QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
2018 2017 2018 2017
(in millions)
Net income (loss) $ (336.0 ) $ 45.4
$ (389.6 ) $ 122.3
Other comprehensive income, net of tax:
Postretirement medical plan change⁽¹⁾
—
—
—
1.6
Fair value of plan assets adjustment⁽²⁾
—
—
0.3
—
Pension and other postretirement plans adjustments:
Amortization of prior service costs⁽³⁾
0.1
0.2
0.2
0.3
Amortization of actuarial losses⁽⁴⁾
0.2
(0.1 ) 0.4
0.1
Other comprehensive income 0.3
0.1
0.9
2.0
Comprehensive income (loss) $ (335.7 ) $ 45.5
$ (388.7 ) $ 124.3



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2019		2018			2019			2018
	(in millions)
Net income (loss)	$	48.8	$	(336.0	)	$	(67.9	)	$	(389.6	)
Other comprehensive income (loss), net of tax:
Fair value of plan assets adjustment⁽¹⁾	—		—			—			0.3
Pension and other postretirement plans adjustments:
Amortization of prior service costs⁽²⁾	—		0.1			0.1			0.2
Amortization of actuarial losses⁽³⁾	—		0.2			0.1			0.4
Net curtailment⁽⁴⁾	0.1		—			(0.3		)	—
Other comprehensive income (loss)	0.1		0.3			(0.1		)	0.9
Comprehensive income (loss)	$	48.9	$	(335.7	)	$	(68.0	)	$	(388.7	)

____________________________


⁽¹⁾	~~Presented net of income tax expense of $1.0 million for the six months ended June 30, 2017.~~


⁽²⁾	Adjustment recorded during the six months ended June 30, 2018, related to a change in the fair value of plan assets as of December 31, 2017.


⁽³⁾⁽²⁾	Presented net of income tax expense of $0.1 million and $0.1 million for the three and six months ended June 30, 2018, respectively. ~~Presented net of income tax expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2017, respectively.~~


⁽⁴⁾⁽³⁾	Presented net of income tax expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2018, respectively.


⁽⁴⁾	Presented net of income tax expense of $0.1 million for the six months ended June 30, ~~2017.~~2019, respectively.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
ASSETS	(in millions)						(in millions)
Current Assets
Cash and cash equivalents	$	—		$	—		$	97.1		$	—
Accounts receivable, net	175.0			141.8			93.5			104.3
Income tax receivable	5.3			4.9			70.8			75.9
Fair value of derivative contracts	23.7			3.4			2.7			87.5
Prepaid expenses	9.8			10.1			7.1			12.7
Other current assets	0.3			4.3			0.2			0.2
Total Current Assets	214.1			164.5			271.4			280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,852.3			11,873.6			9,316.0			9,096.9
Unproved properties	1,041.0			1,086.4			706.6			705.5
Gathering and other	359.7			318.7			169.1			167.7
Materials and supplies	32.2			32.9			20.9			29.9
Total Property, Plant and Equipment	14,285.2			13,311.6			10,212.6			10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	7,267.1			6,642.9			5,050.9			4,882.4
Gathering and other	116.2			124.3			58.4			58.1
Total Accumulated Depreciation, Depletion and Amortization	7,383.3			6,767.2			5,109.3			4,940.5
Net Property, Plant and Equipment	6,901.9			6,544.4			5,103.3			5,059.5
Fair value of derivative contracts	5.4			0.1			15.2			35.4
Operating lease right-of-use assets, net							60.2			—
Other noncurrent assets	56.5			53.0			54.2			49.6
Noncurrent assets held for sale	211.8			632.8			—			692.7
TOTAL ASSETS	$	7,389.7		$	7,394.8		$	5,504.3		$	6,117.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	8.5		$	44.0		$	5.3		$	14.6
Accounts payable and accrued expenses	388.0			363.8			227.9			258.1
Production and property taxes	36.3			31.6			15.9			24.1
Current portion of long term debt							51.7			—
Interest payable	32.7			26.0			32.5			32.4
Fair value of derivative contracts	155.2			103.6			17.6			—
Current operating lease liabilities							18.8			—
Asset retirement obligations	6.0			3.5			6.8			5.1
Total Current Liabilities	626.7			572.5			376.5			334.3
Long-term debt	2,649.4			2,160.8			2,028.1			2,507.1
Deferred income taxes	397.7			518.0			181.4			269.2
Asset retirement obligations	154.6			159.0			94.6			96.9
Fair value of derivative contracts	49.3			31.8			0.9			0.7
Operating lease liabilities							47.9			—
Other long-term liabilities	97.8			102.2			85.6			97.4
Other long-term liabilities held for sale	52.8			52.6			—			61.3
Commitments and contingencies (Note 10)
Commitments and contingencies (Note 11)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 239.7 million and 243.0 million shares issued, respectively	2.4			2.4
Treasury stock – 2.7 million and 2.0 million shares, respectively	(41.2		)	(34.2		)
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.0 million and 239.8 million shares issued, respectively							2.4			2.4
Treasury stock – 4.1 million and 3.1 million shares, respectively							(53.6		)	(45.6		)
Additional paid-in capital	1,415.7			1,398.2			1,446.3			1,431.9
Retained earnings	1,994.7			2,442.6			1,308.6			1,376.5
Accumulated other comprehensive income (loss)	(10.2		)	(11.1		)	(14.4		)	(14.3		)
Total Common Shareholders' Equity	3,361.4			3,797.9			2,689.3			2,750.9
TOTAL LIABILITIES AND EQUITY	$	7,389.7		$	7,394.8		$	5,504.3		$	6,117.8

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED ~~STATEMENT~~STATEMENTS OF EQUITY

(Unaudited)


	Common Stock					Treasury Stock					Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income(Loss)				Total			Common Stock				Treasury Stock					Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income(Loss)			Total
	Shares		Amount			Shares		Amount					Shares				Accumulated Other Comprehensive Income(Loss)			Amount					Shares		Amount						Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income(Loss)			Total
	(in millions)																							(in millions)
Balance at December 31, 2017	243.0		$	2.4		(2.0	)	$	(34.2	)	Additional Paid-in Capital		$	Retained Earnings	1,398.2		$	2,442.6			Total		$	(11.1	)	$	3,797.9
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)	—		—			—		—			—			(389.6		)	—				(389.6		)	—		—		—		—			—		48.8		—			48.8
Common stock repurchased and retired	(6.2	)	(0.1		)	—		—			—			(58.3		)	—				(58.4		)
Share-based compensation	2.9		0.1			(0.7	)	(7.0		)	17.5			—			—				10.6			—		—		(0.2	)	(1.8		)	6.1		—		—			4.3
Change in pension and postretirement liability, net of tax	—		—			—		—			—			—			0.9				0.9			—		—		—		—			—		—		0.1			0.1
Balance at June 30, 2018	239.7		$	2.4		(2.7	)	$	(41.2	)	$	1,415.7		$	1,994.7		$	(10.2	)		$	3,361.4
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



Balance at March 31, 2018	240.3		$	2.4	(2.6	)	$	(39.5	)	$	1,408.0	$	2,336.3		$	(10.5	)	$	3,696.7
Net income (loss)	—		—		—		—			—		(336.0		)	—			(336.0		)
Common stock repurchased and retired	(0.6	)	—		—		—			—		(5.6		)	—			(5.6		)
Share-based compensation	—		—		(0.1	)	(1.7		)	7.7		—			—			6.0
Change in pension and postretirement liability, net of tax	—		—		—		—			—		—			0.3			0.3
Balance at June 30, 2018	239.7		$	2.4	(2.7	)	$	(41.2	)	$	1,415.7	$	1,994.7		$	(10.2	)	$	3,361.4



Balance at December 31, 2017	243.0		$	2.4		(2.0	)	$	(34.2	)	$	1,398.2	$	2,442.6		$	(11.1	)	$	3,797.9
Net income (loss)	—		—			—		—			—		(389.6		)	—			(389.6		)
Common stock repurchased and retired	(6.2	)	(0.1		)	—		—			—		(58.3		)	—			(58.4		)
Share-based compensation	2.9		0.1			(0.7	)	(7.0		)	17.5		—			—			10.6
Change in pension and postretirement liability, net of tax	—		—			—		—			—		—			0.9			0.9
Balance at June 30, 2018	239.7		$	2.4		(2.7	)	$	(41.2	)	$	1,415.7	$	1,994.7		$	(10.2	)	$	3,361.4

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2019			2018
OPERATING ACTIVITIES	(in millions)						(in millions)
Net income (loss)	$	(389.6	)	$	122.3		$	(67.9	)	$	(389.6	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	438.7			383.3			251.3			438.7
Deferred income taxes (benefit)	(120.5		)	67.2			(87.7		)	(120.5		)
Impairment	404.4			0.1			5.0			404.4
Share-based compensation	23.4			7.7
Non-cash share-based compensation							11.2			16.3
Amortization of debt issuance costs and discounts	2.6			3.1			2.7			2.6
Bargain purchase gain from acquisition	—			0.4
Net (gain) loss from asset sales, inclusive of restructuring costs	0.4			(19.8		)	(4.6		)	0.4
Unrealized (gains) losses on marketable securities	(0.4		)	(1.4		)	(2.7		)	(0.4		)
Unrealized (gains) losses on derivative contracts	43.6			(277.6		)	121.3			43.6
Changes in operating assets and liabilities	(25.7		)	10.7			(32.9		)	(18.6		)
Net Cash Provided by (Used in) Operating Activities	376.9			296.0			195.7			376.9
INVESTING ACTIVITIES
Property acquisitions	(45.1		)	(76.6		)	(1.8		)	(45.1		)
Property, plant and equipment, including exploratory well expense	(764.3		)	(477.9		)	(316.8		)	(764.3		)
Proceeds from disposition of assets	48.8			2.3			666.7			48.8
Net Cash Provided by (Used in) Investing Activities	(760.6		)	(552.2		)	348.1			(760.6		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(35.5		)	(0.5		)	(9.3		)	(35.5		)
Long-term debt issuance costs paid	—			(1.1		)
Proceeds from credit facility	2,029.5			—			56.0			2,029.5
Repayments of credit facility	(1,543.5		)	—			(486.0		)	(1,543.5		)
Common stock repurchased and retired	(58.4		)	—			—			(58.4		)
Treasury stock repurchases	(5.9		)	(6.4		)	(6.3		)	(5.9		)
Other capital contributions	0.2			—			—			0.2
Net Cash Provided by (Used in) Financing Activities	386.4			(8.0		)	(445.6		)	386.4
Change in cash, cash equivalents and restricted cash	2.7			(264.2		)
Change in cash, cash equivalents and restricted cash⁽¹⁾							98.2			2.7
Beginning cash, cash equivalents and restricted cash⁽¹⁾	23.4			465.4			28.1			23.4
Ending cash, cash equivalents and restricted cash⁽¹⁾	$	26.1		$	201.2		$	126.3		$	26.1

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	63.5		$	64.3		$	63.3		$	63.5
Cash paid for income taxes, net	$	0.2		$	—		$	1.5		$	0.2
Cash paid for amounts included in the measurement of lease liabilities							$	13.1		$	—
Non-cash Operating Activities:
Right-of-use assets obtained in exchange for operating lease obligations							$	9.8		$	—
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	20.2		$	42.4		$	20.3		$	20.2

____________________________


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

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

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 Louisiana)~~Texas) and the Northern Region (primarily in North ~~Dakota and Utah)~~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 of Interim Condensed Consolidated Financial Statements

The interim Condensed Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Condensed Consolidated 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 Condensed 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 Condensed Consolidated Financial Statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These Condensed Consolidated 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, ~~2017.~~2018.

