UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q  
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 

For the quarterly period ended June 30, 2015
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from ______ to ______

Commission File Number: 001-34778

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)
STATE OF DELAWARE
 
87-0287750
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
 
1050 17 th Street, Suite 800, Denver, Colorado 80265
(Address of principal executive offices)
 
Registrant’s telephone number, including area code (303) 672-6900
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
 
Large accelerated filer
ý
Accelerated filer
o
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
 
At June 30, 2015 , there were 176,667,217 shares of the registrant’s common stock, $0.01 par value, outstanding.
 


QEP Resources, Inc.
Form 10-Q for the Quarter Ended June 30, 2015

TABLE OF CONTENTS
 
 
 
 
Page
 
 
 
 
 
ITEM 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
 
 
ITEM 1.
 
 
 
 
 
ITEM 1A.
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
ITEM 5.
 
 
 
 
 
ITEM 6.
 
 

1


PART I. FINANCIAL INFORMATION
 
ITEM 1. FINANCIAL STATEMENTS
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
REVENUES
(in millions, except per share amounts)
Gas sales
$
111.9

 
$
215.1

 
$
233.9

 
$
437.6

Oil sales
250.4

 
358.8

 
429.2

 
647.5

NGL sales
26.1

 
65.0

 
45.2

 
128.2

Other revenue
5.2

 
(0.8
)
 
9.6

 
1.7

Purchased gas and oil sales
215.0

 
249.1

 
382.3

 
489.7

Total Revenues
608.6

 
887.2

 
1,100.2

 
1,704.7

OPERATING EXPENSES
 

 
 

 
 

 
 

Purchased gas and oil expense
217.2

 
249.2

 
386.6

 
487.1

Lease operating expense
57.1

 
59.5

 
118.9

 
115.9

Gas, oil and NGL transportation and other handling costs
73.0

 
67.5

 
138.1

 
127.4

Gathering and other expense
1.4

 
1.8

 
3.1

 
3.4

General and administrative
51.3

 
52.3

 
98.7

 
97.6

Production and property taxes
32.7

 
53.5

 
60.5

 
101.4

Depreciation, depletion and amortization
215.8

 
235.2

 
411.2

 
461.1

Exploration expenses
0.8

 
1.7

 
1.9

 
3.9

Impairment
0.5

 
1.5

 
20.5

 
3.5

Total Operating Expenses
649.8

 
722.2

 
1,239.5

 
1,401.3

Net gain (loss) from asset sales
24.5

 
(200.9
)
 
(6.0
)
 
(198.5
)
OPERATING INCOME (LOSS)
(16.7
)
 
(35.9
)
 
(145.3
)
 
104.9

Realized and unrealized gains (losses) on derivative contracts (Note 8)
(66.0
)
 
(88.0
)
 
14.9

 
(168.9
)
Interest and other income
3.8

 
0.8

 
1.2

 
3.7

Income from unconsolidated affiliates
—


0.1


—


0.1

Interest expense
(36.2
)
 
(45.0
)
 
(73.0
)
 
(86.9
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(115.1
)
 
(168.0
)
 
(202.2
)
 
(147.1
)
Income tax (provision) benefit
38.8

 
61.9

 
70.3

 
53.7

NET INCOME (LOSS) FROM CONTINUING OPERATIONS
(76.3
)
 
(106.1
)
 
(131.9
)
 
(93.4
)
Net income from discontinued operations, net of income tax
—

 
13.8

 
—

 
40.8

NET INCOME (LOSS)
$
(76.3
)
 
$
(92.3
)
 
$
(131.9
)
 
$
(52.6
)
 
 
 
 
 
 
 
 
Earnings (Loss) Per Common Share
 

 
 

 
 

 
 

Basic from continuing operations
$
(0.43
)
 
$
(0.59
)
 
$
(0.75
)
 
$
(0.52
)
Basic from discontinued operations
—

 
0.08

 
—

 
0.23

Basic total
$
(0.43
)
 
$
(0.51
)
 
$
(0.75
)
 
$
(0.29
)
Diluted from continuing operations
$
(0.43
)
 
$
(0.59
)
 
$
(0.75
)
 
$
(0.52
)
Diluted from discontinued operations
—

 
0.08

 
—

 
0.23

Diluted total
$
(0.43
)
 
$
(0.51
)
 
$
(0.75
)

$
(0.29
)
Weighted-average common shares outstanding
 

 
 

 
 

 
 

Used in basic calculation
176.7

 
180.1

 
176.4

 
179.9

Used in diluted calculation
176.7

 
180.1

 
176.4

 
179.9

Dividends per common share
$
0.02

 
$
0.02

 
$
0.04

 
$
0.04


See Notes accompanying the Condensed Consolidated Financial Statements.

2


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

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Net income (loss)
$
(76.3
)
 
$
(92.3
)
 
$
(131.9
)
 
$
(52.6
)
Other comprehensive income, net of tax:
 

 
 

 
 

 
 

Pension and other postretirement plans adjustments:
 

 
 

 
 

 
 

Amortization of net actuarial loss (1)
—

 
0.1

 
0.2

 
0.2

Amortization of prior service cost (2)
0.1

 
0.8

 
0.6

 
1.7

Other comprehensive income
0.1

 
0.9

 
0.8

 
1.9

Comprehensive income (loss)
$
(76.2
)
 
$
(91.4
)

$
(131.1
)

$
(50.7
)
____________________________
(1)  
Presented net of income tax expense of $0.1 million during the six months ended June 30, 2015 , and $0.1 million and $0.2 million during the three and six months ended June 30, 2014 , respectively.
(2)  
Presented net of income tax expense of $0.1 million and $0.4 million during the three and six months ended June 30, 2015 , respectively, and $0.5 million and $1.0 million during the three and six months ended June 30, 2014 , respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.


3


QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
June 30,
2015
 
December 31,
2014
ASSETS
(in millions)
Current Assets
 
 
 
Cash and cash equivalents
$
445.6

 
$
1,160.1

Accounts receivable, net
330.8

 
441.9

Income taxes receivable
55.7

 
—

Fair value of derivative contracts
163.6

 
339.0

Gas, oil and NGL inventories, at lower of average cost or market
10.4

 
13.7

Prepaid expenses and other
38.0

 
46.8

Total Current Assets
1,044.1

 
2,001.5

Property, Plant and Equipment (successful efforts method for oil and gas properties)
 

 
 

Proved properties
12,686.4

 
12,278.7

Unproved properties
814.1

 
825.2

Marketing and other
298.1

 
293.8

Material and supplies
41.6

 
54.3

Total Property, Plant and Equipment
13,840.2

 
13,452.0

Less Accumulated Depreciation, Depletion and Amortization
 

 
 

Exploration and production
6,415.1

 
6,153.0

Marketing and other
77.7

 
67.8

Total Accumulated Depreciation, Depletion and Amortization
6,492.8

 
6,220.8

Net Property, Plant and Equipment
7,347.4

 
7,231.2

Fair value of derivative contracts
6.1

 
9.9

Other noncurrent assets
35.5

 
44.2

TOTAL ASSETS
$
8,433.1

 
$
9,286.8

LIABILITIES AND EQUITY


 
 

Current Liabilities
 

 
 

Checks outstanding in excess of cash balances
$
7.4

 
$
54.7

Accounts payable and accrued expenses
463.3

 
575.4

Income taxes payable
—

 
532.1

Production and property taxes
59.3

 
61.7

Interest payable
36.4

 
36.4

Fair value of derivative contracts
1.0

 
—

Deferred income taxes
36.9

 
84.5

Total Current Liabilities
604.3

 
1,344.8

Long-term debt
2,218.5

 
2,218.1

Deferred income taxes
1,381.4

 
1,362.7

Asset retirement obligations
184.9

 
193.8

Fair value of derivative contracts
1.6

 
—

Other long-term liabilities
94.7

 
92.1

Commitments and contingencies (Note 10)


 


EQUITY
 

 
 

Common stock - par value $0.01 per share; 500.0 million shares authorized; 
177.0 million and 176.2 million shares issued, respectively
1.8

 
1.8

Treasury stock - 0.4 million and 0.8 million shares, respectively
(11.5
)
 
(25.4
)
Additional paid-in capital
538.1

 
535.3

Retained earnings
3,442.8

 
3,587.9

Accumulated other comprehensive income (loss)
(23.5
)
 
(24.3
)
Total Common Shareholders' Equity
3,947.7

 
4,075.3

TOTAL LIABILITIES AND EQUITY
$
8,433.1


$
9,286.8

 

See Notes accompanying the Condensed Consolidated Financial Statements.

