	-- Jo Mill
	-- Spraberry Shale A
	-- Spraberry Shale B
	-- Spraberry Shale C
	-- Dean
	-- Wolfcamp A
	-- Wolfcamp B

UL 0312 Production Performance

	35,000
(BOPD)	30,000
25,000
Oil Rate	20,000
15,000
10kNorm	5,000
	10,000
	0
	MS	LS	SB	SC	WA	0312 Budget TC

Performance Observations

• Wolfcamp A and Spraberry Shale C-bench wells outperforming expectations
• Spraberry Shale B-bench & Lower Spraberry wells performing as expected
• Middle Spraberry wells outperforming after initial cleanup
• Deployed continuous tank development resulting in supercharge conditions with positive impacts on frac network complexity and initial production

UL 0312 Cumulative Production Performance

(MBO)	3,500
3,000
Oil	2,500
Cum	2,000
Norm	1,500
10k
1,000
DSU
500
	0
	0312 Total	0312 Budget TC

10

DSU 0312 Outperforming Average Peer Production

Peer Comparison- Middle Spraberry, Lower Spraberry, Spraberry Shale and Dean/Wolfcamp A

10,000' Norm Oil Production

1,500	150,000
1,250	125,000
1,000	100,000
750	75,000
500	50,000
250	25,000
0	0

0	30			60	90	120
					Days
		0312 Prod		Peer Avg	0312 Cum		Peer Avg Cum

Cum 10,000' Norm Oil Production

Well Count

QEP - UL 0312	25
Peer Average	755

(1) Peer data from IHS, All Martin/Andrews County wells POP'd 2018 and later.

11

Permian Basin - University 1125E

1125E

	½ mile
		-- Middle Spraberry
		-- Lower Spraberry
		-- Jo Mill
		-- Spraberry Shale A
		-- Spraberry Shale B
		-- Spraberry Shale C
		-- Dean
		-- Wolfcamp A
10,000'	12,500'	-- Wolfcamp B

UL 1125E Production Performance

	15000
(BOPD)	12500
10000
RateOil
7500
DSU	5000
	2500
	0
	MS	LS	SA	SB	SC	WA	Rolling 1125E Budget TCs

Performance Observations

• Wells completed in March 2020; POP dates were delayed until oil prices improved
• Cut oil sooner with lower water ratios
• Cumulative oil performance ahead of expectations
• Decline rates trending with pre-drill expectations
• Lower DSU density due to offset wells located to the East

UL 1125E Cumulative Production Performance

	900
	800
(MBO)	700
600
Oil	500
Cum	400
300
DSU
200

100

0

1125E Total		Rolling 1125E Budget TCs

12

Strong Performance vs. Peers Across All Benches

Cum 10,000' Norm Oil Production

Cum 10,000' Norm Oil Production

250,000

200,000

150,000

100,000

50,000

0

0

250,000

200,000

150,000

100,000

50,000

0

0

	Middle Spraberry				Performance Observations
					• Recent County Line development outperforming peers in the
					Basin
					• Middle Spraberry wells experienced longer clean up times due
					to tank development, but are now performing above average
					• Validates benefits of tank-style development and
					advancements in completion design
2	4	6	8	10	12
	QEP 0312	Months	QEP 1125
	Wolfcamp A		ProductionOil	250,000		Spraberry Shale
					150,000
						200,000
					Norm	100,000
					Cum10,000'	0
						50,000
2	4	6	8	10	12	0	2	4	6	8	10	12
	QEP 0312 MonthsQEP 1125					QEP 0312	Months	QEP 1125

13

Peer Leading Permian Efficiency

QEP has dramatically

lowered D&C costs and is

the most efficient

on a $/ Ft. basis

QEP has the most

efficient frac operation

Delivering peer

leading LOE

metrics

				D&C Costs Per Lateral Foot
$1,000					2018/2019 Peer Avg. $832
$750								$641	$443
$500
$250
$0
	A	B	E	D	C	F	QEP 18/19 Avg. QEP 2020 Avg.

Completed Lateral Feet Per Day

4,000					2018/2019 Peer Avg. 854 feet per day			3,867
							2,583
3,000
2,000
1,000
0
	E	D	A	B	C	F	QEP 18/19 Avg.	QEP 2020 Avg.