The preparation of the Condensed Consolidated 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. The results of operations for the three and six months ended June 30, ~~2018,~~2019, are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2018.~~2019.

Reclassifications

Certain prior period balances on the Condensed Consolidated ~~Balance Sheets and Condensed Consolidated~~ Statements of Cash Flows have been reclassified ~~due to noncurrent held for sale classification related to the signing of a purchase and sale agreement associated with the pending divestiture of the Uinta Basin assets and~~ 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.

Impairment of Long-Lived Assets

During the six months ended June 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

During the six months ended June 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered due to the signing of a purchase and sale agreement for the divestiture of the Uinta Basin assets. Additionally, QEP recorded $1.6 million related to expiring leaseholds on unproved properties and impairment of proved properties for a divestiture in the Other Northern area.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist principally 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.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets to the amounts shown in the Condensed Consolidated Statements of Cash Flows:


	June 30,				June 30,
	2018		2017		2019		2018
	(in millions)				(in millions)
Cash and cash equivalents	$	—	$	178.8	$	97.1	$	—
Restricted cash⁽¹⁾	26.1		22.4		29.2		26.1
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	26.1	$	201.2	$	126.3	$	26.1

_______________________

⁽¹⁾

As of June 30, 2018, the restricted cash balance consisted of $26.1 million included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of June 30, 2017, the restricted cash balance consisted of $22.4 million included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin.

⁽¹⁾As of June 30, 2019 and 2018, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Condensed Consolidated Balance Sheets.

New Accounting Pronouncements

In ~~May 2014,~~February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. ~~2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~, which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when revenue is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures are required. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption was permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company has selected the modified retrospective method and adopted this standard in the first quarter of 2018. Refer to Note 2 – Revenue for more information.

~~In conjunction with ASU No. 2014-09, in March 2016, the FASB issued ASU No. 2016-08,~~ ~~Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net),~~ ~~which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10,~~ ~~Revenue from contracts with customers (Topic 606): Identifying performance obligations and licensing,~~ which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-11, ~~Revenue recognition (Topic 605) and Derivatives and hedging (Topic 815): Rescission of SEC guidance because of ASU 2014-09 and 2014-16,~~ ~~which rescinds certain SEC staff observer comments that are codified in~~ ~~Topic 605, Revenue Recognition.~~ ~~In May 2016, the FASB issued ASU No. 2016-12,~~ ~~Revenue from contracts with customers (Topic 606): Narrow-scope improvements and practical expedients,~~ which intends to reduce the cost and complexity of applying the new revenue standard by narrowing the scope of improvements to the guidance on collectability, non-cash consideration, and completed contracts at transition. In December 2016, the FASB issued ASU No. 2016-20, ~~Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers,~~ which intends to make corrections or improvements to the FASB Accounting Standards Codification which includes guidance and reference clarification, simplification and minor improvements. These amendments were effective prospectively for reporting periods beginning on or after December 31, 2017, and early adoption was permitted for periods beginning on or after December 31, 2016. The Company adopted these ASUs in the first quarter of 2018.~~Refer to Note 2 – Revenue for more information.~~

~~In February 2016, the FASB issued ASU No.~~ 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and ~~disclosing~~disclose key quantitative and qualitative information about leasing arrangements. The ~~amendment will be effective~~FASB subsequently issued various ASUs which provided additional implementation guidance. The Company adopted ASU 2016-02 on January 1, 2019 using the modified retrospective approach and elected to not adjust periods prior to January 1, 2019. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed the carry forward of the historical lease classification, including accounting treatment for ~~reporting periods beginning on or after December 15, 2018, and early adoption is permitted. QEP does not plan to early adopt this new standard.~~land easements. This standard does not apply to QEP's leases that provide the right to explore for ~~or use~~ minerals, oil or natural gas ~~resources, including~~resources. The adoption of this guidance resulted in the ~~right to explore for those natural resources. QEP believes this new guidance will likely increase the recorded asset~~recognition of net operating lease right-of-use assets and ~~liability balances~~operating lease liabilities on ~~the Company's~~QEP's Condensed Consolidated Balance ~~Sheets due~~Sheets. These leases primarily relate to ~~the required recognition of right-of-use assets~~office buildings, compressors and ~~corresponding lease liabilities, but has not determined the aggregate amount of change.~~

~~In October 2016, the FASB issued ASU No. 2016-16,~~ ~~Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory,~~which intends to reduce the complexity in accounting standards related to intra-entity asset transfers by requiring a reporting entity to recognize the tax effects from the sale of assets when a transfer occurs, even though the pre-tax effects of t~~he transaction are eliminated in consolidation.~~generators. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoptionguidance did not have a ~~material~~significant impact ~~on the Company's Condensed Consolidated Financial Statements.~~

~~In November 2016, the FASB issued ASU No. 2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted cash,~~which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption did not have a material impact on the Company's Condensed Consolidated Statements of Cash Flows.

~~In February 2018, the FASB issued ASU No. 2018-02,~~ ~~Income statement - Reporting comprehensive income (Topic 220) - Reclassification of certain tax effects from accumulated other comprehensive income,~~ which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

~~In March 2018, the FASB issued ASU No. 2018-05,~~ ~~Income Taxes (Topic 740) - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,~~ which amends guidance on certain investments and income taxes as a result of the Tax Cuts and Jobs Act of 2017. The amendment is effective upon issuance. The adoption did not have a material impact on the Company's Condensed Consolidated Financial Statements.

~~Note 2 – Revenue~~

~~Adoption of ASC Topic 606,~~ ~~Revenue from Contracts with Customers~~

~~On January 1, 2018, QEP adopted ASC Topic 606,~~ ~~Revenue from Contracts with Customers,~~ using the modified retrospective approach, which was applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC Topic 606, while prior period amounts are reported in accordance with ASC Topic 605, ~~Revenue Recognition~~.

In accordance with ASC Topic 606, QEP now records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated ~~Statements~~Statement of ~~Operations. Prior to the adoption of ASC Topic 606, these transportation and processing costs were recorded as an expense within "Transportation and processing costs" on~~Operations or the Condensed Consolidated ~~Statements~~Statement of ~~Operations. There was no impact~~Cash Flows. Refer to ~~net income (loss) or opening retained earnings as a result of adopting ASC Topic 606.~~Note 8 – Leases for more information.

Note 2 – Revenue

~~The following table presents the impact to the Condensed Consolidated Statements of Operations as a result of adopting ASC Topic 606.~~

Three Months Ended Six Months Ended
June 30, 2018 June 30, 2018
As Reported ASC Topic 606 Adjustments
As Adjusted⁽¹⁾
As Reported ASC Topic 606 Adjustments
As Adjusted⁽¹⁾
REVENUES (in millions, except per share amounts)
Oil and condensate, gas and NGL sales $ 520.3
$ 12.4
$ 532.7
$ 930.1
$ 25.1
$ 955.2
Other revenue 3.0
—
3.0
8.0
—
8.0
Purchased oil and gas sales 9.1
—
9.1
23.2
—
23.2
Total Revenues 532.4
12.4
544.8
961.3
25.1
986.4
OPERATING EXPENSES
Purchased oil and gas expense 9.8
—
9.8
25.3
—
25.3
Lease operating expense 66.5
—
66.5
139.0
—
139.0
Transportation and processing costs 31.2
12.4
43.6
65.2
25.1
90.3
Gathering and other expense 3.4
—
3.4
6.2
—
6.2
General and administrative 55.8
—
55.8
115.9
—
115.9
Production and property taxes 37.6
—
37.6
66.5
—
66.5
Depreciation, depletion and amortization 242.2
—
242.2
438.7
—
438.7
Exploration expenses 0.1
—
0.1
0.1
—
0.1
Impairment 403.7
—
403.7
404.4
—
404.4
Total Operating Expenses 850.3

12.4
862.7
1,261.3

25.1
1,286.4
Net gain (loss) from asset sales, inclusive of restructuring costs (3.9 ) —
(3.9 ) (0.4 ) —
(0.4 )
OPERATING INCOME (LOSS) (321.8 )
—
(321.8 ) (300.4 )
—
(300.4 )
Realized and unrealized gains (losses) on derivative contracts (Note 7) (79.1 ) —
(79.1 ) (132.3 ) —
(132.3 )
Interest and other income (expense) (3.1 ) —
(3.1 ) (3.8 ) —
(3.8 )
Interest expense (38.2 ) —
(38.2 ) (73.2 ) —
(73.2 )
INCOME (LOSS) BEFORE INCOME TAXES (442.2 )
—
(442.2 ) (509.7 )
—
(509.7 )
Income tax (provision) benefit 106.2
—
106.2
120.1
—
120.1
NET INCOME (LOSS) $ (336.0 )
$ —
$ (336.0 ) $ (389.6 )
$ —
$ (389.6 )

Earnings (loss) per common share
Basic $ (1.42 ) $ —
$ (1.42 ) $ (1.63 ) $ —
$ (1.63 )
Diluted $ (1.42 ) $ —
$ (1.42 ) $ (1.63 ) $ —
$ (1.63 )

Weighted-average common shares outstanding
Used in basic calculation 237.0
—
237.0
238.9
—
238.9
Used in diluted calculation 237.0
—
237.0
238.9
—
238.9
Dividends per common share $ —
$ —
$ —
$ —
$ —
$ —

~~_______________________~~


⁽¹⁾	~~This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.~~

Revenue Recognition

QEP recognizes revenue from the ~~sales~~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 ~~we have~~QEP has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The ~~sales~~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 ~~indexes~~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 is typically sold at specific delivery points under contract terms that are common in ~~our~~the industry. QEP's gas and NGL are also sold under contract types that are common in ~~our~~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 ~~the Company~~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 ~~losses on unutilized capacity~~credit risk related to ~~firm transportation~~third party purchasers, to fulfill volume commitments when production does not fulfill contractual commitments and ~~storage activities.~~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. ~~A wellhead imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.~~

The following tables present ~~our~~QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following ~~tables~~table are not all of the transportation and processing costs that ~~the Company~~QEP incurs, only the

expenses that are netted against revenues pursuant to ASC Topic 606.