4


QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
 
June 30,
 
2015
 
2014
 
(in millions)
OPERATING ACTIVITIES
 

 
 

Net income (loss)
$
(131.9
)
 
$
(52.6
)
Net income attributable to noncontrolling interest
—

 
10.8

Adjustments to reconcile net income to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
411.2

 
489.9

Deferred income taxes
(29.4
)
 
15.8

Impairment
20.5

 
3.5

Share-based compensation
15.6

 
14.6

Pension curtailment loss
11.2

 
—

Amortization of debt issuance costs and discounts
3.3

 
3.4

Net (gain) loss from asset sales
6.0

 
198.6

Income from unconsolidated affiliates
—

 
(3.4
)
Distributions from unconsolidated affiliates and other
—

 
6.3

Unrealized (gains) losses on derivative contracts
181.8

 
98.2

Changes in operating assets and liabilities
(490.9
)
 
75.2

Net Cash (Used in) Provided by Operating Activities
(2.6
)
 
860.3

INVESTING ACTIVITIES
 

 
 

Property acquisitions
—

 
(949.4
)
Property, plant and equipment, including dry exploratory well expense
(651.3
)
 
(779.0
)
Proceeds from (payments for) disposition of assets
(2.4
)
 
706.3

Acquisition deposit held in escrow
—

 
50.0

Net Cash Used in Investing Activities
(653.7
)

(972.1
)
FINANCING ACTIVITIES
 

 
 

Checks outstanding in excess of cash balances
(47.3
)
 
(85.2
)
Long-term debt issued
—

 
300.0

Long-term debt issuance costs paid
—

 
(1.1
)
Proceeds from credit facility
—

 
3,151.0

Repayments of credit facility
—

 
(2,538.0
)
Treasury stock repurchases
(1.9
)
 
(5.5
)
Other capital contributions
(0.1
)
 
4.1

Dividends paid
(7.1
)
 
(7.3
)
Excess tax (provision) benefit on share-based compensation
(1.8
)
 
(0.6
)
Distribution to noncontrolling interest
—

 
(15.2
)
Net Cash (Used in) Provided by Financing Activities
(58.2
)
 
802.2

Change in cash and cash equivalents
(714.5
)

690.4

Beginning cash and cash equivalents
1,160.1

 
11.9

Ending cash and cash equivalents
$
445.6

 
$
702.3

 
 
 
 
Supplemental Disclosures:
 

 
 

Cash paid for interest, net of capitalized interest
$
69.7

 
$
84.9

Cash paid for income taxes
548.5

 
0.2

Non-cash investing activities:
 

 
 

Change in capital expenditure accrual balance
$
(91.6
)
 
$
26.3

 
See Notes accompanying the Condensed Consolidated Financial Statements.

5


QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
Note 1 - Nature of Business

QEP Resources, Inc. (QEP or the Company) is a holding company with two principal subsidiaries, QEP Energy Company and QEP Marketing Company, which are engaged in two primary lines of business: (i) oil and gas exploration and production (QEP Energy) and (ii) oil and gas marketing, operation of a gas gathering system and an underground gas storage facility and corporate (QEP Marketing and Other).

QEP's operations are focused in two geographic regions: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Shares of QEP’s common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol “QEP”.

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements
 
The interim Condensed Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Condensed Consolidated Financial Statements were prepared in accordance with United States Generally Accepted Accounting Principles (GAAP) and with the instructions for Quarterly Reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Condensed Consolidated Financial Statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014 .
 
The preparation of the Condensed Consolidated Financial Statements and Notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and six months ended June 30, 2015 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 .

Impairment of Long-Lived Assets

During the six months ended June 30, 2015 , QEP Energy recorded impairment charges of $20.5 million , of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. Of the $19.4 million impairment on proved properties, $14.5 million related to oil and gas properties in the Southern Region and $4.9 million related to oil and gas properties in the Northern Region.

New Accounting Pronouncements

In May 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-07, Fair Value Measurement (Topic 820) , which removes the requirement to categorize investments for which fair values are measured using the net asset value per share practical expedient. It also limits disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-05, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40) , which assists entities in evaluating the accounting for fees paid by a customer in a cloud computing arrangement by providing guidance as to whether an arrangement includes the sales or license of software. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.


6


In April 2015, the FASB issued ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30) , which simplifies the presentation of debt issuance costs by requiring that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The amendments will be effective retrospectively for reporting periods beginnin g on or after December 15, 2015, and early adoption is permitted. The Company plans to implement the ASU effective January 1, 2016 and does not believe there will be a significant impact on the Company's consolidated financial statements.

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) , which amends the current consolidation guidance. The amendment affects both the variable interest entity and voting interest entity consolidation models. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In January 2015, the FASB issued ASU No. 2015-01, Income Statement — Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from GAAP. The amendment will be effective for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. Additionally, a reporting entity also may apply the amendment retrospectively for all periods presented in the financial statements. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year and the amendments are now effective prospectively for reporting periods beginning after December 15, 2017 and early adoption is not permitted. The Company is currently assessing the impact on the Company's Consolidated Financial Statements.

Note 3 - Acquisitions and Divestitures

Permian Basin Acquisition

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million (the Permian Basin Acquisition). The acquired properties consisted of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and the remainder was funded from its revolving credit facility.

The Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations , as it included significant proved properties. QEP allocated the cost of the Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $40.1 million and $69.6 million and net income of $2.4 million and $0.9 million were generated from the acquired properties during the three and six months ended June 30, 2015 . Revenues of $61.9 million and net income of $14.0 million were generated from the acquired properties from February 25, 2014, to June 30, 2014 , and are included in QEP's Condensed Consolidated Statements of Operations.

The following table presents a summary of the Company's purchase accounting entries (in millions):
Consideration:
 
Total consideration
$
941.8

 
 
Amounts recognized for fair value of assets acquired and liabilities assumed:
 
Proved properties
$
472.1

Unproved properties
480.6

Asset retirement obligations
(9.7
)
Liabilities assumed
(1.2
)
Total fair value
$
941.8


7



The following unaudited, pro forma results of operations are provided for the six months ended June 30, 2014 . Pro forma results are not provided for the three months ended June 30, 2014 , or the three and six months ended June 30, 2015 , because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore there is no pro forma impact on the these periods. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the period presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the six months ended June 30, 2014 , the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.
 
 
Six Months Ended
 
 
June 30, 2014
 
 
Actual
 
Pro forma
 
(in millions, except per share data)
Revenues
 
$
1,704.7

 
$
1,730.8

Net income
 
$
(52.6
)
 
$
(45.6
)
Earnings per common share
Basic
 
$
(0.29
)
 
$
(0.25
)
Diluted
 
$
(0.29
)
 
$
(0.25
)

Divestitures

In December 2014, QEP Energy sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of $96.3 million , subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $53.3 million for the year ended December 31, 2014. QEP Energy recorded a pre-tax loss on sale of $1.1 million and $2.9 million for the three and six months ended June 30, 2015 , respectively, due to post-closing purchase price adjustments.

In June 2014, QEP Energy sold its interest in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of $668.2 million , subject to post-closing purchase price adjustments, and recorded a pre-tax loss of $199.4 million for the year ended December 31, 2014. QEP recorded a pre-tax gain on sale of $0.4 million and a pre-tax loss on sale of $26.4 million for the three and six months ended June 30, 2015 , respectively, due to post-closing purchase price adjustments. These gains and losses are reported on the Condensed Consolidated Statements of Operations in "Net gain (loss) from asset sales".

Note 4 - Discontinued Operations

In October 2014, the Company announced that its wholly owned subsidiary, QEP Field Services Company (QEP Field Services), had entered into a definitive agreement to sell substantially all of its midstream business, including its ownership interest in QEP Midstream Partners, LP (QEP Midstream) to Tesoro Logistics LP (Tesoro). On December 2, 2014, QEP closed the sale of its midstream business to Tesoro (Midstream Sale) for total cash proceeds of approximately $2.5 billion , including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014.

