QEP Resources Reports Third Quarter 2019 Financial and Operating Results

DENVER, Oct. 23, 2019 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported third quarter 2019 financial and operating results.

HIGHLIGHTS

Increased full-year production guidance for crude oil, natural gas and NGL
Lowered mid-point of capital expenditure guidance by approximately $15 million, down $65 million year-to-date
Reduced G&A expense to 2020 target run-rate, down approximately 40% from third quarter 2018 to third quarter 2019
Greater than 60% of projected 2020 oil production hedged at $58.31 per barrel
Ended the quarter with $92.4 million of cash and cash equivalents and no borrowings under credit facility

"Operational performance in the third quarter exceeded expectations, with our core Permian Basin assets delivering record oil production. The outperformance of the Permian assets is directly attributable to the enhanced flowback and artificial lift strategy, along with improved frac to first production timing that we implemented earlier in the year. As a result, we have increased our annual production guidance for crude oil, natural gas and NGL and lowered the midpoint of CAPEX guidance by approximately $15 million compared to the second quarter," commented Tim Cutt, President and CEO of QEP.

"Our continued focus on reducing expenses has allowed us to lower the outlook for Lease Operating and G&A Expense. These tangible expense savings, coupled with the year-to-date reductions to drilling, completion and facility cost, resulted in QEP generating Free Cash Flow in the third quarter and positions the Company to generate significant Free Cash Flow in the fourth quarter. Our ability to generate significant Free Cash Flow on an annual basis going forward is expected to allow us to organically de-lever our balance sheet and return capital to shareholders."

The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release.

QEP Third Quarter 2019 Financial Results

The Company reported net income of $81.0 million for the third quarter 2019, or $0.34 per diluted share, compared with net income of $7.3 million, or $0.03 per diluted share, for the third quarter 2018. The Company's increase in net income in the third quarter of 2019 compared to 2018 was primarily due to an $87.4 million gain on realized and unrealized derivative contracts in the third quarter of 2019.

Net income includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, asset impairments and certain other items. Excluding these items, the Company’s third quarter 2019 Adjusted Net Income (a non-GAAP measure) was $11.0 million, or $0.05 per diluted share, compared to Adjusted Net Income of $39.6 million, or $0.17 per diluted share, for the third quarter 2018.

Adjusted EBITDA (a non-GAAP measure) for the third quarter 2019 was $193.5 million compared with $326.2 million for the third quarter 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower equivalent production in the Williston Basin and a 16% decrease in average field-level oil prices, partially offset by an 18% increase in equivalent production in the Permian Basin, a $33.5 million decrease in realized derivative losses and an $18.7 million decrease in general and administrative expenses.

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

Production

Oil equivalent production was 8.4 million barrels of oil equivalent (MMboe) in the third quarter 2019, a decrease of 42% compared with the third quarter 2018. The decrease in oil equivalent production was primarily the result of the loss of 5.2 MMboe (3% liquids) of equivalent production associated with the assets sold in the Haynesville/Cotton Valley and Uinta Basin divestitures.

Oil and condensate production in the Permian Basin was 4.0 million barrels (MMbbl) in the third quarter 2019, an increase of 12% compared with the third quarter of 2018, and a Company record. The production increase was offset by lower volumes in the Williston Basin due to a reduced level of activity in the third quarter of 2019 and a loss of volumes as a result of the Uinta Basin divestiture.

Operating Expenses

During the third quarter 2019, lease operating expense (LOE) was $38.3 million, a decrease of 41% compared with the third quarter 2018. The decrease is primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $14.1 million, driven by a decrease in maintenance and repair expenses, labor and water disposal in the Permian and Williston basins as a result of continuing efforts to reduce operating expenses.

During the third quarter of 2019, LOE was $4.56 per Boe, an increase of 2% compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE per Boe decreased by 20% compared to the third quarter of 2018. The 20% decrease per BOE rate was related to lower cost production from the recent horizontal well completions in the Permian Basin, partially offset by decreased production in the Williston Basin.

During the third quarter 2019, Transportation and Processing (T&P) Costs were $18.0 million, a decrease of 36% compared with the third quarter 2018. Adjusted T&P Costs (a non-GAAP measure) were $32.2 million, a decrease of 26% compared with the third quarter 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, Adjusted T&P Costs increased $5.2 million, primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations as well as increased production in the Permian Basin, partially offset by decreased production in the Williston Basin.

