Qep Resources, Inc. (QEP) 8-K Earnings Release

"QEP’s assets performed as expected in all categories during the first quarter 2019. Our drilling and completions teams continue to deliver efficiency and cost improvements which positively impacted cycle time and capital intensity. These cost savings, along with other efficiency projects, are expected to free up enough capital to allow us to drill and complete an additional 10 to 12 wells in the Permian in 2019, while still living within our original 2019 capital guidance," commented Tim Cutt, President and CEO of QEP.

"During the quarter we initiated our previously announced plan to reset our general and administrative expense with a goal of reducing ‘normalized’ expense by approximately 45% between year-end 2018 and 2020. We expect to be operating at our go-forward staffing levels by mid-year 2019, at which point we will have reduced our total workforce by approximately 60% since the announcement of our strategic initiatives in February 2018. Although we have been aggressive with both employee and non-employee expense reductions, we are confident that we have retained the core business, technical and operating staff and systems required to execute our forward plans."

"With our focus on cost reduction and volume delivery, we remain confident in our ability to achieve cash flow neutrality before year-end at commodity prices of $55 for crude oil and $2.75 for natural gas."

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

QEP First Quarter 2019 Financial Results

The Company reported a net loss of $116.7 million for the first quarter 2019, or $0.49 per diluted share, compared with a net loss of $53.6 million, or $0.22 per diluted share, for the first quarter 2018. The net loss in the first quarter 2019 was primarily driven by (i) a $134.2 million decrease in oil and condensate, gas and natural gas liquid (NGL) sales, primarily due to a 74% decrease in gas production, primarily associated with the Haynesville/Cotton Valley and Uinta Basin divestitures and a 19% decrease in average field-level oil prices, and (ii) a $128.5 million increase in realized and unrealized derivative losses. These changes were partially offset by a $98.1 million increase in income tax benefit, a decrease in depreciation, depletion and amortization expense of $73.2 million and a decrease in both transportation and processing costs and lease operating expense of $44.1 million due to the Haynesville/Cotton Valley and Uinta Basin divestitures.

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 first quarter 2019 Adjusted Net Income (a non-GAAP measure) was $34.1 million, or $0.15 per diluted share, compared with an Adjusted Net Loss of $47.9 million, or $0.20 per diluted share, for the first quarter 2018.

Adjusted EBITDA (a non-GAAP measure) for the first quarter 2019 was $119.8 million compared with $171.9 million for the first quarter 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures and a 19% decrease in average field-level oil prices. These changes were partially offset by a $37.3 million decrease in realized derivative losses.

The definitions and reconciliations of Adjusted Net Income 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 2.9 million barrels (MMbbl) in the first quarter 2019, an increase of 35% compared with the first quarter of 2018. The production increase was partially offset by lower volumes in the Williston Basin due to the lack of new well completions in the second half of 2018 while the asset was in a sales process and a loss of volumes as a result of the Uinta Basin divestiture.

Oil equivalent production was 7.8 million barrels of oil equivalent (MMboe) in the first quarter 2019, a decrease of 33% compared with the first quarter 2018. The decrease in equivalent production was primarily the result of the loss of 4.8 MMboe of equivalent production associated with the assets sold in the Haynesville/Cotton Valley and Uinta Basin divestitures.

Operating Expenses

During the first quarter 2019, lease operating expense (LOE) was $51.5 million, or $6.60 per Boe, a decrease of 29% compared with the first quarter 2018. The decrease in total LOE was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $3.7 million, driven by a decrease in workovers and maintenance and repair expenses in the Williston Basin.

During the first quarter 2019, Adjusted Transportation and Processing (T&P) Costs (a non-GAAP measure) were $24.7 million, or $3.17 per Boe, a decrease of 47% of T&P costs compared with the first quarter 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, T&P Costs increased $0.6 million, primarily due to increased production in the Permian Basin, partially offset by decreased production in the Williston Basin.