The operating results of QEP Field Services, excluding the Haynesville Gathering System (the Discontinued Operations of QEP Field Services), have been classified as discontinued operations on the Condensed Consolidated Statements of Operations and Notes accompanying the Condensed Consolidated Financial Statements for the three and six months ended June 30, 2014 . QEP will have continuing cash outflows to the entities sold as a part of the Midstream Sale for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. The contracts related to these cash flows vary in length from month-to-month to over a year and will be reviewed periodically in the normal course of business. Historically, these transactions were eliminated in consolidation, as they represented transactions between two related entities but are now reflected as part of the continuing operations for QEP. For the six months ended June 30, 2015 and 2014 , cash outflows for these transactions included in continuing operations were $69.3 million and $74.0 million , respectively.

8



In connection with QEP's plan to separate its midstream business, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump-sum cash payment on the earlier of December 31, 2014, or whenever the separation of QEP Field Services occurred, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date. QEP recognized $10.4 million of costs under this retention plan in 2014, of which $2.6 million and $4.8 million was included in "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 , respectively.

Condensed Consolidated Statement of Operations

The Discontinued Operations of QEP Field Services are summarized below:
 
Three Months Ended
 
Six Months Ended
 
June 30, 2014
 
(in millions)
REVENUES
 
 
 
NGL sales
$
27.8

 
$
65.8

Other revenue
34.9

 
76.8

Purchased gas and oil sales (1)
(13.2
)
 
(26.6
)
Total Revenues
49.5

 
116.0

OPERATING EXPENSES
 
 
 
Purchased gas and oil expense (1)
(13.3
)
 
(27.1
)
Lease operating expense (1)
(2.0
)
 
(3.1
)
Natural gas, oil and NGL transport and other handling costs (1)
(13.1
)
 
(29.5
)
Gathering, processing, and other
22.8

 
47.1

General and administrative
11.9

 
23.2

Production and property taxes
2.5

 
4.0

Depreciation, depletion and amortization
14.5

 
28.8

Total Operating Expenses
23.3

 
43.4

Net loss from asset sales
(0.1
)
 
(0.1
)
OPERATING INCOME
26.1

 
72.5

Income from unconsolidated affiliates
1.1

 
3.3

Interest expense
(0.7
)
 
(1.3
)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)
26.5

 
74.5

Income tax provision
(7.7
)
 
(22.9
)
NET INCOME FROM DISCONTINUED OPERATIONS
18.8

 
51.6

Net income attributable to noncontrolling interest
(5.0
)
 
(10.8
)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX
$
13.8

 
$
40.8

(1)  
Includes discontinued intercompany eliminations.
(2)  
Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8% ) of $5.7 million and $12.5 million for the three and six months ended June 30, 2014 , respectively.

Condensed Consolidated Statement of Cash Flows

The impact of the Discontinued Operations of QEP Field Services on the Condensed Consolidated Statement of Cash Flows for " Depreciation, depletion and amortization " contained in "Cash flows from operating activities" was $14.5 million and $28.8 million for the three and six months ended June 30, 2014 , respectively. The impact on cash used for " Property, plant and equipment, including dry exploratory well expense " contained in "Cash flows from investing activities" was $24.4 million and $37.1 million for the three and six months ended June 30, 2014 , respectively.


9


Note 5 – Earnings Per Share
 
Basic earnings per share (EPS) are computed by dividing net income by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP’s unvested restricted shares are included in weighted-average basic common shares outstanding because once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.
 
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three and six months ended June 30, 2014 , 0.4 million and 0.3 million shares, respectively, were not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss. During the three and six months ended June 30, 2015 , there were no anti-dilutive shares.

A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2015

2014
 
2015
 
2014
 
(in millions)
Weighted-average basic common shares outstanding
176.7

 
180.1

 
176.4

 
179.9

Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan
—

 
—

 
—

 
—

Average diluted common shares outstanding
176.7

 
180.1

 
176.4

 
179.9



Note 6 – Asset Retirement Obligations
 
QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $185.9 million and $195.1 million ARO liability for the periods ended June 30, 2015 and December 31, 2014 , $1.0 million and $1.3 million were included, respectively, as a current liability in "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.


10


The following is a reconciliation of the changes in the Company's ARO for the period specified below:
 
Asset Retirement Obligations
 
2015
 
(in millions)
ARO liability at January 1,
$
195.1

Accretion
4.3

Additions
1.9

Revisions
0.2

Liabilities related to divestitures
(14.6
)
Liabilities settled
(1.0
)
ARO liability at June 30,
$
185.9


Note 7 – Fair Value Measurements
 
QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures . This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.
 
QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 8 - Derivative Contracts) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.
 
Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.

11



The fair value of financial assets and liabilities at June 30, 2015 and December 31, 2014 , is shown in the table below:
 
Fair Value Measurements
 
Gross Amounts of Assets and Liabilities
 
Netting
Adjustments (1)
 
Net Amounts Presented on the Condensed Consolidated Balance Sheets
 
Level 1
 
Level 2
 
Level 3
 
 
 
(in millions)
 
June 30, 2015
Financial Assets
 
 
 
 
 
 
 
 
 
Commodity derivative instruments - short-term
$
—

 
$
170.7

 
$
—

 
$
(7.1
)
 
$
163.6

Commodity derivative instruments - long-term
—

 
7.0

 
—

 
(0.9
)
 
6.1

Total financial assets
$
—

 
$
177.7

 
$
—

 
$
(8.0
)
 
$
169.7

 
 
 
 
 
 
 
 
 
 
Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity derivative instruments - short-term
$
—

 
$
8.1

 
$
—

 
$
(7.1
)
 
$
1.0

Commodity derivative instruments - long-term
—

 
2.5

 
—

 
(0.9
)
 
1.6

Total financial liabilities
$
—

 
$
10.6

 
$
—

 
$
(8.0
)
 
$
2.6

 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
Financial Assets
 
 
 
 
 
 
 
 
 
Commodity derivative instruments - short-term
$
—

 
$
339.3

 
$
—

 
$
(0.3
)
 
$
339.0

Commodity derivative instruments - long-term
—

 
9.9

 
—

 
—

 
9.9

Total financial assets
$
—

 
$
349.2

 
$
—

 
$
(0.3
)
 
$
348.9

 
 
 
 
 
 
 
 
 
 
Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity derivative instruments - short-term
$
—

 
$
0.3

 
$
—

 
$
(0.3
)
 
$
—

Total financial liabilities
$
—

 
$
0.3

 
$
—

 
$
(0.3
)
 
$
—

_______________________
(1)  
The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, as the contracts contain netting provisions. Refer to Note 8 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes accompanying the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q:
 
Carrying
Amount
 
Level 1
Fair Value
 
Carrying
Amount
 
Level 1
Fair Value
 
June 30, 2015
 
December 31, 2014
 
(in millions)
Financial assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
445.6

 
$
445.6

 
$
1,160.1

 
$
1,160.1

Financial liabilities
 

 
 

 
 

 
 

Checks outstanding in excess of cash balances
$
7.4

 
$
7.4

 
$
54.7

 
$
54.7

Long-term debt
$
2,218.5

 
$
2,230.9

 
$
2,218.1

 
$
2,171.6


The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company’s debt at the end of the quarter. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.


12


The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s ARO is presented in Note 6 – Asset Retirement Obligations.

Note 8 – Derivative Contracts
 
QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves, but generally, QEP intends to enter into commodity derivative contracts for approximately 50% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP may enter into commodity derivative contracts on a portion of its gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps or collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of gas, oil, or NGL between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Gas price derivative instruments are typically structured as fixed-price swaps or collars at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use Intercontinental Exchange, Inc. (ICE) Brent oil prices as the reference price. QEP also enters into crude oil and natural gas basis swaps to achieve a fixed price swap for a portion of its oil and gas that it sells at prices that reference specific index prices.

QEP enters into commodity derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are normally financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids concentration of credit exposure by transacting with multiple counterparties.

During 2014, QEP also used interest rate swaps to mitigate a portion of its exposure to interest rate volatility associated with its $600.0 million term loan. For the $300.0 million term loan issued during 2012, QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR. For the incremental $300.0 million borrowed under the term loan during 2014, QEP locked in a fixed interest rate of 0.86% . These interest rate swaps were terminated in December 2014 in conjunction with the extinguishment of QEP's term loan.

