Board Concludes Strategic Alternatives Review Process

DENVER, Aug. 07, 2019 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported second quarter 2019 financial and operating results and announced the outcome of its strategic alternatives review process.

HIGHLIGHTS

• QEP’s Board of Directors concluded formal strategic alternatives review process
• Go forward strategy focuses on free cash flow, reducing leverage and returning capital to shareholders
• Announced reinstatement of quarterly dividend of $0.02 per share
• Increased full-year production guidance for crude oil, natural gas and NGL
• Lowered mid-point of capital expenditure guidance by $50 million, or 8%, reflecting lower drilling and completion costs
• Lowered quarterly general and administrative expense to $32 million, a 50% decrease compared with first quarter 2019
• Poised to deliver Free Cash Flow in second half of 2019 and in 2020 at $50 oil while growing oil production 6% year over year
• Announced plans to add two new independent directors and form an Operations Committee of the Board

"QEP delivered solid performance in the second quarter, demonstrating significant progress on a number of fronts. The Company has completed its formal strategic review process and accelerated its transition to a high-performance, low-cost operator focused on free cash flow generation and returning capital to shareholders. We have increased annual production guidance for crude oil, natural gas and NGL, lowered CAPEX guidance by $50 million and reduced G&A expense by 50% - over $30 million - compared with the first quarter," commented Tim Cutt, President and CEO of QEP.

"Following a comprehensive review of strategic alternatives that began in February of this year, our Board has determined that the best path to create superior value for our shareholders is to move forward as an independent company. By continuing to improve operations and reduce costs, we will have the ability to generate meaningful free cash flow, which we will deploy to strengthen our balance sheet and return capital to shareholders, beginning with our reinstated quarterly dividend. The Board remains open to shareholder input and committed to all steps to maximize shareholder value, and has decided to add two new independent directors and form an Operations Committee to build on the progress we have made to-date, and continue to improve operational performance."

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

QEP SECOND QUARTER 2019 Financial Results

The Company reported net income of $48.8 million for the second quarter 2019, or $0.20 per diluted share, compared with a net loss of $336.0 million, or $1.42 per diluted share, for the second quarter 2018. The Company generated more income in the second quarter 2019 than in 2018 primarily due to a $403.7 million impairment expense in the second quarter 2018. See below for additional discussions on our production and operating expenses.

Net income or loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, asset impairments and certain other items. Excluding these items, the Company’s second quarter 2019 Adjusted Net Loss (a non-GAAP measure) was $7.3 million, or $0.04 per diluted share, compared with an Adjusted Net Income of $13.8 million, or $0.06 per diluted share, for the second quarter 2018.

Adjusted EBITDA (a non-GAAP measure) for the second quarter 2019 was $166.5 million compared with $282.6 million for the second quarter 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower production in the Williston Basin and an 11% decrease in average field-level oil prices, partially offset by a 13% increase in production in the Permian, a $29.5 million decrease in realized derivative losses and a $24.3 million decrease in general and administrative expenses.

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

Production

Oil and condensate production in the Permian Basin was 3.3 million barrels (MMbbl) in the second quarter 2019, an increase of 2% compared with the second quarter of 2018. The production increase was offset by lower volumes in the Williston Basin due to the lack of new well completions in 2019 and a loss of volumes as a result of the Uinta Basin divestiture.

Oil equivalent production was 7.5 million barrels of oil equivalent (MMboe) in the second quarter 2019, a decrease of 47% compared with the second quarter 2018. The decrease in oil equivalent production was primarily the result of the loss of 5.6 MMboe of equivalent production associated with the assets sold in the Haynesville/Cotton Valley and Uinta Basin divestitures.

Operating Expenses

During the second quarter 2019, lease operating expense (LOE) was $45.7 million, a decrease of 31% compared with the second quarter 2018. The decrease is primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $5.8 million, driven by a decrease in maintenance and repair expenses, labor and water disposal in the Williston Basin.

During the second quarter of 2019, LOE was $6.06 per Boe, an increase of 29% compared to the second quarter of 2018, but was flat excluding the loss of lower LOE production due to the Haynesville/Cotton Valley and Uinta Basin divestitures. The flat per BOE rate was related to lower cost production from the recent horizontal well completions in the Permian Basin offset by decreased production in the Williston Basin.