	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, 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

	Three Months Ended June 30, 2018
Northern Region
Williston Basin	$	207.6	$	8.4		$	14.7	$	(10.7	)	$	220.0
Uinta Basin	9.5		7.9			1.7		—			19.1
Other Northern	0.9		0.2			0.1		—			1.2
Southern Region
Permian Basin	190.3		3.2			9.9		(1.7		)	201.7
Haynesville/Cotton Valley	0.2		77.9			—		—			78.1
Other Southern	—		0.2			—		—			0.2
Total oil and condensate, gas and NGL sales	$	408.5	$	97.8		$	26.4	$	(12.4	)	$	520.3

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, 2018
Northern Region
Williston Basin $ 207.6
$ 8.4
$ 14.7
$ (10.7 ) $ 220.0
Uinta Basin 9.5
7.9
1.7
—
19.1
Other Northern 0.9
0.2
0.1
—
1.2
Southern Region
Permian Basin 190.3
3.2
9.9
(1.7 ) 201.7
Haynesville/Cotton Valley 0.2
77.9
—
—
78.1
Other Southern —
0.2
—
—
0.2
Total oil and condensate, gas and NGL sales $ 408.5
$ 97.8
$ 26.4
$ (12.4 ) $ 520.3

Three Months Ended June 30, 2017⁽¹⁾
Northern Region
Williston Basin $ 135.4
$ 11.0
$ 9.3
$ —
$ 155.7
Pinedale 6.0
51.2
8.4
—
65.6
Uinta Basin 6.9
12.3
1.1
—
20.3
Other Northern 1.4
4.9
0.1
—
6.4
Southern Region
Permian Basin 66.0
3.6
3.8
—
73.4
Haynesville/Cotton Valley 0.2
51.0
0.1
—
51.3
Other Southern 0.1
0.2
—
—
0.3
Total oil and condensate, gas and NGL sales $ 216.0
$ 134.2
$ 22.8
$ —
$ 373.0

~~_______________________~~


⁽¹⁾	~~Prior period amounts have not been adjusted under the modified retrospective method.~~



	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, 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

	Six Months Ended June 30, 2018
Northern Region
Williston Basin	$	368.1		$	18.2	$	26.5		$	(20.6	)	$	392.2
Uinta Basin	17.9			18.0		3.4			—			39.3
Other Northern	2.8			1.2		(0.1		)	—			3.9
Southern Region
Permian Basin	320.1			7.8		16.4			(4.5		)	339.8
Haynesville/Cotton Valley	0.6			154.3		—			—			154.9
Other Southern	(0.3		)	0.3		—			—			—
Total oil and condensate, gas and NGL sales	$	709.2		$	199.8	$	46.2		$	(25.1	)	$	930.1

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, 2018
Northern Region
Williston Basin $ 368.1
$ 18.2
$ 26.5
$ (20.6 ) $ 392.2
Uinta Basin 17.9
18.0
3.4
—
39.3
Other Northern 2.8
1.2
(0.1 ) —
3.9
Southern Region
Permian Basin 320.1
7.8
16.4
(4.5 ) 339.8
Haynesville/Cotton Valley 0.6
154.3
—
—
154.9
Other Southern (0.3 ) 0.3
—
—
—
Total oil and condensate, gas and NGL sales $ 709.2
$ 199.8
$ 46.2
$ (25.1 ) $ 930.1

Six Months Ended June 30, 2017⁽¹⁾
Northern Region
Williston Basin $ 290.8
$ 23.0
$ 21.8
$ —
$ 335.6
Pinedale 12.8
111.8
20.0
—
144.6
Uinta Basin 14.3
26.9
2.7
—
43.9
Other Northern 2.8
10.8
0.2
—
13.8
Southern Region
Permian Basin 116.2
6.8
6.9
—
129.9
Haynesville/Cotton Valley 0.6
89.2
0.2
—
90.0
Other Southern 0.2
0.2
—
—
0.4
Total oil and condensate, gas and NGL sales $ 437.7
$ 268.7
$ 51.8
$ —
$ 758.2

~~_______________________~~


⁽¹⁾	~~Prior period amounts have not been adjusted under the modified retrospective method.~~

Note 3 – Acquisitions and Divestitures

Acquisitions

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

During the six months ended June 30, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $45.1 ~~million, subject to post-closing purchase price adjustments.~~million. Of the $45.1 million, $37.5 million was related to acquisitions from various ~~persons who~~entities that owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin ~~Acquisition in the fourth quarter of 2017.~~Acquisition.

During the six months ended June 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $76.6 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.

Divestitures

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives ~~(Strategic Initiatives)~~ including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. ~~As a part~~The Company subsequently closed the sale of ~~this process, the Company engaged advisors to assist with the divestitures of~~ its ~~Williston Basin and~~ Uinta Basin assets in the third quarter of 2018 and ~~provided data for potential buyers to evaluate. The~~the sale of the Haynesville/Cotton Valley assets ~~will be considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes is generally upon~~in the ~~execution~~first quarter of ~~purchase and sale agreements.~~

~~Uinta Basin Divestiture~~

~~On July 5,~~2019. In November 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a ~~definitive~~purchase and sale agreement for its assets in the Williston Basin, however, in February 2019, the Company agreed with the buyer to ~~sell~~terminate the purchase and sale agreement.

Haynesville/Cotton Valley Divestiture

In January 2019, QEP closed the sale of its assets in Haynesville/Cotton Valley (Haynesville Divestiture), and in July 2019 QEP reached final settlement on asserted title defects. The purchase price, after adjustments, is $634.2 million. QEP received net cash proceeds of $627.1 million during the six months ended June 30, 2019, and, as of June 30, 2019, recorded a $9.5 million receivable and a $2.4 million payable which were included in "Accounts receivable, net" and "Accounts payable and accrued expenses", respectively. The total pre-tax loss on sale was $3.7 million, of which $0.7 million was recognized during the six months ended June 30, 2019, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. Included in the $0.7 million pre-tax loss on sale is $1.4 million of restructuring costs related to the Haynesville Divestiture. Refer to Note 9 – Restructuring for more information. As of December 31, 2018, it was deemed unlikely that there will be any significant changes to the Haynesville Divestiture. Accordingly, the assets and liabilities associated with the Haynesville Divestiture were classified as noncurrent assets and liabilities held for sale, on the Condensed Consolidated Balance Sheets.

During the six months ended June 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $0.7 million, as income from continuing operations on the Condensed Consolidated Statements of Operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. 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 a pre-tax gain on sale of $14.3 million. During the six months ended June 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $3.3 million, which includes the pre-tax loss on sale of $0.7 million. For the three and six months ended June 30, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $7.4 million and $19.7 million, respectively.

The following table presents the carrying amounts of the major classes of assets and liabilities related to the Haynesville Divestiture classified as noncurrent assets and liabilities held for sale on the Condensed Consolidated Balance Sheets:



	December 31, 2018⁽¹⁾
	(in millions)
Assets
Current assets, total	$	1.2
Net Property, Plant and Equipment	683.7
Other noncurrent assets	7.8
Noncurrent assets held for sale	$	692.7
Liabilities
Current liabilities, total	$	3.4
Asset retirement obligations, current	0.7
Asset retirement obligations, long-term	56.9
Other long-term liabilities	0.3
Other long-term liabilities held for sale	$	61.3

____________________________


⁽¹⁾	The Haynesville Divestiture closed in January 2019, therefore there are no assets and liabilities held for sale as of June 30, 2019.

Uinta Basin Divestiture

In September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of ~~$155.0~~$153.0 million ~~subject~~(Uinta Basin Divestiture). During the three and six months ended June 30, 2019, QEP recorded a pre-tax loss on sale of $0.3 million and $0.2 million, respectively, due to ~~customary~~post-closing purchase price adjustments, ~~(the Uinta Basin Divestiture)~~which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". The transaction is expected to close in September 2018. Since the transaction was substantially finalized at June 30, 2018, the assets and liabilities associated with the Uinta Basin Divestiture have been classified as noncurrent assets and liabilities held for sale on the Condensed Consolidated Balance Sheets and the notes accompanying the Condensed Consolidated Financial Statements. Pursuant to signing a purchase and sale agreement for the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment duringFor the three and six months ended June 30, 2018, ~~(refer to Note 1 – Basis of Presentation for more information). In addition,~~ QEP recorded ~~$1.9 million of estimated restructuring costs~~a net loss before income taxes related to ~~this divestiture during~~ the ~~three~~divested Uinta Basin assets of $409.9 million and ~~six months ended June 30, 2018, included in "Net gain (loss) from asset sales, inclusive~~$414.9 million, respectively. The net loss before income taxes was primarily due to an impairment charge on proved and unproved properties of ~~restructuring costs" on~~$402.8 million recognized as a result of signing the ~~Condensed Consolidated Statements of Operations (refer to Note 8 – Restructuring for more information).~~purchase and sale agreement.

