UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2020

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number: 001-34778

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	87-0287750
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

1050 17^th Street, Suite 800, Denver, Colorado 80265

(Address of principal executive offices)

Registrant's telephone number, including area code (303) 672-6900

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, $0.01 par value	QEP	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐

No ☒

At June 30, 2020, there were 242,324,832 shares of the registrant's common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2020

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2020 AND 2019	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2020 AND 2019	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2020 AND DECEMBER 31, 2019	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2020 AND 2019	5
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2020 AND 2019	6
		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7
	ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	48
	ITEM 4.	CONTROLS AND PROCEDURES	52
PART II. OTHER INFORMATION			52
	ITEM 1.	LEGAL PROCEEDINGS	52
	ITEM 1A.	RISK FACTORS	53
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	58
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	58
	ITEM 4.	MINE SAFETY DISCLOSURES	58
	ITEM 5.	OTHER INFORMATION	58
	ITEM 6.	EXHIBITS	59
SIGNATURES			60

1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	118.3	$	294.6	$	340.1	$	570.2
Other revenues	(0.2)		1.6		0.2		5.3
Purchased oil and gas sales	2.5		—		6.1		1.3
Total Revenues	120.6		296.2		346.4		576.8
OPERATING EXPENSES
Purchased oil and gas expense	3.9		—		7.4		1.4
Lease operating expense	28.8		45.7		69.0		97.2
Transportation and processing costs	12.3		9.9		25.8		20.8
Gathering and other expense	2.8		3.0		5.5		6.8
General and administrative	26.3		31.5		42.2		94.8
Production and property taxes	9.6		23.6		28.3		47.6
Depreciation, depletion and amortization	149.4		128.0		291.6		251.3
Impairment	—		—		—		5.0
Total Operating Expenses	233.1		241.7		469.8		524.9
Net gain (loss) from asset sales, inclusive of restructuring costs	—		17.8		3.7		4.6
OPERATING INCOME (LOSS)	(112.5)		72.3		(119.7)		56.5
Realized and unrealized gains (losses) on derivative contracts	(98.7)		38.5		351.2		(143.2)
Interest and other income (expense)	2.6		0.9		—		3.7
Gain from early extinguishment of debt	0.4		—		25.6		—
Interest expense	(29.8)		(33.2)		(61.4)		(67.2)
INCOME (LOSS) BEFORE INCOME TAXES	(238.0)		78.5		195.7		(150.2)
Income tax (provision) benefit	53.6		(29.7)		(12.7)		82.3
NET INCOME (LOSS)	$	(184.4)	$	48.8	$	183.0	$	(67.9)
Earnings (loss) per common share
Basic	$	(0.76)	$	0.20	$	0.76	$	(0.29)
Diluted	$	(0.76)	$	0.20	$	0.76	$	(0.29)
Weighted-average common shares outstanding
Used in basic calculation	242.3		238.0		240.7		237.5
Used in diluted calculation	242.3		238.0		240.7		237.5

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
	(in millions)
Net income (loss)	$	(184.4)	$	48.8	$	183.0	$	(67.9)
Other comprehensive income (loss), net of tax:
Pension and other postretirement plans adjustments:
Amortization of prior service costs	—		—		—		0.1
Amortization of actuarial losses(1)	0.3		—		0.4		0.1
Net curtailment(2)	—		0.1		—		(0.3)
Other comprehensive income (loss)	0.3		0.1		0.4		(0.1)
Comprehensive income (loss)	$	(184.1)	$	48.9	$	183.4	$	(68.0)

____________________________

⁽¹⁾Presented net of income tax benefit of $0.1 million for the three and six months ended June 30, 2020.

⁽²⁾Presented net of income tax expense of $0.1 million for the six months ended June 30, 2019.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2020		December 31, 2019
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	3.4	$	166.3
Accounts receivable, net	97.9		108.4
Income tax receivable	165.0		37.4
Fair value of derivative contracts	169.4		1.5
Prepaid expenses and other current assets	10.7		11.6
Total Current Assets	446.4		325.2
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,786.2		9,574.9
Unproved properties	543.6		599.1
Gathering and other	165.5		164.2
Materials and supplies	16.5		15.6
Total Property, Plant and Equipment	10,511.8		10,353.8
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,482.4		5,250.5
Gathering and other	66.3		61.0
Total Accumulated Depreciation, Depletion and Amortization	5,548.7		5,311.5
Net Property, Plant and Equipment	4,963.1		5,042.3
Fair value of derivative contracts	6.2		0.2
Operating lease right-of-use assets, net	54.1		56.8
Other noncurrent assets	54.3		53.3
TOTAL ASSETS	$	5,524.1	$	5,477.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	2.3	$	18.3
Accounts payable and accrued expenses	157.0		227.2
Production and property taxes	9.2		18.9
Current portion of long-term debt	274.9		—
Interest payable	27.9		31.0
Fair value of derivative contracts	1.8		18.7
Current operating lease liabilities	20.3		18.0
Asset retirement obligations	6.2		6.0
Total Current Liabilities	499.6		338.1
Long-term debt	1,589.4		2,015.6
Deferred income taxes	416.1		274.5
Asset retirement obligations	94.9		94.9
Fair value of derivative contracts	3.2		0.5
Operating lease liabilities	39.2		44.8
Other long-term liabilities	36.8		48.8
Commitments and contingencies (Note 11)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 247.2 million and 242.1 million shares issued, respectively	2.5		2.4
Treasury stock – 4.9 million and 4.4 million shares, respectively	(56.6)		(55.4)
Additional paid-in capital	1,463.3		1,456.5
Retained earnings	1,447.8		1,269.6
Accumulated other comprehensive income (loss)	(12.1)		(12.5)
Total Common Shareholders' Equity	2,844.9		2,660.6
TOTAL LIABILITIES AND EQUITY	$	5,524.1	$	5,477.8

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income(Loss)		Total
	Shares	Amount		Shares	Amount
	(in millions)
Balance at March 31, 2020	247.0	$	2.5	(4.8)	$	(56.2)	$	1,459.9	$	1,632.2	$	(12.4)	$	3,026.0
Net income (loss)	—	—		—	—		—		(184.4)		—		(184.4)
Share-based compensation	0.2	—		(0.1)	(0.4)		3.4		—		—		3.0
Change in pension and postretirement liability, net of tax	—	—		—	—		—		—		0.3		0.3
Balance at June 30, 2020	247.2	$	2.5	(4.9)	$	(56.6)	$	1,463.3	$	1,447.8	$	(12.1)	$	2,844.9

Balance at December 31, 2019	242.1	$	2.4	(4.4)	$	(55.4)	$	1,456.5	$	1,269.6	$	(12.5)	$	2,660.6
Net income (loss)	—	—		—	—		—		183.0		—		183.0
Cash dividends paid, $0.02 per share	—	—		—	—		—		(4.8)		—		(4.8)
Share-based compensation	5.1	0.1		(0.5)	(1.2)		6.8		—		—		5.7
Change in pension and postretirement liability, net of tax	—	—		—	—		—		—		0.4		0.4
Balance at June 30, 2020	247.2	$	2.5	(4.9)	$	(56.6)	$	1,463.3	$	1,447.8	$	(12.1)	$	2,844.9

Balance at March 31, 2019	242.0	$	2.4	(3.9)	$	(51.8)	$	1,440.2	$	1,259.8	$	(14.5)	$	2,636.1
Net income (loss)	—	—		—	—		—		48.8		—		48.8
Share-based compensation	—	—		(0.2)	(1.8)		6.1		—		—		4.3
Change in pension and postretirement liability, net of tax	—	—		—	—		—		—		0.1		0.1
Balance at June 30, 2019	242.0	$	2.4	(4.1)	$	(53.6)	$	1,446.3	$	1,308.6	$	(14.4)	$	2,689.3

Balance at December 31, 2018	239.8	$	2.4	(3.1)	$	(45.6)	$	1,431.9	$	1,376.5	(14.3)		$	2,750.9
Net income (loss)	—	—		—	—		—		(67.9)		—		(67.9)
Share-based compensation	2.2	—		(1.0)	(8.0)		14.4		—		—		6.4
Change in pension and postretirement liability, net of tax	—	—		—	—		—		—		(0.1)		(0.1)
Balance at June 30, 2019	242.0	$	2.4	(4.1)	$	(53.6)	$	1,446.3	$	1,308.6	$	(14.4)	$	2,689.3

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

5

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30
	2020		2019
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	183.0	$	(67.9)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	291.6		251.3
Deferred income taxes (benefit)	141.4		(87.7)
Impairment	—		5.0
Non-cash share-based compensation	6.4		11.2
Amortization of debt issuance costs and discounts	2.6		2.7
Net (gain) loss from asset sales, inclusive of restructuring costs	(3.7)		(4.6)
Gain from early extinguishment of debt	(25.6)		—
Unrealized (gains) losses on marketable securities	—		(2.7)
Unrealized (gains) losses on derivative contracts	(188.2)		121.3
Changes in operating assets and liabilities	(183.1)		(32.9)
Net Cash Provided by (Used in) Operating Activities	224.4		195.7
INVESTING ACTIVITIES
Property acquisitions	(4.1)		(1.8)
Expenditures for property, plant and equipment, including exploratory well expense	(245.8)		(316.8)
Proceeds from disposition of assets	12.9		666.7
Net Cash Provided by (Used in) Investing Activities	(237.0)		348.1
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(15.9)		(9.3)
Long-term debt issuance costs paid	(0.5)		—
Repurchases of senior notes	(127.7)		—
Proceeds from credit facility	—		56.0
Repayments of credit facility	—		(486.0)
Treasury stock repurchases	(0.7)		(6.3)
Dividends paid	(4.8)		—
Net Cash Provided by (Used in) Financing Activities	(149.6)		(445.6)
Change in cash, cash equivalents and restricted cash(1)	(162.2)		98.2
Beginning cash, cash equivalents and restricted cash(1)	196.4		28.1
Ending cash, cash equivalents and restricted cash(1)	$	34.2	$	126.3
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	62.1	$	63.3
Cash paid (refunds received) for income taxes, net	$	(1.2)	$	1.5
Cash paid for amounts included in the measurement of lease liabilities	$	12.2	$	13.1
Other Non-cash Activities:
Right-of-use assets obtained in exchange for operating lease obligations	$	5.3	$	9.8
Non-cash Investing Activities:
Capital expenditure accruals as of June 30, 2020 and 2019	$	32.7	$	74.9

____________________________

⁽¹⁾Refer to Cash, Cash Equivalents and Restricted Cash in Note 1 – Basis of Presentation.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

6

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Basis of Presentation

The interim Condensed Consolidated Financial Statements (financial statements) contain the accounts of QEP and its majority-owned or controlled subsidiaries. The financial statements were prepared in accordance with Generally Accepted Accounting Principles (GAAP) in the United States and with the instructions for Quarterly Reports on Form 10-Q and Regulation S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Consolidated Financial Statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim financial statements do not include all of the information and notes required by GAAP for annual consolidated financial statements. These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

The preparation of the financial statements and Notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. Further, these estimates and other factors, including those outside the Company's control, such as the impact of sustained lower commodity prices, could have a significant adverse impact to the Company's financial condition, results of operations and cash flows. The results of operations for the three and six months ended June 30, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020.

Certain prior period balances on the Condensed Consolidated Balance Sheets (balance sheets) and Condensed Consolidated Statements of Cash Flows (statements of cash flows) have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share or retained earnings previously reported.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents primarily consist of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. Restricted cash are funds that are legally or contractually reserved for a specific purpose and therefore not available for immediate or general business use.

7

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the balance sheets to the amounts shown in the statements of cash flows:

	June 30,
	2020		2019
	(in millions)
Cash and cash equivalents	$	3.4	$	97.1
Restricted cash(1)	30.8		29.2
Total cash, cash equivalents and restricted cash shown in the statements of cash flows	$	34.2	$	126.3

_______________________

⁽¹⁾ As of June 30, 2020 and 2019, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin. The restricted cash balance is recorded within "Other noncurrent assets" on the balance sheets.

Income Tax

The tax legislation enacted in December 2017 reduced our federal corporate tax rate from 35% to 21%. In addition, the tax legislation eliminated the corporate Alternative Minimum Tax (AMT), allowing the Company to claim AMT refunds for AMT credits carried forward from prior tax years. The Company received $73.9 million of AMT credit refunds in 2019. The Coronavirus Aid Relief, and Economic Security Act (CARES Act) enacted in March 2020 permitted the Company to carry back its net operating loss (NOL) generated in 2018, creating additional AMT credits, and accelerate all of its AMT refunds. The Company now anticipates that after carrybacks, it will receive $165.6 million of AMT credit refunds which are included in "Income tax receivable" on the balance sheets as of June 30, 2020.

QEP’s effective federal and state income tax rate was 22.5% during the second quarter of 2020 compared to a rate of 37.8% during the second quarter of 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items (unusual or infrequent items impacting the tax provision) recognized during the second quarter of 2019. The primary discrete item recognized during the second quarter of 2019 related to non-deductible executive compensation.

QEP’s effective federal and state income tax rate was 6.5% during the six months ended June 30, 2020 compared to a rate of 54.8% during the six months ended June 30, 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items recognized during the six months ended June 30, 2020 and 2019. The primary discrete items recognized during the six months ended June 30, 2020, related to the remeasurement of deferred taxes due to a NOL carryback under the CARES Act to a year with a higher federal tax rate. The primary discrete items recognized during the six months ended June 30, 2019 related to the remeasurement of deferred taxes associated with the Haynesville Divestiture and non-deductible executive compensation.

Impairment of Long-Lived Assets

During the six months ended June 30, 2020, there were no impairment charges. During the six months ended June 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

Employee Benefits

QEP provides pension and other postretirement benefits to certain employees through three retiree benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (the SERP), and a postretirement medical plan (the Medical Plan). The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. The Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that participants do not earn additional defined benefits for future services. The SERP is a nonqualified retirement plan that is unfunded and provides postretirement benefits to certain QEP employees. The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees.

8

During the six months ended June 30, 2020, the Company made contributions of $9.4 million to its retiree benefit plans (including $2.0 million to the Pension Plan and $7.4 million to the SERP) and expects to contribute an additional $3.4 million during the remainder of 2020 (including $2.0 million to the Pension Plan, $1.2 million to the SERP and $0.2 million to the Medical Plan). Contributions to the Pension Plan increase plan assets whereas contributions to the SERP and Medical Plan are used to fund current benefit payments.

The Company recognizes service costs related to SERP and Medical Plan benefits on the Condensed Consolidated Statements of Operations (statements of operations) within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the statements of operations within "Interest and other income (expense)".

QEP also offers a nonqualified, unfunded deferred compensation wrap plan (Wrap Plan) to certain individuals. The Wrap Plan provides participants with certain tax planning benefits as well as supplemental funds for retirement and allows participants to defer the receipt of various types of compensation. Participants are able to select from a variety of investment options, including mutual funds and phantom QEP shares. As of June 30, 2020 and December 31, 2019, the Wrap Plan obligations for participants' future benefits were $25.5 million and $26.8 million, respectively, and are included in "Other long-term liabilities" on the balance sheets. The Company established a trust (Rabbi Trust) to hold the investments associated with the Wrap Plan (other than phantom QEP shares) and to pay Wrap Plan obligations as they arise. As of June 30, 2020 and December 31, 2019, the marketable securities held in the Rabbi Trust were $23.5 million and $23.1 million, respectively, and are included in "Other noncurrent assets" on the balance sheets.