13


QEP Energy Derivative Contracts
The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative swap contracts as of June 30, 2015 : 
Year
 
Index
 
Total
Volumes
 
Average Swap price per unit
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
(MMBtu)

 
 
2015
 
 NYMEX HH
 
35.0

 
$
3.48

2015
 
 IFNPCR
 
23.9

 
$
3.55

2016
 
NYMEX HH
 
18.3

 
$
3.24

2016
 
IFNPCR
 
25.6

 
$
2.92

Oil sales
 
 
 
(bbls)

 
 

2015
 
NYMEX WTI
 
5.2

 
$
82.09

2015
 
ICE Brent
 
0.2

 
$
104.95

2016
 
NYMEX WTI
 
3.3

 
$
65.43


The following table sets forth details of QEP Energy's gas collars as of June 30, 2015 :
 
 
 
 
Total Volume
 
Average Price
 
Average Price
Year
 
Index
 
 
Floor
 
Ceiling
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
(MMBtu)

 
($/MMBtu)
 
($/MMBtu)
2016
 
NYMEX HH
 
7.3

 
$
2.75

 
$
3.89


QEP uses gas basis swaps, combined with NYMEX HH fixed price swaps, to achieve fixed price swaps at the location at which it sells its physical production.

The following table sets forth details of QEP Energy's gas basis swaps as of June 30, 2015 :
Year
 
Index
 
Index Less Differential
 
Total Volumes
 
Weighted Average Differential
 
 
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
(MMBtu)

 
($/MMBtu)

2015
 
NYMEX HH
 
IFNPCR
 
22.1

 
$
(0.28
)

14



QEP Marketing Derivative Contracts
QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells gas volumes at a fixed price. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of June 30, 2015 :
Year
 
Type of Contract
 
Index
 
Total
Volumes
 
Average Swap price
per MMBtu
 
 
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
 
 
(MMBtu)

 
 
2015
 
SWAP
 
IFNPCR
 
2.4

 
$
3.25

2016
 
SWAP
 
IFNPCR
 
1.8

 
$
3.19

Gas purchases
 
 
 
 
 
(MMBtu)

 
 

2015
 
SWAP
 
IFNPCR
 
0.9

 
$
2.80


 
QEP Derivative Financial Statement Presentation
The following table identifies the condensed consolidated balance sheet location of QEP’s outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation in the Condensed Consolidated Balance Sheets and the related fair values at the balance sheet dates:
 
 
 
Gross asset derivative
instruments fair value
 
Gross liability derivative
instruments fair value
 
Balance Sheet
line item
 
June 30,
2015
 
December 31, 2014
 
June 30,
2015
 
December 31, 2014
 
 
 
(in millions)
Current:
 
 
 
 
 
 
 
 
 
Commodity
Fair value of derivative contracts
 
$
170.7

 
$
339.3

 
$
8.1

 
$
0.3

Long-term:
 
 
 

 
 

 
 
 
 

Commodity
Fair value of derivative contracts
 
7.0

 
9.9

 
2.5

 
—

Total derivative instruments
 
$
177.7

 
$
349.2

 
$
10.6

 
$
0.3



15


The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Condensed Consolidated Statements of Operations are summarized in the following table:
 
 
Three Months Ended
 
Six Months Ended
Derivative instruments not designated as cash flow hedges
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Realized gains (losses) on commodity derivative contracts
 
(in millions)
QEP Energy
 
 
 
 
 
 
 
 
Gas derivative contracts
 
$
28.1

 
$
(8.4
)
 
$
46.0

 
$
(28.8
)
Oil derivative contracts
 
64.5

 
(25.1
)
 
148.5

 
(38.0
)
QEP Marketing
 
 

 
 

 
 

 
 

Gas derivative contracts
 
(0.3
)
 
(0.6
)
 
2.2

 
(2.0
)
Total realized gains (losses) on commodity derivative contracts
 
92.3

 
(34.1
)
 
196.7

 
(68.8
)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
 
 

 
 

 
 

 
 

Gas derivative contracts
 
(34.5
)
 
6.2

 
(23.1
)
 
(18.1
)
Oil derivative contracts
 
(123.7
)
 
(58.0
)
 
(156.8
)
 
(78.9
)
QEP Marketing
 
 

 
 

 
 

 
 

Gas derivative contracts
 
(0.1
)
 
0.7

 
(1.9
)
 
0.4

Total unrealized gains (losses) on commodity derivative contracts
 
(158.3
)
 
(51.1
)
 
(181.8
)
 
(96.6
)
Total realized and unrealized gains (losses) on commodity derivative contracts
 
$
(66.0
)
 
$
(85.2
)
 
$
14.9

 
$
(165.4
)
 
 
 
 
 
 
 
 
 
Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps
 
$
—

 
$
(1.2
)
 
$
—

 
$
(1.9
)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps
 
—

 
(1.6
)
 
—

 
(1.6
)
Total realized gains (losses) on interest rate swaps
 
$
—

 
$
(2.8
)
 
$
—

 
$
(3.5
)
Total net realized gains (losses) on derivative contracts
 
$
92.3

 
$
(35.3
)
 
$
196.7

 
$
(70.7
)
Total net unrealized gains (losses) on derivative contracts
 
(158.3
)
 
(52.7
)
 
(181.8
)
 
(98.2
)
Grand Total
 
$
(66.0
)
 
$
(88.0
)
 
$
14.9

 
$
(168.9
)


16


Note 9 – Debt
 
As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under QEP's revolving credit facility and senior notes, consisted of the following:
 
June 30,
2015
 
December 31,
2014
 
(in millions)
Revolving Credit Facility due 2019
$
—

 
$
—

6.05% Senior Notes due 2016
176.8

 
176.8

6.80% Senior Notes due 2018
134.0

 
134.0

6.80% Senior Notes due 2020
136.0

 
136.0

6.875% Senior Notes due 2021
625.0

 
625.0

5.375% Senior Notes due 2022
500.0

 
500.0

5.25% Senior Notes due 2023
650.0

 
650.0

Total principal amount of debt
2,221.8

 
2,221.8

Less unamortized discount
(3.3
)
 
(3.7
)
Total long-term debt outstanding
$
2,218.5

 
$
2,218.1

 
Of the total debt outstanding on June 30, 2015 , the 6.05% Senior Notes due September 1, 2016 , the 6.80% Senior Notes due April 1, 2018 and the 6.80% Senior Notes due March 1, 2020 , will mature within the next five years . The revolving credit facility matures on December 2, 2019 .
 
Credit Facility
QEP’s revolving credit facility, which matures in December 2019 , provides for loan commitments of $1.8 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions.

On December 2, 2014, QEP entered into the Fourth Amendment to its Credit Agreement, which increased the aggregate principal amount of commitments to $1.8 billion , extended the maturity date to December 2, 2019, and made minor adjustments to other provisions and covenants.

During the six months ended June 30, 2014 , QEP’s weighted-average interest rate on borrowings from its credit facility was 2.20% . At June 30, 2015 and December 31, 2014 , QEP had no borrowings outstanding under the credit facility, had $3.7 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit facility.

Senior Notes
At June 30, 2015 , the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 to May 2023 and coupons ranging from 5.25% to 6.875% . The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 10 - Contingencies

QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies , an accrual is recorded for a loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable, and unfavorable resolutions can occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, the ongoing discovery and/or development of information important to the matter. QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for its loss contingencies for the reasons set forth above. QEP believes, however,

17


that the resolution of pending proceedings (after accruals, insurance coverage, and indemnification arrangements) will not be material to QEP's financial position but could be material to results of operations in a particular quarter or year.

Litigation

Rocky Mountain Resources, LLC v. QEP Energy Company, Wexpro Company, Ultra Resources, Inc. and Lance Oil & Gas Company, Inc., Civil No. 2011-7816, District Court of Sublette County, Wyoming. Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint on March 30, 2011, seeking determination of the existence of a 4% overriding royalty interest in State of Wyoming oil and gas Lease No. 79-0645 covering Section 16, T32-N R-109-W, Sublette County, Wyoming. QEP and the other defendants are current lessees of Lease 79-0645. Rocky Mountain alleges that the defendants have received benefits from Lease 79-0645 and have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. Rocky Mountain asserts claims for quiet title, declaratory judgment, breach of contract, breach of duty of good faith, conversion, constructive trust and prejudgment interest. On May 7, 2014, the trial court entered its order granting plaintiff's motion for summary judgment on the issue of whether the overriding royalty interest burdens QEP's lease. On June 17, 2014, the Supreme Court of Wyoming denied QEP's Petition for Writ of Review. On August 21, 2014, the trial court denied QEP’s Motion to Certify Questions of Law to the Wyoming Supreme Court. At the conclusion of a trial in February 2015, and after being instructed by the Court that the overriding royalty interest burdened QEP’s lease, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million , including interest. QEP believes that the Court’s ruling on summary judgment and the resulting jury instructions are in error and will appeal to the Wyoming Supreme Court. On March 27, 2015, defendants filed a Motion for New Trial arguing that the verdict is not sustained by sufficient evidence, is contrary to law and resulted from errors of law occurring at the trial. The Court has taken the motion under advisement. Post-judgment interest accrues at the statutory rate of 10%. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to $20.0 million .