During the third quarter 2019, T&P Costs increased by $0.20 per Boe, or 10%, compared with the third quarter 2018. Adjusted T&P costs increased $0.79 per Boe, or 26%, during the third quarter of 2019 compared to the third quarter of 2018. The increase was primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations, partially offset by the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher adjusted transportation and processing costs per Boe.

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

During the third quarter 2019, general and administrative (G&A) expense was $29.6 million, a decrease of 39% compared to the third quarter 2018. During the third quarter of 2019 and 2018, QEP incurred $10.0 million and $14.2 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $10.4 million and $12.8 million, respectively, related to restructuring costs. Excluding these costs, G&A expense decreased by $14.4 million, or 42%, primarily due to $12.7 million lower labor, benefits and other associated costs due to the reduction in our workforce and $3.2 million in lower legal and outside service costs, partially offset by a $2.2 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures. During the quarter the third quarter 2019, G&A was $3.52 per BOE.

During the third quarter 2019, production and property taxes were $20.0 million, a decrease of 47% compared to the third quarter 2018. The decrease in production and property taxes was primarily due to decreased revenues in the Williston Basin as well as the Haynesville/Cotton Valley and Uinta Basin divestitures.

During the third quarter of 2019, production and property taxes were $2.38 per Boe, a decrease of 8% compared to the third quarter of 2018, but decreased 35% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 35% decrease was due to a decrease in average field-level equivalent prices in the Permian and Williston basins.

Capital Investment

Capital investment, excluding property acquisitions, was $128.9 million (on an accrual basis) for the third quarter 2019, compared with $203.7 million for the third quarter 2018, of which $122.9 million related to the drilling, completion and equipping of wells and $6.0 million was related to midstream infrastructure investment. The decrease in capital expenditures was primarily related to a decrease in completion activity in the Permian Basin, partially offset by increased capital expenditures in the Williston Basin as the Company resumed drilling and completion activity in the basin.

Asset Divestitures

QEP closed on the sale of several assets during the third quarter 2019, including the corporate aircraft, for total net cash proceeds of approximately $9.8 million.

Liquidity

Net Cash Provided by Operating Activities for the third quarter 2019 was $146.3 million, compared with $298.0 million for the third quarter 2018. Free Cash Flow (a non-GAAP measure) was $17.5 million for the third quarter 2019, compared with $26.2 million for the third quarter 2018. Free Cash Flow was negative $66.9 million for the first three quarters of 2019 compared with negative $375.9 million for the first three quarters of 2018. Although the Company generated negative Free Cash Flow during the first three quarters of 2019, $676.5 million of proceeds was raised through the disposition of assets.

As of September 30, 2019, the Company had $92.4 million in cash and cash equivalents, no borrowings under its revolving credit facility and $2.9 million in letters of credit outstanding.

2019 Updated Guidance

QEP's fourth quarter and full year 2019 guidance assumes: (1) an oil price of $55 per barrel and a natural gas price of $2.50 per MMBtu, (2) that QEP will elect to recover ethane from its produced gas in the Permian Basin when processing economics support it, (3) no additional property acquisitions or divestitures, other than those already disclosed (4) includes approximately 10 days of production activity in the Haynesville/Cotton Valley and (5) includes the impact of lower flare volume and higher gas and NGL capture in the Permian Basin.

Rig Count:

Permian Basin: average of three rigs for first half of 2019 and two rigs for the second half of 2019
Williston Basin: one rig in the first quarter 2019 to drill seven gross operated wells

Wells Put on Production:

Permian Basin: 59 net operated wells
Williston Basin: six net operated wells

2019 Guidance
	4Q 2019	2019	2019
	Guidance	Previous Guidance	Updated Guidance
Oil & condensate production (MMbbl)	5.7 - 6.0	21.0 - 21.5	21.6 - 21.9
Gas production (Bcf)	7.9 - 8.4	28.0 - 30.0	32.4 - 32.9
NGL production (MMbbl)	1.3 - 1.5	4.25 - 4.50	5.0 - 5.2
Total oil equivalent production (MMboe)	8.3 - 8.9	29.9 - 31.0	32.0 - 32.6