Changes in the fair value of Wrap Plan obligations and marketable securities are recorded as "Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" within "General and administrative" and "Interest and other income (expense)", respectively, on the statements of operations. "Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" for the three and six months ended June 30, 2020 and 2019, respectively, are summarized in the table below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
	(in millions)
Deferred compensation mark-to-market adjustments	$	5.0	$	0.3	$	4.7	$	(3.2)	$	3.7	$	(6.9)
Unrealized (gain)/loss on marketable securities	(3.3)		0.8		$	(4.1)	—		(2.7)		$	2.7

Refer to Note 6 – Fair Value Measurements for information on the fair value measurement of the marketable securities held in the Rabbi Trust and the Wrap Plan obligations.

Recent Accounting Developments

In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-13, Financial Instruments - Credit Losses (Topic 326) - Measurement of credit losses on financial instruments, which requires a company immediately recognize management's current estimated credit losses ("CECL") for all financial instruments that are not accounted for at fair value through net income. Previously, credit losses on financial assets were only required to be recognized when they were incurred. The Company adopted ASU 2016-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.

In August 2018, the FASB issued ASU No. 2018-13, Fair value measurement (Topic 820) - Disclosure framework - Changes to the disclosure requirements for fair value measurement, which modifies the disclosure requirements on fair value measurements in Topic 820. The Company adopted ASU 2018-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (LIBOR). The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This amendment is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company's financial statements.

9

Note 2 – Revenue

Revenue Recognition

QEP recognizes revenue from the sale of oil and condensate, gas and NGL in the period that the performance obligations are satisfied. QEP's performance obligations are satisfied when the customer obtains control of product, when QEP has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sale of oil and condensate, gas and NGL are made under contracts with customers, which typically include consideration that is based on pricing tied to local indices and volumes delivered in the current month. Reported revenues include estimates for the two most recent months using published commodity price indices and volumes supplied by field operators. Performance obligations under our contracts with customers are typically satisfied at a point in time through monthly delivery of oil and condensate, gas and/or NGL. Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery.

QEP's oil and condensate is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate QEP for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.

The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following table are not all of the transportation and processing costs that QEP incurs, only the costs that are netted against revenues pursuant to ASC Topic 606, Revenue Recognition.

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue		Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended June 30, 2020
Northern Region
Williston Basin	$	35.4	$	3.0	$	0.5	$	(8.6)	$	30.3
Other Northern	—		1.1		—		—		1.1
Southern Region
Permian Basin	83.1		4.7		5.8		(6.7)		86.9
Other Southern	—		—		—		—		—
Total oil and condensate, gas and NGL sales	$	118.5	$	8.8	$	6.3	$	(15.3)	$	118.3
	Three Months Ended June 30, 2019
Northern Region
Williston Basin	$	107.5	$	7.5	$	5.8	$	(8.9)	$	111.9
Other Northern	0.5		0.1		—		—		0.6
Southern Region
Permian Basin	177.6		(0.6)		8.5		(3.8)		181.7
Other Southern	0.1		0.3		—		—		0.4
Total oil and condensate, gas and NGL sales	$	285.7	$	7.3	$	14.3	$	(12.7)	$	294.6

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	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue		Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Six Months Ended June 30, 2020
Northern Region
Williston Basin	$	114.6	$	7.6	$	4.0	$	(17.9)	$	108.3
Other Northern	0.1		1.2		—		—		1.3
Southern Region
Permian Basin	223.8		6.5		11.9		(11.7)		230.5
Other Southern	—		—		—		—		—
Total oil and condensate, gas and NGL sales	$	338.5	$	15.3	$	15.9	$	(29.6)	$	340.1
	Six Months Ended June 30, 2019
Northern Region
Williston Basin	$	217.4	$	20.0	$	13.2	$	(19.0)	$	231.6
Other Northern	0.9		0.3		—		—		1.2
Southern Region
Permian Basin	316.8		4.0		18.0		(7.5)		331.3
Other Southern	0.1		6.0		—		—		6.1
Total oil and condensate, gas and NGL sales	$	535.2	$	30.3	$	31.2	$	(26.5)	$	570.2

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Note 3 – Acquisitions and Divestitures

Acquisitions

During the six months ended June 30, 2020 and 2019, QEP acquired various oil and gas properties, which primarily included proved leasehold acreage in the Permian Basin for an aggregate purchase price of $4.1 million and $1.8 million, respectively, subject to post-closing purchase price adjustments.

Divestitures

During the six months ended June 30, 2020, QEP received proceeds of $12.9 million and recorded a pre-tax gain on sale of $3.7 million, primarily related to the divestiture of certain properties outside its main operating areas. Gains and losses are reported on the statements of operations within "Net gain (loss) from asset sales, inclusive of restructuring costs".

Haynesville/Cotton Valley Divestiture

In January 2019, QEP sold its Haynesville/Cotton Valley assets (Haynesville Divestiture), and during the year ended December 31, 2019, reached final settlement on asserted environmental and title defects and received aggregate net cash proceeds of $633.9 million. QEP recorded a total net pre-tax loss on sale, including restructuring costs of $4.0 million. During the three and six months ended June 30, 2019, QEP recorded $14.3 million of pre-tax gain on sale and $0.7 million of pre-tax loss on sale, respectively, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.

During the three and six months ended June 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax gain on sale of $14.3 million and pre-tax loss on sale of $0.7 million, respectively, as income from continuing operations on the statements of operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations. During the three months ended June 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $14.4 million, which includes the pre-tax gain on sale of $14.3 million.

Other Divestitures

In addition to the Haynesville Divestiture, during the six months ended June 30, 2019, QEP received net cash proceeds of $39.7 million and recorded a pre-tax gain on sale of $5.5 million, primarily related to the divestiture of properties outside its main operating areas.

These gains and losses were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.

Note 4 – Earnings Per Share

Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the three months ended June 30, 2020, and the six months ended June 30, 2019, the Company was in a net loss position, therefore, all potentially dilutive securities were anti-dilutive.

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The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2020	2019	2020	2019
	(in millions)
Weighted-average basic common shares outstanding	242.3	238.0	240.7	237.5
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	242.3	238.0	240.7	237.5

Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs or estimated lives. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate.

The balance sheet line items of QEP's ARO liability are presented in the table below:

	Asset Retirement Obligations
	June 30,		December 31,
	2020		2019
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.2	$	6.0
Long-term:
Asset retirement obligations	94.9		94.9
Total ARO Liability	$	101.1	$	100.9

The following is a reconciliation of the changes in the Company's ARO for the period specified below:

	Asset Retirement Obligations
	(in millions)
ARO liability at January 1, 2020	$	100.9
Accretion	1.9
Additions	1.0
Revisions	(0.5)
Liabilities related to assets sold	(1.3)
Liabilities settled	(0.9)
ARO liability at June 30, 2020	$	101.1

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Note 6 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 7 – Derivative Contracts for more information) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.

QEP has determined that the marketable securities held in the Rabbi Trust and the Wrap Plan obligations are Level 1. The fair value of the marketable securities in the Rabbi Trust is based on actively traded mutual funds. The Wrap Plan obligations, which represent the underlying liabilities to the participants in the Wrap Plan, are recorded at amounts due to participants, based on the fair value of participants' selected investments, including both actively traded mutual funds and phantom QEP shares. Refer to Note 1 – Basis of Presentation for additional information.

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The fair value of financial assets and liabilities at June 30, 2020 and December 31, 2019, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)		Net Amounts Presented on the Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets	June 30, 2020
Fair value of derivative contracts – short-term	$	—	$	173.8	$	—	$	(4.4)	$	169.4
Fair value of derivative contracts – long-term	—		6.9		—		(0.7)		6.2
Fair value of Rabbi Trust marketable securities	23.5		—		—		—		23.5
Total financial assets	$	23.5	$	180.7	$	—	$	(5.1)	$	199.1
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	6.2	$	—	$	(4.4)	$	1.8
Fair value of derivative contracts – long-term	—		3.9		—		(0.7)		3.2
Fair value of Wrap Plan obligations	25.5		—		—		—		25.5
Total financial liabilities	$	25.5	$	10.1	$	—	$	(5.1)	$	30.5
	December 31, 2019
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	1.5	$	—	$	—	$	1.5
Fair value of derivative contracts – long-term	—		0.2		—		—		0.2
Fair value of Rabbi Trust marketable securities	23.1		—		—		—		23.1
Total financial assets	$	23.1	$	1.7	$	—	$	—	$	24.8
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	18.7	$	—	$	—	$	18.7
Fair value of derivative contracts – long-term	—		0.5		—		—		0.5
Fair value of Wrap Plan obligations	26.8		—		—		—		26.8
Total financial liabilities	$	26.8	$	19.2	$	—	$	—	$	46.0

_______________________

⁽¹⁾The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the balance sheets for the contracts that contain netting provisions. Refer to Note 7 – Derivative Contracts for additional information regarding the Company's derivative contracts.

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the financial statements:

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2020				December 31, 2019
Financial Liabilities	(in millions)
Total debt outstanding	$	1,864.3	$	1,354.2	$	2,015.6	$	2,029.4

The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the quarter. At times when the Company has outstanding debt under the credit facility, the

15

carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt is set for periods of one month or less.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO includes plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 5 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company reviews its proved oil and gas properties and operating lease right-of-use assets for potential impairment at least annually and when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. If impairment is indicated, the fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of future cash flows, the fair value of property is measured utilizing a probability-weighted approach in which the likelihood of possible outcomes is taken into consideration. Given the unobservable nature of the inputs, fair value calculations associated with long-term operating lease right-of-use assets and proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the six months ended June 30, 2020, the Company did not have an impairment charge. During the six months ended June 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date, which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil and condensate, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, and future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 3 – Acquisitions and Divestitures for more information on the fair value of acquired properties.

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. QEP does not enter into commodity derivative contracts for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps, basis swaps or costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. QEP also enters into oil price derivative swaps that use Intercontinental Exchange, Inc. (ICE) Brent or regional price indices as the reference price. In addition, QEP enters into oil basis swaps to achieve a fixed-price swap for a portion of its oil sales at prices that reference specific regional index prices. Gas price derivative instruments are typically structured as fixed-price swaps or collars at NYMEX Henry Hub or regional price indices.

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QEP does not currently have any commodity derivative instruments that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of June 30, 2020:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2020	NYMEX WTI	7.9	$	57.29
2020	Argus WTI Midland	0.7	$	57.30
2021	NYMEX WTI	6.4	$	43.92
Gas sales		(MMbtu)	($/MMbtu)
2020	IF Waha(1)	7.4	$	0.97
2020	NYMEX HH	5.5	$	2.20
2021	IF Waha(1)	14.6	$	1.75
2021	NYMEX HH	9.1	$	2.44

_______________________

⁽¹⁾IF Waha Index pricing reported in Platts' Inside FERC's Gas Market Report, reflects the weighted average price of Natural Gas transactions at the Waha Hub in west Texas on the first day of the month. 

QEP uses oil basis swaps, combined with NYMEX WTI fixed-price swaps, to achieve fixed price swaps for the location at which it physically sells its production. The following table presents details of QEP's oil basis swaps as of June 30, 2020:

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2020	NYMEX WTI	Argus WTI Midland	3.7	$	0.22
2021	NYMEX WTI	Argus WTI Midland	4.4	$	0.99

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The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the statements of operations are summarized in the following table:

	Three Months Ended				Six Months Ended
Derivative contracts	June 30,				June 30,
	2020		2019		2020		2019(1)
Realized gains (losses) on commodity derivative contracts	(in millions)
Oil derivative contracts	$	120.2	$	(16.0)	$	162.8	$	(19.0)
Gas derivative contracts	0.2		—		0.2		(2.9)
Realized gains (losses) on commodity derivative contracts	120.4		(16.0)		163.0		(21.9)
Unrealized gains (losses) on commodity derivative contracts
Oil derivative contracts	(217.2)		54.5		196.7		(122.8)
Gas derivative contracts	(1.9)		—		(8.5)		(0.3)
Unrealized gains (losses) on commodity derivative contracts	(219.1)		54.5		188.2		(123.1)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production	$	(98.7)	$	38.5	$	351.2	$	(145.0)
Derivatives associated with Haynesville Divestiture
Unrealized gains (losses) on commodity derivative contracts
Gas derivative contracts	—		—		—		1.8
Unrealized gains (losses) on commodity derivative contracts related to divestitures (1)	$	—	$	—	$	—	$	1.8
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(98.7)	$	38.5	$	351.2	$	(143.2)

_______________________

⁽¹⁾During the six months ended June 30, 2019, the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture were comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.

Note 8 – Leases

QEP enters into contractual lease arrangements to rent office space, compressors, generators, drilling rigs and other equipment from third-party lessors. QEP records a net operating lease right-of-use (ROU) asset and operating lease liability on the balance sheets for all operating leases with a contract term in excess of 12 months. ROU assets represent QEP’s right to use an underlying asset for the lease term and lease liabilities represent QEP’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. With the exception of generators, QEP does not account for lease components separately from the non-lease components. The contractual consideration provided under QEP's leased generators is allocated between lease components, such as equipment, and non-lease components, such as maintenance service fees, based on estimated costs from the vendor. QEP uses its incremental borrowing rate at commencement date of the contract in calculating the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for QEP's risk. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of QEP's leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that QEP will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

QEP determines if an arrangement is a lease at inception of the contract and records the resulting operating lease asset on the balance sheets as “Operating lease right-of-use assets, net” with offsetting liabilities recorded as “Current operating lease liabilities” and “Operating lease liabilities.” QEP recognizes a lease in the financial statements when the arrangement either

18

explicitly or implicitly involves property, plant, or equipment (PP&E), the contract terms are dependent on the use of the PP&E, and QEP has the ability or right to operate the PP&E or to direct others to operate the PP&E and receive the majority of the economic benefits of the assets. As of June 30, 2020, QEP does not have any financing leases.

Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows:

	Three Months Ended				Six Months Ended
	June 30, 2020		June 30, 2019		June 30, 2020		June 30, 2019
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(1)	$	2.7	$	4.1	$	7.1	$	8.8
	Three Months Ended				Six Months Ended
	June 30, 2020		June 30, 2019		June 30, 2020		June 30, 2019
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	2.9	$	3.0	$	5.4	$	6.1
Gathering and other expense	1.9		2.3		3.8		3.8
General and administrative	1.5		1.6		3.0		3.2
Total lease cost	$	9.0	$	11.0	$	19.3	$	21.9

 ____________________________

⁽¹⁾Represents short-term lease capital expenditures related to drilling rigs for the three and six months ended June 30, 2020 and 2019. These costs are capitalized as a part of "Proved properties" on the balance sheets.