During the second quarter 2019, Transportation and Processing (T&P) Costs were $9.9 million, a decrease of 68% compared with the second quarter 2018. Adjusted T&P Costs (a non-GAAP measure) were $22.6 million, a decrease of 48% of T&P costs compared with the second quarter 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, Adjusted T&P Costs decreased $1.7 million, primarily due to decreased production in the Williston Basin, partially offset by increased production in the Permian Basin.

During the second quarter of 2019, T&P Costs decreased by $0.90 per Boe, or 41%, compared with the second quarter 2018. Adjusted T&P costs decreased $0.09 per Boe, or 3%, during the second quarter of 2019 compared to the second quarter of 2018. The decrease was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher Adjusted T&P Costs per Boe. Excluding the Haynesville/Cotton Valley and Uinta Basin divestitures, Adjusted T&P Costs per Boe were up 5% due to increased gas and NGL production, which has higher T&P 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 second quarter 2019, general and administrative (G&A) expense was $31.5 million, a decrease of 44% compared to the second quarter 2018. During the second quarter of 2019 and 2018, QEP incurred $7.2 million and $13.0 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $6.0 million and $9.5 million, respectively, related to restructuring costs. Excluding these costs, G&A expense decreased by $18.7 million, primarily due to $19.1 million lower labor, benefits and other associated costs due to the reduction in our workforce, partially offset by a $2.3 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures.

During the second quarter 2019, production and property taxes were $23.6 million, a decrease of 37% compared to the second 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 second quarter of 2019, production and property taxes were $3.13 per Boe, an increase of 18% compared to the second quarter of 2018, but decreased 16% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 16% decrease was due to a decrease in average field-level equivalent prices in the Permian and Williston basins, partially offset by higher ad valorem charges per Boe in the Permian Basin.

Capital Investment

Capital investment, excluding property acquisitions, was $169.9 million (on an accrual basis) for the second quarter 2019, compared with $365.7 million for the second quarter 2018, of which $155.1 million related to the drilling, completion and equipping of wells and $14.8 million was related to midstream infrastructure investment. The decrease in capital expenditures was primarily related to decreased drilling and completion activity in the Permian Basin and limited activity in the Williston Basin.

Asset Divestitures

QEP closed on the sale of several assets during the second quarter 2019 for total net cash proceeds of approximately $37.6 million.

Liquidity

Net Cash Provided by Operating Activities for the second quarter 2019 was $117.4 million, compared with $216.5 million for the second quarter 2018. Free Cash Flow (a non-GAAP measure) was negative $15.5 million for the second quarter 2019, compared with negative $150.3 million for the second quarter 2018. Free Cash Flow was negative $84.4 million for the first half of 2019 compared with negative $402.1 million for the first half of 2018. Although we had negative Free Cash Flow during the first half of 2019, it was offset by our $666.7 million of proceeds from the disposition of assets. We expect to generate Free Cash Flow during the second half of 2019 and for the full year 2020.

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

As of June 30, 2019, the Company had $97.1 million in cash and cash equivalents, no borrowings under its revolving credit facility and $2.9 million in letters of credit outstanding. The Company estimates that as of June 30, 2019, it could incur additional indebtedness of approximately $551.1 million and be in compliance with the covenants contained in its revolving credit facility.

2019 Updated Guidance

QEP's third 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 where processing economics support it, (3) no property acquisitions or divestitures, other than the Haynesville / Cotton Valley Divestiture (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 arrived in the first quarter 2019 to drill seven gross operated wells

Wells Put on Production:

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

2019 Guidance
	3Q 2019	2019	2019
	Guidance	Previous Guidance	Updated Guidance
Oil & condensate production (MMbbl)	5.2 - 5.4	20.5 - 21.5	21.0 - 21.5
Gas production (Bcf)	5.8 - 6.2	25.5 - 27.5	28.0 - 30.0
NGL production (MMbbl)	0.9 - 1.1	3.7 - 4.2	4.25 - 4.50
Total oil equivalent production (MMboe)	7.1 - 7.5	28.5 - 30.3	29.9 - 31.0
Lease operating expense and Adjusted Transportation and Processing Costs (per Boe)(1)		$9.00 - $10.00	$9.00 - $10.00
Depletion, depreciation and amortization (per Boe)		$16.75 - $17.75	$16.75 - $17.75
Production and property taxes (% of field-level revenue)		7.0%	7.0%
(in millions)
Total general and administrative expense(2)		$165.0 - $175.0	$160.0 - $170.0
Less: Special general & administrative expense(3)		$54.0	$54.0
Total General and administrative expense (excluding special general & administrative expense)		$113.0 - $119.0	$106.0 - $116.0
Capital investment (excluding property acquisitions)
Drilling, Completion and Equip(4)		$540.0 - $590.0	$520.0 - $540.0
Midstream Infrastructure(5)		$70.0	$55.0
Corporate		$5.0	$5.0
Total capital investment (excluding property acquisitions)	$150.0 - $160.0	$615.0 - $665.0	$580.0 - $600.0
Wells put on production (net)	22	63 - 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 $32.0 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 agreements, and includes approximately $11.0 million of accelerated shared-based compensation expense that is included in the $32.0 million of expenses related to non-cash, share-based compensation and other mark-to-market liabilities.
(4) Drilling, Completion and Equip includes approximately $24.0 million of non-operated well completion 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 June 30, 2019
	Gross			Net			Gross			Net
Well Progress
Drilling	5			5.0			2			2.0
At total depth - under drilling rig	6			6.0			—			—
Waiting to be completed	22			22.0			5			4.4
Undergoing completion	4			4.0			—			—
Completed, awaiting production	12			12.0			—			—
Waiting on completion	44			44.0			5			4.4
Put on production(1)	23			23.0			—			—
_______________________
(1) Total wells put on production during the three months ended June 30, 2019.

Permian Basin

Permian Basin net oil equivalent production averaged approximately 50.0 Mboed (86% liquids) during the second quarter 2019, a 10% increase compared with the first quarter 2019 primarily due to a greater number of wells being put on production during the quarter, and a 13% increase compared with the second quarter 2018. A portion of the quarter-over-quarter and year-over-year increase is driven by higher gas capture rates compared with prior quarters, primarily as a result of completion of midstream infrastructure. Oil and condensate production in the Permian Basin was 3.3 MMbbl in the second quarter 2019, a 2% increase compared with the second quarter of 2018.

In the second quarter 2019, the Company put on production 23 gross-operated horizontal wells, all on Mustang Springs (average working interest 100%).

At the end of the second quarter 2019, of the 23 wells put on production during the quarter, six wells had reached peak production rates and 17 wells were still in the process of cleaning up. The wells put on production during the second quarter 2019 have an average lateral length of 10,459 feet.

At the end of the second quarter 2019, the Company had five gross-operated horizontal wells in process of being drilled (of which all had surface casing set, but had no drilling rig present) (average working interest 100%), six horizontal wells at total depth under drilling rigs, 22 horizontal wells waiting to be completed (average working interest 100%), four horizontal wells undergoing completion (average working interest 100%), and 12 fully completed horizontal wells awaiting first production, which were part of a tank "pressure wall" (average working interest 100%).

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

Williston Basin

Williston Basin net oil equivalent production averaged approximately 32.6 Mboed (81% liquids) during the second quarter 2019, a 13% decrease compared with the first quarter 2019 and a 33% decrease compared with the second quarter 2018, primarily due to the lack of new well completions partially offset by higher gas capture rates.

During the second quarter 2019 the Company commenced drilling on a seven well (gross) pad on South Antelope. As of the end of quarter, five of the seven wells were waiting on completion. These wells are expected to be completed during the fourth quarter 2019.

At the end of the second quarter 2019, the Company had one drilling rig in the Williston Basin.