Yannick Gagné and others similarly situated v. QEP Resources, Inc., et al., No. 480-06-1-132, Superior Court, Province of Quebec, Canada. Plaintiffs seek to represent a class of all persons who sustained damages as a result of the July 6, 2013 train derailment in Lac-Mégantic, Quebec, which resulted in substantial loss of life and property. The fourth amended motion to authorize the bringing of a class action was filed on February 19, 2014, and names numerous defendants, including the rail company that transported the crude oil (which filed for bankruptcy protection in August 2013). The plaintiffs contend that QEP, and other producer defendants, sold Bakken crude oil to third-party purchasers in North Dakota, who resold the oil and transported it on the derailed train. Plaintiffs alleged that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, knowingly added volatile light end petroleum liquids and/or vapors or blended the crude with condensate, failed to conduct adequate well site testing to determine the proper hazard classification of the oil, failed to properly classify the shipping requirements for the oil, failed to take reasonable care to ensure that the oil was properly labeled and shipped, failed to identify the risk of the train derailment and take action to prevent it, and failed to adopt, implement and enforce rules and procedures pertaining to the safe shipment of the oil. The plaintiffs seek damages, but specific monetary damages are not asserted. Class certification hearings took place in June 2014, and a court order regarding class certification is pending. Many of the defendants, including QEP, and their insurers have reached an agreement with Trustees in both Canadian and U.S. Bankruptcy Courts to resolve all of these claims. The terms of the agreement are confidential and are contingent upon the approval of the courts. In addition, on July 15, 2015, QEP was served with a complaint entitled Samuel Audet, et al. vs. Devlar Energy Marketing, LLC, et al., No. DC-15-06428, District Court of Dallas County, Texas, 95 th Judicial District. The plaintiffs, defendants, allegations, and damages sought are materially similar to those in the Yannick Gagné case, and plaintiffs state that this lawsuit is filed to preserve claims under the applicable two-year statute of limitations. Plaintiffs also filed a motion to stay proceedings in this case for 90 days pending the outcome of the global settlement discussions described above in the Yannick Gagné case. The court's order on this request for a stay is pending.


18


Note 11 – Share-Based Compensation
 
QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted shares, and performance share units. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 9.2 million shares available for future grants under the LTSIP at June 30, 2015 . Share-based compensation expense related to continuing operations is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations, and expenses related to discontinued operations (including compensation expense related to the QEP Midstream Long Term Incentive Plan) are reflected in "Net income from discontinued operations, net of income tax". During the three and six months ended June 30, 2015 , QEP recognized $6.5 million and $15.6 million , respectively, in total compensation expense related to share-based compensation for continuing operations, compared to $5.9 million and $12.3 million , respectively, during the three and six months ended June 30, 2014 . During the three and six months ended June 30, 2014 , QEP recognized $1.2 million and $2.3 million , respectively, in total compensation expense related to share-based compensation for discontinued operations.
 
Stock Options
QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of the grant. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below for the six months ended June 30, 2015 :
 
Stock Option Assumptions
Weighted-average grant-date fair value of awards granted during the period
$
6.82

Weighted-average risk-free interest rate
1.38
%
Weighted-average expected price volatility
36.8
%
Expected dividend yield
0.37
%
Expected term in years at the date of grant
4.5


Stock option transactions under the terms of the LTSIP are summarized below:
 
Options
Outstanding
 
Weighted-
Average Exercise Price
 
Weighted-Average
Remaining
Contractual Term
 
Aggregate
Intrinsic Value
 
 
 
(per share)
 
(in years)
 
(in millions)
Outstanding at December 31, 2014
1,996,215

 
$
28.60

 
 
 
 
Granted
425,877

 
21.69

 
 
 
 
Exercised
(15,000
)
 
19.37

 
 
 
 
Forfeited
(2,817
)
 
31.31

 
 
 
 
Canceled
(60,000
)
 
27.84

 
 
 
 
Outstanding at June 30, 2015
2,344,275

 
$
27.42

 
3.48
 
$
—

Options Exercisable at June 30, 2015
1,658,563

 
$
28.32

 
2.40
 
$
—

Unvested Options at June 30, 2015
685,712

 
$
25.23

 
6.12
 
$
—

 
The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million and $0.5 million during the six months ended June 30, 2015 and 2014 , respectively. As of June 30, 2015 , $3.3 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.34 years.

19


 
Restricted Shares
Restricted share grants typically vest in equal installments over a three -year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the six months ended June 30, 2015 and 2014 , was $18.1 million and $15.2 million , respectively. The weighted average grant-date fair value of restricted stock was $21.66 per share and $31.63 per share for the six months ended June 30, 2015 and 2014 , respectively. As of June 30, 2015 , $33.0 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.42 years.

Transactions involving restricted shares under the terms of the LTSIP are summarized below:
 
Restricted Shares
Outstanding
 
Weighted-
Average Grant-Date Fair Value
 
 
 
(per share)
Unvested balance at December 31, 2014
1,426,453

 
$
31.02

Granted
1,373,300

 
21.66

Vested
(585,611
)
 
30.88

Forfeited
(83,590
)
 
27.54

Unvested balance at June 30, 2015
2,130,552

 
$
25.16

 
Performance Share Units
The performance share units' cash payouts are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but have historically been delivered in cash at the end of the performance period. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of June 30, 2015 , the Company expects to settle all awards in cash. The weighted average grant-date fair value of the performance share units was $21.69 per share and $31.67 per share for the six months ended June 30, 2015 and 2014 , respectively. As of June 30, 2015 , $2.5 million of unrecognized compensation cost, representing the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.09 years.

Transactions involving performance share units under the terms of the CIP are summarized below:
 
Performance Share
Units Outstanding
 
Weighted-
Average Grant-Date Fair Value
Unvested balance at December 31, 2014
552,209

 
$
30.85

Granted
234,085

 
21.69

Vested and paid out
(131,665
)
 
30.77

Canceled (1)
(14,612
)
 
30.77

Forfeited
(6,792
)
 
28.29

Unvested balance at June 30, 2015
633,225

 
$
27.52

____________________________
(1)  
Represents units that were not paid out due to performance under the plan.

Note 12 – Employee Benefits

Pension and other postretirement benefits
The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (SERP), and a postretirement medical plan (the Medical Plan).


20


The Pension Plan is a qualified, closed, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2015 , the Company made contributions of $2.0 million to the Pension Plan and does not expect to make additional contributions to the Pension Plan during 2015. Contributions to the Pension Plan increase plan assets.

As a result of the Company's 2014 divestitures and expected retirements in 2015, the number of participants in the Pension Plan is expected to fall below 50 employees by December 31, 2015, which is below the minimum number of participants for a plan to be qualified under the Internal Revenue Services' participation rules. In order to prevent disqualification, the Pension Plan was amended in June 2015 and will be frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Condensed Consolidated Statements of Operations within "General and administrative" expense during the three and six months ended June 30, 2015 .

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2015 , the Company made contributions of $1.8 million to its SERP and expects to contribute an additional $2.6 million to its SERP during the remainder of 2015 . Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and will be closed to new participants effective, January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. During the six months ended June 30, 2015 , the Company made contributions of $0.2 million to its Medical Plan and expects to contribute an additional $0.2 million to its Medical Plan during the remainder of 2015 . Contributions to the Medical Plan are used to fund current benefit payments.