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 first quarter 2019, general and administrative (G&A) expense was $63.3 million, an increase of 5% compared with the first quarter 2018. During the first quarter of 2019 and 2018, QEP incurred $26.0 million and $9.5 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $20.3 million and $7.9 million, respectively, related to restructuring costs. Excluding these costs, G&A expense decreased by $13.2 million, primarily due to $10.0 million lower labor, benefits and other associated costs due to the reduction in our workforce, and $4.8 million in lower legal and outside service costs. Overall G&A expense, not including any mark-to-market liabilities, is expected to decrease substantially throughout 2019.

During the first quarter 2019, production and property taxes were $24.0 million, or $3.07 per Boe, a decrease of 17% compared with the first quarter 2018. The decrease in production and property taxes was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, production and property taxes increased $0.4 million, primarily due to increased property taxes and revenues in the Permian Basin, partially offset by decreased revenues in the Williston Basin.

Capital Investment

Capital investment, excluding property acquisitions, was $167.2 million (on an accrual basis) for the first quarter 2019, compared with $418.8 million for the first quarter 2018, of which $149.1 million related to the drilling, completion and equipping of wells and $18.1 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

In January 2019, QEP closed its previously announced divestiture of its oil and gas assets and the gathering system in Haynesville/Cotton Valley for net cash proceeds of $615.3 million, subject to post-closing purchase price adjustments (the Haynesville Divestiture) and recorded a pre-tax loss on sale of $18.0 million. Of the $18.0 million pre-tax loss on sale, $15.0 million was recognized during the first quarter of 2019, and $3.0 million was recognized during the fourth quarter of 2018. As part of this transaction the buyer assumed all firm gas transportation agreements related to these assets. As of March 31, 2019, $22.1 million of the purchase price remained in escrow due to title defects asserted prior to closing to be resolved pursuant to the purchase and sale agreement's title dispute resolution procedures.

In addition to the Haynesville Divestiture, QEP closed on the sale of several assets during the first quarter 2019 for total net cash proceeds of approximately $2.1 million.

Liquidity

Net Cash Provided by Operating Activities for the first quarter 2019 was $78.3 million, compared with $160.4 million for the first quarter 2018. Discretionary Cash Flow (a non-GAAP measure) was $90.1 million for the first quarter 2019, compared with $146.6 million for the first quarter 2018.

The definitions and reconciliations of Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures are provided under the heading Non-GAAP Measures at the end of this release.

As of March 31, 2019, the Company had $89.9 million in cash and cash equivalents, no borrowings under its revolving credit facility and $1.3 million in letters of credit outstanding. The Company estimates that as of March 31, 2019, it could incur additional indebtedness of approximately $552.7 million and be in compliance with the covenants contained in its revolving credit facility.

2019 Updated Guidance

QEP's second quarter and full year 2019 guidance assumes: (1) an oil price of $55 per barrel and a natural gas price of $2.75 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 and (4) includes approximately 10 days of production activity in the Haynesville / Cotton Valley, which was excluded from previous guidance.

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 arriving in the first quarter 2019 to drill seven gross operated wells

Wells Put on Production:


▪	Permian Basin: approximately 57 - 59 net operated wells, an increase of 10 - 12 wells from previous guidance


▪	Williston Basin: approximately six net operated wells



2019 Guidance
	2Q 2019	2019	2019
	Guidance	Previous Guidance	Updated Guidance
Oil & condensate production (MMbbl)	4.95 - 5.15	20.5 - 21.5	20.5 - 21.5
Gas production (Bcf)	5.4 - 5.8	23.0 - 25.0	25.5 - 27.5
NGL production (MMbbl)	0.9 - 1.1	3.7 - 4.2	3.7 - 4.2
Total oil equivalent production (MMboe)	6.8 - 7.2	28.0 - 29.9	28.5 - 30.3

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)
General and administrative expense⁽²⁾		$170.0 - $180.0	$165.0 - $175.0

Capital investment (excluding property acquisitions)
Drilling, Completion and Equip⁽³⁾		$540.0 - $590.0	$540.0 - $590.0
Midstream Infrastructure⁽⁴⁾		$70.0	$70.0
Corporate		$5.0	$5.0
Total capital investment (excluding property acquisitions)	$185.0 - $205.0	$615.0 - $665.0	$615.0 - $665.0

Wells put on production (net)	23	53	63 - 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 general and administrative expense includes approximately $35.0 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. The mid-point general and administrative expense also includes approximately $54.0 million of estimated expenses related to our strategic initiatives, primarily related to severance and retention agreements and includes approximately $11.0 million of accelerated shared-based compensation expense that is included in the $35.0 million of expenses related to non-cash, share-based compensation and other mark-to-market liabilities.


