DENVER, Feb. 20, 2019 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE: QEP) (QEP or the Company) today reported fourth quarter and full year 2018 financial and operating results and provided initial 2019 guidance and capital investment plan.

FULL YEAR 2018 HIGHLIGHTS

• Delivered record oil and condensate production of 23.9 MMbbls, including a record of 12.1 MMbbls in the Permian Basin
• Reported year-end total proved reserves in the Permian Basin of 307.8 MMboe, a 13% increase over 2017
• Reported year-end total proved reserves of 658.2 MMboe, including record proved crude oil and condensate reserves of 339.1 MMbbls

"2018 was a year of transition and transformation for QEP. We made significant progress on the strategic initiatives we outlined in February 2018, which were aimed at streamlining our operations, optimizing our cost structure and rationalizing our asset portfolio," commented Tim Cutt, President and CEO of QEP. "We enter 2019 with a renewed focus on actively managing and improving our cost structure, more specifically, reducing our G&A expense and lowering the capital intensity of the business. We are committed to aligning our activity and our production profile to the current commodity price environment and reaching cash-flow neutrality in 2019.

"Earlier today we announced that we have commenced a comprehensive review of strategic alternatives to maximize shareholder value, which could result in a merger or sale of the Company or other transaction involving the Company or its assets. Our Board and management team are committed to taking all appropriate and necessary actions to drive value for QEP shareholders and we believe the best way to accomplish this goal is to run a broad process designed to identify the potential value of these strategic alternatives.

"We also announced that we have terminated our agreement with Vantage Acquisition Operating Company, LLC, to sell our Williston Basin assets. We now intend to move forward with a paced development of the remaining high-return Williston inventory to maximize the value of the asset.

“As we look to supplement cash flows in 2019, we intend to pursue the monetization of our gas midstream infrastructure in the Permian Basin in the first half of the year and continue to evaluate strategic options for our remaining Permian midstream infrastructure, as well as other non-core properties in our portfolio.

"QEP has undergone significant, positive changes over the last 12 months and we remain focused on operating our business safely, delivering best in class capital and operating costs, and maintaining technical and operating excellence."

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

QEP Fourth Quarter and Full Year 2018 Financial Results

The Company reported a net loss of $629.3 million for the fourth quarter 2018, or $2.66 per diluted share, compared with income of $150.3 million, or $0.62 per diluted share, in the fourth quarter 2017. The net loss in the fourth quarter 2018 includes $1,156.5 million of impairment expense, a result of the signing of a purchase and sale agreement for the divestiture of the Williston Basin assets, a $12.3 million increase in general and administrative expense, primarily due to restructuring costs related to our 2018 Strategic Initiatives, and a $10.0 million decrease in net loss from asset sales, inclusive of restructuring costs. These increases to the net loss were partially offset by a $469.5 million increase in gain on derivative contracts, a $19.9 million decrease to lease operating expense and a 10% increase in oil and condensate production.

For the year ended December 31, 2018, QEP reported a net loss of $1,011.6 million, or $4.25 per diluted share, compared with net income of $269.3 million, or $1.12 per diluted share, for the comparable 2017 period.

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 fourth quarter 2018 Adjusted Net Loss (a non-GAAP measure) was $29.6 million, or $0.13 per diluted share, compared with an Adjusted Net Income of $274.0 million, or $1.13 per diluted share, in the fourth quarter 2017. For the year ended December 31, 2018, the Company’s Adjusted Net Loss was $42.1 million, or $0.17 per diluted share, compared with an Adjusted Net Income of $185.2 million, or $0.77 per diluted share, for 2017.

Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2018 was $194.1 million compared to $195.1 million in the fourth quarter 2017. For the year ended December 31, 2018, the Company reported Adjusted EBITDA of $974.8 million compared to $736.1 million for full year 2017, a 32% increase, primarily due to an 18% increase in average realized prices, a 30% decrease in Adjusted Transportation and Processing Costs (a non-GAAP measure) and an 11% decrease in lease operating expense. These changes were partially offset by a 17% decrease in gas production due to the Pinedale divestiture in late 2017 and the Uinta Basin divestiture in September 2018 (the Uinta Basin Divestiture), a 44% increase in general and administrative expenses and a 14% increase in production and property taxes.

The definitions and reconciliations of Adjusted EBITDA, Adjusted Net Income to Net Income (Loss) and Adjusted Transportation and Processing Costs are provided within the financial tables of this release.