21


The following table sets forth the Company’s net periodic benefit costs related to its Pension Plan, SERP and Medical Plan:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Pension Plan and SERP benefits
 
 
 
 
 
 
 
Service cost
$
0.4

 
$
0.7

 
$
1.0

 
$
1.4

Interest cost
1.1

 
1.4

 
2.4

 
2.8

Expected return on plan assets
(1.4
)
 
(1.2
)
 
(2.8
)
 
(2.4
)
Amortization of prior service costs (1)
0.1

 
1.2

 
0.9

 
2.5

Amortization of actuarial losses (1)
—

 
0.2

 
0.3

 
0.4

Curtailment loss (2)
11.2

 
2.0

 
11.2

 
2.0

Special termination benefits (3)
—

 
0.3

 
—

 
0.3

Periodic expense
$
11.4

 
$
4.6

 
$
13.0

 
$
7.0

 
 
 
 
 
 
 
 
Medical Plan benefits
 
 
 
 
 
 
 
Interest cost
$
—

 
$
0.1

 
$
0.1

 
$
0.2

Amortization of prior service costs (1)
0.1

 
0.1

 
0.1

 
0.2

Curtailment loss (2)
—

 
0.4

 
—

 
0.4

Periodic expense
$
0.1

 
$
0.6

 
$
0.2

 
$
0.8

____________________________
(1)  
Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."
(2)  
A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses are included on the Condensed Consolidated Statements of Operations within "General and administrative" expense for the three and six months ended June 30, 2015, as the expenses incurred in that period related to the Pension Plan amendment (see above), and within "Net gain (loss) from asset sales" for the three and six months ended June 30, 2014, as the expenses incurred in that period related to the Midcontinent property sales (see Note 3 - Acquisitions and Divestitures).
(3)  
During the three and six months ended June 30, 2014, the Company recognized special termination benefits on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales" as the expense related to the Midcontinent property sales (see Note 3 - Acquisitions and Divestitures).

During the three and six months ended June 30, 2015 , for continuing operations, QEP recognized $11.5 million and $13.2 million , respectively, in employee benefit expense, compared to $4.1 million and $6.1 million , respectively, during the three and six months ended June 30, 2014 . During the three and six months ended June 30, 2014 , for discontinued operations, QEP recognized $1.1 million and $1.7 million , respectively, in employee benefit expense.


22


Note 13 – Operations by Line of Business
 
QEP’s lines of business include oil and gas exploration and production (QEP Energy); and oil and gas marketing, operation of the Haynesville Gathering System and an underground storage facility, and corporate (QEP Marketing and Other). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors.

Our financial results for the three and six months ended June 30, 2014 , have been revised, in accordance with GAAP, to reflect the impact of the Midstream Sale. See Note 4 - Discontinued Operations for detailed information on the Midstream Sale.

The following table is a summary of operating results for the three months ended June 30, 2015 , by line of business:
 
QEP Energy
 
QEP Marketing
 and Other
 
Eliminations
 
QEP
Consolidated
 
(in millions)
REVENUES
 
 
 
 
 
 
 
From unaffiliated customers
$
407.9

 
$
200.7

 
$
—

 
$
608.6

From affiliated customers
—

 
248.1

 
(248.1
)
 
—

Total Revenues
407.9


448.8


(248.1
)

608.6

OPERATING EXPENSES
 

 
 

 
 

 
 

Purchased gas and oil expense
16.8

 
445.4

 
(245.0
)
 
217.2

Lease operating expense
57.1

 
—

 
—

 
57.1

Gas, oil and NGL transportation and other handling costs
75.5

 
—

 
(2.5
)
 
73.0

Gathering and other expense
—

 
1.4

 
—

 
1.4

General and administrative
50.0

 
1.9

 
(0.6
)
 
51.3

Production and property taxes
31.2

 
1.5

 
—

 
32.7

Depreciation, depletion and amortization
213.2

 
2.6

 
—

 
215.8

Impairment and exploration expense
1.3

 
—

 
—

 
1.3

Total Operating Expenses
445.1

 
452.8

 
(248.1
)
 
649.8

Net gain (loss) from asset sales
26.5

 
(2.0
)
 
—

 
24.5

OPERATING INCOME (LOSS)
(10.7
)
 
(6.0
)
 
—

 
(16.7
)
Realized and unrealized gains (losses) on derivative contracts
(65.6
)
 
(0.4
)
 
—

 
(66.0
)
Interest and other income
3.1

 
53.1

 
(52.4
)
 
3.8

Interest expense
(52.6
)
 
(36.0
)
 
52.4

 
(36.2
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(125.8
)
 
10.7

 
—

 
(115.1
)
Income tax (provision) benefit
42.4

 
(3.6
)
 
—

 
38.8

NET INCOME (LOSS)
$
(83.4
)
 
$
7.1

 
$
—

 
$
(76.3
)


23


The following table is a summary of operating results for the three months ended June 30, 2014 , by line of business:
 
QEP Energy
 
QEP Marketing
 and Other
 
Eliminations
 
Discontinued Operations
 
QEP
Consolidated
 
(in millions)
REVENUES
 
 
 
 
 
 
 
 
 
From unaffiliated customers
$
687.2

 
$
200.0

 
$
—

 
$
—

 
$
887.2

From affiliated customers
—

 
411.6

 
(411.6
)
 
—

 
—

Total Revenues
687.2

 
611.6

 
(411.6
)
 
—

 
887.2

OPERATING EXPENSES
 

 
 

 
 

 
 
 
 

Purchased gas and oil expense
50.1

 
605.4

 
(406.3
)
 
—

 
249.2

Lease operating expense
59.5

 
—

 
—

 
—

 
59.5

Gas, oil and NGL transportation and other handling costs
72.1

 
—

 
(4.6
)
 
—

 
67.5

Gathering and other expense
—

 
1.8

 
—

 
—

 
1.8

General and administrative
52.5

 
0.5

 
(0.7
)
 
—

 
52.3

Production and property taxes
53.1

 
0.4

 
—

 
—

 
53.5

Depreciation, depletion and amortization
232.3

 
2.9

 
—

 
—

 
235.2

Impairment and exploration expense
3.2

 
—

 
—

 
—

 
3.2

Total Operating Expenses
522.8

 
611.0

 
(411.6
)
 
—

 
722.2

Net gain (loss) from assets sales
(200.8
)
 
(0.1
)
 
—

 
—

 
(200.9
)
OPERATING INCOME (LOSS)
(36.4
)
 
0.5

 
—

 
—

 
(35.9
)
Realized and unrealized gains (losses) on derivative contracts
(85.3
)
 
(2.7
)
 
—

 
—

 
(88.0
)
Interest and other income
0.6

 
56.7

 
(56.5
)
 
—

 
0.8

Income from unconsolidated affiliates
0.1

 
—

 
—

 
—

 
0.1

Interest expense
(56.6
)
 
(44.9
)
 
56.5

 
—

 
(45.0
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(177.6
)
 
9.6

 
—

 
—

 
(168.0
)
Income tax (provision) benefit
67.2

 
(5.3
)
 
—

 
—

 
61.9

INCOME (LOSS) FROM CONTINUING OPERATIONS
(110.4
)
 
4.3

 
—

 
—

 
(106.1
)
Net income from discontinued operations, net of income tax
—

 
—

 
—

 
13.8

 
13.8

NET INCOME (LOSS)
$
(110.4
)
 
$
4.3

 
$
—

 
$
13.8

 
$
(92.3
)



24


The following table is a summary of operating results for the six months ended June 30, 2015 , by line of business:

 
QEP Energy
 
QEP Marketing
 and Other
 
Eliminations
 
QEP
Consolidated
 
(in millions)
REVENUES
 
 
 
 
 
 
 
From unaffiliated customers
$
761.2

 
$
339.0

 
$
—

 
$
1,100.2

From affiliated customers
—

 
455.6

 
(455.6
)
 
—

Total Revenues
761.2

 
794.6

 
(455.6
)
 
1,100.2

OPERATING EXPENSES
 

 
 

 
 

 
 

Purchased gas and oil expense
48.0

 
788.2

 
(449.6
)
 
386.6

Lease operating expense
118.9

 
—

 
—

 
118.9

Gas, oil and NGL transportation and other handling costs
142.9

 
—

 
(4.8
)
 
138.1

Gathering and other expense
—

 
3.1

 
—

 
3.1

General and administrative
96.2

 
3.7

 
(1.2
)
 
98.7

Production and property taxes
58.7

 
1.8

 
—

 
60.5

Depreciation, depletion and amortization
405.9

 
5.3

 
—

 
411.2

Impairment and exploration expense
22.4

 
—

 
—

 
22.4

Total Operating Expenses
893.0

 
802.1

 
(455.6
)
 
1,239.5

Net gain (loss) from asset sales
(1.3
)
 
(4.7
)
 
—

 
(6.0
)
OPERATING INCOME (LOSS)
(133.1
)
 
(12.2
)
 