The following table presents the carrying amounts of the major classes of assets and liabilities classified as noncurrent assets and liabilities held for sale on the Condensed Consolidated Balance Sheets:

June 30, 2018 December 31, 2017
(in millions)
Assets
Current assets, total $ 0.4
$ 0.9
Property, Plant and Equipment 192.5
612.6
Other noncurrent assets 18.9
19.3
Noncurrent assets held for sale $ 211.8
$ 632.8
Liabilities
Current liabilities, total $ 0.9
$ 0.8
Asset retirement obligations, current 3.5
4.0
Asset retirement obligations, long-term 48.2
47.6
Other long-term liabilities 0.2
0.2
Other long-term liabilities held for sale $ 52.8
$ 52.6

Pinedale Divestiture

In September 2017, QEP sold its Pinedale assets ~~in Pinedale (the Pinedale~~(Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million. ~~For~~During the six months ended June 30, 2018, QEP recorded a pre-tax gain on sale of $0.8 million, due to ~~additional~~ post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. For the three and six months ended June 30, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $15.0 million and $43.0 million, respectively..

~~As a part of the Pinedale Divestiture,~~ QEP agreed to reimburse the buyer of its Pinedale assets for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million.As of June 30, ~~2018,~~2019, the remaining liability associated with estimated future payments for this commitment was ~~$23.8~~$2.0 million ~~which~~and is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses".

Other Divestitures

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

During the six months ended June 30, 2018, QEP received net cash proceeds of $48.8 million and recorded a ~~net~~ pre-tax gain on sale of $0.7 million, primarily related to the divestiture of properties outside ~~our~~its main operating areas in the Uinta Basin, Pinedale and Other Northern area, and the sale of an underground gas storage facility.

During the six months ended June 30, 2017, QEP received proceeds of $2.3 million and recorded accounts receivable of $36.7 million, resulting in a pre-tax gain on sale of $19.8 million, primarily related to the divestiture of certain non-core properties in the Other Northern area.

~~The~~These gains and losses were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated 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. During the three and six months ended June 30, 2019 there were no anti-dilutive shares. During the three and six months ended June 30, 2018, 0.1 million shares were not included in diluted common shares outstanding as they were anti-dilutive to QEP's net loss. ~~During the three and six months ended June 30, 2017, there were no anti-dilutive shares.~~

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,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	238.0	237.0	237.5	238.9
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	238.0	237.0	237.5	238.9

Three Months Ended Six Months Ended
June 30, June 30,
2018
2017 2018 2017
(in millions)
Weighted-average basic common shares outstanding 237.0
240.5
238.9
240.4
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan —
0.1
—
0.1
Average diluted common shares outstanding 237.0
240.6
238.9
240.5

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. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $160.6 million and $162.5 million ARO liability for the periods ended June 30, 2018 and December 31, 2017, respectively, $6.0 million and $3.5 million, respectively, were included as a current liability within "Asset retirement obligations" on the

The Condensed Consolidated Balance ~~Sheets.~~Sheet line items of QEP's ARO liability are presented in the table below:



	Asset Retirement Obligations
	June 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.8	$	5.1
Long-term:
Asset retirement obligations	94.6		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	101.4	$	159.6

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, 2019	$	159.6
Accretion	3.1
Additions	0.4
Revisions	(0.3		)
Liabilities related to assets sold⁽¹⁾	(60.7		)
Liabilities settled	(0.7		)
ARO liability at June 30, 2019	$	101.4

Asset Retirement Obligations
(in millions)
ARO liability at December 31, 2017⁽¹⁾
$ 162.5
Accretion 2.6
Additions 3.5
Revisions (3.5 )
Liabilities settled (4.5 )
ARO liability at June 30, 2018⁽¹⁾
$ 160.6

_______________________

⁽¹⁾

~~Excludes $51.6~~Liabilities related to assets sold during the six months ended June 30, 2019, includes $57.6 million ~~of ARO classified as "Other long-term liabilities held for sale" on the Condensed Consolidated Balance Sheets~~ related to the ~~Uinta Basin~~Haynesville Divestiture ~~as of both June 30, 2018~~(refer to Note 3 – Acquisitions and ~~December 31, 2017.~~Divestitures for more information).

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)~~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.

The fair value of financial assets and liabilities at June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, is shown in the table below:



	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	(in millions)
Financial Assets	June 30, 2019
Fair value of derivative contracts – short-term	$	—	$	2.7	$	—	$	—		$	2.7
Fair value of derivative contracts – long-term	—		15.2		—		—			15.2
Total financial assets	$	—	$	17.9	$	—	$	—		$	17.9

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	17.6	$	—	$	—		$	17.6
Fair value of derivative contracts – long-term	—		0.9		—		—			0.9
Total financial liabilities	$	—	$	18.5	$	—	$	—		$	18.5

	December 31, 2018
Financial Assets
Fair value of derivative contracts – short-term⁽²⁾	$	—	$	88.2	$	—	$	(0.4	)	$	87.8
Fair value of derivative contracts – long-term	—		35.4		—		—			35.4
Total financial assets	$	—	$	123.6	$	—	$	(0.4	)	$	123.2

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.4	$	—	$	(0.4	)	$	—
Fair value of derivative contracts – long-term	—		0.7		—		—			0.7
Total financial liabilities	$	—	$	1.1	$	—	$	(0.4	)	$	0.7

Fair Value Measurements
Gross Amounts of Assets and Liabilities
Netting Adjustments⁽¹⁾
Net Amounts Presented on the Condensed Consolidated Balance Sheets
Level 1 Level 2 Level 3
June 30, 2018
Financial Assets (in millions)
Fair value of derivative contracts – short-term $ —
$ 28.0
$ —
$ (4.3 ) $ 23.7
Fair value of derivative contracts – long-term —
7.3
—
(1.9 ) 5.4
Total financial assets $ —
$ 35.3
$ —
$ (6.2 ) $ 29.1

Financial Liabilities
Fair value of derivative contracts – short-term $ —
$ 159.5
$ —
$ (4.3 ) $ 155.2
Fair value of derivative contracts – long-term —
51.2
—
(1.9 ) 49.3
Total financial liabilities $ —
$ 210.7
$ —
$ (6.2 ) $ 204.5

December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term $ —
$ 20.6
$ —
$ (17.2 ) $ 3.4
Fair value of derivative contracts – long-term —
2.3
—
(2.2 ) 0.1
Total financial assets $ —
$ 22.9
$ —
$ (19.4 ) $ 3.5

Financial Liabilities
Fair value of derivative contracts – short-term $ —
$ 120.8
$ —
$ (17.2 ) $ 103.6
Fair value of derivative contracts – long-term —
34.0
—
(2.2 ) 31.8
Total financial liabilities $ —

$ 154.8

$ —

$ (19.4 )
$ 135.4

_______________________


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


⁽²⁾	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of

December 31, 2018 on the Condensed Consolidated Balance Sheets related to the Haynesville Divestiture.

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q:



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	97.1	$	97.1	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	5.3	$	5.3	$	14.6	$	14.6
Total debt outstanding	$	2,079.8	$	2,042.5	$	2,507.1	$	2,350.5

Carrying Amount Level 1 Fair Value Carrying Amount Level 1 Fair Value
June 30, 2018 December 31, 2017
Financial Assets (in millions)
Cash and cash equivalents $ —
$ —
$ —
$ —
Financial Liabilities
Checks outstanding in excess of cash balances $ 8.5
$ 8.5
$ 44.0
$ 44.0
Long-term debt $ 2,649.4
$ 2,684.2
$ 2,160.8
$ 2,256.2

The carrying amounts of cash and cash equivalents 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. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

The fair value of the deficiency charge obligation associated with the Pinedale Divestiture was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. Refer to Note 3 – Acquisitions and Divestitures for ~~additional~~more information.

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 utilizes fair value on a periodic basis, at least annually, to review its proved oil and gas properties and operating lease right-of-use assets for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. 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. ~~Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy.~~ 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 ~~pursuant to~~utilizing a probability-weighted approach in which the ~~terms~~likelihood of possible outcomes is taken into consideration. Given the unobservable nature of the ~~purchase~~inputs, fair value calculations associated with long-term operating lease right-of-use assets and ~~sale agreement.~~proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the six months ended June 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease. During the six months ended June 30, 2018, the Company recorded impairments on certain proved oil and gas properties of $397.6 ~~million, resulting in a reduction of the associated carrying amount to fair value. During the six months ended June 30, 2017, the Company recorded no impairments on proved oil and gas properties.~~million.

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. In addition, during the time that QEP ~~has historically~~owned gas storage facilities or had contracts for gas storage capacity, QEP entered into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price 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. Gas price derivative instruments are typically structured as fixed-price swaps or collars at NYMEX Henry Hub or regional price indices. QEP also enters into oil ~~and gas~~ basis swaps to achieve a fixed-price swap for a portion of its oil ~~and gas~~ sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative ~~transactions~~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, ~~2018:~~2019:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	6.6	$	55.24
2019	ICE Brent	0.9	$	66.73
2019	Argus WTI Houston	0.2	$	65.70
2020	NYMEX WTI	6.2	$	60.07
2020	Argus WTI Midland	0.7	$	60.00

Year Index Total Volumes Average Swap Price per Unit
(in millions)
Oil sales (bbls)
($/bbl)
2018 NYMEX WTI 8.3
$ 52.46
2019 NYMEX WTI 9.5
$ 52.66
2020 NYMEX WTI 1.5
$ 60.47
Gas sales (MMBtu)
($/MMBtu)
2018 NYMEX HH 53.7
$ 3.00
2019 NYMEX HH 43.8
$ 2.86

QEP uses oil ~~and gas~~ basis swaps, combined with NYMEX WTI ~~and NYMEX HH fixed price~~fixed-price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil ~~and gas~~ basis swaps as of June 30, ~~2018:~~2019:


Year	Index	Basis	Total Volumes	Weighted-Average Differential			Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)						(in millions)
Oil sales			(bbls)	($/bbl)					(bbls)	($/bbl)
2018	NYMEX WTI	Argus WTI Midland	4.6	$	(0.99	)
2018	NYMEX WTI	Argus WTI Houston⁽¹⁾	0.2	$	6.30
2019	NYMEX WTI	Argus WTI Midland	4.7	$	(0.77	)	NYMEX WTI	Argus WTI Midland	3.3	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston⁽¹⁾	0.4	$	4.35		NYMEX WTI	Argus WTI Houston	0.9	$	3.69
2020	NYMEX WTI	Argus WTI Midland	1.5	$	(1.01	)	NYMEX WTI	Argus WTI Midland	4.4	$	(0.02	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	3.7	$	(0.16	)
2020 (January - June)							NYMEX WTI	Argus WTI Houston	0.4	$	3.75