Production

Oil equivalent production was 11.6 MMboe for the fourth quarter 2018 compared with 12.1 MMboe for the fourth quarter 2017, a 4% decrease. Natural gas production decreased 18%, while oil and condensate and NGL production increased 10% and 4%, respectively. Fourth quarter 2018 equivalent production was negatively impacted by decreased oil production in the Williston Basin, decreased gas production due to lack of new activity in the Haynesville/Cotton Valley and the Uinta Basin Divestiture, in September 2018, which contributed 3.9 Bcf in the fourth quarter 2017.

Operating Expenses

During the fourth quarter 2018, lease operating expense (LOE) was $59.5 million, or $5.11 per Boe, a decrease of 25% compared with the fourth quarter 2017. The decrease in total LOE was primarily due to reduced workovers in the Williston Basin and Haynesville/Cotton Valley and the Uinta Basin Divestiture, partially offset by increased power and fuel, labor, maintenance and repair expenses on our Permian Basin properties.

During the fourth quarter 2018, Adjusted Transportation and Processing (T&P) Costs (a non-GAAP measure) were $38.5 million, or $3.31 per Boe, a decrease of 10% compared with the fourth quarter 2017, primarily due to the Uinta Basin divestiture combined with a decrease in Haynesville/Cotton Valley from lower gas production. These decreases were partially offset by increases in the Permian Basin due to higher gas recovery.

During the fourth quarter 2018, general and administrative expense (G&A) was $57.5 million, or $4.95 per Boe, an increase of 27% compared with the fourth quarter 2017. The increase in total G&A expense in the fourth quarter 2018 was primarily due to an increase in costs associated with the implementation of our 2018 Strategic Initiatives. The increase was partially offset by a decrease in share-based compensation and in the mark-to-market value of the deferred compensation wrap plan and a decrease in outside services.

During the fourth quarter 2018, production and property taxes were $26.9 million, or $2.31 per Boe, a decrease of 5% compared with the fourth quarter 2017. The decrease in production and property taxes was primarily due to decreased revenues in the Williston and Uinta basins and production tax exemptions in Haynesville/Cotton Valley, partially offset by increased revenues in the Permian Basin.

Capital Investment

Total capital investment was $205.7 million (on an accrual basis) for the fourth quarter 2018, compared with $1,056.3 million for the fourth quarter 2017. Total capital investment for the year ended December 31, 2018 (on an accrual basis), was $1,242.2 million, down $792.8 million compared with the year ended December 31, 2017, due to the acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) in the fourth quarter 2017.

Capital investment, excluding property acquisitions, was $188.4 million (on an accrual basis) for the fourth quarter 2018, compared with $372.2 million for the fourth quarter 2017, of which $170.7 million related to the drilling, completion and equipping of wells and $16.8 million was related to 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 and Haynesville/Cotton Valley in the fourth quarter 2018.

Capital investment, excluding property acquisitions, was $1,176.6 million (on an accrual basis) for the year ended December 31, 2018 compared with $1,219.8 million for the year ended December 31, 2017, of which $1,089.3 million related to the drilling, completion and equipping of wells and $83.0 million was related to infrastructure investment. The decrease in capital expenditures was primarily related to decreased drilling and completion activity in the Williston Basin and reduced well refracturing activity in the Haynesville/Cotton Valley, partially offset by increased drilling and completion activity in the Permian Basin.

During the year ended December 31, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin, for an aggregate purchase price of $65.6 million, subject to customary post-closing adjustments. Of the $65.6 million, $49.1 million was related to acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.

Asset Divestitures

In January 2019, QEP closed its previously announced divestiture of its oil and gas assets and the gathering system in the Haynesville/Cotton Valley for net cash proceeds of $605.1 million, subject to post-closing purchase price adjustments (the Haynesville Divestiture). As part of this transaction the buyer assumed all firm gas transportation agreements related to these assets. In addition, $32.2 million was placed in escrow due to title defects asserted prior to closing, all or a portion of which QEP expects to receive pursuant to the purchase and sale agreement's title dispute resolution procedures.

In November 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a purchase and sale agreement for its assets in the Williston Basin for a purchase price of $1,725.0 million, subject to purchase price adjustments (the Planned Williston Basin Divestiture). The purchase price was comprised of $1,650.0 million in cash and contractual rights to receive $75.0 million of the buyer's common stock if certain conditions were met. The transaction was subject to certain conditions, including, approval of buyer's shareholder and regulatory approvals. In February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement for its assets in the Williston Basin. Following the termination, QEP will continue to operate and develop its assets in the Williston Basin, including the Company's South Antelope and Fort Berthold leaseholds.

QEP closed on the sale of several non-core assets during the fourth quarter 2018 for total net cash proceeds of approximately $26.1 million.