				LOE per Boe (1Q20)
$6.00				1Q20 Peer Avg.: $4.70
						$3.97
$4.00										$3.12
$2.00
$0.00
A	B	F	C	D	E	QEP 1Q20	QEP 2020 Avg.

(1)	Data sourced from Rystad Energy ShaleWellCube & company filings.	14
(2)	Peer group includes: Callon, Concho, Diamondback, Parsley, Pioneer and SM Energy.

Williston Basin Refrac Performance

Refrac Initial Performance

(Bopd)	10,000
RateOil	1,000
Incremental
100
	10

0	20	40	60	80	100	120
		Days Post Refrac
Type Curve			HEMI 1-27-34BH			HEMI 2-27-34BH
SEVERIN 1-16-17BH			SEVERIN 2-16-17BH			SEVERIN 9-8-16-17LL

Average Refrac Cost by Year

millions	$6.0
$5.2
$4.0			$4.1	$3.9
$ In
	$2.0
	$0.0
	2018	2019	2020

Hemi Refracs (2 wells)

Five refracs completed in 2020

• Wells performing as expected

• Up to 100 remaining refrac candidates

			Improving capital efficiency
			over time
			• 5% improvement in costs in
			2020
Severin Refracs (3 wells)	• 2020 refracs delivering
			competitive ROR at $40 WTI

15

Corporate Overhead Continuing to Decline

Significantly reduced G&A over last two years

• Lowered employee headcount by 60%
• Decreased officer headcount by more than half
• Retained technical, operating and business expertise
• Significantly reduced non-employee expense

Continued focus on reducing costs

• Streamline IT systems
• Reduce corporate office footprint
• Optimize use of outside services
• Apply continuous improvement mindset

Cash G&A and stock based compensation have

both decreased over 60% since 2018

$ in millions

$250.0

$200.0

$150.0

$100.0

$50.0

$0.0

Annual G&A

$33.0

$28.0

$189.0

$12.0

$128.0

$75.5

2018A	2019A		2020F
		G&A (excl. Stock Comp)		Stock Comp.

16

2021 Capital & Production Outlook

Capital Program

• Permian receiving majority of capital budget allocation with a two rig program
• Plan to complete the remaining four wells on the Disco pad in the Williston
• Approximately 70% of capital expenditures in first six months
• Completion activity reduced in second half of the year

Production

• Expected to peak in second half of year
• Expect 5% year-over-year oil production growth
• Flexibility to adjust full year activity according to market conditions

Improvements to capital efficiency in the Permian delivering stable production at significantly lower capital spend

significantly lower capital spend

$ in millions

MMboe

$1,200 $1,000 $800 $600 $400 $200 $0

35.0

30.0

25.0

20.0

15.0

10.0

5.0

0.0

Capital

2018A	2019A	2020F	2021F
		Permian		Williston	Forecast (Feb. 2020)

Equivalent Production

2018A	2019A	2020F	2021F
		Permian		Williston	Forecast (Feb. 2020)

17

High-Quality Permian Acreage Economic at $40 Oil

1 mile

-- Middle Spraberry (5/mi)

-- Lower Spraberry (5/mi)

-- Spraberry Shale A

-- Spraberry Shale B 16/mi -- Spraberry Shale C

-- Dean/Wolfcamp A (5/mi)

2021 DSU Example

Activity through 2021 solely concentrated on County Line development(1)

	Formation	2021 Well Counts
	Middle Spraberry	11
	Lower Spraberry	12
	Spraberry Shale	38
	Dean/Wolfcamp A	11
	TOTAL WELLS	72

• DSU level economics achieve >30% BFIT ROR at $40/$2.00 flat
• Significant ROR gains with relatively small increases to commodity price

			$40/$2.00	$45/$2.00	$50/$2.00
	Area	Target	BFIT ROR %	BFIT ROR %	BFIT ROR %
	County Line	Middle Spraberry	21%	30%	41%
	County Line	Lower Spraberry	41%	58%	77%
	County Line	Spraberry Shale	33%	48%	65%
	County Line	Dean/Wolfcamp A	36%	52%	72%
		DSU TOTAL	32%	47%	63%

(1) Assumes UL 1125W through UL 1933E.	18
Note: ROR calculation includes direct well costs and initial artificial lift installation.