Second Quarter 2019 Results Conference Call

QEP’s management will discuss second quarter 2019 results in a conference call today, August 7, 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 August 25, 2019, 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 #13692793. In addition, QEP’s slides for the second 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 second half of 2019 and 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; third quarter production guidance and assumptions for such guidance; plans regarding ethane rejection and recovery; the amount of additional indebtedness QEP could incur and be compliance with loan covenants; and usefulness of non-GAAP measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: changes in oil, gas and NGL prices; liquidity constraints, including those resulting from the cost or unavailability of financing due to debt and equity capital and credit market conditions, changes in QEP’s credit rating, QEP’s compliance with loan covenants, the increasing credit pressure on QEP’s industry or demands for cash collateral by counterparties to derivative and other contracts; market conditions; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries and other oil producing countries such as Russia; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural oil, gas and NGL; impact of new laws and regulations, including the use of hydraulic fracture stimulation; impact of U.S. dollar exchange rates on oil, gas and NGL prices; elimination of federal income tax deductions for oil and gas exploration and development; guidance for implementation of the Tax Cuts and Jobs Act; actual proceeds from asset sales; actions of Elliott Management Corporation or other activist shareholders; tariffs on products QEP uses in its operations or on the products QEP sells; drilling results; shortages of oilfield equipment, services and personnel; the availability of storage and refining capacity; operating risks such as unexpected drilling conditions; transportation constraints, including gas and crude oil pipeline takeaway capacity in the Permian Basin; weather conditions; changes in maintenance, service and construction costs; permitting delays; outcome of contingencies such as legal proceedings; inadequate supplies of water and/or lack of water disposal sources; credit worthiness of counterparties to agreements; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2019. 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								Six Months Ended
	June 30,								June 30,
	2019				2018				2019				2018
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	294.6			$	520.3			$	570.2			$	930.1
Other revenues	1.6				3.0				5.3				8.0
Purchased oil and gas sales	—				9.1				1.3				23.2
Total Revenues	296.2				532.4				576.8				961.3
OPERATING EXPENSES
Purchased oil and gas expense	—				9.8				1.4				25.3
Lease operating expense	45.7				66.5				97.2				139.0
Transportation and processing costs	9.9				31.2				20.8				65.2
Gathering and other expense	3.0				3.4				6.8				6.2
General and administrative	31.5				55.8				94.8				115.9
Production and property taxes	23.6				37.6				47.6				66.5
Depreciation, depletion and amortization	128.0				242.2				251.3				438.7
Exploration expenses	—				0.1				—				0.1
Impairment	—				403.7				5.0				404.4
Total Operating Expenses	241.7				850.3				524.9				1,261.3
Net gain (loss) from asset sales, inclusive of restructuring costs	17.8				(3.9		)		4.6				(0.4		)
OPERATING INCOME (LOSS)	72.3				(321.8		)		56.5				(300.4		)
Realized and unrealized gains (losses) on derivative contracts	38.5				(79.1		)		(143.2		)		(132.3		)
Interest and other income (expense)	0.9				(3.1		)		3.7				(3.8		)
Interest expense	(33.2		)		(38.2		)		(67.2		)		(73.2		)
INCOME (LOSS) BEFORE INCOME TAXES	78.5				(442.2		)		(150.2		)		(509.7		)
Income tax (provision) benefit	(29.7		)		106.2				82.3				120.1
NET INCOME (LOSS)	$	48.8			$	(336.0	)		$	(67.9	)		$	(389.6	)
Earnings (loss) per common share
Basic	$	0.20			$	(1.42	)		$	(0.29	)		$	(1.63	)
Diluted	$	0.20			$	(1.42	)		$	(0.29	)		$	(1.63	)
Weighted-average common shares outstanding
Used in basic calculation	238.0				237.0				237.5				238.9
Used in diluted calculation	238.0				237.0				237.5				238.9

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30, 2019				December 31, 2018
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	97.1			$	—
Accounts receivable, net	93.5				104.3
Income tax receivable	70.8				75.9
Fair value of derivative contracts	2.7				87.5
Prepaid expenses	7.1				12.7
Other current assets	0.2				0.2
Total Current Assets	271.4				280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,316.0				9,096.9
Unproved properties	706.6				705.5
Gathering and other	169.1				167.7
Materials and supplies	20.9				29.9
Total Property, Plant and Equipment	10,212.6				10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,050.9				4,882.4
Gathering and other	58.4				58.1
Total Accumulated Depreciation, Depletion and Amortization	5,109.3				4,940.5
Net Property, Plant and Equipment	5,103.3				5,059.5
Fair value of derivative contracts	15.2				35.4
Operating lease right-of-use assets, net	60.2				—
Other noncurrent assets	54.2				49.6
Noncurrent assets held for sale	—				692.7
TOTAL ASSETS	$	5,504.3			$	6,117.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	5.3			$	14.6
Accounts payable and accrued expenses	227.9				258.1
Production and property taxes	15.9				24.1
Current portion of long term debt	51.7				—
Interest payable	32.5				32.4
Fair value of derivative contracts	17.6				—
Current operating lease liabilities	18.8				—
Asset retirement obligations	6.8				5.1
Total Current Liabilities	376.5				334.3
Long-term debt	2,028.1				2,507.1
Deferred income taxes	181.4				269.2
Asset retirement obligations	94.6				96.9
Fair value of derivative contracts	0.9				0.7
Operating lease liabilities	47.9				—
Other long-term liabilities	85.6				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; 242.0 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	1,446.3				1,431.9
Retained earnings	1,308.6				1,376.5
Accumulated other comprehensive income (loss)	(14.4		)		(14.3		)
Total Common Shareholders' Equity	2,689.3				2,750.9
TOTAL LIABILITIES AND EQUITY	$	5,504.3			$	6,117.8