⁽³⁾	Drilling, Completion and Equip includes approximately $37.0 million of non-operated well completion costs.


⁽⁴⁾	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 March 31, 2019
	Gross	Net	Gross	Net
Well Progress
Drilling	11	11.0	7	6.4

At total depth - under drilling rig	3	3.0	—	—
Waiting to be completed	28	28.0	—	—
Undergoing completion	4	4.0	—	—
Completed, awaiting production	11	11.0	—	—
Waiting on completion	46	46.0	—	—

Put on production	12	12.0	—	—

Permian Basin

Permian Basin net oil equivalent production averaged approximately 45.4 Mboed (86% liquids) during the first quarter 2019, a 4% decrease compared with the fourth quarter 2018 primarily due to a lower number of wells and the timing of these wells being put on production during the quarter, and a 47% increase compared with the first quarter 2018. A portion of the year-over-year increase is driven by higher gas capture rates compared with prior quarters as a result of completion of midstream infrastructure. Oil and condensate production in the Permian Basin was 2.9 MMbbl in the first quarter 2019, an increase of 35% compared with the first quarter of 2018.

In the first quarter 2019, the Company put on production 12 gross-operated horizontal wells, all on Mustang Springs, two more than forecast for the first quarter 2019 (average working interest 100%).

At the end of the first quarter 2019, all of the 12 wells put on production during the quarter were still in the process of cleaning up and have an average lateral length of 12,886 feet.

At the end of the first quarter 2019, the Company had 11 gross-operated horizontal wells in process of being drilled (of which nine had surface casing set, but had no drilling rig present) (average working interest 100%), three horizontal wells at total depth under drilling rigs, 28 horizontal wells waiting to be completed (average working interest 100%), four horizontal wells undergoing completion (average working interest 100%), and 11 fully completed horizontal wells awaiting first production, which were part of a tank "pressure wall" (average working interest 100%).

At the end of the first quarter 2019, the Company had three operated rigs in the Permian Basin.

Slides 9-10 in the April 2019 Investor Presentation depict QEP's acreage and activity in the Permian Basin.

Williston Basin

Williston Basin net oil equivalent production averaged approximately 37.5 Mboed (81% liquids) during the first quarter 2019, an 8% decrease compared with the fourth quarter 2018 and a 9% decrease compared with the first quarter 2018, primarily due to the lack of new well completions partially offset by higher gas capture rates.

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

Slides 11-12 in the April 2019 Investor Presentation depict QEP's acreage and activity in the Williston Basin.

First Quarter 2019 Results Conference Call

QEP’s management will discuss first quarter 2019 results in a conference call on Thursday April 25, 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 May 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 #13689122. In addition, QEP’s slides for the first quarter 2019, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, 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 with operations 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: actively managing and improving our cost structure; reducing G&A expense; lowering the capital intensity of our business; aligning our activity and our production profile to the current commodity price environment; reaching cash-flow neutrality in 2019; goals and potential results of our review of strategic alternatives; plans for development of our Permian Basin and Williston Basin assets; operating our business safely; delivering best in class capital and operating costs; maintaining technical and operating excellence; receipt of the portion of the purchase price for the Haynesville Divestiture placed in escrow pursuant to title dispute resolution procedures; 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 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; first 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; estimated reserves; 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. 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
	March 31,
	2019			2018
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	275.6		$	409.8
Other revenues	3.7			5.0
Purchased oil and gas sales	1.3			14.1
Total Revenues	280.6			428.9
OPERATING EXPENSES
Purchased oil and gas expense	1.4			15.5
Lease operating expense	51.5			72.5
Transportation and processing costs	10.9			34.0
Gathering and other expense	3.8			2.8
General and administrative	63.3			60.1
Production and property taxes	24.0			28.9
Depreciation, depletion and amortization	123.3			196.5
Impairment	5.0			0.7
Total Operating Expenses	283.2			411.0
Net gain (loss) from asset sales, inclusive of restructuring costs	(13.2		)	3.5
OPERATING INCOME (LOSS)	(15.8		)	21.4
Realized and unrealized gains (losses) on derivative contracts	(181.7		)	(53.2		)
Interest and other income (expense)	2.8			(0.7		)
Interest expense	(34.0		)	(35.0		)
INCOME (LOSS) BEFORE INCOME TAXES	(228.7		)	(67.5		)
Income tax (provision) benefit	112.0			13.9
NET INCOME (LOSS)	$	(116.7	)	$	(53.6	)