Credit Facility & Liquidity Overview

• Commitment: $850 million
• Maturity: 9/1/2022
• NOT a Reserve Based Loan (RBL)
• • No semi-annual borrowing base redetermination
• Material subsidiaries guarantee credit facility (CF)
• • Not secured
• Financial covenants
• • Leverage Ratio: <2.50x using CF borrowings only
  • PV9 Ratio: >1.50x Calculated using CF borrowings only
  • Minimum Liquidity: $100 million at all times
• Senior Note Repurchases
• • Able to borrow up to $500 million on CF to repurchase notes
• Junior Guaranteed Indebtedness
• • Able to issue subordinated subsidiary guarantees for up to $500 million of unsecured debt
  • Indebtedness would be subordinate to CF and structurally senior to existing senior unsecured notes

QEP believes it has sufficient liquidity to meet all financial

commitments and navigate the current market cycle

Credit Facility Availability (1)

$ in millions

Leverage Ratio	842.5

PV9 Ratio

842.5

Minimum Liquidity		742.5
$0	$170	$340	$510	$680	$850

Available Capacity

Unavailable Capacity

Most Restrictive Covenant at 6/30/2020

Calculated in accordance with the 8th Amendment of Credit Agreement. Available Capacity calculated as: total credit facility aggregate commitments ($850 million) less any outstanding credit facility borrowings and letters of credit, net of any cash and cash equivalents.

$100 million of Minimum Liquidity potentially available pursuant to lender approval.

19

Debt Maturity Schedule

Senior Notes (Unsecured)

• Outstanding: $1.877 billion
• Average coupon: 5.6%
• Average duration: 3.1 years
• Key covenant: Limitation on Liens

Credit Facility (Unsecured)

• Commitment: $850 million
• Maturity: 9/1/2022
• Material subsidiary guarantees

As of June 30, 2020

$1,250

	$1,000				Unsecured
			$850 million
				Credit Facility
	$750
in millions						$636.8
$500				$465.1					$500.0
$							Coupon			Coupon
			$275.3		Coupon		5.250%
								5.625%
	$250				5.375%		Maturity
		Coupon						Maturity
			6.875%		Maturity		May 1,
			Maturity		October 1,		2023			March 1,
				2022					2026
			March 1,
	$0		2021
	2020	2021	2022		2023	2024	2025	2026

20

Creating Value for Shareholders

World Class Assets

Differentiated Well Development

Capital Discipline and Cost Improvement

QEP's commitment to

execution excellence and capital discipline maximizes value for shareholders

Annual Free Cash Flow Generation

Improving Balance Sheet and Liquidity

21

Appendix

Derivative Positions - As of July 22, 2020

Production Commodity Derivative Swaps

Year	Index		Total Volumes	Avg. Swap Price per Unit
Oil Sales			(MMBbls)	($/Bbl)
2020	NYMEX WTI		7.9	$57.29
2020	Argus WTI Midland		0.7	$57.30
2021	NYMEX WTI		8.6	$43.47
Gas Sales			(in Millions MMBtu)	($/MMbtu)
2020	IF Waha		7.4	$0.97
2020	NYMEX HH		5.5	$2.20
2021	IF Waha		14.6	$1.75
2021	NYMEX HH		9.1	$2.44
		Production Commodity Derivate Basis Swaps
Year	Index	Basis	Total volumes	Weighted Avg. Differential
Oil Sales			(MMBbls)	($/Bbl)
2020	NYMEX WTI	Argus WTI Midland	3.7	$0.22
2021	NYMEX WTI	Argus WTI Midland	4.4	$0.99

Note: Positions in 2020 are for the time period July- Dec 2020.