Lease operating expense and Adjusted Transportation and Processing Costs (per Boe)⁽¹⁾		$9.00 - $10.00	$8.50 - $9.25
Depletion, depreciation and amortization (per Boe)		$16.75 - $17.75	$16.75 - $17.75
Production and property taxes (% of field-level revenue)		7.0%	7.5%
(in millions)
Total general and administrative expense⁽²⁾		$160.0 - $170.0	$155.0 - $165.0
Less: Special general & administrative expense⁽³⁾		$54.0	$54.0
Total General and administrative expense (excluding special general & administrative expense)		$106.0 - $116.0	$101.0 - $111.0

Capital investment (excluding property acquisitions)
Drilling, Completion and Equipment ⁽⁴⁾		$520.0 - $540.0	$515.0 - $530.0
Midstream Infrastructure⁽⁵⁾		$55.0	$50.0
Corporate		$5.0	$2.0
Total capital investment (excluding property acquisitions)	$101.0 - $116.0	$580.0 - $600.0	$567.0 - $582.0

Wells put on production (net)	3	65	65

____________________________
⁽¹⁾Adjusted Transportation and Processing Costs (per Boe) is a non-GAAP measure. Refer to Non-GAAP Measures at the end of this release.
⁽²⁾The mid-point of G&A expense includes approximately $26.0 million of expenses related to non-cash, share-based compensation and other mark-to-market liabilities. Because these mark-to-market liabilities fluctuate with stock price changes, the amount of actual expense may vary from the forecasted amount.
⁽³⁾ Special G&A expense also includes approximately $54.0 million of estimated expenses associated with our strategic initiative process, primarily related to severance and retention programs, and includes approximately $11.0 million of accelerated shared-based compensation expense that is included in the $26.0 million of expenses related to non-cash, share-based compensation and other mark-to-market liabilities.
⁽⁴⁾Drilling, Completion and Equipment includes approximately $20.0 million of non-operated well costs.
⁽⁵⁾Includes capital expenditures in the Permian Basin associated with (a) water sourcing, gathering, recycling and disposal and (b) crude oil and natural gas gathering system.

Operations Summary

	Permian Basin		Williston Basin

	As of September 30, 2019
	Gross	Net	Gross	Net
Well Progress
Drilling	7	7.0	—	—

At total depth - under drilling rig	6	6.0	—	—
Waiting to be completed	25	25.0	—	—
Completed, awaiting production	—	—	4	3.4
Waiting on completion	31	31.0	4	3.4

Put on production⁽¹⁾	24	24.0	3	3.0

_______________________
⁽¹⁾Total wells put on production during the three months ended September 30, 2019.

Permian Basin

Permian Basin net oil equivalent production averaged a Company record of approximately 61.5 Mboed (86% liquids) during the third quarter 2019, a 23% increase compared with the second quarter 2019 and an 18% increase compared with the third quarter 2018. Oil and condensate production in the Permian Basin was 4.0 MMbbl in the third quarter 2019, a 12% increase compared with the third quarter of 2018.

In the third quarter 2019, the Company put on production 24 gross-operated horizontal wells, all on Mustang Springs (average working interest 100%).

At the end of the third quarter 2019, of the 24 wells put on production during the quarter, 12 wells had reached peak production rates and 12 wells were still in the process of cleaning up. The wells put on production during the third quarter 2019 have an average lateral length of 8,631 feet.

At the end of the third quarter 2019, the Company had seven gross-operated horizontal wells in process of being drilled (of which five had surface casing set, but had no drilling rig present) (average working interest 100%), six horizontal wells at total depth under drilling rigs and 25 horizontal wells waiting to be completed (average working interest 100%).

At the end of the third quarter 2019, the Company had two operated rigs in the Permian Basin.

Williston Basin

Williston Basin net oil equivalent production averaged approximately 29.6 Mboed (80% liquids) during the third quarter 2019, a 9% decrease compared with the second quarter 2019 and a 38% decrease compared with the third quarter 2018, primarily due to a reduced level of activity.

During the third quarter 2019 the Company completed a seven well (gross) pad on South Antelope. During the last week of third quarter 2019 three wells (gross) of the seven wells (gross) were put on production. The remaining four wells (gross) were put on production in early October 2019.

At the end of the third quarter 2019, the Company had no drilling rigs in the Williston Basin.

Third Quarter 2019 Results Conference Call

QEP’s management will discuss third quarter 2019 results in a conference call tomorrow, October 24, 2019, beginning at 9:00 a.m. ET. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website immediately after the call through November 23, or by dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for international calls, and then entering the conference ID #13695492. In addition, QEP’s slides for the third quarter 2019 can be found on the Company’s website.