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 Initiatives~~comprehensive review of strategic alternatives to ~~transition~~maximize shareholder value, resulting in our decision to ~~a pure-play Permian Basin company,~~move forward as an independent company;


•	our strategy to continue to focus on high-return investments in our business with disciplined production growth;

our commitment to strengthening our balance sheet, reducing leverage and returning capital to shareholders;

improved performance and deliverability of our asset base;

plans to reduce general and administrative expense significantly;

timing of the implementation of organizational changes;

expected costs associated with contractual termination benefits, including severance and accelerated vesting of share-based compensations, as part of the ~~use of proceeds from such asset sales;~~strategic initiatives;

~~reducing~~plans to reduce operating and ~~per well~~ drilling, completion and facility costs and managing liquidity;

plans to grow oil and condensate ~~production in the Permian Basin;~~production;

drilling and completion plans and strategies;

~~acquiring~~adding additional acreage in our operating areas;

adequacy of procedures implemented to protect against credit-related losses;

expectations and assumptions regarding oil, gas and NGL prices, including volatility and effects on our business;

our ability to meet delivery and sales commitments;

impact of potential activist shareholders to our operations, personnel retention, strategies and costs;

the ~~Permian Basin to add development opportunities and facilitate the drilling~~unfunded status of ~~long lateral wells;~~our pension plan;

~~estimated~~estimates of future ~~payments to reimburse the buyer in the Pinedale Divestiture~~liability for ~~certain~~ deficiency charges ~~related to~~in connection with the ~~gas processing and NGL transportation and fractionation contracts;~~

~~future development costs and funding for such development costs;~~divestiture of our assets in Pinedale;

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;~~

~~ability of our inventory locations to provide a~~ solid base for growth in production and ~~reserves;~~reserves provided by our inventory of drilling locations;

adjustments to our capital investment program based on a variety of factors; including an evaluation of ~~potential acquisitions~~drilling and ~~divestiture opportunities;~~

~~our balance sheet~~completion activities and ~~liquidity position allowing us to grow oil production in the Permian Basin and achieve our Strategic Initiatives;~~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 ~~including estimated impairment amounts,~~ 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 and fair value~~obligations;

critical accounting estimates, ~~of stock options;~~including assets retirement obligations;

impact of global geopolitical and macroeconomic events and 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, including the effect of such delays on quarterly operating ~~results;~~results and planned conversion of PUD reserves;

~~plans and ability to pursue acquisition opportunities;~~

~~sufficiency of our~~maintaining a sufficient liquidity position to ensure financial flexibility, withstand commodity price volatility, and fund our development projects, operations, capital expenditures and ~~capital expenditures;~~costs related to strategic initiatives;

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

~~implementation and impact~~factors impacting ability to incur additional indebtedness;

off-balance sheet arrangements;

redemption of ~~new accounting pronouncements;~~senior notes;

assumptions regarding share-based compensation;

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

~~recognition of compensation expense related to share-based compensation grants;~~AMT credits amount and timing; and

~~expected~~our plans regarding contributions to ~~our employee benefit plans;~~the nonqualified retirement plan (SERP), medical plan and 401(k) plan.

~~novation of commodity derivatives upon the closing of the Uinta Basin Divestiture;~~

~~effect of the Strategic Initiatives on employee benefit plans; and~~

~~costs associated with employee retention program and contractual termination benefits, including severance and accelerated vesting of share-based compensations.~~

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 ~~2017~~2018 Form 10-K and Item 1A of Part II of this Quarterly Report on Form 10-Q;

any potential impact from the announcement that the Board of Directors of the Company completed its comprehensive review of strategic alternatives and is moving forward as an independent company;

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 risks and liabilities associated with acquired assets;

asset impairments;

~~fair value estimates;~~

~~timing of and proceeds from asset divestitures;~~

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;

the amount of AMT credit refunds realized;

tariffs on products we use in our operations on products we sell;

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;

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;

actions of activist shareholders; 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, ~~2018.~~2019. Based on such evaluation, such officers have concluded that, as of June 30, ~~2018,~~2019, 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 ~~SEC's~~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, ~~2018,~~2019, 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

~~There have been no~~The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. Item 103 of the SEC's Regulation S-K requires disclosure of material ~~changes with respect~~pending legal proceedings, other than ordinary routine litigation incidental to the ~~legal~~business, to which QEP or any of its subsidiaries is a party or of which any of their property is the subject. Item 103 also requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings ~~reported in our 2017 Form 10-K.~~ and the proceedings involve potential monetary sanctions that the Company reasonably believes could exceed $100,000. The matter below is disclosed pursuant to that second requirement. Refer to Note 1011 – Commitments and Contingencies in Item I of Part I of this Quarterly Report on Form 10-Q for additional information regarding our legal proceedings.

Environmental Protection Agency (EPA) Request for Information- As previously disclosed, in July 2015, QEP received an information request from the EPA pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP's Williston Basin operations. QEP timely responded to the information request, and has been in discussions with the EPA regarding this matter. In June, 2019, QEP and the EPA entered into a Consent Agreement under which QEP agreed to pay an immaterial monetary penalty and adopt an enhanced inspection, monitoring and repair program.

ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its ~~2017~~2018 Form 10-K. There have been no material changes to such risk factors since filing the ~~2017~~2018 Form 10-K, except for the risk ~~factors~~factor below. The risks described below and in the ~~2017~~2018 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.

~~QEP~~Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may ~~be unable to successfully execute certain aspects~~adversely affect the market value of ~~its announced Strategic Initiatives.QEP announced Strategic Initiatives to transition to a pure-play Permian Basin company. This transition contemplates QEP divesting its assets~~QEP’s current or future debt obligations, including QEP’s revolving credit facility. Regulators and law enforcement agencies in the ~~Williston Basin, Uinta Basin~~United Kingdom and ~~Haynesville Shale. Any divestiture of a business or assets involves potential risks.~~

~~Organizational modifications due to divestitures or other strategic changes can alter~~elsewhere are conducting civil and criminal investigations into whether the risk and control environments; disrupt ongoing business; distract management and employees; increase expenses; result in additional liabilities, investigations and litigation; harm QEP's strategy; and adversely affect results of operations. Even if these challenges are dealt with successfully, the anticipated benefits of the divestitures may not be realized.

~~QEP is subject to complex federal, state, tribal, local and other laws and regulations~~banks that ~~could adversely affect its cost of doing business and recording of proved reserves~~. QEP's operations are subject to extensive federal, state, tribal and local tax, energy, environmental, health and safety laws and regulations. The failure to comply with applicable laws and regulations can result in substantial penalties and may threaten the Company's authorization to operate.

Environmental laws and regulations are complex, change frequently and have tended to become more onerous over time. This regulatory burden on the Company's operations increases its cost of doing business and, consequently, affects its profitability. In additioncontributed to the ~~costs~~British Bankers Association (BBA) in connection with the calculation of ~~compliance, substantial costs~~daily LIBOR may ~~be incurred~~have been under-reporting or otherwise manipulating or attempting to ~~take corrective actions at both owned~~manipulate LIBOR. A number of BBA member banks have entered into settlements with their regulators and ~~previously owned facilities. Accidental spills and leaks requiring cleanup may occur in~~law enforcement agencies with respect to this alleged manipulation of LIBOR. Actions by the ~~ordinary course~~BBA or any other administrator of QEP's business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time, but now require remedial work to meet current standards. Failure to comply with these laws and regulationsLIBOR, regulators or law enforcement agencies may result in ~~fines, significant costs for remedial activities, other damages,~~changes to the manner in which LIBOR is determined, the phasing out of LIBOR or ~~injunctions~~the establishment of alternative reference rates. For example, in July 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. As a result, LIBOR may be discontinued by 2021. Furthermore, in the United States, efforts to identify a set of alternative U.S. dollar reference interest rates that could ~~limit~~replace LIBOR include proposals by the ~~scope~~Alternative Reference Rates Committee of the Federal Reserve Board and the Federal Reserve Bank of New York. At this time, it is not possible to predict whether any such changes will occur, whether LIBOR will be phased out or any such alternative reference rates or other reforms to LIBOR will be enacted in the United Kingdom, the United States or elsewhere or the effect that any such changes, phase out, alternative reference rates or other reforms, if they occur, would have on the amount of interest paid on, or the market value of, QEP’s current or future debt obligations, including QEP's revolving credit facility. Uncertainty as to the nature of such potential changes, phase out, alternative reference rates or other reforms may materially adversely affect the terms of QEP's ~~planned operations.~~

~~Clean Air Act regulations at 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) became effective in 2012, with further amendments effective in 2013~~revolving credit facility. Reform of, or the replacement or phasing out of, LIBOR and ~~2014. Subpart OOOO imposes air quality controls~~proposed regulation of LIBOR and ~~requirements upon QEP's operations. Additionally, in June 2016,~~other "benchmarks" may materially adversely affect the EPA finalized closely related rules in new Subpart OOOOa to achieve additional methane and volatile organic compound reductions from certain activities in the oil and gas industry. The new rules include, among others, new requirements for finding and repairing leaks at new well sites and "reduced emission completion" requirements for hydraulically fractured oil and gas wells. The future status of Subpart OOOOa remains uncertain given ongoing litigation and administrative regulatory actions. EPA has proposed a two-year staymarket value of, the ~~effective dates~~applicable interest rate on and the amount of ~~several requirements~~interest paid on QEP’s current or future debt obligations, including QEP's revolving credit facility.