Earnings (loss) per common share
Basic	$	(0.49	)	$	(0.22	)
Diluted	$	(0.49	)	$	(0.22	)

Weighted-average common shares outstanding
Used in basic calculation	237.1			240.9
Used in diluted calculation	237.1			240.9

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2019			December 31, 2018
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	89.9		$	—
Accounts receivable, net	80.2			104.3
Income tax receivable	68.8			75.9
Fair value of derivative contracts	—			87.5
Prepaid expenses	7.3			12.7
Other current assets	0.2			0.2
Total Current Assets	246.4			280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,250.1			9,096.9
Unproved properties	706.5			705.5
Gathering and other	171.3			167.7
Materials and supplies	29.8			29.9
Total Property, Plant and Equipment	10,157.7			10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,994.3			4,882.4
Gathering and other	61.0			58.1
Total Accumulated Depreciation, Depletion and Amortization	5,055.3			4,940.5
Net Property, Plant and Equipment	5,102.4			5,059.5
Fair value of derivative contracts	6.7			35.4
Operating lease right-of-use assets, net	61.4			—
Other noncurrent assets	53.3			49.6
Noncurrent assets held for sale	—			$	692.7
TOTAL ASSETS	$	5,470.2		$	6,117.8

LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	10.3		$	14.6
Accounts payable and accrued expenses	216.0			258.1
Production and property taxes	22.0			24.1
Current portion of long term debt	51.7			—
Interest payable	33.0			32.4
Fair value of derivative contracts	60.3			—
Current operating lease liabilities	20.1			—
Asset retirement obligations	5.9			5.1
Total Current Liabilities	419.3			334.3
Long-term debt	2,026.7			2,507.1
Deferred income taxes	151.2			269.2
Asset retirement obligations	96.2			96.9
Fair value of derivative contracts	1.5			0.7
Operating lease liabilities	49.4			—
Other long-term liabilities	89.8			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; 242.0 million and 239.8 million shares issued, respectively	2.4			2.4
Treasury stock – 3.9 million and 3.1 million shares, respectively	(51.8		)	(45.6		)
Additional paid-in capital	1,440.2			1,431.9
Retained earnings	1,259.8			1,376.5
Accumulated other comprehensive income (loss)	(14.5		)	(14.3		)
Total Common Shareholders' Equity	2,636.1			2,750.9
TOTAL LIABILITIES AND EQUITY	$	5,470.2		$	6,117.8

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended
	March 31,
	2019			2018
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	(116.7	)	$	(53.6	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	123.3			196.5
Deferred income taxes (benefit)	(117.9		)	(14.1		)
Impairment	5.0			0.7
Non-cash share-based compensation	8.0			9.2
Amortization of debt issuance costs and discounts	1.3			1.3
Net (gain) loss from asset sales, inclusive of restructuring costs	13.2			(3.5		)
Unrealized (gains) losses on marketable securities	(1.9		)	0.1
Unrealized (gains) losses on derivative contracts	175.8			10.0
Changes in operating assets and liabilities	(11.8		)	13.8
Net Cash Provided by (Used in) Operating Activities	78.3			160.4
INVESTING ACTIVITIES
Property acquisitions	(0.6		)	(36.2		)
Property, plant and equipment, including exploratory well expense	(164.6		)	(370.7		)
Proceeds from disposition of assets	617.4			33.3
Net Cash Provided by (Used in) Investing Activities	452.2			(373.6		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(4.3		)	(24.2		)
Proceeds from credit facility	44.5			1,068.5
Repayments of credit facility	(474.5		)	(772.5		)
Common stock repurchased and retired	—			(52.8		)
Treasury stock repurchases	(5.8		)	(4.7		)
Net Cash Provided by (Used in) Financing Activities	(440.1		)	214.3
Change in cash, cash equivalents and restricted cash	90.4			1.1
Beginning cash, cash equivalents and restricted cash	28.1			23.4
Ending cash, cash equivalents and restricted cash	$	118.5		$	24.5