Liquidity

Net Cash Provided by Operating Activities for the fourth quarter 2018 was $141.3 million, compared with $117.4 million for the fourth quarter 2017. Discretionary Cash Flow (a non-GAAP measure) was $45.4 million for the fourth quarter 2018, compared with $67.4 million for the fourth quarter 2017.

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

As of December 31, 2018, QEP had $430.0 million of borrowings and $0.3 million in letters of credit outstanding under its credit facility. The Company estimates that, as of December 31, 2018, it could incur additional indebtedness of approximately $819.7 million and be in compliance with the covenants contained in its revolving credit facility.

As of February 15, 2019, QEP had no borrowings outstanding and $0.3 million in letters of credit outstanding under its credit facility. QEP used the proceeds from the Haynesville Divestiture to pay off its outstanding balance on its credit facility in January 2019.

2019 Guidance

QEP's first quarter and full year 2019 guidance assumes an oil price of $55 per barrel and a natural gas price of $2.75 per MMBtu, assumes that QEP will elect to recover ethane from its produced gas in the Permian Basin where processing economics support ethane recovery, and assumes no property acquisitions or divestitures.

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 second quarter 2019 to drill seven gross operated wells

Wells Put on Production

• Permian Basin: approximately 47 net operated wells
• Williston Basin: approximately six net operated wells

2019 Guidance
	1Q 2019	2019
Oil & condensate production (MMbbl)	4.95 - 5.15	20.5 - 21.5
Gas production (Bcf)	5.85 - 6.35	23.0 - 25.0
NGL production (MMbbl)	0.90 - 1.05	3.7 - 4.2
Total oil equivalent production (MMboe)	6.83 - 7.26	28.0 - 29.9
Lease operating and Adjusted Transportation and Processing Costs (per Boe)(1)		$9.00 - $10.00
Depletion, depreciation and amortization (per Boe)		$16.75 -$17.75
Production and property taxes (% of field-level revenue)		7.0%
(in millions)
General and administrative expense(2)		$170.0 - $180.0
Capital investment (excluding property acquisitions)
Drilling, Completion and Equip(3)		$540.0 - $590.0
Midstream Infrastructure(4)		$70.0
Corporate		$5.0
Total capital investment (excluding property acquisitions)		$615.0 - $665.0
Wells put on production (net)	9.8	53.1

____________________________
⁽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⁾ General and administrative expense includes approximately $18.0 million of share-based compensation expense and approximately $54.0 million of estimated expenses related to restructuring costs, primarily severance and retention agreements entered into in connection with our strategic initiatives, which includes approximately $11.0 million of accelerated share-based compensation expense.
⁽³⁾ Drilling, Completion and Equip includes approximately $57.0 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						Haynesville/Cotton Valley
	As of December 31, 2018
	Gross			Net			Gross			Net			Gross			Net
Well Progress
Drilling	13			13.0			—			—			—			—
At total depth - under drilling rig	8			8.0			—			—			—			—
Waiting to be completed	17			17.0			—			—			—			—
Undergoing completion	5			5.0			—			—			—			—
Completed, awaiting production	5			5.0			—			—			—			—
Waiting on completion	35			35.0			—			—			—			—
Put on production(1)	17			16.7			—			—			—			—

____________________________
⁽¹⁾ Total operated wells put on production during the three months ended December 31, 2018.

Permian Basin

Permian Basin net oil equivalent production averaged approximately 47.5 Mboed (87% liquids) during the fourth quarter 2018, a 9% decrease compared to the third quarter 2018 primarily due to a lower number of wells and the timing of these wells being put on production, and a 71% increase compared to the fourth quarter 2017. A portion of the year over year increase is driven by higher gas capture rates compared to prior quarters as a result of completion of midstream infrastructure.

In the fourth quarter 2018, the Company put on production 17 gross-operated horizontal wells, six on County Line and 11 on Mustang Springs (average working interest 98%).

At the end of the fourth quarter 2018, two of the six wells put on production on County Line were still in the process of cleaning up. The four wells that cleaned up on County Line reached average peak 24-hour IP of 138 Boed per 1,000 lateral feet (86% oil) from an average lateral length of 7,282 feet. On Mustang Springs, six of the 11 wells put on production were still in the process of cleaning up. The five wells that cleaned up on Mustang Springs reached average peak 24-hour IP of 125 Boed per 1,000 lateral feet (84% oil) from an average lateral length of 9,825 feet.