—

 
(145.3
)
Realized and unrealized gains (losses) on derivative contracts
14.6

 
0.3

 
—

 
14.9

Interest and other income (expense)
(0.4
)
 
101.1

 
(99.5
)
 
1.2

Interest expense
(99.8
)
 
(72.7
)
 
99.5

 
(73.0
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(218.7
)
 
16.5

 
—

 
(202.2
)
Income tax (provision) benefit
76.0

 
(5.7
)
 
—

 
70.3

NET INCOME (LOSS)
$
(142.7
)
 
$
10.8

 
$
—

 
$
(131.9
)





25


The following table is a summary of operating results for the six months ended June 30, 2014 , by line of business:

 
QEP Energy
 
QEP Marketing
 and Other
 
Eliminations
 
Discontinued Operations
 
QEP
Consolidated
 
(in millions)
REVENUES
 
 
 
 
 
 
 
 
 
From unaffiliated customers
$
1,300.4

 
$
404.3

 
$
—

 
—

 
$
1,704.7

From affiliated customers
—

 
715.1

 
(715.1
)
 
—

 
$
—

Total Revenues
1,300.4

 
1,119.4

 
(715.1
)
 
—

 
1,704.7

OPERATING EXPENSES
 

 
 

 
 

 
 
 
 
Purchased gas and oil expense
88.1

 
1,103.3

 
(704.3
)
 
—

 
487.1

Lease operating expense
115.9

 
—

 
—

 
—

 
115.9

Gas, oil and NGL transportation and other handling costs
136.6

 
—

 
(9.2
)
 
—

 
127.4

Gathering and other expense
—

 
3.4

 
—

 
—

 
3.4

General and administrative
97.5

 
1.7

 
(1.6
)
 
—

 
97.6

Production and property taxes
100.5

 
0.9

 
—

 
—

 
101.4

Depreciation, depletion and amortization
455.7

 
5.4

 
—

 
—

 
461.1

Impairment and exploration expense
7.4

 
—

 
—

 
—

 
7.4

Total Operating Expenses
1,001.7

 
1,114.7

 
(715.1
)
 
—

 
1,401.3

Net gain (loss) from assets sales
(198.4
)
 
(0.1
)
 
—

 
—

 
(198.5
)
OPERATING INCOME (LOSS)
100.3

 
4.6

 
—

 
—

 
104.9

Realized and unrealized gains (losses) on derivative contracts
(163.8
)
 
(5.1
)
 
—

 
—

 
(168.9
)
Interest and other income
3.5

 
105.5

 
(105.3
)
 
—

 
3.7

Income from unconsolidated affiliates
0.1

 
—

 
—

 
—

 
0.1

Interest expense
(105.5
)
 
(86.7
)
 
105.3

 
—

 
(86.9
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(165.4
)
 
18.3

 
—

 
—

 
(147.1
)
Income tax (provision) benefit
60.1

 
(6.4
)
 
—

 
—

 
53.7

INCOME (LOSS) FROM CONTINUING OPERATIONS
(105.3
)
 
11.9

 
—

 
—

 
(93.4
)
Net income from discontinued operations, net of income tax
—

 
—

 
—

 
40.8

 
40.8

NET INCOME (LOSS)
$
(105.3
)
 
$
11.9

 
$
—

 
$
40.8

 
$
(52.6
)



26


Note 14 - Subsequent Events

On July 30, 2015, QEP Resources announced the closing of its regional office in Tulsa, Oklahoma.  Closing the Tulsa office will result in all of the Company’s technical and commercial teams being located at QEP’s headquarters in Denver, Colorado. Restructuring costs are estimated to be approximately $6.0 million to $10.0 million , the majority of which are expected to be incurred during the year ended December 31, 2015.  Although management believes this range of estimated cost is reasonable, actual results could differ depending on final results of the restructuring and potential lease termination costs.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP’s financial condition provided in its 2014 Annual Report on Form 10-K/A filing and analyzes the changes in the results of operations between the three and six months ended June 30, 2015 and 2014 . For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in QEP’s 2014 Annual Report on Form 10-K/A.

Our MD&A focuses on our continuing operations. Discontinued operations are excluded from our MD&A except as indicated otherwise.

OVERVIEW

QEP Resources, Inc. (QEP or the Company) is a holding company with two principal subsidiaries, QEP Energy Company and QEP Marketing Company, which are engaged in two primary lines of business: (i) oil and gas exploration and production (QEP Energy) and (ii) oil and gas marketing, operation of a gas gathering system and an underground gas storage facility and corporate (QEP Marketing and Other).

QEP's operations are focused in two geographic regions: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Strategies

We seek to create value for our shareholders through returns-focused growth, superior execution and a low-cost structure. To achieve these objectives we strive to:

•
operate in a safe and environmentally responsible manner;
•
allocate capital to those projects that generate the highest returns;
•
acquire businesses and assets that complement or expand our current business;
•
maintain a sustainable, diverse inventory of low-cost, high-margin resource plays;
•
be in the highest-potential areas of the resource plays in which we operate;
•
build contiguous acreage positions that drive operating efficiencies;
•
be the operator of our assets, whenever possible;
•
be the low-cost driller and producer in each area where we operate;
•
actively market our production to maximize value;
•
utilize derivative contracts to mitigate the impact of gas, oil or NGL price volatility and fluctuating interest rates and to lock in acceptable cash flows required to support future capital expenditures;
•
attract and retain the best people; and
•
maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

27



In response to the current commodity price environment, we are reducing drilling and completion activities, slowing production growth, and preserving liquidity. We have reduced QEP operated drilling rigs to eight rigs at the end of the second quarter of 2015 compared to a high of 21 during 2014. We have reduced our annual capital expenditure budget for 2015 to approximately $975.0 million from $2.7 billion in 2014 (which included $941.8 million for the Permian Basin Acquisition (defined below)). We are highly focused on driving improved operating performance by optimizi ng reservoir development, enhancing well completion designs and aggressively pursuing cost reductions.

On December 2, 2014, QEP completed the sale of its midstream business; see "Discontinued Operations" below. QEP believes this transaction represents a significant milestone in the strategic repositioning of the Company, as it will be better positioned to deliver continued growth by focusing on its exploration and production assets.

Discontinued Operations

In October 2014, the Company announced that its wholly owned subsidiary, QEP Field Services Company (QEP Field Services), had entered into a definitive agreement to sell substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP (Tesoro). On December 2, 2014, QEP closed the sale of its midstream business to Tesoro (Midstream Sale) for total cash proceeds of approximately $2.5 billion , including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014 . QEP Marketing retained ownership of the Haynesville Gathering System. As a result of the Midstream Sale, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as a discontinued operation on the Condensed Consolidated Statement of Operations and the Notes accompanying the Condensed Consolidated Financial Statements. For reporting purposes, the retained Haynesville Gathering System has been combined with QEP Marketing and Other.

Acquisitions

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million (the Permian Basin Acquisition). The acquired properties consisted of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and the remainder from QEP's revolving credit facility.

While QEP believes that it can grow production and reserves from its extensive inventory of identified drilling locations, the Company continues to evaluate acquisition opportunities that it believes will create significant long-term value. QEP believes that its experience, expertise, and presence in its core operating areas, combined with its low-cost operating model and financial strength, enhance its ability to pursue acquisition opportunities.

Divestitures

The Company periodically divests select non-core portfolio assets. In December 2014, QEP sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of approximately $96.3 million , subject to post-closing purchase price adjustments. In June 2014, QEP sold its interests in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of approximately $668.2 million , subject to post-closing purchase price adjustments. The Company used the proceeds to repay borrowings on its revolving credit facility incurred to fund the Permian Basin Acquisition.

Outlook

The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the Williston Basin, Permian Basin, Pinedale Anticline, Uinta Basin and Haynesville Shale. These resource plays are characterized by unconventional oil or gas accumulations in continuous tight sands or shales that underlie broad geographic areas. The lateral continuity of such resource plays means that aside from wells abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells as it develops these resource plays. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high-density, repeatable drilling and completion operations. The Company has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore United States that provide a solid base for growth in organic production and reserves.


28


In January 2014 , QEP's Board of Directors authorized the repurchase of up to  $500.0 million  of the Company's outstanding shares of common stock. This program was extended through December 2015 . The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. During the three and six months ended June 30, 2015 , no shares were repurchased under this plan.