	Production by Region
	Three Months Ended March 31,
	2019	2018	Change
	(in Mboe)
Northern Region
Williston Basin	3,377.0	3,729.7	(9	)%
Uinta Basin	—	804.5	(100	)%
Other Northern	24.7	105.5	(77	)%
Total Northern Region	3,401.7	4,639.7	(27	)%
Southern Region
Permian Basin	4,082.3	2,782.9	47	%
Haynesville/Cotton Valley	317.2	4,290.5	(93	)%
Other Southern	5.1	11.5	(56	)%
Total Southern Region	4,404.6	7,084.9	(38	)%
Total production	7,806.3	11,724.6	(33	)%



	Total Production
	Three Months Ended March 31,
	2019	2018	Change
Oil and condensate (Mbbl)	5,083.6	4,974.0	2	%
Gas (Bcf)	9.2	35.1	(74	)%
NGL (Mbbl)	1,178.8	904.4	30	%
Total production (Mboe)	7,806.3	11,724.6	(33	)%
Average daily production (Mboe)	86.7	130.3	(33	)%



	Prices
	Three Months Ended March 31,
	2019			2018			Change
Oil (per bbl)
Average field-level price	$	49.08		$	60.45
Commodity derivative impact	(0.58		)	(8.91		)
Net realized price	$	48.50		$	51.54		(6	)%
Gas (per Mcf)
Average field-level price	$	2.49		$	2.91
Commodity derivative impact	(0.31		)	0.03
Net realized price	$	2.18		$	2.94		(26	)%
NGL (per bbl)
Average field-level price	$	14.31		$	21.99
Commodity derivative impact	—			—
Net realized price	$	14.31		$	21.99		(35	)%
Average net equivalent price (per Boe)
Average field-level price	$	37.08		$	36.04
Commodity derivative impact	(0.75		)	(3.70		)
Net realized price	$	36.33		$	32.34		12	%



	Operating Expenses
	Three Months Ended March 31,
	2019		2018		Change
	(in millions)
Lease operating expense	$	51.5	$	72.5	(29	)%
Adjusted transportation and processing costs⁽¹⁾	24.7		46.7		(47	)%
Production and property taxes	24.0		28.9		(17	)%
Total production costs	$	100.2	$	148.1	(32	)%

	(per Boe)
Lease operating expense	$	6.60	$	6.18	7	%
Adjusted transportation and processing costs⁽¹⁾	3.17		3.98		(20	)%
Production and property taxes	3.07		2.47		24	%
Total production costs	$	12.84	$	12.63	2	%

____________________________


⁽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
	March 31,
	2019			2018
	(in millions)
Net income (loss)	$	(116.7	)	$	(53.6	)
Interest expense	34.0			35.0
Interest and other (income) expense	(2.8		)	0.7
Income tax provision (benefit)	(112.0		)	(13.9		)
Depreciation, depletion and amortization	123.3			196.5
Unrealized (gains) losses on derivative contracts	175.8			10.0
Net (gain) loss from asset sales, inclusive of restructuring costs	13.2			(3.5		)
Impairment	5.0			0.7
Adjusted EBITDA	$	119.8		$	171.9

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 March 31,
	2019			2018
	(in millions, except earnings per share)
Net income (loss)	$	(116.7	)	$	(53.6	)
Adjustments to net income (loss)
Unrealized (gains) losses on derivative contracts	175.8			10.0
Income taxes on unrealized (gains) losses on derivative contracts⁽¹⁾	(39.2		)	(2.1		)
Net (gain) loss from asset sales, inclusive of restructuring costs	13.2			(3.5		)
Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs⁽¹⁾	(2.9		)	0.7
Impairment	5.0			0.7
Income taxes on impairment⁽¹⁾	(1.1		)	(0.1		)
Total after tax adjustments to net income	150.8			5.7
Adjusted Net Income (Loss)	$	34.1		$	(47.9	)