Lease term and discount rate related to the Company's leases are as follows:

	June 30, 2020		June 30, 2019
Weighted-average remaining lease term (years)	4.0		3.6
Weighted-average discount rate	8.6	%	7.7	%

As of June 30, 2020 and December 31, 2019, the maturity analysis for long-term operating leases under the scope of ASC 842 is as follows:

	June 30, 2020		December 31, 2019
Year	(in millions)
2020	$	12.4	$	22.3
2021	22.4		20.4
2022	16.5		15.9
2023	11.4		10.6
2024	2.3		1.4
After 2024	2.6		2.4
Less: Interest(1)	(8.1)		(10.2)
Present value of lease liabilities(2)	$	59.5	$	62.8

 ____________________________

⁽¹⁾Calculated using the estimated interest rate for each lease.

⁽²⁾As of June 30, 2020 and December 31, 2019, of the total present value of lease liabilities, $20.3 million and $18.0 million, was recorded in "Current operating lease liabilities", respectively, and $39.2 million and $44.8 million was recorded in "Operating lease liabilities", respectively, on the balance sheets.

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Note 9 – Restructuring

In February 2018, QEP's Board of Directors (Board) approved certain strategic and financial initiatives. In February 2019, QEP's Board commenced a comprehensive review of strategic alternatives to maximize shareholder value. In connection with these activities, QEP has incurred various restructuring costs associated with contractual termination benefits including severance, accelerated vesting of share-based compensation and other expenses. The termination benefits are accounted for under ASC 712, Compensation – Nonretirement Postemployment Benefits and ASC 718, Compensation – Stock Compensation.

Restructuring costs recognized are summarized below:

	Total recognized		Recognized in "General and administrative"		Recognized in "Net (gain) loss from asset sales, inclusive of restructuring costs"		Recognized in "Interest and other (income) expense"
	Three Months Ended June 30, 2020
	(in millions)
Termination benefits	$	—	$	—	$	—	$	—
Accelerated share-based compensation	0.3		0.3		—		—
Retention expense (including share-based compensation)	0.2		0.2		—		—
Total restructuring costs	$	0.5	$	0.5	$	—	$	—
	Six Months Ended June 30, 2020
Termination benefits	$	1.0	$	1.0	$	—	$	—
Accelerated share-based compensation	0.5		0.5		—		—
Retention expense (including share-based compensation)	0.4		0.4		—		—
Total restructuring costs	$	1.9	$	1.9	$	—	$	—
	Three Months Ended June 30, 2019
Termination benefits	$	(0.1)	$	(0.1)	$	—	—
Accelerated share-based compensation	1.3		1.3		—		—
Retention expense (including share-based compensation)	4.8		4.8		—		—
Pension and Medical Plan curtailment	0.1		—		—		0.1
Total restructuring costs	$	6.1	$	6.0	$	—	$	0.1
	Six Months Ended June 30, 2019
Termination benefits	$	6.7	$	6.6	$	0.1	—
Office lease termination costs	0.6		0.6		—		—
Accelerated share-based compensation	9.7		8.2		1.5		—
Retention expense (including share-based compensation)	10.9		10.9		—		—
Pension and Medical Plan curtailment	(0.4)		—		(0.2)		(0.2)
Total restructuring costs	$	27.5	$	26.3	$	1.4	$	(0.2)

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	Costs recognized from inception through June 30, 2020(1)		Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	45.6	$	—
Office lease termination costs	1.6		—
Accelerated share-based compensation	24.1		—
Retention expense (including share-based compensation)	38.7		—
Pension and Medical Plan curtailment	1.3		—
Total restructuring costs	$	111.3	$	—

 ____________________________

⁽¹⁾Represents costs incurred since February 2018 when QEP's Board approved certain strategic and financial initiatives.

The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the balance sheets.

	Restructuring liability
	Termination benefits		Office lease termination costs		Accelerated share-based compensation		Retention expense		Pension curtailment		Total
	(in millions)
Balance at December 31, 2019	$	1.2	$	—	$	—	$	6.5	$	—	$	7.7
Costs incurred and charged to expense	1.0		—		0.5		0.4		—		1.9
Costs paid or otherwise settled	(2.2)		—		(0.5)		(6.9)		—		(9.6)
Balance at June 30, 2020	$	—	$	—	$	—	$	—	$	—	$	—

Note 10 – Debt

As of the indicated dates, the principal amount of QEP's debt consisted of the following:

	June 30, 2020		December 31, 2019
	(in millions)
Revolving Credit Facility due 2022	$	—	$	—
6.875% Senior Notes due 2021	275.3		382.4
5.375% Senior Notes due 2022	465.1		500.0
5.25% Senior Notes due 2023	636.8		650.0
5.625% Senior Notes due 2026	500.0		500.0
Less: unamortized discount and unamortized debt issuance costs	(12.9)		(16.8)
Total principal amount of debt (including current portion)	1,864.3		2,015.6
Less: current portion of long-term debt	(274.9)		—
Total long-term debt outstanding	$	1,589.4	$	2,015.6

Of the total debt outstanding on June 30, 2020, the 6.875% Senior Notes due March 1, 2021, the 5.375% Senior Notes due October 1, 2022 and the 5.25% Senior Notes due May 1, 2023, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.

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Credit Facility

In June 2020, QEP entered into the Eighth Amendment to its credit agreement, which, among other things, reduced the aggregate principal amount of commitments to $850.0 million, requires the Company’s material subsidiaries to guarantee the obligations under the credit agreement as well as certain swap obligations and modified the leverage ratio and present value financial covenants, such that they only pertain to net priority guaranteed debt (primarily consisting of borrowings under the credit facility and letters of credit). The amended credit agreement also provides the ability to use up to $500.0 million of loan proceeds to repurchase outstanding senior notes, provides the ability to issue subsidiary guarantees of up to $500.0 million of unsecured debt, with such guarantees being subordinated to the obligations under the credit agreement, and may limit the Company’s ability to make certain restricted payments, including dividends. The amended credit agreement, which matures on September 1, 2022, provides for borrowings at short-term interest rates and contains customary covenants and restrictions and contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a minimum liquidity amount of at least $100.0 million (ii) a net priority guaranteed leverage ratio under which net priority guaranteed debt may not exceed 2.50 times consolidated EBITDAX (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net priority guaranteed debt by at least 1.50 times at any time on or after June 4, 2020. At June 30, 2020 and December 31, 2019, QEP was in compliance with the covenants under its credit agreement. The Company recorded a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility and recorded the loss within "Gain from early extinguishment of debt" on the statements of operations.

As of June 30, 2020, QEP had no borrowings outstanding and $10.9 million in letters of credit outstanding under the credit facility. As of December 31, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility.

Senior Notes

At June 30, 2020, the Company had $1,877.2 million in principal amount of senior notes outstanding with maturities ranging from March 1, 2021 to March 1, 2026, and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of QEP's other existing and future senior unsecured indebtedness. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets. During the six months ended June 30, 2020, QEP repurchased principal amounts of $107.1 million of its 6.875% Senior Notes due March 2021, $34.9 million of its 5.375% Senior Notes due October 1, 2022 and $13.2 million of its 5.25% Senior Notes due May 1, 2023. The Company recorded $27.5 million in "Gain from early extinguishment of debt" on the statements of operations associated with the repurchase of Senior Notes during the six months ended June 30, 2020.

Note 11 – Commitments and Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues and the ongoing discovery and/or development of information important to the matter.

Mandan, Hidatsa and Arikara Nation ("MHA Nation") Title Dispute – In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's IMDA lease covering the disputed minerals underlying the Missouri River. In May 2020, the Office of the Solicitor of the United States Department of the Interior issued an opinion finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River. QEP holds leases granted by the State of North Dakota covering the majority of QEP’s producing tracts underlying the Missouri River.

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Overriding Royalty Interest Litigation – In July 2019, owners of small overriding royalty interests in certain wells in the South Antelope oil and gas field in North Dakota filed suit against QEP, alleging QEP has improperly taken deductions for post-production expenses.

In many cases, the Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies. To the extent that the Company can reasonably estimate losses for contingencies where the risk of material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses to be in a range of zero to approximately $10.0 million, in the aggregate.

Note 12 – Share-Based and Long-Term Incentive Compensation

In 2018, QEP's Board and QEP's shareholders approved the QEP Resources, Inc. 2018 Long-Term Incentive Plan (LTIP), which replaced the 2010 Long-Term Stock Incentive Plan (LTSIP) and provides for the issuance of up to 10.0 million shares such that the Board may grant long-term incentive compensation. QEP issues restricted share awards, restricted cash awards and restricted share units under its LTSIP or LTIP and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees and non-employee directors. Grants issued prior to May 15, 2018 were under the LTSIP and grants issued on or after May 15, 2018 are under the LTIP. QEP recognizes the expense over the vesting periods for stock options, restricted share awards, restricted cash awards, restricted share units and performance share units. There were 3.6 million shares available for future grants under the LTIP at June 30, 2020.

Share-based compensation expense is generally recognized within "General and administrative" expense on the statements of operations and is summarized in the table below.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2020(1)		2019(2)		2020(1)		2019(2)
	(in millions)
Non-cash share-based compensation
Stock options	$	—	$	—	$	—	$	0.3
Restricted share awards	3.1		4.8		6.4		10.9
Total non-cash share-based compensation	3.1		4.8		6.4		11.2
Cash share-based compensation
Restricted cash awards	0.5		—		0.7		—
Performance share units	(0.4)		0.3		—		5.5
Restricted share units	—		0.1		—		0.2
Total cash share-based compensation	0.1		0.4		0.7		5.7
Total share-based compensation expense	$	3.2	$	5.2	$	7.1	$	16.9

 ________________________

⁽¹⁾During the three and six months ended June 30, 2020, the Company recorded $0.3 million and $0.5 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program and is included in the table above. Refer to Note 9 – Restructuring for additional information.

⁽²⁾During the three and six months ended June 30, 2019, the Company recorded $1.3 million and $9.7 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program. Of the $9.7 million recorded during the six months ended June 30, 2019, $1.5 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statement of operations and the remaining $8.2 million is included in the table above. Refer to Note 9 – Restructuring for additional information.

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Stock Options

During the six months ended June 30, 2020, QEP did not issue stock options to its employees. In periods when QEP granted stock options, the Company historically used the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of options not traded on an exchange. The Company utilized the "simplified" method to estimate the expected term of the stock options granted as there was limited historical exercise data available in estimating the expected term of the stock options. QEP used a historical volatility method to estimate the fair value of stock option awards, and the risk-free interest rate was based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over three years from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company recognizes forfeitures of stock options as they occur.

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
		(per share)		(in years)	(in millions)
Outstanding at December 31, 2019	1,802,387	$	20.87
Cancelled	(305,163)	30.12
Outstanding at June 30, 2020	1,497,224	$	18.98	2.26	$	—
Options Exercisable at June 30, 2020	1,494,157	$	19.00	2.26	$	—
Unvested Options at June 30, 2020	3,067	$	7.52	4.18	$	—

During the six months ended June 30, 2020 there were no exercises of stock options. The Company recognized $1.0 million of income tax expense for the cancellation of options for the six months ended June 30, 2020, and no income tax expense related to stock options for the six months ended June 30, 2019. As of June 30, 2020, there was less than $0.1 million of unrecognized compensation expense related to stock options granted under the LTSIP. Refer to Note 9 – Restructuring for additional information.

Restricted Share Awards

Restricted share award grants typically vest in equal installments over three years from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the six months ended June 30, 2020 and 2019 was $11.1 million and $25.0 million, respectively. The Company recognized $2.0 million of income tax expense for shares that were either vested or forfeited during the six months ended June 30, 2020, and no income tax expense related to restricted shares for the six months ended June 30, 2019. The weighted-average grant date fair value of restricted share awards was $2.10 per share and $7.98 per share for the six months ended June 30, 2020 and 2019, respectively. As of June 30, 2020, $13.0 million of unrecognized compensation expense related to restricted share awards granted under the LTSIP and LTIP is expected to be recognized over a weighted-average vesting period of 2.33 years.

Transactions involving restricted share awards under the terms of the LTSIP and LTIP are summarized below:

	Restricted Share Awards Outstanding	Weighted-Average Grant Date Fair Value
		(per share)
Unvested balance at December 31, 2019	2,845,033	$	8.67
Granted	5,080,589	2.10
Vested	(1,149,316)	9.67
Forfeited	(85,218)	5.05
Unvested balance at June 30, 2020	6,691,088	$	3.55

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Restricted Cash Awards

Beginning in March 2020, QEP issued restricted cash awards under its LTIP to certain employees. Restricted cash award grants vest in equal installments over three years from the grant date. The Company recognizes restricted cash forfeitures as they occur. There were no restricted cash awards granted or outstanding during the six months ended June 30, 2019. As of June 30, 2020, $2.6 million of unrecognized compensation expense related to restricted cash awards granted under the LTIP is expected to be recognized over a weighted-average vesting period of 2.74 years.

Transactions involving restricted cash awards under the terms of the LTIP are summarized below:

	Restricted Cash Awards Outstanding
Unvested balance at December 31, 2019	$	—
Granted	3,249,925
Vested	—
Forfeited	(54,250)
Unvested balance at June 30, 2020	$	3,195,675

Performance Share Units

The payouts associated with performance share units under the CIP are dependent upon the Company's total shareholder return compared to a group of its peers over three years. The awards are denominated in share units and have historically been paid in cash. The Company has the option to settle earned awards in cash or shares of common stock under the Company's LTIP; however, as of June 30, 2020, the Company expects to settle all awards under the CIP in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the balance sheets. Because these awards are dependent upon the Company's total shareholder return and stock price, they are remeasured at fair value at the end of each reporting period. The Company paid $0.3 million and $11.4 million, respectively, for vested performance share units during the six months ended June 30, 2020 and 2019. The weighted-average grant date fair value of the performance share units granted during the six months ended June 30, 2020 and 2019 was $2.17 and $7.93 per share, respectively. As of June 30, 2020, $1.7 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.33 years. Refer to Note 9 – Restructuring for additional information.

Transactions involving performance share units under the terms of the CIP are summarized below:

	Performance Share Units Outstanding	Weighted-Average Grant Date Fair Value
		(per share)
Unvested balance at December 31, 2019	625,922	$	9.04
Granted	1,926,026	2.17
Vested and paid	(96,734)	13.06
Unvested balance at June 30, 2020	2,455,214	$	3.56

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over three years and are deferred into the Company's Wrap Plan at the time of grant. These awards are ultimately paid in cash when distributed from the deferred compensation plan. They are classified as liabilities in "Other long-term liabilities" on the balance sheets and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $2.08 and $7.93 per share for the six months ended June 30, 2020 and 2019, respectively. The Company recognized $0.2 million of income tax expense related to restricted share units for the six months ended June 30, 2020, and no income tax expense related to restricted share units for the six months ended June 30, 2019. As of June 30, 2020, there was less than $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted. Refer to Note 9 – Restructuring for additional information.

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Transactions involving restricted share units under the terms of the LTSIP and LTIP are summarized below:

	Restricted Share Units Outstanding	Weighted-Average Grant Date Fair Value
		(per share)
Unvested balance at December 31, 2019	34,393	$	8.16
Granted	76,083	2.08
Vested and paid	(26,770)	8.20
Unvested balance at June 30, 2020	83,706	$	2.62

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP's financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2019 (2019 Form 10-K) and analyzes the changes in the results of operations between the three and six months ended June 30, 2020 and 2019. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the 2019 Form 10-K.