At the end of the fourth quarter 2018, the Company had 13 gross-operated horizontal wells in process of being drilled (of which 10 had surface casing set, but had no drilling rig present) (average working interest 100%), eight horizontal wells at total depth under drilling rigs (average working interest 100%), 17 horizontal wells waiting to be completed (average working interest 100%), five horizontal wells undergoing completion (average working interest 100%), and five fully completed horizontal wells awaiting first production, which were part of a tank "pressure wall" (average working interest 100%).

At the end of the fourth quarter 2018, the Company had four operated rigs in the Permian Basin.

Slides 7-8 in the February 2019 Investor Presentation depict QEP's acreage and activity in the Permian Basin.

Williston Basin

Williston Basin net oil equivalent production averaged approximately 40.9 Mboed (82% liquids) during the fourth quarter 2018, a 14% decrease compared to the third quarter 2018 and a 16% decrease compared to the fourth quarter 2017, primarily due to the lack of new well completions and refrac timing.

In the fourth quarter 2018, the Company completed and returned to production four gross-operated refracs on South Antelope (average working interest 94%). All four refracs had reached peak oil rates by the end of the quarter with an average IP24 gross uplift of 1,366 Boed (78% oil).

At the end of the fourth quarter 2018, the Company had no drilling rigs in the Williston Basin.

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

Estimated Proved Reserves

At December 31, 2018, QEP's estimated proved reserves were approximately 658.2 MMboe, a 4% decrease compared to 2017, primarily due to the sale of reserves in-place associated with the Uinta Basin Divestiture, which was partially offset by an increase of proved reserves as a result of extensions and discoveries in the Permian Basin. Williston Basin and Haynesville/Cotton Valley proved reserves increased primarily due to successful refracturing programs in 2018. Extensions and discoveries were 76.3 MMboe, were primarily in the Permian Basin and related to new well completions and associated new PUD locations. Approximately 62% of total proved reserves at year-end 2018 and 56% of total proved reserves at year-end 2017 were crude oil and NGL. Proved developed reserves were 228.9 MMboe, or 35%, of total estimated proved reserves at year-end 2018.

A reconciliation of reported quantities of estimated proved reserves is summarized in the table below:

	Oil and condensate			Gas			NGL			Total
	(MMbbl)			(Bcf)			(MMbbl)			(MMboe)(1)
Balance at December 31, 2017	320.5			1,793.6			65.2			684.7
Revisions of previous estimates	2.1			314.0			6.7			61.0
Extensions and discoveries	57.1			56.5			9.8			76.3
Purchase of reserves in place	8.2			7.9			1.3			10.9
Sale of reserves in place	(24.9	)		(544.8	)		(7.1	)		(122.8	)
Production	(23.9	)		(139.6	)		(4.7	)		(51.9	)
Balance at December 31, 2018	339.1			1,487.6			71.2			658.2

____________________________
⁽¹⁾ Natural gas is converted to crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

Details on the reported quantities of estimated year-end 2018 and 2017 proved reserves presented by operating area, proved reserve category and percentage of total estimated proved reserves composed of crude oil and NGL (liquids) are as follows:

	Total (in MMboe)			% of total			PUD %			liquids %
For the year ended December 31, 2018
Northern Region
Williston Basin	166.8			25	%		42	%		85	%
Uinta Basin	—			—	%		—	%		—	%
Other Northern	0.3			—	%		—	%		67	%
Southern Region
Permian Basin	307.8			47	%		69	%		87	%
Haynesville/Cotton Valley	183.3			28	%		81	%		—	%
Other Southern	—			—	%		—	%		—	%
Total proved reserves	658.2			100	%		65	%		62	%
For the year ended December 31, 2017
Northern Region
Williston Basin	146.9			21	%		36	%		88	%
Uinta Basin	100.8			15	%		62	%		15	%
Other Northern	4.5			1	%		—	%		13	%
Southern Region
Permian Basin	272.7			40	%		77	%		88	%
Haynesville/Cotton Valley	159.8			23	%		66	%		—	%
Other Southern	—			—	%		—	%		—	%
Total proved reserves	684.7			100	%		63	%		56	%

Fourth Quarter and Full Year 2018 Results Conference Call

QEP's management will discuss fourth quarter and full year 2018 results in a conference call on Thursday, February 21, 2019, beginning at 9:00 a.m. EST. 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 March 21, 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 #13687037. In addition, QEP’s slides for the fourth quarter 2018, 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 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: streamlining our operations; optimizing our cost structure; rationalizing our asset portfolio; 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 Williston Basin assets; supplementing cash flows in 2019; monetization of our Permian gas midstream infrastructure; evaluation of strategic options for our remaining Permian midstream infrastructure and non-core properties; 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 Resources 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.