Earnings (Loss) per Common Share
Diluted earnings per share	$	(0.49	)	$	(0.22	)
Diluted after-tax adjustments to net income (loss) per share	0.64			0.02
Diluted Adjusted Net Income per share	$	0.15		$	(0.20	)

Weighted-average common shares outstanding
Diluted	237.1			240.9

____________________________


⁽¹⁾	Income tax impact of adjustments is calculated using QEP’s statutory rate of 22.3% and 20.7% for the three months ended March 31, 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 March 31,
	2019		2018		Change
	(in millions)
Transportation and processing costs, as presented	$	10.9	$	34.0	$	(23.1	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	13.8		12.7		1.1
Adjusted transportation and processing costs	$	24.7	$	46.7	$	(22.0	)

	(per Boe)
Transportation and processing costs, as presented	$	1.40	$	2.90	$	(1.50	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.77		1.08		0.69
Adjusted transportation and processing costs	$	3.17	$	3.98	$	(0.81	)

Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures

This release contains references to the non-GAAP measures of Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures.

The Company defines Discretionary Cash Flow as net cash provided by (used in) operating activities less the changes in operating assets and liabilities. Management believes that this measure is useful to management and investors as a measure of the Company's ability to internally fund its capital expenditures and to service or incur additional debt.

The Company defines Discretionary Cash Flow in Excess of Capital Expenditures as Discretionary Cash Flow (defined above) less 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 internally fund acquisitions, exploration and development.

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



	Three Months Ended						Three Months Ended			Year Ended
	March 31,						December 31,
	2019			2018			2018 ⁽¹⁾			2018 ⁽¹⁾
	(in millions)
Cash Flow Information:
Net Cash Provided by (Used in) Operating Activities	$	78.3		$	160.4		$	141.3		$	816.2
Net Cash Provided by (Used in) Investing Activities	452.2			(373.6		)	(193.2		)	(1,056.1		)
Net Cash Provided by (Used in) Financing Activities	(440.1		)	214.3			52.8			244.6

Discretionary Cash Flow:
Net Cash Provided by (Used in) Operating Activities	$	78.3		$	160.4		$	141.3		$	816.2
Changes in operating assets and liabilities	11.8			(13.8		)	95.9			114.8
Discretionary Cash Flow	90.1			146.6			237.2			931.0
Property acquisitions	(0.6		)	(36.2		)	(17.3		)	(65.6		)
Property, plant and equipment, including exploratory well expense	(164.6		)	(370.7		)	(202.0		)	(1,234.1		)
Discretionary Cash Flow in Excess of Capital Expenditures	$	(75.1	)	$	(260.3	)	$	17.9		$	(368.7	)

____________________________


⁽¹⁾	"Discretionary Cash Flow" and "Discretionary Cash Flow in Excess of Capital Expenditures" amounts have been corrected from the fourth quarter of 2018.

The following tables present QEP's volumes and average prices for its open derivative positions as of April 19, 2019:



Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	9.5	$	54.93
2019	ICE Brent	1.4	$	66.73
2019 (May through December)	Argus Houston MEH	0.2	$	65.70
2020	NYMEX WTI	5.5	$	60.01
2020	Argus WTI Midland	0.4	$	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	5.0	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.6	$	3.75
2020	NYMEX WTI	Argus WTI Midland	2.6	$	(0.46	)

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Qep Resources, Inc. provided additional information to their SEC Filing as exhibits

Exhibit 99.1: Additional Exhibits

Ticker: QEP
CIK: 1108827
Form Type: 8-K Corporate News
Accession Number: 0001108827-19-000029
Submitted to the SEC: Wed Apr 24 2019 4:17:44 PM EST
Accepted by the SEC: Wed Apr 24 2019
Period: Wednesday, April 24, 2019
Industry: Crude Petroleum And Natural Gas

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Qep Resources, Inc. (QEP) SEC Filing 8-K Material Event for the period ending Wednesday, April 24, 2019

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