OVERVIEW

QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

As a result of the reduction of the Company's operational footprint in 2019 following the Board's comprehensive review of strategic alternatives and determination to move forward as an independent company, QEP reassessed its organizational needs and significantly reduced its general and administrative expense to ensure its cost structure is competitive with industry peers.

As a part of the strategic initiatives and reduction in general and administrative expense, QEP has incurred costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 3 – Acquisitions and Divestitures and Note 9 – Restructuring in Part 1, Item I of this Quarterly Report on Form 10-Q for more information.

The Company continues to focus on reducing its operating costs, per well drilling costs, general and administrative costs and managing its liquidity.  We believe our plan to generate Free Cash Flow (FCF) (a non-GAAP financial measure defined and reconciled below) on an annual basis will allow us to further strengthen our balance sheet and continue returning capital to shareholders.

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Financial and Operating Highlights

During the three months ended June 30, 2020, QEP:

•Generated a net loss of $184.4 million, or $0.76 per diluted share;

•Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $157.3 million;

•Reported oil and condensate production of 3.9 MMbbls in the Permian Basin, an increase of 18% compared to the second quarter of 2019;

•Lowered lease operating expense by 37% compared to the second quarter of 2019;

•Reduced general and administrative expenses by 17% compared to the second quarter of 2019;

•Amended the credit agreement, increasing liquidity by more than $500.0 million; and

•Repurchased a principal amount of $57.0 million of senior notes, due in 2021 and recorded a $2.1 million gain on early extinguishment of debt.

During the six months ended June 30, 2020, QEP:

•Generated net income of $183.0 million, or $0.76 per diluted share;

•Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $331.2 million;

•Reported cash provided by operating activities of $224.4 million;

•Reported Free Cash Flow (a non-GAAP measure defined and reconciled below) of $63.7 million;

•Reported oil and condensate production of 7.2 MMbbls in the Permian Basin, an increase of 16% compared to the first half of 2019;

•Lowered lease operating expense by 29% compared to the first half of 2019;

•Reduced general and administrative expenses by 55% compared to the first half of 2019;

•Recognized an additional $128.1 million in accelerated alternative minimum tax (AMT) credit refunds from the CARES Act, resulting in an aggregate income tax receivable of $165.0 million as of June 30, 2020; and

•Repurchased a principal amount of $155.2 million of senior notes, due in 2021, 2022 and 2023, and recorded a $27.5 million gain on early extinguishment of debt.

Outlook

The novel coronavirus disease (COVID-19) has created unprecedented challenges for our industry, customers and employees. The Company continues to take action to protect the core of its business and to ensure the health and safety of its employees, business partners and communities. Starting in March 2020, the Company instituted various measures, including remote working and business travel restrictions, and we remain engaged with our business and community partners on how we can assist them during this time. The Company continues to evaluate additional safeguards and has implemented new procedures and policies to help protect the health and safety of the portion of the workforce whose jobs cannot be completed from home, including those who run our field operations. We continue to monitor the guidelines and recommendations provided by the relevant authorities, and we will continue to ensure we are doing our part in preventing the spread of the virus.

As a result of lower demand caused by the COVID-19 pandemic and resulting oversupply of crude oil, the future prices of crude oil continue to be at low levels. In light of market conditions, during the first half of 2020 the Company took significant steps to proactively manage its cash flow and preserve liquidity by suspending completion operations and releasing two drilling rigs in the Permian Basin. In the Williston Basin, we have completed all operated development activity for the year. These actions have reduced the Company's capital spending forecast for 2020 by 37% compared to our original 2020 guidance. While these decisions will result in lower 2020 oil production than originally forecasted, the Company believes that it will be able to maintain positive cash flow and protect its balance sheet, with the ultimate goal of protecting shareholder returns over the long term. Although the Company has already significantly reduced activity, we are prepared to reduce activity further for an extended period if necessary. The Company has utilized the slowdown to improve on its best in class operations and will continue to reduce expenses to the lowest and most efficient cost structure possible.

Due to the Company’s derivative positions and reduction in capital expenditures, the Company expects to generate FCF in 2020 despite the current market conditions. In addition to generating FCF, the Company anticipates receiving alternative minimum tax (AMT) credit refunds of $165.6 million in the next 12 months due to changes enacted by the CARES Act. The Company expects that the generation of FCF, cash on hand, anticipated AMT credit refunds and, as needed, borrowings made under its revolving credit facility, will be sufficient to meet its liquidity needs for the next 12 months, including its debt maturity in March 2021.

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The Company believes that the overall reduction of global spending on new development projects, especially in the U.S., will cause a reduction in the global oil supply, and that the eventual recovery from the COVID-19 pandemic will cause demand to be more in line with previously anticipated levels and, consequently, cause oil prices to recover. As a result of the actions taken, and continuing to be taken, and the expected stabilization of the global economy, the Company expects to emerge in a stronger position.

Based on current commodity prices, we expect to be able to fund our planned capital program for 2020 with cash on hand and cash flow from operating activities. The mid-point of our total capital expenditures (excluding property acquisitions) for 2020 is expected to be approximately $360.0 million, a decrease of over 37% from both our 2019 capital expenditures and our original 2020 guidance. We continuously evaluate our level of drilling and completion activity in light of commodity prices, drilling results and changes in our operating and development costs and will adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.

Factors Affecting Results of Operations

Supply, Demand, Market Risk and their Impact on Oil Prices

In the second quarter of 2020 the average price of WTI crude oil dropped 33% from the second quarter of 2019. Crude oil prices were negatively impacted by a variety of factors affecting current and expected supply and demand dynamics, including: the COVID-19 pandemic and related shut-down of various sectors of the global economy, which has resulted in a significant reduction in demand for crude oil, continued U.S. supply growth driven by advances in drilling and completion technologies, and the delay of an agreement in early 2020 on production levels by members of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries, resulting in increased supply in the global market. Other factors impacting the supply and demand of our products include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar as well as other factors, the majority of which are outside of our control. While OPEC and other oil producing countries have reduced production levels, and U.S. production has declined, a significant crude oil price recovery is not expected until global supply matches current lower levels of demand caused by the factors mentioned above, including the COVID-19 pandemic.

Changes in the market prices for oil directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, its proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. The decline in the price of crude oil negatively impacted our oil revenue during the second quarter of 2020 but the value of our realized oil derivatives portfolio increased significantly, helping to offset the negative impact. Additionally, the volatility in commodity prices has impacted the Company’s stock price and the fair value of the Company's debt securities, all of which impact our financial and operating results. Due to the changes in our drilling plans, we expect that our 2020 PUD conversion rate will be lower than originally anticipated; however, our total PUD reserves currently remain unchanged. Our future drilling plans, including our level of expenditures for the development of our oil reserves, total PUD reserves, operations and financial condition may be materially and adversely affected by declines in future oil prices.

QEP's producing properties are primarily located in the Permian and Williston basins. As a result of our lack of diversification

in asset type and limited geographic diversification, any delays or interruptions of production caused by factors such as

governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation, price

fluctuations, natural disasters or shutdowns of the pipelines, connecting our production to refineries, including the potential shutdown of the Dakota Access Pipeline, would have a significantly greater impact on our results of operations than if we possessed more diverse assets and locations.

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Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including global economic issues impacted by COVID-19; political unrest; oil producing countries' oil production and policies regarding production quotas; actions taken by the United States Congress and the President of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; the impact of regulations and public and financial market sentiment regarding environmental, social and governance matters; commodity price volatility; tariffs on goods we use in our operations or on the products we sell; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP have had, and could continue to have, a significant impact on short-term and long-term oil and condensate, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs which could materially impact the Company's financial position, results of operations and cash flow from operations. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices.

Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on maintaining a sufficient liquidity position to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. Gains on settled derivatives offset a large portion of the impact of the recent decline in oil prices on our oil revenues. There can be no assurances that we will be able to add derivative positions to cover the balance of our forecasted production for 2021 at favorable prices. See Part 1, Item 3 – "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP's commodity derivatives transactions.

Potential for Future Asset Impairments

The carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development and operating costs and expenses and, therefore, are at risk of impairment. The Company uses a cash flow model to assess its proved oil and gas properties and operating lease right-of-use assets for impairment. The cash flow model includes numerous assumptions, including estimates of future oil and condensate, gas and NGL production, estimates of future prices for production that are based on the price forecast that management uses to make investment decisions, including estimates of basis differentials, future operating costs, transportation expenses, production taxes, and development costs that management believes are consistent with its price forecast, and discount rates. Management also considers a number of other factors, including the forward curve for future oil and gas prices, and developments in regional transportation infrastructure when developing its estimate of future prices for production. All inputs for the cash flow model are evaluated at each date of estimate.

We base our estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development drilling plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs. The signing of a purchase and sale agreement could also cause the Company to recognize an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value.

During the six months ended June 30, 2020, the Company recorded no impairment charges. During the six months ended June 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

We could be at risk for proved and unproved property and operating lease right-of-use asset impairments if current market conditions persist for an extended period of time, we experience negative changes in estimated reserve quantities or the

forward oil prices decline from June 30, 2020 levels. The actual amount of impairment incurred, if any, for oil and gas properties will depend on a variety of factors including, but not limited to: subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with our properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.

29

Income Tax

The tax legislation enacted in December 2017 reduced our federal corporate tax rate from 35% to 21%. In addition, the tax legislation eliminated the corporate Alternative Minimum Tax (AMT), allowing the Company to claim AMT refunds for AMT credits carried forward from prior tax years. The Company received $73.9 million of AMT credit refunds in 2019. The CARES Act enacted in March 2020 permitted the Company to carry back its net operating loss (NOL) generated in 2018, creating additional AMT credits, and accelerate all of its AMT credit refunds. The Company now anticipates that after carrybacks it will receive $165.6 million of AMT credit refunds which are included in "Income tax receivable" on the balance sheets as of June 30, 2020.

Acquisitions and Divestitures

QEP's strategy is to generate FCF, and it believes its inventory of identified drilling locations provides a solid base to achieve this strategy, but it will continue to evaluate and potentially acquire properties in its operating areas to add additional development opportunities and facilitate the drilling of long lateral wells.

Acquisitions

During the six months ended June 30, 2020 and 2019, QEP acquired various oil and gas properties, which primarily included proved acreage in the Permian Basin for an aggregate purchase price of $4.1 million and $1.8 million, respectively, subject to post-closing purchase price adjustments.

Divestitures

During the six months ended June 30, 2020, QEP received net cash proceeds of $12.9 million and recorded a net pre-tax gain on sale of $3.7 million, primarily related to the divestiture of properties outside its main operating areas.

In January 2019, QEP sold its Haynesville/Cotton Valley assets (Haynesville Divestiture) and during the year ended December 31, 2019, reached final settlement on asserted environmental and title defects and received aggregate net cash proceeds of $633.9 million. QEP recorded a total net pre-tax loss, including restructuring costs, of $4.0 million. During the three and six months ended June 30, 2019, QEP recorded $14.3 million of pre-tax gain on sale and $0.7 million of pre-tax loss on sale, respectively, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations. Refer to Note 3 – Acquisitions and Divestitures in Part 1, Item I of this Quarterly Report on Form 10-Q for more information. In addition to the Haynesville Divestiture, during the six months ended June 30, 2019, QEP recorded net cash proceeds of $39.6 million and recorded a net pre-tax gain on sale of $5.3 million related to the divestiture of properties outside our main operating areas.

Multi-Well Pad Drilling and Completion

To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling, where practical. For example, in the Permian Basin, QEP utilizes "tank-style" development, in which we simultaneously develop multiple subsurface targets by drilling and completing all wells in a given "tank" before any individual well is turned to production. We believe this approach maximizes the economic recovery of oil and condensate through the simultaneous development of multiple subsurface targets, while improving capital efficiency though shared surface facilities, which we believe will reduce per-unit operating costs and result in expanded operating margins and improve our returns on invested capital. Because wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location, multi-well pad drilling delays the completion of wells, the commencement of production from new wells, and may negatively affect production from existing offset wells. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact the timing of planned conversions of PUD reserves to proved developed reserves.

Uncertainties Related to Claims

QEP is currently subject to claims that could adversely impact QEP's liquidity, operating results and capital expenditures for a particular reporting period, including, but not limited to those described in Note 11 – Commitments and Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes.

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Critical Accounting Estimates

QEP's significant accounting policies are described in Item 7 of Part II of its 2019 Form 10-K. The Company's financial statements are prepared in accordance with GAAP. The preparation of the Company's financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of long-lived assets and income taxes, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of sustained lower commodity prices, could have a significant adverse impact to the Company’s financial condition, results of operations and cash flows.

Drilling, Completion and Production Activities

The following table presents operated and non-operated wells in the process of being drilled or waiting on completion as of June 30, 2020:

		Operated				Non-operated
	Drilling	Drilling		Waiting on completion		Drilling		Waiting on completion
	Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	—	—	—	6	4.4	—	—	21	3.4
Southern Region
Permian Basin(1)	1	9	7.8	37	33.9	—	—	4	0.4

____________________________

⁽¹⁾Eight of the nine gross operated wells in the Permian Basin represent wells for which intermediate casing had been set as of June 30, 2020.

Delays in completion of wells could impact planned conversions of PUD reserves to proved developed reserves and volatility in QEP's quarterly operating results. QEP had 43 gross operated wells waiting on completion as of June 30, 2020.

The following table presents the number of operated wells in the process of being drilled or waiting on completion at June 30, 2020 and operated wells completed and turned to sales (put on production) for the six months ended June 30, 2020:

	Permian Basin		Williston Basin
	As of June 30, 2020
	Gross	Net	Gross	Net
Well Progress
Drilling	9	7.8	—	—
Waiting to be completed	37	33.9	4	2.9
Undergoing completion	—	—	2	1.5
Waiting on completion	37	33.9	6	4.4
Put on production	36	34.4	—	—

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The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the three and six months ended June 30, 2020:

	Operated Put on Production				Non-operated Put on Production
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2020		June 30, 2020		June 30, 2020		June 30, 2020
	Gross	Net	Gross	Net	Gross	Net	Gross	Net (1)
Northern Region
Williston Basin	—	—	—	—	—	—	5	—
Southern Region
Permian Basin	11	9.5	36	34.4	—	—	—	—

_______________________

⁽¹⁾ Net working interest related to the 5 gross non-operated wells in the Williston Basin is immaterial as QEP's working interest is less than 0.1% for the three and six months ended June 30, 2020.

RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the second quarter of 2020 of $184.4 million, or $0.76 per diluted share, compared to a net income of $48.8 million, or $0.20 per diluted share, in the second quarter of 2019. The $233.2 million decrease in net income in the second quarter of 2020 compared to 2019 was primarily due to a $273.6 million increase in unrealized derivative losses, partially offset by an $83.3 million increase in income tax benefit.

During the first half of 2020, QEP generated net income of $183.0 million, or $0.76 per diluted share, compared to a net loss of $67.9 million or $0.29 per diluted share, in the first half of 2019. The $250.9 million increase in net income in the first half of 2020 compared to 2019 was primarily due to a $309.5 million increase in unrealized derivative gains, partially offset by an $95.0 million increase in income tax expense.