Disclosures regarding non-proved reserves

The Securities and Exchange Commission (SEC) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves; however, QEP has made no such disclosures in its filings with the SEC. Estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially more risks of actually being realized. Actual quantities that may be ultimately recovered from QEP’s interests may differ substantially from the reserve estimates contained in this release. Investors are urged to closely consider the disclosures and risk factors about the Company’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2018.

Contact

Investors/Media:
William I. Kent, IRC
Director, Investor Relations
303-405-6665

QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended								Year Ended
	December 31,								December 31,
	2018				2017				2018				2017
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	397.2			$	406.2			$	1,871.3			$	1,545.3
Other revenues	0.7				4.7				12.5				15.0
Purchased oil and gas sales	12.6				18.1				48.8				62.6
Total Revenues	410.5				429.0				1,932.6				1,622.9
OPERATING EXPENSES
Purchased oil and gas expense	12.4				18.9				51.0				64.3
Lease operating expense	59.5				79.4				263.1				294.8
Transportation and processing costs	24.4				42.7				117.6				245.3
Gathering and other expense	4.7				2.3				15.5				7.3
General and administrative	57.5				45.2				221.7				153.5
Production and property taxes	26.9				28.2				130.8				114.3
Depreciation, depletion and amortization	183.5				194.3				857.1				754.5
Exploration expenses	0.2				0.3				0.3				22.0
Impairment	1,156.5				50.5				1,560.9				78.9
Total Operating Expenses	1,525.6				461.8				3,218.0				1,734.9
Net gain (loss) from asset sales, inclusive of restructuring costs	(1.7		)		8.3				25.0				213.5
OPERATING INCOME (LOSS)	(1,116.8		)		(24.5		)		(1,260.4		)		101.5
Realized and unrealized gains (losses) on derivative contracts	330.7				(138.8		)		90.4				24.5
Interest and other income (expense)	(5.5		)		(0.9		)		(9.6		)		1.6
Loss from early extinguishment of debt	—				(32.7		)		—				(32.7		)
Interest expense	(37.5		)		(34.7		)		(149.4		)		(137.8		)
INCOME (LOSS) BEFORE INCOME TAXES	(829.1		)		(231.6		)		(1,329.0		)		(42.9		)
Income tax (provision) benefit	199.8				381.9				317.4				312.2
NET INCOME (LOSS)	$	(629.3	)		$	150.3			$	(1,011.6	)		$	269.3
Earnings (loss) per common share
Basic	$	(2.66	)		$	0.62			$	(4.25	)		$	1.12
Diluted	$	(2.66	)		$	0.62			$	(4.25	)		$	1.12
Weighted-average common shares outstanding
Used in basic calculation	236.7				241.0				237.9				240.6
Used in diluted calculation	236.7				241.0				237.9				240.6

QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

	December 31,  2018				December 31,  2017
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	—			$	—
Accounts receivable, net	104.3				140.0
Income tax receivable	75.9				4.9
Fair value of derivative contracts	87.5				3.4
Prepaid expenses	12.7				10.1
Other current assets	0.2				3.6
Total Current Assets	280.6				162.0
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,096.9				8,081.0
Unproved properties	705.5				1,028.5
Gathering and other	167.7				111.0
Materials and supplies	29.9				24.8
Total Property, Plant and Equipment	10,000.0				9,245.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,882.4				3,315.2
Gathering and other	58.1				63.4
Total Accumulated Depreciation, Depletion and Amortization	4,940.5				3,378.6
Net Property, Plant and Equipment	5,059.5				5,866.7
Fair value of derivative contracts	35.4				0.1
Other noncurrent assets	49.6				45.1
Noncurrent assets held for sale	692.7				1,320.9
TOTAL ASSETS	$	6,117.8			$	7,394.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	14.6			$	44.0
Accounts payable and accrued expenses	258.1				360.1
Production and property taxes	24.1				31.6
Interest payable	32.4				26.0
Fair value of derivative contracts	—				103.6
Asset retirement obligations	5.1				2.8
Total Current Liabilities	334.3				568.1
Long-term debt	2,507.1				2,160.8
Deferred income taxes	269.2				518.0
Asset retirement obligations	96.9				104.1
Fair value of derivative contracts	0.7				34.8
Other long-term liabilities	97.4				101.9
Other long-term liabilities held for sale	61.3				109.2
Commitments and Contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 239.8 million and 243.0 million shares issued, respectively	2.4				2.4
Treasury stock - 3.1 million and 2.0 million shares, respectively	(45.6		)		(34.2		)
Additional paid-in capital	1,431.9				1,398.2
Retained earnings	1,376.5				2,442.6
Accumulated other comprehensive income (loss)	(14.3		)		(11.1		)
Total Common Shareholders' Equity	2,750.9				3,797.9
TOTAL LIABILITIES AND EQUITY	$	6,117.8			$	7,394.8