Our business could be negatively affected as a result of ~~Subpart OOOOa, including fugitive emission requirements, well site pneumatic pump standards,~~actions of activist shareholders, and ~~requirements for certification~~such activism could impact the strategic direction of ~~closed vent systems. The rules, however, remain in effect as~~QEP and the trading value of ~~the filing~~our securities.Elliott Management Corporation (Elliott), a beneficial holder of ~~this report. The regulatory uncertainty surrounding the implementation~~approximately 4.9% of ~~this rule poses some complications for QEP's operations and compliance efforts. Additionally, many states are adopting air permitting and other air quality control regulations specific~~our common stock (based on Elliott's Form 13F-HR filed on May 15, 2019), made a proposal to ~~oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations.~~

~~On April 30, 2018, EPA formally designated much~~our Board on January 7, 2019, to acquire all shares of ~~the Uinta Basin as marginal nonattainment under the 2015 ozone standard, effective on August 3, 2018.~~our common stock. As a result of ~~this designation, oil~~that proposal, our Board of Directors engaged in a comprehensive review of strategic alternatives and ~~gas operators on~~concluded that the ~~Uinta and Ouray Indian Reservation (U&O Reservation) in the Uinta Basin will not be able~~best alternative for QEP's shareholders was to obtain permits by rule for new and modified oil and gas facilities under the federal implementation plan (FIP) established in 2016 for a Federal Minor New Source Review Program in Indian Country. Operators will, instead, be required to obtain individual permits, which may increase the time and expensemove forward as an independent company. Activities of obtaining permits on the U&O Reservation. While EPA has recently proposed amendments to apply the FIP to the U&O Reservation portion of the intended Uinta Basin Ozone Nonattainment Area, such amendments may not become effective in time and may not become effective at all, resulting in the unavailability for a period of several months or more of a streamlined permit-by-rule process under the FIP. As a result, our operational costs may increase or our production may be restricted in the Uinta Basin, whichactivist shareholders could ~~materially and~~ adversely affect our ~~financial condition, results of~~business and/or operations because:

responding to actions by activist shareholders could be costly and time-consuming, disrupting our operations and ~~cash flows.~~diverting the attention of our management and employees; and

~~QEP may be unable to divest of assets on financially attractive terms, resulting in reduced cash proceeds.~~ QEP has announced the sale of certain upstream and midstream assets. QEP's success in divesting assets depends, in part, upon QEP's ability to identify suitable buyers or joint venture partners; assess potential transaction terms; negotiate agreements; and, if applicable, obtain required approvals. Various factorssuch activities could materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include, but are not limited to: current and forecasted commodity prices; current laws, regulations and permitting processes impacting oil and gas operations in the areas where the assets are located; covenants under QEP's credit agreement; tax impacts; willingness of the purchaser to assume certain liabilities such as asset retirement obligations; QEP's willingness to indemnify buyers for certain matters; and other factors.

In addition, QEP's credit agreement contains limitations on the amount of asset sales that it is permitted to divest each year. If QEP seeks to sell more assets than is permitted under the credit agreement and is unable to receive waivers of such restrictions, then it may be unable to divest of these assets.

~~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 June 2014, the North Dakota Industrial Commission (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. It is possible that other states will require gas capture plans in the future to reduce flaring. Additionally, in November 2016, the Bureau of Land Management (BLM) finalized a new rule related to further controls on the venting, flaring and emissions of natural gas on BLM and tribal leases (the 2016 Venting and Flaring Rule). The rule took effect in January 2017. Some provisions of the rule required compliance in January 2017, including the royalty provisions, while other provisions including those related to further controls on the venting and flaring of natural gas, did not require compliance until January 2018. The 2016 Venting and Flaring Rule is the subject of active litigation in the U.S. District Court for the District of Wyoming. In December 2017, the BLM published a rule to delay the January 2018 compliance deadlines and suspend the obligation to complyinterfere with certain provisions that had required compliance in January 2017, until January 2019 (2017 Delay Rule). Certain states and environmental nongovernmental organizations (ENGOs) filed litigation in the U.S. District Court for the Northern District of California challenging the 2017 Delay Rule, and the court preliminarily enjoined the 2017 Delay Rule on February 22, 2018, requiring operators to immediately comply with the 2016 Venting and Flaring Rule. These state and federal gas capture requirements, and 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. On April 4, 2018, the U.S. District Court for the District of Wyoming stayed certain compliance obligations required by the 2016 Venting and Flaring while the BLM completes a rulemaking process in which it may revise the 2016 Venting and Flaring Rule. The District of Wyoming's decision has been appealed to the U.S Court of Appeals for the Tenth Circuit.

~~Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect~~ our ability to ~~conduct drilling activities in areas where we operate.~~ ~~Oil and natural gas operations in~~execute our ~~operating areas may be adversely affected by seasonal~~strategic plan or ~~permanent restrictions on drilling activities designed to protect various species and wildlife. Seasonal restrictions may limit~~realize short- or long-term value from our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened and endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse effect on our ability to develop and produce our reserves. For example, the Department of the Interior's Fish and Wildlife Service (FWS) listed the Louisiana Pine Snake as threatened under the Endangered Species Act (ESA) in April 2018. The FWS identified Bienville Parish as one of the parishes where the snake can be found. QEP operates within Bienville Parish. Additionally, the FWS plans to issue a proposed rule listing the Lesser Prairie-Chicken as a threatened or endangered species. The Lesser Prairie-Chicken is a grouse species native to Texas, including parts of the Permian Basin where QEP operates. The FWS is in the process of making a final determination in 2018 of whether to list under the ESA.assets.

~~Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce~~. Climate change, the costs that may be associated with its effects and the regulation of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products, reducing the demand for and consumption of our products (due to changes in both costs and weather patterns) and negatively impacting the economic health of the regions in which we operate, all of which can create financial risks. In addition, if restrictions on GHG emissions significantly increase our costs to produce oil and gas, or significantly decrease demand for our products, the value of our oil and gas reserves may decrease. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. In addition, legislative and regulatory responses related to GHG emissions and climate change may result in increased operating costs, delays in obtaining air emissions and other necessary permits for new or modified facilities and reduced demand for the oil, gas and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale of climate change regulation under various laws pertaining to the environment, energy use and energy resource development. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, or banning the use of gasoline or diesel powered vehicles, which may reduce demand for oil and natural gas. Further, state and local governments may pursue litigation against producers for damages allegedly resulting from climate change. QEP's ability to access and develop new oil and gas reserves may also be restricted by climate change regulation, including GHG reporting and regulation.

Congress has previously considered but not adopted proposed legislation aimed at reducing GHG emissions. The EPA has adopted final regulations under the Clean Air Act for the measurement and reporting of GHG emitted from certain large facilities and, as discussed above, has adopted additional regulations at 40 C.F.R Part 60, Subparts OOOO and OOOOa, to include additional requirements to reduce methane and volatile organic compound emissions from oil and natural gas facilities. The status of Subpart OOOOa is uncertain given the ongoing litigation, administrative reconsideration and proposed action to stay portions of those rules. Additionally, in June 2014, the United States Supreme Court upheld a portion of EPA's GHG stationary source permitting program in Utility Air Regulatory Group v. EPA, but also invalidated a portion of it. The Court's holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations to which QEP's operations are subject.

In December 2015, over 190 countries, including the U.S., reached an agreement in Paris (COP 21) to reduce global emissions of GHG (the Paris Agreement). The Paris Agreement provides for the cutting of carbon emissions every five years, beginning in 2023, and sets a goal of keeping global warming to a maximum limit of two degrees Celsius and a target limit of 1.5 degrees Celsius greater than pre-industrial levels. In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. Withdrawal will take a few years to implement due to the Paris Agreement's legal structure and language. The current state of development of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties or domestic regulations. Following the initiation of the U.S. withdrawal from the Paris Agreement, state and local regulation efforts are expected to increase. In several of the states in which QEP operates the regulatory authorities are considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. For example, in January 2018, the Utah Department of Environment Quality (UDEQ) adopted additional rules that impose leak detection and repair requirements at certain oil and gas facilities in Utah. In addition, the failure of the federal government to address climate change concerns, including, for example, a protracted delay by President Trump's administration in determining its own carbon-cost estimate (i.e., the estimate of how much carbon pollution costs society via climate damages) after rejecting the $40 per ton of carbon dioxide equivalent estimate of the Obama administration, could empower ENGOs to pursue legal challenges to oil and gas drilling and pipeline projects.

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in precipitation and extreme weather events. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are exacerbated by climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable.

QEP relies on highly skilled personnel and, if QEP is unable to retain or motivate key personnel, hire qualified personnel, or transfer knowledge from retiring personnel, QEP's operations may be negatively impacted. QEP's performance largely depends on the talents and efforts of highly skilled individuals. QEP's future success depends on its continuing ability to identify, hire, develop, motivate, and retain highly skilled personnel for all areas of its organization. Competition in the oil and gas industry for qualified employees is intense. QEP's continued ability to compete effectively depends on its ability to attract new employees and to retain and motivate its existing employees. QEP does not maintain key-man insurance for its key management personnel. In connection with the announcement of its plans to divest of its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley, QEP entered into retention and severance agreements with its executives and other key management personnel. Nonetheless, the loss of services of one or more of its key management personnel could have a negative impact on QEP's financial condition and results of operations.

~~General economic and other conditions could negatively impact QEP's operating results~~. QEP's operating results may also be negatively affected by changes in global economic conditions; availability and economic viability of oil and gas properties for sale or exploration; rate of inflation and interest rates; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy and other pipeline and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; tariffs on steel and steel products used in oil and gas operations; tariffs on oil, gas and NGLs: and terrorist attacks or acts of war.

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

On February 28, 2018, QEP announced the authorization by its Board of Directors to repurchase up to $1.25 billion of the Company's outstanding shares of common stock (the February 2018 $1.25 billion Repurchase Program). The timing and amount of any QEP share repurchases will be subject to available liquidity and market ~~conditions and proceeds from the asset sales.~~conditions. The share repurchase program does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.

During the three months ended June 30, 2019, no shares were repurchased under the previously announced plan. The following repurchases of QEP shares were made by QEP in association with vested restricted share awards withheld for

taxes and pursuant to the Company's share repurchase authorization.

Period
Total shares purchased⁽¹⁾⁽²⁾
Weighted-average price paid per share Total shares purchased as part of publicly announced plans or programs Remaining dollar amount that may be purchased under the plans or programs
(in millions)
April 1, 2018 - April 30, 2018 651,838
$ 9.64
592,310
$ 1,191.6
May 1, 2018 - May 31, 2018 35,214
$ 12.20
—
$ 1,191.6
June 1, 2018 - June 30, 2018 7,812
$ 12.06
—
$ 1,191.6
Total 694,864
592,310



Period	Total shares purchased⁽¹⁾	Weighted-average price paid per share		Total shares purchased as part of publicly announced plans or programs	Remaining dollar amount that may be purchased under the plans or programs
					(in millions)
April 1, 2019 - April 30, 2019	48,090	$	8.05	—	$	1,191.6
May 1, 2019 - May 31, 2019	11,248	$	7.44	—	$	1,191.6
June 1, 2019 - June 30, 2019	6,997	$	6.01	—	$	1,191.6
Total	66,335			—

____________________________


⁽¹⁾	During the three months ended June 30, ~~2018,~~2019, QEP purchased ~~102,554~~66,335 shares from employees in connection with the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants.