See below for additional discussion regarding the components of net income (loss) for each of the periods presented.

Adjusted EBITDA (Non-GAAP)

Management defines Adjusted EBITDA (a non-GAAP measure) 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, gains or losses 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 could reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

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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 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

In the second quarter of 2020, Adjusted EBITDA decreased to $157.3 million compared to $166.5 million in the second quarter of 2019, primarily due to a $176.3 million decrease in oil, gas, and NGL sales, which was primarily due to a 59% decrease in average field-level prices, partially offset by a $136.4 million increase in realized derivative gains, a $16.9 million reduction in lease operating expenses and a $14.0 million decrease in production and property taxes.

In the first half of 2020, Adjusted EBITDA increased to $331.2 million compared to $286.3 million in the first half of 2019, primarily due to a $184.9 million increase in realized derivative gains, a $52.6 million decrease in general and administrative expenses and a $28.2 million decrease in lease operating costs, partially offset by a $230.1 million decrease in oil, gas and NGL sales, primarily due to a 40% decrease in average field-level prices.

Free Cash Flow (Non-GAAP)

Management defines Free Cash Flow as Adjusted EBITDA plus non-cash share-based compensation less interest expense, excluding amortization of debt issuance costs and discounts, 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.

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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.

	Six Months Ended
	June 30,
	2020		2019
	(in millions)
Cash Flow Information:
Net Cash Provided by (Used in) Operating Activities	$	224.4	$	195.7
Net Cash Provided by (Used in) Investing Activities	(237.0)		348.1
Net Cash Provided by (Used in) Financing Activities	(149.6)		(445.6)
Free Cash Flow
Net Cash Provided by (Used in) Operating Activities	$	224.4	$	195.7
Amortization of debt issuance costs and discounts	(2.6)		(2.7)
Interest expense	61.4		67.2
Unrealized (gains) losses on marketable securities	—		2.7
Interest and other income (expense)	—		(3.7)
Deferred income taxes (benefit)	(141.4)		87.7
Income tax (provision) benefit	12.7		(82.3)
Non-cash share-based compensation	(6.4)		(11.2)
Changes in operating assets and liabilities	183.1		32.9
Adjusted EBITDA	$	331.2	$	286.3
Non-cash share-based compensation	6.4		11.2
Interest expense, excluding amortization of debt issuance costs and discounts	(58.8)		(64.5)
Accrued property, plant and equipment capital expenditures	(215.1)		(337.1)
Free Cash Flow	$	63.7	$	(104.1)

In the first half of 2020, the Company generated FCF of $63.7 million compared to an outspend of $104.1 million in the first half of 2019, primarily due to an $122.0 million decrease in accrued property, plant and equipment capital expenditures and a $44.9 million increase in Adjusted EBITDA.

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Revenue

The following table presents our revenues disaggregated by revenue source.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		Change		2020		2019		Change
	(in millions)
Oil and condensate, gas and NGL sales, as presented	$	118.3	$	294.6	$	(176.3)	$	340.1	$	570.2	$	(230.1)
Transportation and processing costs included in revenue(1)	15.3		12.7		2.6		29.6		26.5		3.1
Oil and condensate, gas and NGL sales, as adjusted(2)	133.6		$	307.3	$	(173.7)	$	369.7	$	596.7	$	(227.0)
Oil and condensate sales	$	118.5	$	285.7	$	(167.2)	$	338.5	$	535.2	$	(196.7)
Gas sales	8.8		7.3		1.5		15.3		30.3		(15.0)
NGL sales	6.3		14.3		(8.0)		15.9		31.2		(15.3)
Oil and condensate, gas and NGL sales, as adjusted(2)	$	133.6	307.3		$	(173.7)	$	369.7	$	596.7	$	(227.0)

 ____________________________

⁽¹⁾Depending on the terms of the contract, a portion of the total transportation and processing costs incurred by the Company are deducted from revenue. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.

⁽²⁾Oil and condensate, gas and NGL sales (the most comparable GAAP measure) as presented on the statements of operations is reconciled to oil and condensate, gas and NGL sales, as adjusted (a non-GAAP measure). Management excludes costs deducted from revenue to reflect total revenue associated with its production prior to deducting any expenses. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total revenue generated from its wells for the period. 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. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP's adjusted production-related revenue categories for the three and six months ended June 30, 2020, compared to the three and six months ended June 30, 2019:

	Oil and condensate		Gas		NGL		Total
	(in millions)
Oil and condensate, gas and NGL sales, as adjusted
Three months ended June 30, 2019	$	285.7	$	7.3	$	14.3	$	307.3
Changes associated with volumes(1)	17.0		0.9		(0.3)		17.6
Changes associated with prices(2)	(184.2)		0.6		(7.7)		(191.3)
Three months ended June, 2020	$	118.5	$	8.8	$	6.3	$	133.6
Oil and condensate, gas and NGL sales, as adjusted
Six months ended June 30, 2019	$	535.2	$	30.3	$	31.2	$	596.7
Changes associated with volumes(1)	23.3		(0.6)		2.1		24.8
Changes associated with prices(2)	(220.0)		(14.4)		(17.4)		(251.8)
Six months ended June, 2020	$	338.5	$	15.3	$	15.9	$	369.7

 ____________________________

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⁽¹⁾The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the three and six months ended June 30, 2020, as compared to the three and six months ended June 30, 2019, by the average field-level price for the three and six months ended June 30, 2019.

⁽²⁾The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the three and six months ended June 30, 2020, as compared to the three and six months ended June 30, 2019, by the respective volumes for the three and six months ended June 30, 2020. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.

Production and Pricing

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
Total production volumes (Mboe)
Northern Region
Williston Basin	2,515.0		2,962.4		(447.4)		5,493.1		6,339.4		(846.3)
Other Northern	4.4		21.0		(16.6)		7.0		45.7		(38.7)
Southern Region
Permian Basin	5,453.2		4,552.4		900.8		10,399.9		8,634.7		1,765.2
Haynesville/Cotton Valley	—		(6.3)		6.3		—		310.9		(310.9)
Other Southern	0.3		5.2		(4.9)		3.8		10.3		(6.5)
Total production	7,972.9		7,534.7		438.2		15,903.8		15,341.0		562.8
Total equivalent prices (per Boe)
Average field-level equivalent price	$	16.76	$	40.77	$	(24.01)	$	23.25	$	38.89	$	(15.64)
Commodity derivative impact	15.10		(2.13)		17.23		10.25		(1.43)		11.68
Net realized equivalent price	$	31.86	$	38.64	$	(6.78)	$	33.50	$	37.46	$	(3.96)

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Oil and Condensate Volumes and Prices

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
Oil and condensate production volumes (Mbbl)
Northern Region
Williston Basin	1,600.6		1,861.4		(260.8)		3,506.3		4,019.4		(513.1)
Other Northern	1.1		13.0		(11.9)		(2.1)		24.0		(26.1)
Southern Region
Permian Basin	3,856.8		3,273.9		582.9		7,173.1		6,188.4		984.7
Other Southern	—		2.0		(2.0)		0.3		2.1		(1.8)
Total production	5,458.5		5,150.3		308.2		10,677.6		10,233.9		443.7
Average field-level oil prices (per bbl)
Northern Region	$	22.15	$	57.60	$	(35.45)	$	32.74	$	54.00	$	(21.26)
Southern Region	$	21.54	$	54.24	$	(32.70)	$	31.20	$	51.18	$	(19.98)
Average field-level price	$	21.72	$	55.46	$	(33.74)	$	31.70	$	52.30	$	(20.60)
Commodity derivative impact	22.01		(3.11)		25.12		15.24		(1.85)		17.09
Net realized price	$	43.73	$	52.35	$	(8.62)	$	46.94	$	50.45	$	(3.51)

Oil and condensate revenues decreased $167.2 million, or 59%, in the second quarter of 2020 compared to the second quarter of 2019, due to lower average field-level prices, partially offset by higher aggregate oil and condensate production volumes. Average field-level oil prices decreased 61% in the second quarter of 2020 compared to the second quarter of 2019, primarily driven by a decrease in average NYMEX-WTI oil prices and a $1.85 per bbl, or 42%, increase in the basis differential relative to the average NYMEX-WTI oil price for the comparable periods. The net realized price for the second quarter of 2020 was $43.73 per barrel, which included a $22.01 per barrel positive impact from our settled derivative contracts. The net realized price was 16% lower than the $52.35 per barrel in the second quarter of 2019 due to the significant decline in the average field-level price. The 6% increase in production volumes was primarily driven by an increase in production in the Permian Basin due to continued drilling and completion activity in the second quarter of 2020 and improved well performance attributable to well completion design, partially offset by a decrease in production in the Williston Basin due to a reduced level of activity.

Oil and condensate revenues decreased $196.7 million, or 37%, in the first half of 2020 compared to the first half of 2019, due to lower average field-level prices, partially offset by higher aggregate oil and condensate production volumes. Average field-level oil prices decreased 39% in the first half of 2020 compared to the first half of 2019, primarily driven by a decrease in average NYMEX-WTI oil prices, partially offset by a $0.23 per bbl, or 5%, decrease in the basis differential relative to the average NYMEX-WTI oil price for the comparable periods. The net realized price for the first half of 2020 was $46.94 per barrel, which included a $15.24 per barrel positive impact from our settled derivative contracts. The net realized price was 7% lower than the $50.45 per barrel in the first half of 2019 due to the significant decline in the average field-level price. The 4% increase in production volumes was primarily driven by an increase in production in the Permian Basin due to continued drilling and completion activity in the first half of 2020, partially offset by a decrease in production in the Williston Basin due to a reduced level of activity.

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Gas Volumes and Prices

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	2.7		3.5		(0.8)		5.7		7.3		(1.6)
Other Northern	0.1		—		0.1		0.1		0.1		—
Southern Region
Permian Basin	5.3		3.7		1.6		10.4		7.1		3.3
Haynesville/Cotton Valley	—		—		—		—		1.9		(1.9)
Other Southern	—		—		—		—		—		—
Total production	8.1		7.2		0.9		16.2		16.4		(0.2)
Average field-level gas prices (per Mcf)
Northern Region	$	1.44	$	2.15	$	(0.71)	$	1.52	$	2.72	$	(1.20)
Southern Region	$	0.89	$	(0.06)	$	0.95	$	0.63	$	1.12	$	(0.49)
Average field-level price	$	1.08	$	1.01	$	0.07	$	0.95	$	1.84	$	(0.89)
Commodity derivative impact	0.03		—		0.03		0.01		(0.18)		0.19
Net realized price	$	1.11	$	1.01	$	0.10	$	0.96	$	1.66	$	(0.70)

During the second quarter of 2020, the Company elected to reject ethane in the Permian Basin. Gas revenues increased $1.5 million, or 21%, in the second quarter of 2020 compared to the second quarter of 2019, due to higher gas production volumes and higher average field-level prices. Production volumes increased 13% in the second quarter of 2020 compared to the second quarter of 2019, primarily in the Permian Basin due to continued drilling and completion activity and the decreased amount of ethane recovered as NGL. This production increase was partially offset by a decrease in production in the Williston Basin due to a reduced level of activity in the second quarter of 2020. Average field-level gas prices increased 7% in the second quarter of 2020 compared to the second quarter of 2019, primarily driven by a $0.99 per Mcf, or 61%, decrease in regional basis differentials, partially offset by a decrease in average NYMEX-HH gas spot prices in comparable periods.

Gas revenues decreased $15.0 million, or 50%, in the first half of 2020 compared to the first half of 2019, due to lower average field-level prices and lower gas production volumes. Average field-level gas prices decreased 48% in the first half of 2020 compared to the first half of 2019, primarily driven by a decrease in average NYMEX-HH gas spot prices, partially offset by a $0.17 per Mcf, or 16%, decrease in regional basis differentials relative to the average NYMEX-HH gas price in comparable periods. Production volumes decreased 1% in the first half of 2020 compared to the first half of 2019, primarily due to the Haynesville Divestiture and a reduced level of activity in the Williston Basin. These production decreases were partially offset by increased production in the Permian Basin due to continued drilling and completion activity and the decreased amount of ethane recovered as NGL in the first half of 2020.

38

NGL Volumes and Prices

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	449.7		526.6		(76.9)		1,035.1		1,105.4		(70.3)
Other Northern	(0.1)		0.7		(0.8)		0.5		0.4		0.1
Southern Region
Permian Basin	714.9		658.6		56.3		1,497.7		1,258.5		239.2
Other Southern	0.1		0.1		—		0.4		0.5		(0.1)
Total production	1,164.6		1,186.0		(21.4)		2,533.7		2,364.8		168.9
Average field-level NGL prices (per bbl)
Northern Region	$	0.97	$	10.96	$	(9.99)	$	3.83	$	11.91	$	(8.08)
Southern Region	$	8.25	$	12.94	$	(4.69)	$	8.00	$	14.30	$	(6.30)
Average field-level price	$	5.44	$	12.06	$	(6.62)	$	6.30	$	13.18	$	(6.88)
Commodity derivative impact	—		—		—		—		—		—
Net realized price	$	5.44	$	12.06	$	(6.62)	$	6.30	$	13.18	$	(6.88)

During the second quarter of 2020, the Company elected to reject ethane in the Permian Basin. NGL revenues decreased $8.0 million, or 56%, during the second quarter of 2020 compared to the second quarter of 2019, due to lower average field-level prices and lower NGL production volumes. The 55% decrease in NGL prices during the second quarter of 2020 compared to the second quarter of 2019 was primarily driven by a decrease in propane, ethane and other NGL component prices. The 2% decrease in NGL production volumes was primarily driven by decreased activity in the Williston Basin and a decreased amount of the ethane recovered in the Permian Basin, partially offset by continued drilling and completion activity in the Permian Basin.

NGL revenues decreased $15.3 million, or 49%, during the first half of 2020 compared to the first half of 2019, due to lower average field-level prices, partially offset by higher NGL production volumes. The 52% decrease in NGL prices during the first half of 2020 compared to the first half of 2019 was primarily driven by a decrease in propane, ethane and other NGL component prices. The 7% increase in NGL production volumes was primarily driven by continued drilling and completion activity in the Permian Basin and an increased amount of ethane recovered in the Williston Basin; partially offset by decreased activity in the Williston Basin and a decreased amount of ethane recovered in the Permian Basin starting in April 2020.