QEP RESOURCES, INC.
CONSOLIDATED CASH FLOWS

	Three Months Ended December 31,								Year Ended December 31,
	2018				2017				2018				2017
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	(629.3	)		$	150.3			$	(1,011.6	)		$	269.3
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	183.5				194.3				857.1				754.5
Deferred income taxes	(128.0		)		(383.3		)		(247.6		)		(314.8		)
Impairment	1,156.5				50.5				1,560.9				78.9
Dry hole exploratory well expense	—				0.1				—				21.3
Share-based compensation	10.8				8.9				39.1				22.4
Amortization of debt issuance costs and discounts	1.4				1.4				5.4				6.2
Bargain purchase gain from acquisitions	—				—				—				0.4
Net (gain) loss from asset sales, inclusive of restructuring costs	1.7				(8.3		)		(25.0		)		(213.5		)
Loss from early extinguishment of debt	—				32.7				—				32.7
Unrealized (gains) losses on marketable securities	2.3				(0.8		)		1.2				(2.9		)
Unrealized (gains) losses on derivative contracts	(361.7		)		121.6				(248.5		)		(40.0		)
Other non-cash activity	—				—				—				(9.4		)
Changes in operating assets and liabilities	(95.9		)		(50.0		)		(114.8		)		(4.9		)
Net Cash Provided by (Used in) Operating Activities	141.3				117.4				816.2				600.2
INVESTING ACTIVITIES
Property acquisitions	(17.3		)		(720.7		)		(65.6		)		(815.2		)
Property, plant and equipment, including exploratory well expense	(202.0		)		(380.0		)		(1,234.1		)		(1,159.6		)
Proceeds from disposition of assets	26.1				18.9				243.6				806.8
Net Cash Provided by (Used in) Investing Activities	(193.2		)		(1,081.8		)		(1,056.1		)		(1,168.0		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(0.8		)		44.0				(29.5		)		31.7
Long-term debt issued	—				500.0				—				500.0
Long-term debt issuance costs paid	—				(13.3		)		(0.1		)		(14.4		)
Long-term debt extinguishment costs paid	—				(28.1		)		—				(28.1		)
Long-term debt repaid	—				(445.6		)		—				(445.6		)
Proceeds from credit facility	992.0				490.0				3,608.0				492.0
Repayments of credit facility	(937.5		)		(401.0		)		(3,267.0		)		(403.0		)
Common stock repurchased and retired	—				—				(58.4		)		—
Treasury stock repurchases	(0.9		)		—				(8.7		)		(6.8		)
Other capital contributions	—				—				0.3				—
Net Cash Provided by (Used in) Financing Activities	52.8				146.0				244.6				125.8
Change in cash, cash equivalents and restricted cash	0.9				(818.4		)		4.7				(442.0		)
Beginning cash, cash equivalents and restricted cash	27.2				841.8				23.4				465.4
Ending cash, cash equivalents and restricted cash	$	28.1			$	23.4			$	28.1			$	23.4

	Production by Region
	Three Months Ended December 31,									Year Ended December 31,
	2018			2017			Change			2018			2017			Change
	(in Mboe)
Northern Region
Williston Basin	3,760.8			4,479.8			(16	)%		16,331.3			18,140.0			(10	)%
Pinedale	—			29.3			(100	)%		0.1			9,871.7			(100	)%
Uinta Basin	11.3			834.8			(99	)%		2,243.5			3,605.4			(38	)%
Other Northern	35.7			136.8			(74	)%		247.0			1,082.4			(77	)%
Total Northern Region	3,807.8			5,480.7			(31	)%		18,821.9			32,699.5			(42	)%
Southern Region
Permian Basin	4,368.7			2,554.3			71	%		15,960.3			8,227.2			94	%
Haynesville/Cotton Valley	3,445.9			4,028.5			(14	)%		17,050.5			12,188.7			40	%
Other Southern	4.8			6.4			(25	)%		25.2			29.5			(15	)%
Total Southern Region	7,819.4			6,589.2			19	%		33,036.0			20,445.4			62	%
Total production	11,627.2			12,069.9			(4	)%		51,857.9			53,144.9			(2	)%