About QEP Resources, Inc.

QEP Resources, Inc. (NYSE: QEP) is an independent crude oil and natural gas exploration and production company focused in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). For more information, visit QEP's website at: www.qepres.com.

Forward-Looking Statements

This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions. Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include statements regarding: ability to generate Free Cash Flow in the fourth quarter of 2019 and full year 2020; ability to strengthen our balance sheet; ability to execute on our development programs and capture opportunities to create shareholder value; actively managing and improving our cost structure; reducing G&A expense; plans for development of our Permian Basin and Williston Basin assets; operating our business safely; the number and location of drilling rigs to be deployed and wells to be put on production; forecast production amounts and related assumptions; forecasted lease operating expense and Adjusted Transportation and Processing Expense, depletion, depreciation and amortization expense, general and administrative expense, non-cash share-based compensation expense, restructuring costs, production and property taxes, and capital investment for 2019 and related assumptions for such guidance; allocation of capital investment; fourth quarter and full year 2019 production guidance and assumptions for such guidance; plans regarding ethane rejection and recovery; the impact of lower flare volume and higher gas and NGL capture in the Permian Basin; and usefulness of non-GAAP measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: changes in oil, gas and NGL prices; liquidity constraints, including those resulting from the cost or unavailability of financing due to debt and equity capital and credit market conditions, changes in QEP’s credit rating, QEP’s compliance with loan covenants, the increasing credit pressure on QEP’s industry or demands for cash collateral by counterparties to derivative and other contracts; market conditions; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries and other oil producing countries such as Russia; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural oil, gas and NGL; impact of new laws and regulations, including the use of hydraulic fracture stimulation; impact of U.S. dollar exchange rates on oil, gas and NGL prices; elimination of federal income tax deductions for oil and gas exploration and development; guidance for implementation of the Tax Cuts and Jobs Act; actual proceeds from asset sales; actions of Elliott Management Corporation or other activist shareholders; tariffs on products QEP uses in its operations or on the products QEP sells; drilling results; shortages of oilfield equipment, services and personnel; the availability of storage and refining capacity; operating risks such as unexpected drilling conditions; transportation constraints, including gas and crude oil pipeline takeaway capacity in the Permian Basin; weather conditions; changes in maintenance, service and construction costs; permitting delays; outcome of contingencies such as legal proceedings; inadequate supplies of water and/or lack of water disposal sources; credit worthiness of counterparties to agreements; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission (SEC), including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 and in the Company's quarterly and current reports filed with the SEC subsequent to the Annual Report on Form 10-K. QEP undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

Contact

Investors/Media:

William I. Kent, IRC

Director, Investor Relations

303-405-6665

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018

REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	305.6		$	544.0		$	875.8		$	1,474.1
Other revenues	1.8			3.8			7.1			11.8
Purchased oil and gas sales	0.1			13.0			1.4			36.2
Total Revenues	307.5			560.8			884.3			1,522.1
OPERATING EXPENSES
Purchased oil and gas expense	0.1			13.3			1.5			38.6
Lease operating expense	38.3			64.6			135.5			203.6
Transportation and processing costs	18.0			28.0			38.8			93.2
Gathering and other expense	3.1			4.6			9.9			10.8
General and administrative	29.6			48.3			124.4			164.2
Production and property taxes	20.0			37.4			67.6			103.9
Depreciation, depletion and amortization	144.2			234.9			395.5			673.6
Exploration expenses	—			—			—			0.1
Impairment	—			—			5.0			404.4
Total Operating Expenses	253.3			431.1			778.2			1,692.4
Net gain (loss) from asset sales, inclusive of restructuring costs	(2.1		)	27.1			2.5			26.7
OPERATING INCOME (LOSS)	52.1			156.8			108.6			(143.6		)
Realized and unrealized gains (losses) on derivative contracts	87.4			(108.0		)	(55.8		)	(240.3		)
Interest and other income (expense)	0.9			(0.3		)	4.6			(4.1		)
Interest expense	(32.8		)	(38.7		)	(100.0		)	(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	107.6			9.8			(42.6		)	(499.9		)
Income tax (provision) benefit	(26.6		)	(2.5		)	55.7			117.6
NET INCOME (LOSS)	$	81.0		$	7.3		$	13.1		$	(382.3	)