23

General and Administrative (G&A) Expense

		Three Months Ended June 30,		Six Months Ended June 30,
		2020		2019		Change	2020		2019		Change
	General and administrative (excluding share-based	$	18.1	$	26.0	$	(7.9)	$	38.3	$	74.2	$	(35.9)
	compensation and deferred compensation)
	General and administrative (share-based compensation and
	deferred compensation):
	Cash share-based compensation (1)	$	0.1	$	0.4	$	(0.3)	$	0.7	$	5.7	$	(5.0)
	Non-cashshare-based compensation (1)	$	3.1	$	4.8	$	(1.7)	$	6.4	$	11.2	$	(4.8)
	Deferred compensation mark-to-market adjustments (2)	$	5.0	$	0.3	$	4.7	$	(3.2)	$	3.7	$	(6.9)
	Total General and administrative	$	26.3	$	31.5	$	(5.2)	$	42.2	$	94.8	$	(52.6)

(1)	Cash share-based compensation represents restricted cash awards, performance share units and restricted share units recorded under the Company's Long-Term Incentive Plan and Cash Incentive Plan. Non-cashshare-based
	compensation represents stock options and restricted share awards recorded under the Company's Long-Term Incentive Plan. Refer to Note 12 - Share-Based and Long-Term Incentive Compensation, in Item I of Part I of this Quarterly
	Report on Form 10-Q for more information on share-based compensation.
(2)	Deferred compensation mark-to-market adjustments represents mark-to-market adjustments of the Company's nonqualified, unfunded deferred compensation plan (Wrap Plan). Refer to Note 1 - Basis of Presentation, in Item I of Part I	24
	of June 20, 2020 Quarterly Report on Form 10-Q for more information on the Wrap Plan.

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 June 30,	Six Months Ended June 30,
	2020			2019		2020	2019
				(in millions)
Net income (loss)		$	(184.4)	$	48.8	$	183.0	$	(67.9)
Interest Expense		29.8		33.2		61.4		67.2
Interest and other (income) expense			(2.6)		(0.9)		-		(3.7)
Income tax provision (benefit)		(53.6)		29.7		12.7		(82.3)
Depreciation, depletion and amortization			149.4		128.0		291.6		251.3
Unrealized (gains) losses on derivative contracts		219.1		(54.5)		(188.2)		121.3
Gain from early extinguishment of debt		(0.4)		-		(25.6)		-
Net (gain) loss from asset sales, inclusive of restructuring costs		-		(17.8)		(3.7)		(4.6)
Impairment			-		-		-		5.0
Adjusted EBITDA		$	157.3	$	166.5	$	331.2	$	286.3

25

Free Cash Flow

The Company defines Free Cash Flow as Adjusted EBITDA plus non-cashshare-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 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	Six Months Ended
	June 30, 2020		June 30, 2020
	2020		2019	2020	2019
Cash Flow Information
			(in millions)
Net Cash Provided by (Used in) Operating Activities	$	72.5	$	117.4	$	224.4	$	195.7
Net Cash Provided by (Used in) Investing Activities		(82.0)		(104.1)		(237.0)		348.1
Net Cash Provided by (Used in) Financing Activities		(57.2)		(5.5)		(149.6)		(445.6)
Free Cash Flow
Net Cash Provided by (Used in) Operating Activities	$	72.5	$	117.4	$	224.4	$	195.7
Amortization of debt issuance costs and discounts		(1.3)		(1.4)		(2.6)		(2.7)
Interest expense		29.8		33.2		61.4		67.2
Unrealized gains (losses) on marketable securities		3.3		0.8		-		2.7
Interest and other (income) expense		(2.6)		(0.9)		-		(3.7)
Deferred income taxes		53.6		(30.2)		(141.4)		87.7
Income tax provision (benefit)		(53.6)		29.7		12.7		(82.3)
Non-cashshare-based compensation		(3.1)		(3.2)		(6.4)		(11.2)
Changes in operating assets and liabilities		58.7		21.1		183.1		32.9
Adjusted EBITDA		157.3		166.5		331.2		286.3
Non-cashshare-based compensation		3.1		3.2		6.4		11.2
Interest expense, excluding amortization of debt issuance costs and discounts		(28.5)		(31.8)		(58.8)		(64.5)
Accrued property, plant and equipment capital expenditures		(36.6)		(169.9)		(215.1)		(337.1)	26
Free Cash Flow	$	95.3	$	(32.0)	$	63.7	$	(104.1)