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Operating Expenses

The following table presents QEP production costs and production costs on a per unit of production basis:

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
	(in millions)
Lease operating expense	$	28.8	$	45.7	$	(16.9)	$	69.0	$	97.2	$	(28.2)
Adjusted transportation and processing costs(1)	27.6		22.6		5.0		55.4		47.3		8.1
Production and property taxes	9.6		23.6		(14.0)		28.3		47.6		(19.3)
Total production costs	$	66.0	$	91.9	$	(25.9)	$	152.7	$	192.1	$	(39.4)
	(per Boe)
Lease operating expense	$	3.62	$	6.06	$	(2.44)	$	4.34	$	6.34	$	(2.00)
Adjusted transportation and processing costs(1)	3.47		3.00		0.47		3.48		3.09		0.39
Production and property taxes	1.21		3.13		(1.92)		1.78		3.10		(1.32)
Total production costs	$	8.30	$	12.19	$	(3.89)	$	9.60	$	12.53	$	(2.93)

 ____________________________

⁽¹⁾Below are reconciliations of transportation and processing costs (the most comparable GAAP measure) as presented on the statements of operations and on a unit of production basis to adjusted transportation and processing costs. Adjusted transportation and processing costs includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the statements of operations. Management adds these costs together to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period. 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. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
	(in millions)
Transportation and processing costs, as presented	$	12.3	$	9.9	$	2.4	$	25.8	$	20.8	$	5.0
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	15.3		12.7		2.6		29.6		26.5		3.1
Adjusted transportation and processing costs	$	27.6	$	22.6	$	5.0	$	55.4	$	47.3	$	8.1
	(per Boe)
Transportation and processing costs, as presented	$	1.55	$	1.31	$	0.24	$	1.62	$	1.36	$	0.26
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.92		1.69		0.23		1.86		1.73		0.13
Adjusted transportation and processing costs	$	3.47	$	3.00	$	0.47	$	3.48	$	3.09	$	0.39

Lease operating expense (LOE). QEP's LOE decreased $16.9 million, or 37%, in the second quarter of 2020 compared to the second quarter of 2019, primarily due to a decrease in workover activity, water disposal expenses, maintenance and repair expenses, and power and fuel expenses in the Williston and Permian basins as a result of continuing efforts to reduce operating expenses.

During the second quarter of 2020, LOE decreased $2.44 per Boe, or 40%, compared to the second quarter of 2019, primarily due to continuing efforts to reduce operating expenses.

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QEP's LOE decreased $28.2 million, or 29%, in the first half of 2020 compared to the first half of 2019, primarily due to a decrease in workover activity, maintenance and repair expenses, power and fuel expenses, water disposal expenses, and labor in the Williston and Permian basins as a result of continuing efforts to reduce operating expenses.

During the first half of 2020, LOE decreased $2.00 per Boe, or 32%, compared to the first half of 2019, primarily due to continuing efforts to reduce operating expenses.

Adjusted transportation and processing costs (non-GAAP). Adjusted transportation and processing costs increased $5.0 million, or 22%, in the second quarter of 2020 compared to the second quarter of 2019. The increase in expense was primarily due to an increase in both production and gathering and processing rates in the Permian Basin and increased gathering and processing rates in the Williston Basin, partially offset by decreased production in the Williston Basin.

During the second quarter of 2020, adjusted transportation and processing costs increased $0.47 per Boe, or 16%, compared to the second quarter of 2019. The increase was primarily due to increased gathering and processing rates in the Williston and Permian basins.

Adjusted transportation and processing costs increased $8.1 million, or 17%, in the first half of 2020 compared to the first half of 2019. The increase in expense was primarily due to increased production in the Permian Basin and increased gathering and processing rates in the Williston Basin, partially offset by the Haynesville Divestiture and decreased production in the Williston Basin.

During the first half of 2020, adjusted transportation and processing costs increased $0.39 per Boe, or 13%, compared to the first half of 2019. The increase was primarily due to increased gathering and processing rates in the Williston Basin, partially offset by the Haynesville Divestiture, which had higher adjusted transportation and processing costs per Boe.

Production and property taxes. Production and property taxes decreased $14.0 million, or 59%, in the second quarter of 2020 compared to the second quarter of 2019, primarily due to decreased revenues in the Williston and Permian basins and the related production taxes, combined with decreased property tax expense in the Permian Basin.

During the second quarter of 2020, production and property taxes decreased $1.92 per Boe, or 61%, compared to the second quarter of 2019, primarily due to a decrease in revenues and the associated production taxes in the Williston and Permian basins and lower property tax expense per Boe in the Permian Basin.

Production and property taxes decreased $19.3 million, or 41%, in the first half of 2020 compared to the first half of 2019, primarily due to decreased revenues in the Williston and Permian basins and the related production taxes, combined with decreased property tax expense in the Permian Basin.

During the first half of 2020, production and property taxes decreased $1.32 per Boe, or 43%, compared to the first half of 2019, primarily due to a decrease in revenues and the associated production taxes in the Williston and Permian basins and lower property tax expense per Boe in the Permian Basin.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $21.4 million in the second quarter of 2020 compared to the second quarter of 2019, primarily due to increased production in the Permian Basin and higher DD&A rates in the Permian and Williston basins. The increases in DD&A expense were partially offset by a decrease in production in the Williston Basin.

DD&A expense increased $40.3 million in the first half of 2020 compared to the first half of 2019, primarily due to increased production in the Permian Basin and higher DD&A rates in the Permian and Williston basins. The increases in DD&A expense were partially offset by a decrease in production in the Williston Basin.

Impairment expense. During the second quarter of 2020 and 2019, there were no impairment charges.

During the first half of 2020, there were no impairment charges. During the first half of 2019, QEP recorded impairment charges of $5.0 million, which related to impairment of an office building lease.

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General and administrative (G&A) expense.

The following table presents detail about QEP's share-based compensation and deferred compensation components of QEP's total general and administrative expense, including the cash and non-cash components, for the three and six months ended June 30, 2020 and 2019.

	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		Change		2020		2019		Change
	(in millions)
General and administrative (excluding share-based compensation and deferred compensation)	$	18.1	$	26.0	$	(7.9)	$	38.3	$	74.2	$	(35.9)
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-cash share-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-cash share-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 wrap plan (Wrap Plan). Refer to Note 1 – Basis of Presentation, in Item I of Part I of this Quarterly Report on Form 10-Q for more information on the Wrap Plan.

During the second quarter of 2020, G&A expense decreased $5.2 million, or 17%, compared to the second quarter of 2019. During the second quarter of 2020 and 2019, QEP incurred $0.6 million and $7.2 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $0.5 million and $6.0 million, respectively, related to restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding costs associated with the implementation of our strategic initiatives, G&A expense increased by $1.5 million, or 6%, primarily due to a $4.7 million increase in expense related to the increase in market value on the deferred compensation plan, partially offset by a $3.2 million decrease in labor, benefits and bonus, primarily due to workforce reductions.

During the first half of 2020, G&A expense decreased $52.6 million, or 55%, compared to the first half of 2019. During the first half of 2020 and 2019, QEP incurred $2.0 million and $33.2 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $1.9 million and $26.3 million, respectively, related to restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding costs associated with the implementation of our strategic initiatives, G&A expense decreased by $21.4 million, or 35%, primarily due to an $11.6 million decrease in labor, benefits and bonus, primarily due to workforce reductions, a $6.9 million decrease in expense related to the decrease in market value on the deferred compensation plan and a $2.3 million decrease in share-based compensation due to the reduction in workforce and the decline in QEP's stock price.

Net gain (loss) from asset sales, inclusive of restructuring costs. During the second quarter of 2020, QEP recognized a gain on the sale of assets of less than $0.1 million, primarily related to divestitures of properties outside our main operating areas. During the second quarter of 2019, QEP recognized a gain on the sale of assets of $17.8 million, primarily related to a net pre-tax gain on sale of $14.3 million related to our Haynesville Divestiture.

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During the first half of 2020, QEP recognized a gain on the sale of assets of $3.7 million, primarily related to divestitures of properties outside our main operating areas. During the first half of 2019, QEP recognized a gain on the sale of assets of $4.6 million, primarily related to the $5.5 million gain from the divestiture of other properties, partially offset by a net pre-tax loss on sale of $0.7 million related to our Haynesville Divestiture, which included $4.3 million of restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information).

Non-operating Expenses

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts, which are marked-to-market each quarter. During the second quarter of 2020, losses on commodity derivative contracts were $98.7 million, of which $219.1 million were unrealized losses and $120.4 million were realized gains on settled derivative contracts. During the second quarter of 2019, gains on commodity derivative contracts were $38.5 million, of which $54.5 million were unrealized gains and $16.0 million were realized losses on settled derivative contracts.

During the first half of 2020, gains on commodity derivative contracts were $351.2 million, of which $188.2 million were unrealized gains and $163.0 million were realized gains on settled derivative contracts. During the first half of 2019, losses on commodity derivative contracts were $143.2 million, of which $123.1 million were unrealized losses, $21.9 million were realized losses on settled derivative contracts and $1.8 million were unrealized gains related to the Haynesville Divestiture (refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information).

Gain on early extinguishment of debt. Gain on early extinguishment of debt increased by $0.4 million in the second quarter of 2020 compared to the second quarter of 2019. The increase during the second quarter of 2020 was primarily due to a $2.1 million gain as a result of repurchasing $57.0 million in principal amount of our senior notes at a discount, partially offset by a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility (Refer to Note 10 – Debt, in Item 1 of Part I of this Quarterly Report on Form 10-Q for more information).

Gain on early extinguishment of debt increased by $25.6 million in the first half of 2020 compared to the first half of 2019. The increase during the first half of 2020 was primarily due to a $27.5 million gain as a result of repurchasing $155.2 million in principal amount of our senior notes at a discount, partially offset by a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility (Refer to Note 10 – Debt, in Item 1 of Part I of this Quarterly Report on Form 10-Q for more information).

Interest and other income (expense). Interest and other income (expense) increased by $1.7 million, or 189%, during the second quarter of 2020 compared to the second quarter of 2019. The increase was primarily related to a $2.4 million gain on the marketable securities associated with its nonqualified, unfunded deferred compensation plan, partially offset by a $0.7 million loss on the write-off of inventory.

Interest and other income (expense) decreased by $3.7 million, or 100%, during the first half of 2020 compared to the first half of 2019. The decrease was primarily related to a $2.6 million loss on the marketable securities associated with its nonqualified, unfunded deferred compensation plan and a $0.7 million loss on the write-off of inventory.

Interest expense. Interest expense decreased $3.4 million, or 10%, during the second quarter of 2020 compared to the second quarter of 2019. The decrease during the second quarter of 2020 was primarily related to decreased interest expense on senior notes due to repurchases, a reduction of accrued interest on the Company's uncertain tax position that expired in the fourth quarter of 2019 and decreased borrowings under the credit facility.

Interest expense decreased $5.8 million, or 9%, during the first half of 2020 compared to the first half of 2019. The decrease during the first half of 2020 was primarily related to decreased interest expense on senior notes due to repurchases, a reduction of accrued interest on the Company's uncertain tax position that expired in the fourth quarter of 2019 and decreased borrowings under the credit facility.

Income tax (provision) benefit. Income tax expense decreased $83.3 million and was a benefit during the second quarter of 2020 compared to an expense during the second quarter of 2019. The decrease in expense was primarily the result of having a pre-tax loss during the second quarter of 2020 compared to pre-tax income in 2019. QEP’s effective federal and state income tax rate was 22.5% during the second quarter of 2020 compared to a rate of 37.8% during the second quarter of 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items recognized during the second quarter of 2019. The primary discrete item recognized during the second quarter of 2019 related to non-deductible executive compensation.

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Income tax benefit decreased $95.0 million during the first half of 2020 compared to the first half of 2019. The decrease in benefit was the result of having pre-tax income during the first half of 2020 compared to a pre-tax loss in 2019. QEP’s effective federal and state income tax rate was 6.5% during the first half of 2020 compared to a rate of 54.8% during the first half of 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items recognized during the first half of 2020 and 2019. The primary discrete items recognized during the first half of 2020 related to the remeasurement of deferred taxes due to a NOL carryback under the CARES Act to a year with a higher federal tax rate. The primary discrete items recognized during the first half of 2019 related to the remeasurement of deferred taxes associated with the Haynesville Divestiture and non-deductible executive compensation.

LIQUIDITY AND CAPITAL RESOURCES

QEP strives to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations and capital expenditures and return capital to shareholders. The Company utilizes derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility. QEP also periodically accesses debt and equity markets and sells properties to enhance its liquidity. In an effort to preserve our liquidity, in March 2020, the Board indefinitely suspended the payment of quarterly dividends. The Company expects that the annual generation of Free Cash Flow, cash on hand, anticipated AMT credit refunds and, as needed, borrowings made under its revolving credit facility, will be sufficient to fund its operations, capital expenditures, interest expense and debt maturities, including $275.3 million of Senior Notes due March 1, 2021, during the next 12 months. To the extent that the Company sells additional assets, the Company plans to use the proceeds to fund on-going operations, reduce debt and for general corporate purposes.

During the six months ended June 30, 2020, QEP received cash proceeds from the disposition of assets of $12.9 million. QEP used the proceeds to repurchase a portion of its senior notes and for general corporate purposes.

As of June 30, 2020, the Company had $3.4 million in cash and cash equivalents, no borrowings under its revolving credit facility and $10.9 million in letters of credit outstanding. The Company estimates that as of June 30, 2020, it could borrow up to $742.5 million under its credit facility and incur up to $500.0 million of junior guaranteed indebtedness and remain in compliance with its financial covenants (as defined in the credit agreement). To the extent actual operating results, realized commodity prices, receipt of AMT credit refunds or uses of cash differ from the Company's assumptions, QEP's liquidity could be adversely affected. Further, we may from time to time seek to retire, amend or restructure some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Facility

In June 2020, QEP entered into the Eighth Amendment to its credit agreement, which, among other things, reduced the aggregate principal amount of commitments to $850.0 million, requires the Company’s material subsidiaries to guarantee the obligations under the credit agreement as well as certain swap obligations and modified the leverage ratio and present value financial covenants, such that they only pertain to net priority guaranteed debt (primarily consisting of borrowings under the credit facility and letters of credit). The amended credit agreement also provides the ability to use up to $500.0 million of loan proceeds to repurchase outstanding senior notes, provides the ability to issue subsidiary guarantees of up to $500.0 million of unsecured debt, with such guarantees being subordinated to the obligations under the credit agreement, and may limit the Company’s ability to make certain restricted payments, including dividends. The amended credit agreement, which matures on September 1, 2022, provides for borrowings at short-term interest rates and contains customary covenants and restrictions and contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a minimum liquidity amount of at least $100.0 million (ii) a net priority guaranteed leverage ratio under which net priority guaranteed debt may not exceed 2.50 times consolidated EBITDAX (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net priority guaranteed debt by at least 1.50 times at any time on or after June 4, 2020. At June 30, 2020 and December 31, 2019, QEP was in compliance with the covenants under its credit agreement. The Company recorded a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility and recorded the loss within "Gain from early extinguishment of debt" on the statements of operations.

As of June 30, 2020, QEP had no borrowings outstanding and $10.9 million in letters of credit outstanding under the credit facility. As of July 22, 2020, QEP had no borrowings outstanding and had $10.9 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

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Senior Notes

The Company's senior notes outstanding as of June 30, 2020 totaled a principal amount of $1,877.2 million and are comprised of four issuances as follows:

•$275.3 million 6.875% Senior Notes due March 2021;

•$465.1 million 5.375% Senior Notes due October 2022;

•$636.8 million 5.25% Senior Notes due May 2023; and

•$500.0 million 5.625% Senior Notes due March 2026.