Earnings (loss) per common share
Basic	$	0.34		$	0.03		$	0.06		$	(1.60	)
Diluted	$	0.34		$	0.03		$	0.06		$	(1.60	)

Weighted-average common shares outstanding
Used in basic calculation	237.9			236.9			237.7			238.3
Used in diluted calculation	237.9			237.0			237.7			238.3

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30, 2019			December 31, 2018

ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	92.4		$	—
Accounts receivable, net	104.3			104.3
Income tax receivable	75.5			75.9
Fair value of derivative contracts	69.8			87.5
Prepaid expenses and other current assets	8.1			12.9
Total Current Assets	350.1			280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,416.9			9,096.9
Unproved properties	698.3			705.5
Gathering and other	162.7			167.7
Materials and supplies	19.3			29.9
Total Property, Plant and Equipment	10,297.2			10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,153.3			4,882.4
Gathering and other	58.5			58.1
Total Accumulated Depreciation, Depletion and Amortization	5,211.8			4,940.5
Net Property, Plant and Equipment	5,085.4			5,059.5
Fair value of derivative contracts	23.2			35.4
Operating lease right-of-use assets, net	57.4			—
Other noncurrent assets	54.5			49.6
Noncurrent assets held for sale	—			692.7
TOTAL ASSETS	$	5,570.6		$	6,117.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	0.7		$	14.6
Accounts payable and accrued expenses	206.2			258.1
Production and property taxes	17.7			24.1
Current portion of long term debt	51.7			—
Interest payable	33.0			32.4
Fair value of derivative contracts	0.8			—
Current operating lease liabilities	18.4			—
Asset retirement obligations	6.7			5.1
Total Current Liabilities	335.2			334.3
Long-term debt	2,029.4			2,507.1
Deferred income taxes	208.0			269.2
Asset retirement obligations	95.5			96.9
Fair value of derivative contracts	0.4			0.7
Operating lease liabilities	45.3			—
Other long-term liabilities	86.8			97.4
Other long-term liabilities held for sale	—			61.3
Commitments and contingencies
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.1 million and 239.8 million shares issued, respectively	2.4			2.4
Treasury stock – 4.3 million and 3.1 million shares, respectively	(54.8		)	(45.6		)
Additional paid-in capital	1,451.9			1,431.9
Retained earnings	1,384.8			1,376.5
Accumulated other comprehensive income (loss)	(14.3		)	(14.3		)
Total Common Shareholders' Equity	2,770.0			2,750.9
TOTAL LIABILITIES AND EQUITY	$	5,570.6		$	6,117.8

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,


	2019			2018			2019			2018


OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	81.0		$	7.3		$	13.1		$	(382.3	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	144.2			234.9			395.5			673.6
Deferred income taxes (benefit)	26.5			0.9			(61.2		)	(119.6		)
Impairment	—			—			5.0			404.4
Non-cash share-based compensation	5.0			7.7			16.2			24.0
Amortization of debt issuance costs and discounts	1.3			1.4			4.0			4.0
Net (gain) loss from asset sales, inclusive of restructuring costs	2.1			(27.1		)	(2.5		)	(26.7		)
Unrealized (gains) losses on marketable securities	(0.1		)	(0.7		)	(2.8		)	(1.1		)
Unrealized (gains) losses on derivative contracts	(92.3		)	69.6			29.0			113.2
Changes in operating assets and liabilities	(21.4		)	4.0			(54.3		)	(14.6		)
Net Cash Provided by (Used in) Operating Activities	146.3			298.0			342.0			674.9
INVESTING ACTIVITIES
Property acquisitions	(1.8		)	(3.2		)	(3.6		)	(48.3		)
Property, plant and equipment, including exploratory well expense	(148.4		)	(267.8		)	(465.2		)	(1,032.1		)
Proceeds from disposition of assets	9.8			168.7			676.5			217.5
Net Cash Provided by (Used in) Investing Activities	(140.4		)	(102.3		)	207.7			(862.9		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(4.6		)	6.8			(13.9		)	(28.7		)
Long-term debt issuance costs paid	—			(0.1		)	—			(0.1		)
Proceeds from credit facility	—			586.5			56.0			2,616.0
Repayments of credit facility	—			(786.0		)	(486.0		)	(2,329.5		)
Common stock repurchased and retired	—			—			—			(58.4		)
Treasury stock repurchases	(0.7		)	(1.9		)	(7.0		)	(7.8		)
Dividends paid	(4.8		)	—			(4.8		)	—
Other capital contributions	—			0.1			—			0.3
Net Cash Provided by (Used in) Financing Activities	(10.1		)	(194.6		)	(455.7		)	191.8
Change in cash, cash equivalents and restricted cash	(4.2		)	1.1			94.0			3.8
Beginning cash, cash equivalents and restricted cash	126.3			26.1			28.1			23.4
Ending cash, cash equivalents and restricted cash	$	122.1		$	27.2		$	122.1		$	27.2