	Total Production
	Three Months Ended December 31,									Year Ended December 31,
	2018			2017			Change			2018			2017			Change
Oil and condensate (Mbbl)	5,749.9			5,240.6			10	%		23,932.0			19,620.7			22	%
Gas (Bcf)	28.1			34.1			(18	)%		139.6			168.9			(17	)%
NGL (Mbbl)	1,188.9			1,140.9			4	%		4,661.4			5,367.3			(13	)%
Total equivalent production (Mboe)	11,627.2			12,069.9			(4	)%		51,857.9			53,144.9			(2	)%
Average daily production (Mboe)	126.4			131.2			(4	)%		142.1			145.6			(2	)%

	Prices
	Three Months Ended December 31,											Year Ended December 31,
	2018				2017				Change			2018				2017				Change
Oil (per bbl)
Average field-level price	$	51.67			$	54.14						$	59.43			$	47.88
Commodity derivative impact	(2.69		)		(2.84		)					(6.41		)		0.34
Net realized price	$	48.98			$	51.30			(5)%			$	53.02			$	48.22			10%
Gas (per Mcf)
Average field-level price	$	3.25			$	2.77						$	2.82			$	2.92
Commodity derivative impact	(0.56		)		(0.07		)					(0.04		)		(0.13		)
Net realized price	$	2.69			$	2.70			—%			$	2.78			$	2.79			—%
NGL (per bbl)
Average field-level price	$	19.12			$	24.41						$	23.79			$	20.85
Commodity derivative impact	—				—							—				—
Net realized price	$	19.12			$	24.41			(22)%			$	23.79			$	20.85			14%
Average net equivalent price (per Boe)
Average field-level price	$	35.38			$	33.65						$	37.15			$	29.08
Commodity derivative impact	(2.68		)		(1.44		)					(3.06		)		(0.29		)
Net realized price	$	32.70			$	32.21			2%			$	34.09			$	28.79			18%

	Operating Expenses
	Three Months Ended December 31,											Year Ended December 31,
	2018				2017				Change			2018				2017				Change
	(in millions)
Lease operating expense	$	59.5			$	79.4			(25	)%		$	263.1			$	294.8			(11	)%
Adjusted transportation and processing costs(1)	38.5				42.7				(10	)%		172.6				245.3				(30	)%
Production and property taxes	26.9				28.2				(5	)%		130.8				114.3				14	%
Total production costs	$	124.9			$	150.3			(17	)%		$	566.5			$	654.4			(13	)%
	(per Boe)
Lease operating expense	$	5.11			$	6.58			(22	)%		$	5.07			$	5.55			(9	)%
Adjusted transportation and processing costs(1)	3.31				3.54				(6	)%		3.33				4.61				(28	)%
Production and property taxes	2.31				2.34				(1	)%		2.52				2.15				17	%
Total production costs	$	10.73			$	12.46			(14	)%		$	10.92			$	12.31			(11	)%

 ____________________________
⁽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, loss from early extinguishment of debt and certain other items. Management uses Adjusted EBITDA to evaluate QEP’s financial performance and trends, make operating decisions, and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP’s performance from period to period. QEP’s Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which 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) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

	Three Months Ended December 31,								Year Ended December 31,
	2018				2017				2018				2017
	(in millions)
Net income (loss)	$	(629.3	)		$	150.3			$	(1,011.6	)		$	269.3
Interest expense	37.5				34.7				149.4				137.8
Interest and other (income) expense	5.5				0.9				9.6				(1.6		)
Income tax provision (benefit)	(199.8		)		(381.9		)		(317.4		)		(312.2		)
Depreciation, depletion and amortization	183.5				194.3				857.1				754.5
Unrealized (gains) losses on derivative contracts	(361.7		)		121.6				(248.5		)		(40.0		)
Exploration expenses	0.2				0.3				0.3				22.0
Net (gain) loss from asset sales, inclusive of restructuring costs	1.7				(8.3		)		(25.0		)		(213.5		)
Impairment	1,156.5				50.5				1,560.9				78.9
Loss from early extinguishment of debt	—				32.7				—				32.7
Other(1)	—				—				—				8.2
Adjusted EBITDA	$	194.1			$	195.1			$	974.8			$	736.1

 ____________________________
⁽¹⁾  Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2017. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

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, loss on early extinguishment of debt 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) (a 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 statements prepared in accordance with GAAP.