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2019				2018				2019				2018
OPERATING ACTIVITIES									(in millions)
Net income (loss)	$	48.8			$	(336.0	)		$	(67.9	)		$	(389.6	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	128.0				242.2				251.3				438.7
Deferred income taxes (benefit)	30.2				(106.4		)		(87.7		)		(120.5		)
Impairment	—				403.7				5.0				404.4
Non-cash share-based compensation	3.2				7.1				11.2				16.3
Amortization of debt issuance costs and discounts	1.4				1.3				2.7				2.6
Net (gain) loss from asset sales, inclusive of restructuring costs	(17.8		)		3.9				(4.6		)		0.4
Unrealized (gains) losses on marketable securities	(0.8		)		(0.5		)		(2.7		)		(0.4		)
Unrealized (gains) losses on derivative contracts	(54.5		)		33.6				121.3				43.6
Changes in operating assets and liabilities	(21.1		)		(32.4		)		(32.9		)		(18.6		)
Net Cash Provided by (Used in) Operating Activities	117.4				216.5				195.7				376.9
INVESTING ACTIVITIES
Property acquisitions	(1.2		)		(8.9		)		(1.8		)		(45.1		)
Property, plant and equipment, including exploratory well expense	(152.2		)		(393.6		)		(316.8		)		(764.3		)
Proceeds from disposition of assets	49.3				15.5				666.7				48.8
Net Cash Provided by (Used in) Investing Activities	(104.1		)		(387.0		)		348.1				(760.6		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(5.0		)		(11.3		)		(9.3		)		(35.5		)
Proceeds from credit facility	11.5				961.0				56.0				2,029.5
Repayments of credit facility	(11.5		)		(771.0		)		(486.0		)		(1,543.5		)
Common stock repurchased and retired	—				(5.6		)		—				(58.4		)
Treasury stock repurchases	(0.5		)		(1.2		)		(6.3		)		(5.9		)
Other capital contributions	—				0.2				—				0.2
Net Cash Provided by (Used in) Financing Activities	(5.5		)		172.1				(445.6		)		386.4
Change in cash, cash equivalents and restricted cash	7.8				1.6				98.2				2.7
Beginning cash, cash equivalents and restricted cash	118.5				24.5				28.1				23.4
Ending cash, cash equivalents and restricted cash	$	126.3			$	26.1			$	126.3			$	26.1

	Production by Region
	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change
	(in Mboe)
Northern Region
Williston Basin	2,962.4			4,459.7			(34	)%		6,339.4			8,189.4			(23	)%
Uinta Basin	—			821.7			(100	)%		—			1,626.2			(100	)%
Other Northern	21.0			42.8			(51	)%		45.7			148.3			(69	)%
Total Northern Region	2,983.4			5,324.2			(44	)%		6,385.1			9,963.9			(36	)%
Southern Region
Permian Basin	4,552.4			4,016.2			13	%		8,634.7			6,799.1			27	%
Haynesville/Cotton Valley	(6.3	)		4,761.3			(100	)%		310.9			9,051.8			(97	)%
Other Southern	5.2			4.4			18	%		10.3			15.9			(35	)%
Total Southern Region	4,551.3			8,781.9			(48	)%		8,955.9			15,866.8			(44	)%
Total production	7,534.7			14,106.1			(47	)%		15,341.0			25,830.7			(41	)%