	Production by Region
	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018	Change		2019	2018	Change

	(in Mboe)
Northern Region
Williston Basin	2,722.5		4,381.1	(38	)%	9,061.9	12,570.5	(28	)%
Uinta Basin	—		606.0	(100	)%	—	2,232.2	(100	)%
Other Northern	19.4		63.1	(69	)%	65.1	211.4	(69	)%
Total Northern Region	2,741.9		5,050.2	(46	)%	9,127.0	15,014.1	(39	)%
Southern Region
Permian Basin	5,658.5		4,792.5	18	%	14,293.2	11,591.6	23	%
Haynesville/Cotton Valley	(0.4	)	4,552.8	(100	)%	310.5	13,604.6	(98	)%
Other Southern	4.0		4.5	(11	)%	14.3	20.4	(30	)%
Total Southern Region	5,662.1		9,349.8	(39	)%	14,618.0	25,216.6	(42	)%
Total production	8,404.0		14,400.0	(42	)%	23,745.0	40,230.7	(41	)%

	Total Production
	Three Months Ended September 30,				Nine Months Ended September 30,


	2019	2018	Change		2019	2018	Change


Oil and condensate (Mbbl)	5,670.5	6,640.5	(15	)%	15,904.4	18,182.1	(13	)%
Gas (Bcf)	8.2	38.1	(78	)%	24.6	111.5	(78	)%
NGL (Mbbl)	1,383.0	1,415.3	(2	)%	3,747.8	3,472.5	8	%
Total production (Mboe)	8,404.0	14,400.0	(42	)%	23,745.0	40,230.7	(41	)%
Average daily production (Mboe)	91.3	156.5	(42	)%	87.0	147.4	(41	)%

	Prices
	Three Months Ended September 30,								Nine Months Ended September 30,


	2019			2018			Change		2019			2018			Change


*Oil (per bbl)*
Average field-level price	$	52.70		$	62.65				$	52.44		$	61.89
Commodity derivative impact	(0.87		)	(6.27		)			(1.50		)	(7.59		)
Net realized price	$	51.83		$	56.38		(8	)%	$	50.94		$	54.30		(6	)%
*Gas (per Mcf)*
Average field-level price	$	1.13		$	2.67				$	1.61		$	2.71
Commodity derivative impact	—			0.09					(0.12		)	0.10
Net realized price	$	1.13		$	2.76		(59	)%	$	1.49		$	2.81		(47	)%
*NGL (per bbl)*
Average field-level price	$	8.63		$	29.65				$	11.50		$	25.39
Commodity derivative impact	—			—					—			—
Net realized price	$	8.63		$	29.65		(71	)%	$	11.50		$	25.39		(55	)%
*Average net equivalent price (per Boe)*
Average field-level equivalent price	$	38.06		$	38.87				$	38.60		$	37.66
Commodity derivative impact	(0.59		)	(2.66		)			(1.13		)	(3.16		)
Net realized equivalent price	$	37.47		$	36.21		3	%	$	37.47		$	34.50		9	%

	Operating Expenses
	Three Months Ended September 30,						Nine Months Ended September 30,


	2019		2018		Change		2019		2018		Change


	(in millions)
Lease operating expense	$	38.3	$	64.6	(41	)%	$	135.5	$	203.6	(33	)%
Adjusted transportation and processing costs⁽¹⁾	32.2		43.8		(26	)%	79.5		134.1		(41	)%
Production and property taxes	20.0		37.4		(47	)%	67.6		103.9		(35	)%
Total production costs	$	90.5	$	145.8	(38	)%	$	282.6	$	441.6	(36	)%

	(per Boe)
Lease operating expense	$	4.56	$	4.49	2	%	$	5.71	$	5.06	13	%
Adjusted transportation and processing costs⁽¹⁾	3.83		3.04		26	%	3.34		3.34		—	%
Production and property taxes	2.38		2.60		(8	)%	2.85		2.58		10	%
Total production costs	$	10.77	$	10.13	6	%	$	11.90	$	10.98	8	%