	Three Months Ended December 31,								Year Ended December 31,
	2018				2017				2018				2017
	(in millions, except earnings per share amounts)
Net income (loss)(1)	$	(629.3	)		$	150.3			$	(1,011.6	)		$	269.3
Adjustments to net income (loss)
Unrealized (gains) losses on derivative contracts	(361.7		)		121.6				(248.5		)		(40.0		)
Income taxes on unrealized (gains) losses on derivative contracts(2)	89.3				(45.1		)		61.4				14.8
Net gain (loss) from asset sales, inclusive of restructuring costs	1.7				(8.3		)		(25.0		)		(213.5		)
Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs(2)	(0.4		)		3.1				6.2				79.2
Impairment	1,156.5				50.5				1,560.9				78.9
Income taxes on impairment(2)	(285.7		)		(18.7		)		(385.5		)		(29.3		)
Loss from early extinguishment of debt	—				32.7				—				32.7
Income taxes on loss from early extinguishment of debt(2)	—				(12.1		)		—				(12.1		)
Other(3)	—				—				—				8.2
Income taxes on other(2)	—				—				—				(3.0		)
Total after-tax adjustments to net income	599.7				123.7				969.5				(84.1		)
Adjusted Net Income (Loss)	$	(29.6	)		$	274.0			$	(42.1	)		$	185.2
Earnings (Loss) per Common Share
Diluted earnings per share	$	(2.66	)		$	0.62			$	(4.25	)		$	1.12
Diluted after-tax adjustments to net income (loss) per share	2.53				0.51				4.08				(0.35		)
Diluted Adjusted Net Income per share	$	(0.13	)		$	1.13			$	(0.17	)		$	0.77
Weighted-average common shares outstanding
Diluted	236.7				241.0				237.9				240.6

________________________
⁽¹⁾  Net income during the year ended December 31, 2017, was also positively impacted by a $307.9 million tax benefit, primarily due to a revaluation of our net deferred tax liability to reflect the federal rate change resulting from 35% to 21% under the new tax legislation.
⁽²⁾  Income tax impact of adjustments is calculated using QEP’s statutory rate of 24.7% and 37.1% for the three and twelve months ended December 31, 2018 and 2017.
⁽³⁾ Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2017. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

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 (a 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 December 31,												Year Ended December 31,
	2018				2017				Change				2018				2017				Change
	(in millions)
Transportation and processing costs, as presented	$	24.4			$	42.7			$	(18.3	)		$	117.6			$	245.3			$	(127.7	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	14.1				—				14.1				55.0				—				55.0
Adjusted transportation and processing costs	$	38.5			$	42.7			$	(4.2	)		$	172.6			$	245.3			$	(72.7	)
	(per Boe)
Transportation and processing costs, as presented	$	2.10			$	3.54			$	(1.44	)		$	2.27			$	4.61			$	(2.34	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.21				—				1.21				1.06				—				1.06
Adjusted transportation and processing costs	$	3.31			$	3.54			$	(0.23	)		$	3.33			$	4.61			$	(1.28	)

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 (a 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 December 31,								Year Ended December 31,
	2018				2017				2018				2017
	(in millions)
Cash Flow Information:
Net Cash Provided by (Used in) Operating Activities	$	141.3			$	117.4			$	816.2			$	600.2
Net Cash Provided by (Used in) Investing Activities	(193.2		)		(1,081.8		)		(1,056.1		)		(1,168.0		)
Net Cash Provided by (Used in) Financing Activities	52.8				146.0				244.6				125.8
Discretionary Cash Flow:
Net Cash Provided by (Used in) Operating Activities	$	141.3			$	117.4			$	816.2			$	600.2
Changes in operating assets and liabilities	(95.9		)		(50.0		)		(114.8		)		(4.9		)
Discretionary Cash Flow	45.4				67.4				701.4				595.3
Property acquisitions	(17.3		)		(720.7		)		(65.6		)		(815.2		)
Property, plant and equipment, including exploratory well expense	(202.0		)		(380.0		)		(1,234.1		)		(1,159.6		)
Discretionary Cash Flow in Excess of Capital Expenditures	$	(173.9	)		$	(1,033.3	)		$	(598.3	)		$	(1,379.5	)

The following tables present QEP's volumes and average prices for its open derivative positions as of February 15, 2019:

Production Commodity Derivative Swaps
Year		Index		Total Volumes			Average Swap Price per Unit
				(in millions)
Oil sales				(bbls)				($/bbl)
2019		NYMEX WTI		10.6			$	54.61
2020		NYMEX WTI		4.4			$	60.22

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		6.0			$	(2.22	)
2019		NYMEX WTI		Argus WTI Houston		0.7			$	3.80
2020		NYMEX WTI		Argus WTI Midland		1.8			$	(0.80	)

QEP Resources, Inc.