During the six months ended June 30, 2020, QEP repurchased principal amounts of $107.1 million of its 6.875% Senior Notes due March 2021, $34.9 million of its 5.375% Senior Notes due October 1, 2022 and $13.2 million of its 5.25% Senior Notes due May 1, 2023. The Company recorded $27.5 million in "Gain from early extinguishment of debt" on the statements of operations primarily associated with the repurchase of Senior Notes during the period ended June 30, 2020.

The Company expects to fund the maturity of its 6.875% Senior Notes due March 2021 with cash on hand, the generation of FCF, the anticipated AMT credit refunds and, as needed, borrowings made under its revolving credit facility.

Cash Flow from Operating Activities

Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months.

Net cash provided by (used in) operating activities is presented below:

	Six Months Ended June 30,
	2020		2019		Change
	(in millions)
Net income (loss)	$	183.0	$	(67.9)	$	250.9
Non-cash adjustments to net income (loss)	224.5		296.5		(72.0)
Changes in operating assets and liabilities	(183.1)		(32.9)		(150.2)
Net cash provided by (used in) operating activities	$	224.4	$	195.7	$	28.7

Net cash provided by operating activities was $224.4 million during the first half of 2020, which included $183.0 million of net income, $224.5 million of non-cash adjustments to net income and $183.1 million in changes in operating assets and liabilities. Non-cash adjustments to net income of $224.5 million primarily included DD&A expense of $291.6 million and deferred income tax of $141.4 million, partially offset by $188.2 million of unrealized gains on derivative contracts and $25.6 million of gains from early extinguishment of debt.

The changes in operating assets and liabilities of $183.1 million primarily resulted from an increase in income tax receivable of $127.6 million and a decrease in accounts payable and accrued expenses of $39.7 million.

Net cash provided by operating activities was $195.7 million during the first half of 2019, which included $67.9 million of net loss, $296.5 million of non-cash adjustments to the net loss and $32.9 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of $296.5 million primarily included DD&A expense of $251.3 million, $121.3 million of unrealized losses on derivative contracts, and $11.2 million of non-cash share-based compensation expense, partially offset by $87.7 million of deferred income tax benefit and net gain from assets sales, inclusive of restructuring costs, of $4.6 million.

The decrease in changes in operating assets and liabilities of $32.9 million primarily resulted from decreases in accounts payable and accrued expenses of $54.0 million, partially offset by a decrease in accounts receivable of $21.2 million.

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Cash Flow from Investing Activities

A comparison of capital expenditures for the first half of 2020 and 2019, are presented in the table below:

	Six Months Ended June 30,
	2020		2019		Change
	(in millions)
Property acquisitions	$	4.1	$	1.8	$	2.3
Property, plant and equipment capital expenditures	215.1		337.1		(122.0)
Total accrued capital expenditures	219.2		338.9		(119.7)
Change in accruals and other non-cash adjustments	$	30.7	$	(20.3)	$	51.0
Total cash capital expenditures	$	249.9	$	318.6	$	(68.7)

In the first half of 2020, on an accrual basis, the Company invested $215.1 million on property, plant and equipment capital expenditures (which excludes property acquisitions), a decrease of $122.0 million compared to the first half of 2019. In the first half of 2020, QEP's primary capital expenditures included $159.6 million in the Permian Basin (including midstream infrastructure of $9.9 million, primarily related to oil and gas gathering and water handling) and $54.5 million in the Williston Basin.

In the first half of 2019, on an accrual basis, the Company invested $337.1 million on property, plant and equipment capital expenditures (which excludes property acquisitions). QEP's significant capital expenditures included $307.0 million in the Permian Basin (including midstream infrastructure of $32.9 million, primarily related to oil and gas gathering and water handling), and $31.0 million in the Williston Basin.

The mid-point of our 2020 forecasted capital expenditures (excluding property acquisitions) is $360.0 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash on hand, cash flow from operating activities and proceeds from our derivative portfolio. The aggregate levels of capital expenditures for 2020 and the allocation of those expenditures are dependent on a variety of factors, including the continued impact on the market due to the COVID-19 pandemic and OPEC actions, oil, gas and NGL prices, industry conditions, changes in management's business assessments as to where QEP's capital can be most profitably deployed, drilling results, the extent to which properties or working interests are acquired or divested and the availability of capital resources to fund the expenditures. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.

Cash Flow from Financing Activities

In the first half of 2020, net cash used in financing activities was $149.6 million compared to net cash used in financing activities of $445.6 million in the first half of 2019. During the first half of 2020, QEP used $127.7 million of cash to repurchase senior notes and pay a quarterly dividend of $4.8 million. During the first half of 2020, QEP had a decrease in checks outstanding in excess of cash balances of $15.9 million.

During the first half of 2019, QEP made repayments on its credit facility of $486.0 million and had borrowings from its credit facility of $56.0 million. In addition, QEP had treasury stock repurchases of $6.3 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. During the first half of 2019, QEP had a decrease in checks outstanding in excess of cash balances of $9.3 million.

As of June 30, 2020, the total amount of long-term debt was $1,864.3 million, of which $1,877.2 million was the principal amount of its senior notes and $12.9 million was net original issue discount and unamortized debt issuance costs.

Off-Balance Sheet Arrangements

QEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At June 30, 2020, the Company's material off-balance sheet arrangements included drilling, gathering, processing and firm transportation arrangements and undrawn letters of credit. There are no other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on QEP's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. For more information regarding off-balance sheet arrangements, we refer you to "Contractual Cash Obligations and Other Commitments" in our 2019 Annual Report on Form 10-K.

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Contractual Cash Obligations and Other Commitments

We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our 2019 Annual Report on Form 10-K.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP's primary market risks arise from changes in the market price for oil, gas and NGL and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. In addition, additional non-cash impairment expense of the Company's oil and gas properties may be required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company's exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters into interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of June 30, 2020, QEP held commodity price derivative contracts, excluding basis swaps, totaling 15.0 million barrels of oil and 36.6 million MMBtu of gas. As of December 31, 2019, QEP held commodity price derivative contracts, excluding basis swaps, totaling 17.5 million barrels of oil and no commodity price gas derivatives.

The following tables present QEP's volumes and average prices for its derivative positions as of July 22, 2020. Refer to Note 7 – Derivative Contracts in Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of June 30, 2020.

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/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		(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 Derivative Basis Swaps
Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2020	NYMEX WTI	Argus WTI Midland	3.7	$	0.22
2021	NYMEX WTI	Argus WTI Midland	4.4	$	0.99

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Changes in the fair value of derivative contracts from December 31, 2019 to June 30, 2020, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2019	$	(17.5)
Contracts settled	(163.0)
Change in oil and gas prices on futures markets	353.1
Contracts added	(2.0)
Net fair value of oil derivative contracts outstanding at June 30, 2020	$	170.6

The following table shows the sensitivity of the fair value of oil derivative contracts to changes in the market price of oil and basis differentials:

	June 30, 2020
	(in millions)
Net fair value – asset (liability)	$	170.6
Fair value if market prices of oil and basis differentials decline by 10%	$	187.7
Fair value if market prices of oil and basis differentials increase by 10%	$	153.6

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $17.0 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $17.1 million as of June 30, 2020. However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company's commodity derivative transactions, refer to Note 7 – Derivative Contracts in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest Rate Risk Management

The Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. During the period ended and at June 30, 2020, the Company had no borrowings outstanding under its revolving credit facility.

The $1,877.2 million of debt outstanding as of June 30, 2020 relates to senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company's debt instruments, refer to Note 10 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

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Forward-Looking Statements

The quarterly report contains information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:

•our strategic objectives;

•expectation to generate free cash flow and focus on reduction of operating costs, drilling costs and general and administrative expenses;

•effect of the COVID-19 pandemic on our business results;

•forecasted 2020 oil production;

•the belief that the Company will be able to maintain positive cash flow and protect its balance sheet, with the ultimate goal of protecting shareholder returns over the long term;

•expectation of proved undeveloped (PUD) reserve conversion rate and total PUD reserves;

•the coverage and amounts of insurance are consistent with industry practice;

•drilling and completion plans and strategies;

•evaluation and potential acquisition of properties in our operating areas to add additional development opportunities and facilitate the drilling of long lateral wells;

•expectations and assumptions regarding oil, gas and NGL prices, and the effects of those prices on our business;

•volatility of oil, gas and NGL prices and factors impacting such prices;

•beliefs about the reduction of global spending on new oil and gas projects and a corresponding reduction in the global oil supply;

•expectations regarding the impact of the agreement among OPEC and other oil producing countries on oil prices;

•factors impacting our ability to transport oil and condensate and gas;

•credit agreement limitations that could prevent QEP from incurring certain indebtedness, which could limit QEP's ability to engage in acquisitions;

•the conditions impacting the timing and amount of share repurchases under our share repurchase program;

•the adjustments made to GAAP Measures to arrive at non-GAAP measures and the usefulness of non-GAAP financial measures;

•our inventory of drilling locations and the ability of that inventory to provide a solid base for generating free cash flow and capital efficiency;

•our balance sheet and sufficient liquidity providing for the ability to ensure financial flexibility, withstand commodity price volatility and fund our development projects, operations and capital expenditures and return capital to shareholders;

•our ability to fund maturities of senior notes;

•future availability under our revolving credit facility or continued compliance with restrictive financial covenants;

•adjustments to our capital investment program based on a variety of factors, including an evaluation of drilling and completion activities and drilling results;

•amount and allocation of forecasted capital expenditures (excluding property acquisitions) and, plans and sources for funding operations and capital investments;

•impact of lower or higher commodity prices and interest rates;

•potential for asset impairments and factors impacting impairment amounts;

•fair value estimates and related assumptions and assessment of the sensitivity of changes in assumptions, and critical accounting estimates, including estimated asset retirement obligations;

•impact of global geopolitical and macroeconomic events and the monitoring of such events;

•plans regarding derivative contracts, including the volumes utilized, and the anticipated benefits derived there from;

•outcome and impact of various claims;

•expected cost savings and other efficiencies from multi-well pad drilling, including "tank-style" development;

•delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling;

•value of pension plan assets and our plans regarding additional contributions to our Pension Plan, nonqualified retirement plan (SERP) and Medical Plan;

•estimates of the amount of additional indebtedness we may incur under our revolving credit facility;

•off-balance sheet arrangements;

•potential retirement of debt through various options, including exchanges, open market purchases, tender offers and privately negotiated transactions;

•factors impacting our ability to borrow and the interest rates offered;

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•assumptions regarding share-based compensation;

•settlement of performance share units and restricted share units in cash; and

•alternative minimum tax credit refunds and timing.

Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:

•the risk factors discussed in Item 1A of Part I of the 2019 Form 10-K and Item 1A of Part II of this Quarterly Report on Form 10-Q;

•changes in oil, gas and NGL prices;

•global geopolitical and macroeconomic factors;

•general economic conditions, including the performance of financial markets and interest rates;

•the length and severity of a pandemic or other health crisis, such as the recent outbreak of COVID-19 and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for oil, gas and NGLs and significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;

•the risks and liabilities associated with acquired assets;

•asset impairments;

•liquidity constraints, including those resulting from the cost and availability of debt and equity financing;

•drilling and completion strategies, methods and results;

•assumptions around well density/spacing and recoverable reserves per well prove to be inaccurate;

•changes in estimated reserve quantities;

•changes in management's assessments as to where QEP's capital can be most profitably deployed;

•shortages and costs of oilfield equipment, services and personnel;

•changes in development plans;

•lack of available pipeline, processing and refining capacity;

•processing volumes and pipeline throughput;

•risks associated with hydraulic fracturing;

•the outcome of contingencies such as legal proceedings;

•delays in obtaining permits and governmental approvals;

•operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;

•weather conditions;

•changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, renewable energy mandates, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

•derivative activities;

•potential losses or earnings reductions from our commodity price risk management programs;

•volatility in the commodity-futures market;

•failure of internal controls and procedures;

•failure of our information technology infrastructure or applications to prevent a cyberattack;

•elimination of federal income tax deductions for oil and gas exploration and development costs;

•production, severance and property taxation rates;

•discount rates;

•regulatory approvals and compliance with contractual obligations;

•actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;

•lack of, or disruptions in, adequate and reliable transportation for our production;

•competitive conditions;

•production and sales volumes;

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•actions of operators on properties in which we own an interest but do not operate;

•estimates of oil and gas reserve quantities;

•reservoir performance;

•operating costs;

•inflation;

•capital costs;

•creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;

•volatility in the securities, capital and credit markets;

•actions by credit rating agencies and their impact on the Company;

•changes in guidance issued related to tax reform legislation and the CARES Act or application of that guidance, including with respect to our anticipated alternative minimum tax credit refunds; and

•other factors, most of which are beyond the Company's control.

QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report on

Form 10-Q, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(b) under the Securities Exchange Act of 1934, as amended), as of June 30, 2020. Based on such evaluation, such officers have concluded that, as of June 30, 2020, the Company's disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission's rules and forms and that information required to be disclosed in the Company's reports filed or submitted under the Exchange Act is accumulated and communicated to the Company's management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended June 30, 2020, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. There have been no material changes with respect to the legal proceedings reported in our 2019 Form 10-K. Refer to Note 11 – Commitments and Contingencies in Item I of Part I of this Quarterly Report on Form 10-Q for additional information regarding our legal proceedings.

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ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its 2019 Form 10-K. There have been no material changes to such risk factors since filing the 2019 Form 10-K, except for the risk factors below. The risks described below and in the 2019 Form 10-K are not the only risks facing QEP. Additional risks and uncertainties not currently known to QEP or that the Company currently deems to be immaterial also may materially adversely affect its business, financial condition, or future results.

The outbreak of COVID-19 and recent oil market developments could adversely impact our financial condition and results of operations. On January 30, 2020, the WHO announced a global health emergency because of a new strain of coronavirus known as COVID-19 due to the risks it imposes on the international community as the virus spreads globally. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. COVID-19 has had and continues to have adverse repercussions across regional and global economies and financial markets which necessarily adversely affects the jurisdictions in which we operate and in turn, our business. The governments of many countries, including the United States, have reacted by instituting lockdowns, business shutdowns, quarantines and restrictions on travel. Businesses have also implemented countermeasures and safety measures to reduce the risk of transmission. Such actions have not only disrupted businesses but have had a material and adverse effect on industries and local, regional and global economies.

The crude oil market has experienced a dramatic decline in oil prices in response to concerns about oil demand due to the global economic impacts of COVID-19. In addition, policy disputes in the first quarter 2020 between OPEC and Russia resulted in Saudi Arabia significantly discounting the price of its crude oil, as well as Saudi Arabia and Russia significantly increasing their oil supply. These actions led to significant weakness in oil prices and caused us to reduce our capital and operating budgets as well as slow our development plan. In addition, the potential spread of the virus into our workforce and the workforces of our counterparties could continue to have an adverse impact on our operations.

In recent weeks, the virus has continued to rapidly spread in the jurisdictions in which we operate. The total magnitude and duration of potential social, economic and labor instability as a direct result of COVID-19 cannot be estimated at this time. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our oil and natural gas products and have an adverse effect on our financial position and results of operations. The COVID-19 pandemic had an adverse effect on our business results in the second quarter of 2020 and we expect this to continue in the third quarter of 2020. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in this “Risk Factors” section, the "Risk Factors" section of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2019, such as those relating to our indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.