	Total Production
	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change
Oil and condensate (Mbbl)	5,150.3			6,567.6			(22	)%		10,233.9			11,541.6			(11	)%
Gas (Bcf)	7.2			38.3			(81	)%		16.4			73.4			(78	)%
NGL (Mbbl)	1,186.0			1,152.8			3	%		2,364.8			2,057.2			15	%
Total production (Mboe)	7,534.7			14,106.1			(47	)%		15,341.0			25,830.7			(41	)%
Average daily production (Mboe)	82.8			155.0			(47	)%		84.8			142.7			(41	)%

	Prices
	Three Months Ended June 30,											Six Months Ended June 30,
	2019				2018				Change			2019				2018				Change
Oil (per bbl)
Average field-level price	$	55.46			$	62.21						$	52.30			$	61.45
Commodity derivative impact	(3.11		)		(7.91		)					(1.85		)		(8.34		)
Net realized price	$	52.35			$	54.30			(4	)%		$	50.45			$	53.11			(5	)%
Gas (per Mcf)
Average field-level price	$	1.01			$	2.55						$	1.84			$	2.72
Commodity derivative impact	—				0.17							(0.18		)		0.10
Net realized price	$	1.01			$	2.72			(63	)%		$	1.66			$	2.82			(41	)%
NGL (per bbl)
Average field-level price	$	12.06			$	22.84						$	13.18			$	22.47
Commodity derivative impact	—				—							—				—
Net realized price	$	12.06			$	22.84			(47	)%		$	13.18			$	22.47			(41	)%
Average net equivalent price (per Boe)
Average field-level equivalent price	$	40.77			$	37.77						$	38.89			$	36.98
Commodity derivative impact	(2.13		)		(3.23		)					(1.43		)		(3.45		)
Net realized equivalent price	$	38.64			$	34.54			12	%		$	37.46			$	33.53			12	%

	Operating Expenses
	Three Months Ended June 30,											Six Months Ended June 30,
	2019				2018				Change			2019				2018				Change
	(in millions)
Lease operating expense	$	45.7			$	66.5			(31	)%		$	97.2			$	139.0			(30	)%
Adjusted transportation and processing costs(1)	22.6				43.6				(48	)%		47.3				90.3				(48	)%
Production and property taxes	23.6				37.6				(37	)%		47.6				66.5				(28	)%
Total production costs	$	91.9			$	147.7			(38	)%		$	192.1			$	295.8			(35	)%
	(per Boe)
Lease operating expense	$	6.06			$	4.71			29	%		$	6.34			$	5.38			18	%
Adjusted transportation and processing costs(1)	3.00				3.09				(3	)%		3.09				3.49				(11	)%
Production and property taxes	3.13				2.66				18	%		3.10				2.57				21	%
Total production costs	$	12.19			$	10.46			17	%		$	12.53			$	11.44			10	%
____________________________
(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								Six Months Ended
	June 30,								June 30,
	2019				2018				2019				2018
	(in millions)
Net income (loss)	$	48.8			$	(336.0	)		$	(67.9	)		$	(389.6	)
Interest expense	33.2				38.2				67.2				73.2
Interest and other (income) expense	(0.9		)		3.1				(3.7		)		3.8
Income tax provision (benefit)	29.7				(106.2		)		(82.3		)		(120.1		)
Depreciation, depletion and amortization	128.0				242.2				251.3				438.7
Unrealized (gains) losses on derivative contracts	(54.5		)		33.6				121.3				43.6
Exploration expenses	—				0.1				—				0.1
Net (gain) loss from asset sales, inclusive of restructuring costs	(17.8		)		3.9				(4.6		)		0.4
Impairment	—				403.7				5.0				404.4
Adjusted EBITDA	$	166.5			$	282.6			$	286.3			$	454.5