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

QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)

Adjusted EBITDA

This release contains references to the non-GAAP measure of Adjusted EBITDA. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment and certain other items. Management uses Adjusted EBITDA to evaluate QEP’s financial performance and trends, make operating decisions and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP’s performance from period to period. QEP’s Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

Below is a reconciliation of Net Income (Loss) (the most comparable GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,


	2019			2018			2019			2018


	(in millions)
Net income (loss)	$	81.0		$	7.3		$	13.1		$	(382.3	)
Interest expense	32.8			38.7			100.0			111.9
Interest and other (income) expense	(0.9		)	0.3			(4.6		)	4.1
Income tax provision (benefit)	26.6			2.5			(55.7		)	(117.6		)
Depreciation, depletion and amortization	144.2			234.9			395.5			673.6
Unrealized (gains) losses on derivative contracts	(92.3		)	69.6			29.0			113.2
Exploration expenses	—			—			—			0.1
Net (gain) loss from asset sales, inclusive of restructuring costs	2.1			(27.1		)	(2.5		)	(26.7		)
Impairment	—			—			5.0			404.4
Adjusted EBITDA	$	193.5		$	326.2		$	479.8		$	780.7

Free Cash Flow

This release contains references to non-GAAP measure of Free Cash Flow.

The Company defines Free Cash Flow as Adjusted EBITDA plus non-cash share-based compensation less cash interest expense, property acquisitions and property, plant equipment, including exploratory well expense. Management believes that this measure is useful to management and investors for analysis of the Company's ability to pay dividends, repay debt or repurchase stock.

Below is a reconciliation of Net Cash Provided by (Used in) Operating Activities (the most comparable GAAP measure) to Free Cash Flow. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,


	2019			2018			2019			2018


	(in millions)
Cash Flow Information:
Net Cash Provided by (Used in) Operating Activities	$	146.3		$	298.0		$	342.0		$	674.9
Net Cash Provided by (Used in) Investing Activities	(140.4		)	(102.3		)	207.7			(862.9		)
Net Cash Provided by (Used in) Financing Activities	(10.1		)	(194.6		)	(455.7		)	191.8

Free Cash Flow
Net Cash Provided by (Used in) Operating Activities	$	146.3		$	298.0		$	342.0		$	674.9
Amortization of debt issuance costs and discounts	(1.3		)	(1.4		)	(4.0		)	(4.0		)
Interest expense	32.8			38.7			100.0			111.9
Unrealized gains (losses) on marketable securities	0.1			0.7			2.8			1.1
Interest and other (income) expense	(0.9		)	0.3			(4.6		)	4.1
Deferred income taxes	(26.5		)	(0.9		)	61.2			119.6
Income tax provision (benefit)	26.6			2.5			(55.7		)	(117.6		)
Non-cash share-based compensation	(5.0		)	(7.7		)	(16.2		)	(24.0		)
Changes in operating assets and liabilities	21.4			(4.0		)	54.3			14.7
Adjusted EBITDA	193.5			326.2			479.8			780.7
Non-cash share-based compensation	5.0			7.7			16.2			24.0
Cash interest expense	(30.8		)	(36.7		)	(94.1		)	(100.2		)
Property acquisitions	(1.8		)	(3.2		)	(3.6		)	(48.3		)
Property, plant and equipment, including exploratory well expense	(148.4		)	(267.8		)	(465.2		)	(1,032.1		)
Free Cash Flow	$	17.5		$	26.2		$	(66.9	)	$	(375.9	)

Slide 13 of our October 2019 Investor Presentation includes a Free Cash Flow estimate for 2020 and relative sensitivity analysis. We are unable, however, to prove a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

Adjusted Net Income (Loss)

This release also contains references to the non-GAAP measure of Adjusted Net Income (Loss). Management defines Adjusted Net Income (Loss) as earnings excluding changes in fair value of derivative contracts, gains and losses from asset sales, impairment and certain other items. Management uses Adjusted Net Income (Loss) to evaluate QEP’s financial performance and trends, make operating decisions, and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP’s performance from period to period. QEP’s Adjusted Net Income (Loss) may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

Below is a reconciliation of Net Income (Loss) (the most comparable GAAP measure) to Adjusted Net Income (Loss). This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP.