The prices for oil, gas and NGL are volatile, and declines in such prices could adversely affect QEP's earnings, cash flows, asset values and stock price. Historically, oil, gas and NGL prices have been volatile and unpredictable, and that volatility is expected to continue. Volatility in oil, gas and NGL prices is due to a variety of factors that are beyond QEP's control, including:

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•changes in local, regional, domestic and foreign supply of and demand for oil, gas and NGL;

•the impact of an abundance of oil, gas and NGL from unconventional sources on the global and local energy supply;

•the level of imports and/or exports of, and the price of, foreign oil, gas and NGL;

•localized supply and demand fundamentals, including the proximity, cost and availability of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

•the availability of refining and storage capacity;

•domestic and global economic and political conditions;

•changes in government energy policies, including imposed price controls or product subsidies or both;

•speculative trading in crude oil and natural gas derivative contracts;

•the continued threat of terrorism and the impact of military and other action;

•the activities of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries such as Russia and Saudi Arabia, including the ability of members of OPEC and Russia to maintain oil price and production controls;

•including events in the Middle East, Africa, South America and Russia;

•the strength of the U.S. dollar relative to other currencies;

•weather conditions, natural disasters and epidemic or pandemic disasters such as the recent outbreak of COVID-19;

•domestic and international laws, regulations and taxes, including regulations, legislation or executive orders relating to climate change, induced seismicity or oil and gas exploration and production activities, including, but not limited to hydraulic fracturing;

•technological advances affecting energy consumption and energy supply;

•conservation efforts;

•the price, availability and acceptance of alternative energy sources, including coal, nuclear energy, renewables and biofuels;

•demand for electricity and natural gas used as fuel for electricity generation;

•pandemic and health events that could reduce demand of petroleum products;

•pandemic events that could impair our employees and contractors abilities to drill and produce oil and gas;

•the level of global oil, gas and NGL inventories and exploration and production activity; and

•the quality of oil and gas produced.

Declines in oil, gas and NGL prices would not only reduce revenue, but could also reduce the amount of oil, gas and NGL that we can economically produce and therefore potentially lower our oil and gas reserve quantities. In addition, a decline in oil and gas prices and volatility could negatively impact our ability to execute our operating and development plans and the ability to generate Free Cash Flow.

The long-term effect of factors impacting the prices of oil, gas and NGL is uncertain. Substantial or prolonged declines in these commodity prices may have the following effects on QEP's business:

•adversely affect QEP's financial condition and liquidity and QEP's ability to finance planned capital expenditures, borrow money, repay debt and raise additional capital;

•reduce the amount of oil, gas and NGL that QEP can produce economically;

•limit QEP's ability to generate Free Cash Flow;

•cause QEP to delay, postpone or cancel some of its capital projects;

•cause QEP to divest properties to generate funds to meet cash flow or liquidity requirements;

•reduce QEP's revenues, operating income or cash flows;

•reduce the amounts of QEP's estimated proved oil, gas and NGL reserves;

•reduce the carrying value of QEP's oil and gas properties due to recognizing additional impairments of proved and unproved properties;

•limit QEP's access to, or increasing the cost of, sources of capital such as equity and long-term debt;

•cause additional counterparty credit risk;

•decrease the value of QEP's common stock; and

•increase shareholder activism.

Alternatively, higher oil prices may result in increased volatility in commodity prices, inflation, slower economic growth, a global recession or more international conflicts.  Higher oil prices may also result in higher costs for QEP and significant mark-to-market losses being incurred in QEP's commodity derivatives, which may in turn cause us to experience net losses.

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QEP's operations are subject to operational hazards and unforeseen interruptions for which QEP may not be adequately insured and that could adversely affect our business, financial condition and results of operations. There are operational risks associated with the exploration, production, gathering, transporting, and storage of oil, gas and NGL, including:

•pandemic health events, injuries and/or deaths of employees, supplier personnel, or other individuals;

•fires, explosions and blowouts;

•earthquakes and other natural disasters;

•aging infrastructure and mechanical problems;

•unexpected drilling conditions, including abnormally pressured formations or loss of drilling fluid circulation;

•pipe, cement or casing failures;

•equipment malfunctions, mechanical failures or accidents;

•theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;

•adverse weather conditions;

•plant, pipeline, railway and other facility accidents and failures;

•truck and rail loading and unloading problems;

•delays imposed by or resulting from compliance with regulatory requirements;

•delays in or limits on the issuance of drilling permits on our federal leases, including as a result of government shutdowns;

•delays imposed by or resulting from legal proceedings;

•environmental accidents such as oil spills, natural gas leaks, pipeline or tank ruptures, or discharges of air pollutants, brine water or well fluids into the environment;

•security breaches, cyberattacks, piracy, or terrorist acts;

•flaring of natural gas, including, where required, accurate and timely payment of royalty on flared gas;

•pipeline takeaway and refining and processing capacity issues; and

•title problems.

QEP could incur substantial losses as a result of pandemic health events, injury to or loss of life, pollution or other environmental damage, damage to or destruction of property or equipment, regulatory compliance investigations, fines or curtailment of operations, or attorneys' fees and other expenses incurred in the prosecution or defense of litigation. As a working interest owner in wells operated by other companies, QEP may also be exposed to the risks enumerated above from operations that are not within its care, custody or control.

Consistent with industry practice, QEP generally indemnifies drilling contractors and oilfield service companies (collectively, contractors) against certain losses suffered by QEP as the operator and certain third parties resulting from a well blowout or fire or other uncontrolled flow of hydrocarbons, regardless of fault. Therefore, QEP may be liable, regardless of fault, for some or all of the costs of controlling a blowout, drilling a relief and/or replacement well and the cleanup of any pollution or contamination resulting from a blowout in addition to claims for personal injury or death suffered by QEP's employees and certain others. QEP's drilling contracts and oilfield service agreements, however, often provide that the contractor will indemnify QEP for claims related to injury and death of employees of the contractor and its subcontractors and for property damage suffered by the contractor and its subcontractors.

QEP's insurance coverage may not be sufficient to cover 100% of potential losses arising as a result of the foregoing risks. QEP has limited or no coverage for certain other risks, such as political risk, lost reserves, business interruption, cyber risk, earthquakes, war and terrorism. Although QEP believes the coverage and amounts of insurance that it carries are consistent with industry practice, QEP does not have insurance protection against all risks that it faces because QEP chooses not to insure certain risks, insurance is not available at a level that balances the costs of insurance and QEP's desired rates of return, or actual losses may exceed coverage limits. QEP could sustain significant losses and substantial liability for uninsured risks. The occurrence of a significant event against which QEP is not fully insured could have a material adverse effect on its financial condition, results of operations and cash flows.

If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock. On April 10, 2020, we received written notification from the New York Stock Exchange (NYSE) that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average closing share price required to maintain listing under Section 802.01C of the NYSE Listed Company Manual. The notice had no immediate impact on the listing of our common stock, and, pursuant to the rules of the NYSE, we had a six month period in which to regain compliance, subject to our compliance with other listing standards. On July 1, 2020, the NYSE notified us that we had regained compliance with the listing standard as our stock had an average closing share price of at least $1.00 on the last trading day of June 2020 and also had an average closing share price of at least $1.00 over the 30-trading day period ending on the last trading day of that month.

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There is no assurance, however, that the price of our common stock will remain above $1.00 per share or that we will be able to continue to remain in compliance with the NYSE’s continued listing requirements. For example, our common stock could also be delisted if (i) our average market capitalization over a consecutive 30 trading-day period is less than $15 million, or (ii) our common stock trades at an “abnormally low” price, which the NYSE has historically viewed to be $0.16 per share. If either event were to occur, we would not have an opportunity to cure the deficiency, and, as a result, our common stock would be suspended from trading on the NYSE immediately, and the NYSE would begin the process to delist our common stock, subject to our right to appeal under NYSE rules. There is no assurance that any appeal we undertake in these or other circumstances would be successful, nor is there any assurance that we will continue to comply with the other NYSE continued listing standards.

Failure to maintain our NYSE listing could negatively impact us and our stockholders by reducing the willingness of investors to hold our common stock because of the resulting decreased price, liquidity and trading of our common stock, limited availability of price quotations, and reduced news and analyst coverage. These developments may also require brokers trading in our common stock to adhere to more stringent rules and may limit our ability to raise capital by issuing additional shares in the future. Delisting may adversely impact the perception of our financial condition and cause reputational harm with investors and parties conducting business with us. In addition, the perceived decreased value of employee equity incentive awards may reduce their effectiveness in encouraging performance and retention.

Substantially all of our producing properties and operations are located in the Williston Basin and Permian Basin, making us vulnerable to risks associated with operating in a limited number of basins. As a result of our lack of diversification in asset type and our limited geographic diversification, any delays or interruptions of production caused by such factors as governmental regulation; density and proration requirements of state regulators; transportation capacity constraints; curtailment of production or interruption of transportation; price fluctuations; natural disasters; or shutdowns of the pipelines connecting our production to refineries would have a significantly greater impact on our results of operations than if we possessed more diverse assets and locations. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Williston Basin and Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Lack of availability of refining, gas processing, storage, gathering or transportation capacity will likely impact results of operations. The lack of availability of satisfactory oil, gas and NGL gathering and transportation, including trucks, railways and pipelines, gas processing, storage or refining capacity may hinder QEP's access to oil, gas and NGL markets or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability, proximity and capacity of gathering, transportation, gas processing facilities, storage or refineries owned and operated by third parties. Although QEP has some contractual control over the transportation of its production through firm transportation and gas processing arrangements, third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents, lack of contracted capacity on such systems or other reasons such as temporary suspension of service due to legal challenges (such as the July 2020 court-ordered shut down of the Dakota Access Pipeline, a major pipeline running out of the Williston Basin) and/or the pipeline’s failure to comply with applicable laws and regulations. If gathering, transportation, gas processing or storage facilities do not exist near producing wells; if gathering, transportation, gas processing, storage or refining capacity is limited; or if gathering, transportation, gas processing or refining capacity is unexpectedly disrupted, completion activity could be delayed, sales could be reduced, gas flaring and transportation costs could increase, or production could be shut-in, each of which could reduce profitability. The curtailments arising from these circumstances may last from a few days to several months, and in many cases, QEP is provided with limited, if any, notice as to when these circumstances will arise and their duration. Furthermore, if QEP were required to shut-in wells, it might also be obligated to pay certain demand charges for gathering and processing services, as well as shut-in royalties to certain mineral interest owners in order to maintain its leases; or depending on the specific lease provisions, some leases could terminate. In addition, rail accidents involving crude oil carriers have resulted in regulations, and may result in additional regulations, on transportation of oil by railway. QEP might be required to install or contract for additional treating or processing equipment for transport of crude oil by rail, which could increase costs. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, transportation pressures, damage to or destruction of transportation facilities and general economic conditions could also adversely affect QEP's ability to transport oil and gas.

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QEP's debt and other financial commitments may limit its financial and operating flexibility. QEP's total debt was approximately $1.9 billion at June 30, 2020. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. QEP's financial commitments could have important consequences to its business, including, but not limited to, limiting QEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends, to repurchase shares of its common stock, or to otherwise realize the value of its assets and opportunities fully because of the need to dedicate a substantial portion of its cash flows from operations and proceeds from the divestiture of its assets to payments on its debt or to comply with any restrictive terms of its debt. QEP may be at a competitive disadvantage as compared to similar companies that have less debt. Higher levels of debt may make QEP more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing QEP's revolving credit facility and the indentures governing QEP's senior notes contain a number of covenants that impose constraints on the Company, including requirements to comply with certain financial covenants and restrictions on QEP's ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in transactions with affiliates. If commodity prices decline and QEP reduces its level of capital spending and production declines or QEP incurs additional impairment expense or the value of the Company's proved reserves declines, the Company may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in its credit agreement in the future. Refer to Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations in Part I of this Quarterly Report on Form 10-Q for more information regarding the financial covenants and our revolving credit agreement.

Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations. Wells in the Williston Basin of North Dakota and the Permian Basin of Texas, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in third party gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In 2014, the NDI Commission, North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDI Commission requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. The NDI Commission is undergoing new efforts to further reduce the flaring in North Dakota, which could trigger a new rulemaking in 2020. It is possible that other states in which QEP operates, including Texas, will require gas capture plans or otherwise institute new regulatory requirements in the future to reduce flaring.

Additionally, in November 2016, the BLM finalized the 2016 Waste Prevention Rule, which further regulates the venting, flaring and emission of natural gas on BLM and tribal leases. The 2016 Waste Prevention Rule took effect in January 2017. In September 2018, the BLM finalized the 2018 Revised Waste Prevention Rule, a rule that revised and replaced the 2016 Waste Prevention Rule, effective November 2018. In July 2020, a federal judge repealed the 2018 rule and reinstated the 2016 rule. The Department of Interior must produce a report on the anticipated compliance process within 30 days. The 2016 rule was also subject to legal challenges which have been revived as a result of the repeal of the 2018 rule. For example, in July 2020, a Wyoming federal judge granted a request from North Dakota and several other states to revive a challenge to the 2016 rule. The outcome of this challenge and any similar challenges is uncertain at this time. However, gas capture requirements, including any similar future obligations in North Dakota or our other locations, increase our operational costs and may restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows. If our interpretation of the applicable regulations is incorrect, or if we receive a non-appealable order to pay royalty on past and future flared volumes in North Dakota, such royalty payments could materially and adversely affect our financial condition and cash flows.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On February 28, 2018, QEP announced the authorization by its Board to repurchase up to $1.25 billion of the Company's outstanding shares of common stock (February 2018 $1.25 billion Repurchase Program). As of June 30, 2020, the remaining value that could have been repurchased under the share repurchase program was $1,191.6 million. On July 28, 2020, the Board suspended the repurchase program. The repurchases of shares during the three months ended June 30, 2020 were in connection with the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

The following exhibits are being filed as part of this report:

Exhibit No.	Description of Exhibit
3.1	Amended and Restated Certificate of Incorporation dated May 15, 2018 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 17, 2018).
3.2	Amended and Restated Bylaws, as amended and restated on May 14, 2019 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 17, 2019).
10.1	Eighth Amendment to Credit Agreement, dated as of June 4, 2020, by and among QEP Resources, Inc., Wells Fargo, National Association, in its capacity as administrative agent for the lenders, the lenders party thereto and the guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 4, 2020).
31.1*	Certification signed by Timothy J. Cutt, QEP Resources, Inc.'s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002,
31.2*	Certification signed by William J. Buese, QEP Resources, Inc.'s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification signed by Timothy J. Cutt and William J. Buese, QEP Resources, Inc.'s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxey Act of 2002.
101.INS*	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Linkbase Document.
101.LAB*	XBRL Label Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.

____________________________

* Filed herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	QEP RESOURCES, INC.
	(Registrant)
July 29, 2020	/s/ Timothy J. Cutt
	Timothy J. Cutt,
	President and Chief Executive Officer
July 29, 2020	/s/ William J. Buese
	William J. Buese,
	Vice President, Chief Financial Officer and Treasurer

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