⁽²⁾	During the three months ended June 30, 2018, QEP repurchased and retired 592,310 shares under the February 2018 $1.25 billion Repurchase Program at a weighted average price of $9.37 per share, excluding commission of $0.02 per share, for $5.6 million. Shares are as of the settlement date.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

~~None.~~Amended and Restated Executive Severance Compensation Plan - CIC

On August 5, 2019, the Compensation Committee of the Company’s Board of Directors approved an amendment and restatement, effective August 7, 2019, of the Company’s Executive Severance Compensation - CIC (CIC Plan), to, among other things, clarify the manner in which severance calculations will be made for certain executives. The CIC Plan provides severance compensation and other benefits to eligible executive officers upon a termination of their employment without cause or a resignation of their employment for good reason, in either case within three years following a change in control. Payments and benefits upon such a qualifying termination generally consist of a payment measured based on a multiple of annual base salary and average annual incentive awards (depending on seniority), a pro-rated annual incentive award payment for the year of termination, a payment in respect of certain enhanced retirement benefits and continued participation (without cost) in health and welfare benefit programs for either two or three years (depending on level of position). Payments are generally made in a lump sum shortly following termination (except the pro-rated annual incentive award payment is paid following the end of the year in which the termination occurs), subject to any legally required delay, and may be reduced in certain circumstances on account of Section 280G of the Internal Revenue Code (Code). No Code Section 280G gross ups are provided.

A copy of the CIC Plan is filed with this Form 10-Q and attached hereto as Exhibit 10.2 and incorporated by reference herein. The foregoing description of the CIC Plan is qualified in its entirety by reference to the full text of the CIC Plan.

Letter Agreement

On August 6, 2019, QEP entered into an agreement (Agreement) with Elliott Management Corporation, a Delaware corporation (Elliott).

Under the terms of the Agreement, the Company agreed to issue a press release announcing, among other things, Elliott’s support of QEP and its strategy to move forward as an independent company.

The Agreement also provides that Elliott and the Company will cooperate with each other to select two individuals (New Directors)to be appointed to the Company’s board of directors (Board)as soon as reasonably practical, but in any event within 75 days of signing the Agreement. The New Directors will qualify as independent under the rules of the New York Stock Exchange, will have technical and operating oil and gas experience and will not be affiliated with Elliott. QEP also agreed to include the New Directors in the slate of directors to be proposed for election by the Board in QEP’s proxy statement (2020 Proxy Statement) for the 2020 annual meeting (2020 Annual Meeting). Elliott and the Company further agreed that, following the appointment of the New Directors, the Board will form a five-person Operations Committee comprised of the chief executive officer, the New Directors and two existing members of the Board. The purpose of the Operations Committee will be to identify best operating practices in the areas of the Company’s operations and to work with management to focus on continuous operational improvement and excellence.

The Agreement also provides that at the 2020 Annual Meeting, Elliott will, so long as the Company’s nominees for the Board include the New Directors, vote or cause to be voted any shares of common stock of the Company that it or certain of its affiliates have the right to vote, as of the record date, in favor of the election of directors nominated by the Company and in accordance with the recommendations of the Board on the other proposals in the Proxy Statement not related to an extraordinary transaction.

Elliott further agreed that, subject to certain exceptions, until the earlier of (i) June 30, 2020 and (ii) the second business day after the completion of the 2020 Annual Meeting, not to, among other things and subject to certain exceptions: (a) make any "solicitation" of proxies (as such terms are used in the proxy rules of the Securities and Exchange Commission), (b) form, join or act in concert with any "group" as defined in Section 13(d)(3) of the United States Securities Exchange Act of 1934 (the Exchange Act), other than solely with affiliates of Elliott with respect to voting securities now or hereafter held by them, (c) acquire, offer or seek to acquire any voting securities of the Company that would result in Elliott having a net long position of, or voting rights with respect to, more than 9.9% of the voting securities of the Company, (d) effect or seek to effect, whether alone or in concert with others, any extraordinary transaction involving the Company, (e) enter into any voting trust or similar arrangement, (f) seek to (i) elect or appoint to, or have representation on, the Board or (ii) remove any member of the Board, (g) make or be the proponent of any shareholder proposal (pursuant to Rule 14a-8 under the Exchange Act or otherwise) or (h) enter into any discussions, negotiations, agreements or understandings with any third party with respect to the foregoing.

A copy of the Agreement is filed with this Form 10-Q and attached hereto as Exhibit 10.3 and incorporated by reference herein. The foregoing description of the Agreement is qualified in its entirety by reference to the full text of the Agreement.

ITEM 6. EXHIBITS

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



Exhibit No.		~~Exhibits~~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, ~~dated effective October 23, 2017~~as amended and restated on May 14, 2019 (incorporated by reference to Exhibit ~~3.2~~3.1 to the Company's ~~Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on October 25, 2017).~~
~~10.1+~~		~~2018 Long-Term Incentive Plan, as adopted on May 15, 2018 (incorporated by reference to the Company’s~~ Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 17, ~~2018)~~2019).
10.210.1+		~~Form of Restricted Stock Agreement for restricted stock granted to executive officers after May 2018 under the 2018 Long-Term Incentive Plan.~~
~~10.3*+~~		~~Form of Performance Share Unit Award Agreement for performance share units granted to executive officers after May 2018 under the 2012 Cash Incentive Plan.~~
~~10.4*+~~		Form of Deferred Share Award Agreement for shares of common stock granted to ~~executives~~non-employee directors under the ~~2019~~2018 Long-Term Incentive Plan and for deferral of receipt of such shares in accordance with the terms of the Director Deferred Compensation ~~Wrap Plan - Deferred Compensation Program.~~Plan.
~~31.1~~10.2*+		Executive Severance Compensation Plan – CIC, as Amended and Restated Effective as of August 7, 2019.
10.3*		Letter Agreement, dated August 6, 2019, by and between QEP Resources, Inc. and Elliott Management Corporation.
31.1*		Certification signed by ~~Charles B. Stanley,~~Timothy J. Cutt, QEP Resources, Inc.'s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
~~31.2~~31.2*		Certification signed by Richard J. Doleshek, QEP Resources, Inc.'s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
~~32.1~~32.1**		Certification signed by ~~Charles B. Stanley~~Timothy J. Cutt and Richard J. Doleshek, QEP Resources, Inc.'s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley 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~~Document.
101.CAL**		XBRL Calculation Linkbase ~~Document~~Document.
101.LAB**		XBRL Label Linkbase ~~Document~~Document.
101.PRE**		XBRL Presentation Linkbase ~~Document~~Document.
101.DEF**		XBRL Definition Linkbase ~~Document~~Document.

____________________________


+	Indicates a management contract or compensatory plan or arrangement.


*	Filed ~~herewith~~herewith.


**	These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.Furnished herewith.

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 25, 2018~~August 7, 2019	/s/ ~~Charles B. Stanley~~Timothy J. Cutt
	~~Charles B. Stanley,~~Timothy J. Cutt,
	~~Chairman,~~ President and Chief Executive Officer

~~July 25, 2018~~August 7, 2019	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

6158



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



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



Large accelerated filer	ý☒	Accelerated filer	o☐
Non-accelerated filer	o ~~(Do not check if a smaller reporting company)~~ ☐	Smaller reporting company	o☐
		Emerging growth company	o☐



	Three Months Ended						Six Months Ended
Derivative contracts	June 30,						June 30,
	2019			2018			2019			2018
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(16.0	)	$	(52.0	)	$	(19.0	)	$	(96.3	)
Gas derivative contracts	—			6.4			(2.9		)	7.3
Gas Storage
Gas derivative contracts	—			0.1			—			0.3
Realized gains (losses) on commodity derivative contracts	(16.0		)	(45.5		)	(21.9		)	(88.7		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	54.5			(20.6		)	(122.8		)	(27.5		)
Gas derivative contracts	—			(13.0		)	(0.3		)	(15.8		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	54.5			(33.6		)	(123.1		)	(43.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	38.5		$	(79.1	)	$	(145.0	)	$	(132.3	)

Derivatives associated with Haynesville Divestiture
Unrealized gains (losses) on commodity derivative contracts
Production
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	$	38.5		$	(79.1	)	$	(143.2	)	$	(132.3	)



	Three Months Ended						Six Months Ended
Derivative contracts	June 30,						June 30,
	2018			2017			2018			2017
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(52.0	)	$	11.5		$	(96.3	)	$	9.5
Gas derivative contracts	6.4			(5.1		)	7.3			(19.3		)
Gas Storage
Gas derivative contracts	0.1			—			0.3			(0.2		)
Realized gains (losses) on commodity derivative contracts	(45.5		)	6.4			(88.7		)	(10.0		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(20.6		)	70.5			(27.5		)	174.8
Gas derivative contracts	(13.0		)	29.4			(15.8		)	100.5
Gas Storage
Gas derivative contracts	—			0.4			(0.3		)	2.3
Unrealized gains (losses) on commodity derivative contracts	(33.6		)	100.3			(43.6		)	277.6
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(79.1	)	$	106.7		$	(132.3	)	$	267.6



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



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



			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, ~~2018~~2019 AND ~~2017~~2018	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND SIX MONTHS ENDED JUNE 30, ~~2018~~2019 AND ~~2017~~2018	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, ~~2018~~2019 AND DECEMBER 31, ~~2017~~2018	4

		UNAUDITED CONDENSED ~~CONOSLIDATED STATEMENT~~CONSOLIDATED STATEMENTS OF EQUITY FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018	5

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, ~~2018~~2019 AND ~~2017~~2018	6