	Three Months Ended September 30,						Nine Months Ended September 30,


	2019			2018			2019			2018


	(in millions, except earnings per share)
Net income (loss)	$	81.0		$	7.3		$	13.1		$	(382.3	)
Adjustments to net income (loss)
Unrealized (gains) losses on derivative contracts	(92.3		)	69.6			29.0			113.2
Income taxes on unrealized (gains) losses on derivative contracts(1)	20.7			(16.6		)	(37.9		)	(26.6		)
Net (gain) loss from asset sales, inclusive of restructuring costs	2.1			(27.1		)	(2.5		)	(26.7		)
Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs(1)	(0.5		)	6.4			3.3			6.3
Impairment	—			—			5			404.4
Income taxes on impairment(1)	—			—			(6.5		)	(95.0		)
Total after tax adjustments to net income	(70.0		)	32.3			(9.6		)	375.6
Adjusted Net Income (Loss)	$	11.0		$	39.6		$	3.5		$	(6.7	)

Earnings (Loss) per Common Share
Diluted earnings per share	$	0.34		$	0.03		$	0.06		$	(1.60	)
Diluted after-tax adjustments to net income (loss) per share	(0.29		)	0.14			(0.04		)	1.58
Diluted Adjusted Net Income per share	$	0.05		$	0.17		$	0.02		$	(0.02	)

Weighted-average common shares outstanding
Diluted	237.9			237.0			237.7			238.3

____________________________

⁽¹⁾Income tax impact of adjustments is calculated using QEP’s statutory rate of 22.4% and 23.8% for the three months ended September 30, 2019 and 2018, respectively and QEP's effective tax rate of 130.8% and 23.5% for the nine months ended September 30, 2019 and 2018, respectively.

Adjusted Transportation and Processing Costs

This release contains references to the non-GAAP measure of Adjusted Transportation and Processing Costs. Management defines Adjusted Transportation and Processing Costs as transportation and processing costs presented on the Condensed Consolidated Statements of Operations and transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. These costs are added together to reflect the total transportation and processing costs associated with QEP's production. Management believes that Adjusted Transportation and Processing Costs is useful supplemental information for investors as this non-GAAP measure, collectively with the Company’s lease operating expenses and production and severance taxes, more completely reflect the Company’s total production costs required to operate the wells for the period.

Below is a reconciliation of Adjusted Transportation and Processing Costs to transportation and processing costs as presented on the Condensed Consolidated Statements of Operations (the most comparable GAAP measure). This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial statements prepared in accordance with GAAP.

	Three Months Ended September 30,							Nine Months Ended September 30,


	2019		2018		Change			2019		2018		Change


	(in millions)
Transportation and processing costs, as presented	$	18.0	$	28.0	$	(10.0	)	$	38.8	$	93.2	$	(54.4	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	14.2		15.8		(1.6		)	40.7		40.9		(0.2		)
Adjusted transportation and processing costs	$	32.2	$	43.8	$	(11.6	)	$	79.5	$	134.1	$	(54.6	)

	(per Boe)
Transportation and processing costs, as presented	$	2.14	$	1.94	$	0.2		$	1.63	$	2.32	$	(0.69	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.69		1.1		0.59			1.71		1.02		0.69
Adjusted transportation and processing costs	$	3.83	$	3.04	$	0.79		$	3.34	$	3.34	$	—

2019 Updated Guidance includes a Lease operating expense and Adjusted Transportation and Processing Costs estimate for 2019. We are unable, however, to prove a quantitative reconciliation of the Adjusted Transportation and Processing Costs forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

The following tables present QEP's volumes and average prices for its open derivative positions as of October 18, 2019:

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)		($/bbl)
2019	NYMEX WTI	3.6	$	55.44
2019	ICE Brent	0.5	$	66.73
2019	Argus WTI Midland	0.2	$	54.6
2019	Argus WTI Houston	0.1	$	65.7
2020	NYMEX WTI	11.3	$	58.29
2020	Argus WTI Midland	1.5	$	57.3
2020 (January - June)	Argus WTI Houston	1.0	$	60.06

Production Commodity Derivative Basis Swaps
Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)		($/bbl)
2019	NYMEX WTI	Argus WTI Midland	1.7	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.5	$	3.69
2020	NYMEX WTI	Argus WTI Midland	6.6	$	0.17
2020 (January - June)	NYMEX WTI	Argus WTI Houston	0.4	$	3.75

Source: QEP Resources, Inc.

Investor Relations

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