Free Cash Flow

This release contains references to non-GAAP measures of Adjusted EBITDA and 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								Six Months Ended
	June 30,								June 30,
	2019				2018				2019				2018
	(in millions)
Cash Flow Information:
Net Cash Provided by (Used in) Operating Activities	$	117.4			$	216.5			$	195.7			$	376.9
Net Cash Provided by (Used in) Investing Activities	(104.1		)		(387.0		)		348.1				(760.6		)
Net Cash Provided by (Used in) Financing Activities	(5.5		)		172.1				(445.6		)		386.4
Free Cash Flow
Net Cash Provided by (Used in) Operating Activities	$	117.4			$	216.5			$	195.7			$	376.9
Amortization of debt issuance costs and discounts	(1.4		)		(1.3		)		(2.7		)		(2.6		)
Interest expense	33.2				38.2				67.2				73.2
Unrealized (gains) losses on marketable securities	0.8				0.5				2.7				0.4
Interest and other income (expense)	(0.9		)		3.1				(3.7		)		3.8
Deferred income taxes (benefit)	(30.2		)		106.4				87.7				120.5
Income tax (provision) benefit	29.7				(106.2		)		(82.3		)		(120.1		)
Non-cash share-based compensation	(3.2		)		(7.1		)		(11.2		)		(16.3		)
Changes in operating assets and liabilities	21.1				32.5				32.9				18.7
Adjusted EBITDA	166.5				282.6				286.3				454.5
Non-cash share-based compensation	3.2				7.1				11.2				16.3
Cash interest expense	(31.8		)		(37.5		)		(63.3		)		(63.5		)
Property acquisitions	(1.2		)		(8.9		)		(1.8		)		(45.1		)
Property, plant and equipment, including exploratory well expense	(152.2		)		(393.6		)		(316.8		)		(764.3		)
Free Cash Flow	$	(15.5	)		$	(150.3	)		$	(84.4	)		$	(402.1	)

Slide 4 of our July 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 June 30,								Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions, except earnings per share)
Net income (loss)	$	48.8			$	(336.0	)		$	(67.9	)		$	(389.6	)
Adjustments to net income (loss)
Unrealized (gains) losses on derivative contracts	(54.5		)		33.6				121.3				43.6
Income taxes on unrealized (gains) losses on derivative contracts(1)	12.2				(7.0		)		(66.5		)		(10.3		)
Net (gain) loss from asset sales, inclusive of restructuring costs	(17.8		)		3.9				(4.6		)		0.4
Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs(1)	4.0				(0.8		)		2.5				(0.1		)
Impairment	—				403.7				5.0				404.4
Income taxes on impairment(1)	—				(83.6		)		(2.7		)		(95.4		)
Total after tax adjustments to net income	(56.1		)		349.8				55.0				342.6
Adjusted Net Income (Loss)	$	(7.3	)		$	13.8			$	(12.9	)		$	(47.0	)
Earnings (Loss) per Common Share
Diluted earnings per share	$	0.20			$	(1.42	)		$	(0.29	)		$	(1.63	)
Diluted after-tax adjustments to net income (loss) per share	(0.24		)		1.48				0.23				1.43
Diluted Adjusted Net Income per share	$	(0.04	)		$	0.06			$	(0.06	)		$	(0.20	)
Weighted-average common shares outstanding
Diluted	238.0				237.0				237.5				238.9
____________________________
(1) Income tax impact of adjustments is calculated using QEP’s statutory rate of 22.4% and 20.7% for the three months ended June 30, 2019 and 2018, respectively and QEP's effective tax rate of 54.8% and 23.6% for the six months ended June 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 June 30,												Six Months Ended June 30,
	2019				2018				Change				2019				2018				Change
	(in millions)
Transportation and processing costs, as presented	$	9.9			$	31.2			$	(21.3	)		$	20.8			$	65.2			$	(44.4	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	12.7				12.4				0.3				26.5				25.1				1.4
Adjusted transportation and processing costs	$	22.6			$	43.6			$	(21.0	)		$	47.3			$	90.3			$	(43.0	)
	(per Boe)
Transportation and processing costs, as presented	$	1.31			$	2.21			$	(0.90	)		$	1.36			$	2.52			$	(1.16	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.69				0.88				0.81				1.73				0.97				0.76
Adjusted transportation and processing costs	$	3.00			$	3.09			$	(0.09	)		$	3.09			$	3.49			$	(0.40	)

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 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 July 19, 2019:

Production Commodity Derivative Swaps
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		7.5			$	59.70
2020		Argus WTI Midland		0.7			$	60.00

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		3.3			$	(2.22	)
2019		NYMEX WTI		Argus WTI Houston		0.9			$	3.69
2020		NYMEX WTI		Argus WTI Midland		4.4			$	(0.02	)
2020 (January - June)		NYMEX WTI		Argus WTI Houston		0.4			$	3.75

 

Source: QEP Resources, Inc.