		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7

	ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2729

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	4849

	ITEM 4.	CONTROLS AND PROCEDURES	5453

PART II. OTHER INFORMATION			5453

	ITEM 1.	LEGAL PROCEEDINGS	5453

	ITEM 1A.	RISK FACTORS	54

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	5955

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	5955

	ITEM 4.	MINE SAFETY DISCLOSURES	5955

	ITEM 5.	OTHER INFORMATION	5955

	ITEM 6.	EXHIBITS	6057

SIGNATURES			6158



	Three Months Ended								Six Months Ended
	June 30, 2018								June 30, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾			As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	520.3		$	12.4	$	532.7		$	930.1		$	25.1	$	955.2
Other revenue	3.0			—		3.0			8.0			—		8.0
Purchased oil and gas sales	9.1			—		9.1			23.2			—		23.2
Total Revenues	532.4			12.4		544.8			961.3			25.1		986.4
OPERATING EXPENSES
Purchased oil and gas expense	9.8			—		9.8			25.3			—		25.3
Lease operating expense	66.5			—		66.5			139.0			—		139.0
Transportation and processing costs	31.2			12.4		43.6			65.2			25.1		90.3
Gathering and other expense	3.4			—		3.4			6.2			—		6.2
General and administrative	55.8			—		55.8			115.9			—		115.9
Production and property taxes	37.6			—		37.6			66.5			—		66.5
Depreciation, depletion and amortization	242.2			—		242.2			438.7			—		438.7
Exploration expenses	0.1			—		0.1			0.1			—		0.1
Impairment	403.7			—		403.7			404.4			—		404.4
Total Operating Expenses	850.3			12.4		862.7			1,261.3			25.1		1,286.4
Net gain (loss) from asset sales, inclusive of restructuring costs	(3.9		)	—		(3.9		)	(0.4		)	—		(0.4		)
OPERATING INCOME (LOSS)	(321.8		)	—		(321.8		)	(300.4		)	—		(300.4		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(79.1		)	—		(79.1		)	(132.3		)	—		(132.3		)
Interest and other income (expense)	(3.1		)	—		(3.1		)	(3.8		)	—		(3.8		)
Interest expense	(38.2		)	—		(38.2		)	(73.2		)	—		(73.2		)
INCOME (LOSS) BEFORE INCOME TAXES	(442.2		)	—		(442.2		)	(509.7		)	—		(509.7		)
Income tax (provision) benefit	106.2			—		106.2			120.1			—		120.1
NET INCOME (LOSS)	$	(336.0	)	$	—	$	(336.0	)	$	(389.6	)	$	—	$	(389.6	)

Earnings (loss) per common share
Basic	$	(1.42	)	$	—	$	(1.42	)	$	(1.63	)	$	—	$	(1.63	)
Diluted	$	(1.42	)	$	—	$	(1.42	)	$	(1.63	)	$	—	$	(1.63	)

Weighted-average common shares outstanding
Used in basic calculation	237.0			—		237.0			238.9			—		238.9
Used in diluted calculation	237.0			—		237.0			238.9			—		238.9
Dividends per common share	$	—		$	—	$	—		$	—		$	—	$	—



	June 30, 2018		December 31, 2017
	(in millions)
Assets
Current assets, total	$	0.4	$	0.9
Property, Plant and Equipment	192.5		612.6
Other noncurrent assets	18.9		19.3
Noncurrent assets held for sale	$	211.8	$	632.8
Liabilities
Current liabilities, total	$	0.9	$	0.8
Asset retirement obligations, current	3.5		4.0
Asset retirement obligations, long-term	48.2		47.6
Other long-term liabilities	0.2		0.2
Other long-term liabilities held for sale	$	52.8	$	52.6



	Asset Retirement Obligations
	(in millions)
ARO liability at December 31, 2017⁽¹⁾	$	162.5
Accretion	2.6
Additions	3.5
Revisions	(3.5		)
Liabilities settled	(4.5		)
ARO liability at June 30, 2018⁽¹⁾	$	160.6


⁽¹⁾	~~Argus WTI Houston~~ ~~is an index price reflecting the weighted average price of WTI at Magellan's East Houston crude oil terminal.~~



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Current:		(in millions)
Commodity⁽¹⁾	Fair value of derivative contracts	$	2.7	$	88.2	$	17.6	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	15.2		35.4		0.9		0.7
Total derivative instruments		$	17.9	$	123.6	$	18.5	$	1.1



	Three Months Ended		Six Months Ended
	June 30, 2019⁽¹⁾		June 30, 2019⁽¹⁾
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions⁽²⁾	$	4.1	$	8.8

	Three Months Ended		Six Months Ended
	June 30, 2019⁽¹⁾		June 30, 2019⁽¹⁾
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	3.0	$	6.1
Gathering and other expense	2.3		3.8
General and administrative	1.6		3.2

Total lease cost	$	11.0	$	21.9


⁽¹⁾	Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule. Refer to Note 1 – Basis of Presentation for additional information.


⁽²⁾	Represents short-term lease capital expenditures related to drilling rigs for the three and six months ended June 30, 2019. These costs are capitalized as a part of "Proved properties" on the Condensed Consolidated Balance Sheets.



	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, 2019
	(in millions)
Termination benefits	$	(0.1	)	$	(0.1	)	$	—		$	—
Office lease termination costs	—			—			—			—
Accelerated share-based compensation⁽¹⁾	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⁽¹⁾	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	)

	Three Months Ended June 30, 2018
Termination benefits	$	3.6		$	1.7		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	1.2			1.2			—			—
Retention expense (including share-based compensation)	6.3			6.3			—			—
Total restructuring costs	$	11.4		$	9.5		$	1.9		$	—

	Six Months Ended June 30, 2018
Termination benefits	$	7.0		$	5.1		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	4.0			4.0			—			—
Retention expense (including share-based compensation)	8.0			8.0			—			—
Total restructuring costs	$	19.3		$	17.4		$	1.9		$	—



	Costs recognized period from inception to June 30, 2018		Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	7.0	$	—	⁽¹⁾
Office lease termination costs	0.3		—		⁽¹⁾
Accelerated share-based compensation	4.0		—		⁽¹⁾
Retention expense	8.0		16.0		⁽²⁾
Pension curtailment	—		—		⁽¹⁾
Total restructuring costs	$	19.3	$	16.0



	Costs recognized from inception to June 30, 2019⁽¹⁾			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	38.9		$	—	⁽²⁾
Office lease termination costs	1.6			—		⁽²⁾
Accelerated share-based compensation	21.0			—		⁽²⁾
Retention expense (including share-based compensation)	29.7			10.1
Pension and Medical Plan curtailment	(0.2		)	—		⁽²⁾
Total restructuring costs	$	91.0		$	10.1


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


⁽²⁾	Due to the nature of the ~~Strategic Initiatives and uncertain factors such~~strategic initiatives, as ~~timing and terms~~ of ~~the potential divestitures,~~June 30, 2019, the Company is not able to reasonably estimate the total cost to be incurred ~~as a part of this restructuring.~~


⁽²⁾	~~QEP expects to incur an additional $12.0 million of expense~~ in ~~2018 and $4.0 million in 2019 related to the retention program.~~connection with these restructurings.



	Restructuring liability
	Termination benefits			Office lease termination costs			Accelerated share-based compensation			Retention expense			Pension curtailment			Total
	(in millions)
Balance at December 31, 2018	$	19.5		$	—		$	—		$	10.8		$	—		$	30.3
Costs incurred and charged to expense	6.7			0.6			9.7			10.9			(0.4		)	27.5
Costs paid or otherwise settled	(23.9		)	(0.6		)	(9.7		)	(15.9		)	0.4			(49.7		)
Balance at June 30, 2019	$	2.3		$	—		$	—		$	5.8		$	—		$	8.1


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


⁽²⁾	Of the total present value of lease liabilities, $18.8 million was recorded in "Current operating lease liabilities" and $47.9 million was recorded in "Operating lease liabilities" on the Condensed Consolidated Balance Sheets.



	Options Outstanding		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2018	2,098,933		$	22.27
Cancelled	(283,029	)	30.90
Outstanding at June 30, 2019	1,815,904		$	20.93	2.80	$	—
Options Exercisable at June 30, 2019	1,761,139		$	21.08	2.74	$	—
Unvested Options at June 30, 2019	54,765		$	15.92	4.69	$	—



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	3,822,133		$	10.76
Granted	2,217,794		7.98
Vested	(2,261,323	)	11.05
Forfeited	(178,985	)	9.23
Unvested balance at June 30, 2019	3,599,619		$	8.94



	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	1,559,312		$	11.47
Granted	589,412		7.93
Vested and paid	(1,117,848	)	10.73
Unvested balance at June 30, 2019	1,030,876		$	9.63



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	42,675		$	10.47
Granted	37,224		7.93
Vested and paid	(36,392	)	10.67
Unvested balance at June 30, 2019	43,507		$	8.16


⁽¹⁾	Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income (loss) are recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".


•	Reduced capital expenditures by $249.1 million compared to the second quarter 2018; and


		Operated				Non-operated					Operated				Non-operated
	Drilling	Drilling		Waiting on completion		Drilling		Waiting on completion		Drilling	Drilling		Waiting on completion		Drilling		Waiting on completion
	Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin(1)	—	—	—	—	—	1	—	9	0.1	1	2	2.0	5	4.4	3	0.1	12	1.7
Uinta Basin	—	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin⁽¹⁾	5	25	24.8	27	26.5	—	—	—	—
Haynesville/Cotton Valley	—	—	—	1	1.0	3	0.2	7	0.3
Permian Basin⁽²⁾										2	5	5.0	44	44.0	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—


⁽¹⁾	The 2 gross operated drilling ~~well count~~wells in the Williston Basin represent wells in which intermediate casing had been set as of June 30, 2019.


⁽²⁾	The 5 gross operated drilling wells in the Permian Basin ~~includes 13~~represent wells for which surface casing ~~has~~had been set ~~but~~ as of June 30, ~~2018, did not have a rig drilling.~~2019.


	Operated Put on Production				Non-operated Put on Production				Operated Put on Production				Non-operated Put on Production
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2018		June 30, 2018		June 30, 2018		June 30, 2018		June 30, 2019		June 30, 2019		June 30, 2019		June 30, 2019
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	11	10.1	11	10.1	2	0.1	2	0.1	—	—	—	—	5	0.1	5	0.1
Uinta Basin	—	—	2	2.0	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin	37	36.1	68	67.1	—	—	—	—	23	23.0	35	34.9	5	0.4	5	0.4
Haynesville/Cotton Valley	1	1.0	3	3.0	3	0.1	9	0.5
Other Southern	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—