Financial and Operating Results

QEP Energy reported total equivalent production of 80.9 Bcfe during the second quarter of 2015 and 156.1 Bcfe during the first half of 2015 , decrease s of 4% and 1% , respectively, compared to the same periods of 2014 . Gas production decrease d to 44.5 Bcf and 87.1 Bcf in the second quarter and first half of 2015 , respectively, decrease s of 8% and 6% from the second quarter and first half of 2014 , respectively. Additionally, NGL production decrease d to 1,198.0 Mbbls and 2,145.4 Mbbls in the second quarter and first half of 2015 , respectively, decrease s of 36% and 38% from the second quarter and first half of 2014 , respectively. These decreases were primarily driven by decreased production in the Midcontinent due to the divestitures of non-core properties during the second and fourth quarters of 2014. Additionally, Pinedale and Uinta NGL volumes decreased due to ethane rejection in the first half of 2015 compared to ethane recovery in the first half of 2014 . These decrease s were partially offset by an increase in oil production to 4,875.9 Mbbls in the second quarter of 2015 and 9,357.3 Mbbls during the first half of 2015 , increase s of 22% and 28% , respectively, compared to the same periods of 2014 . Continuing development of properties in the Williston Basin contributed oil production of 3,769.2 Mbbls and 7,200.7 Mbbls in the second quarter and first half of 2015 , respectively, compared to 2,831.5 Mbbls and 5,351.7 Mbbls in the second quarter and first half of 2014 , respectively. Additionally, QEP Energy completed the Permian Basin Acquisition on February 25, 2014, which contributed 628.1 Mbbls and 1,199.9 Mbbls of oil production in the second quarter and first half of 2015 , respectively, compared to 418.2 Mbbls and 558.2 Mbbls of oil production during the second quarter and first half of 2014 , respectively, due to development of the area and because production results included six months of production in 2015 compared to four months of production in 2014. Average realized prices (including the impact of settled commodity derivatives) decrease d 18% to $5.94 per Mcfe during the second quarter of 2015 and 20% to $5.79 during the first half of 2015 due primarily to decreases in gas, oil and NGL prices compared to the second quarter and first half of 2014 .

Factors Affecting Results of Operations

Oil, Gas, and NGL Prices
Changes in the market prices for gas, oil, and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties. Historically, field-level prices received for QEP's gas, oil and NGL production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic crude oil and natural gas supplies have grown dramatically, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing. These changes have allowed producers to extract increased quantities of hydrocarbons from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supplies, particularly in the eastern portion of the country, have resulted in downward pressure on U.S. natural gas prices and a high degree of pricing variability among different regional natural gas pricing hubs. High natural gas demand in 2014, driven primarily by unusually cold winter weather, resulted in improved natural gas prices in the first half of 2014, but continued growth in production, a more normal winter during 2014 and 2015, and adequate storage levels led to natural gas price declines later in the year and into 2015. Similarly, growth in U.S. oil production combined with global crude oil supplies that exceed global demand and other factors, such as a strong U.S. dollar, have led to a dramatic weakening of global oil prices starting in late 2014, which has continued into 2015. NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient export capacity. Prices of heavier NGL components, typically correlated to crude oil prices, have declined consistently with weakening oil prices, while ethane and propane prices have decreased as a result of growing North American oversupply. In addition, QEP's NGL prices are affected by ethane recovery and rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of an NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. QEP recovered ethane for the majority of 2014 but rejected ethane in the first half of 2015 and expects to continue to reject ethane throughout 2015 as gas processing economics do not support recovery of ethane from the natural gas stream.

During 2014, the NYMEX-WTI oil monthly average spot price ranged from a high of $105.79 per bbl in June 2014 to a low of $59.29 per bbl in December 2014, while the NYMEX-HH natural gas one-month future price ranged from a high of $5.15 per MMBtu in February 2014 to a low of $3.65 per MMBtu in November 2014. Prices continue to be volatile in 2015 as the NYMEX-WTI oil monthly average spot price fell to a low of $43.39 per bbl in March 2015 and the NYMEX-HH natural gas

29


one-month future price fell to a low of $2.49 per MMBtu in April 2015. Due to increased global economic uncertainty and the corresponding volatility of commodity prices, QEP has built a strong liquidity position to ensure financial flexibility and has reduced drilling and completion activity and decreased planned capital expenditures. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% of its forecasted annual production by the end of the first quarter of each fiscal year. At June 30, 2015 , assuming forecasted 2015 annual production of 306 Bcfe, QEP Energy had approximately 57% of its forecasted gas equivalent production for the remainder of 2015 covered with fixed-price swaps, including 65% of its forecasted gas production and 56% of its forecasted oil production. See Part 1, Item 3 “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk Management” for further details concerning QEP’s commodity derivatives transactions. QEP Energy has allocated approximately 96% of its forecasted 2015 drilling and completion capital expenditure budget to oil and liquids-rich gas projects in its portfolio.

Global Geopolitical and Macroeconomic Factors
QEP continues to monitor the global economy, including Europe's economic outlook; political unrest in Eastern Europe, the Middle East, and Africa; slowing growth in Asia, particularly in China; the United States' federal budget deficit; changes in regulatory oversight policy; commodity price volatility; the potential impact of rising interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on gas, oil and NGL supply, demand and prices, the Company's ability to continue its planned drilling programs on federal and Native American lands, and could materially impact the Company's financial position, results of operations and cash flow from operations.

Supply, Demand and Other Market Risk Factors
During the last five years, the U.S. natural gas directed drilling rig count has decreased as producers reduced drilling activity for dry natural gas in response to lower natural gas prices and directed investment toward oil and liquid-rich projects. Over the same period of time, U.S. natural gas production has continued to grow, particularly in the Marcellus Shale region, as efficiency gains have allowed more wells to be drilled and completed per operating rig, higher per-well natural gas production from horizontal wells as a result of investment focused on more prolific resources, and increased amounts of natural gas produced in association with crude oil. As a result, U.S. natural gas production continued to increase into 2015, despite the gradually decreasing rig-count. Strong natural gas demand from electric power generation, cold winter weather during the 2013-2014 heating season, and other demand sources caused a general firming of natural gas prices during the second half of 2013 and into 2014. Natural gas prices weakened in the second half of 2014 and through the first half of 2015 due to more typical winter season demand levels and continued increases in supply. QEP expects U.S. natural gas prices to remain range-bound over the near term. Relatively low natural gas prices in recent years have caused U.S. E&P companies, including QEP, to shift capital investments away from predominantly dry gas areas toward plays that produce crude oil, condensate and liquids-rich gas. This shift in focus has caused domestic NGL production to increase dramatically. Increased NGL production and price dislocations from infrastructure bottlenecks in certain regions have all contributed to a weakening of domestic NGL prices, particularly ethane and, more recently, propane. QEP expects that ethane prices will continue to be range-bound until new ethylene crackers and export facilities are built. Propane prices have declined as a result of abnormally high inventory levels. An increase in exports and typical seasonal demand is expected to draw down propane inventories to more normal levels over the coming year. The prices of heavier components of the NGL barrel have weakened as a result of the decline in crude oil prices.

Increased oil production in the U.S. combined with various other factors has led to weaker oil prices. According to data from the Energy Information Agency, U.S. oil production has increased by more than four million barrels per day, or more than 70%, since 2011. International oil supply disruptions in recent years have prevented oversupply and a corresponding negative price impact, but reduced supply disruptions over the last year combined with softening global demand, a stronger U.S. dollar, and other factors have led to substantially lower oil prices starting in late 2014 that have continued into 2015. As a result, many oil producers around the world are dramatically reducing activity. QEP anticipates global oil prices will improve in the coming years as supply growth moderates due to lower level of investment and modest demand increases. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices. In addition, transportation, refining, or other infrastructure constraints could introduce significant price differentials between regional markets where QEP sells its production and national (NYMEX HH at Henry Hub or NYMEX WTI at Cushing) and global (ICE Brent) markets. Because of the global and regional price volatility and the uncertainty around the natural gas, oil and NGL price environments, QEP continues to manage its capital spending program and liquidity accordingly and has scaled back its capital expenditure budget and drilling and completion activities for 2015.


30


Potential for Future Asset Impairments
The carrying value of the Company's properties is sensitive to declines in gas, oil and NGL prices. These assets are at risk of impairment if future prices for gas, oil or NGL prices decline and/or drilling and completion costs increase. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management's estimates of future oil, gas and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward gas, oil or NGL prices alone could result in an impairment of properties. During the year ended December 31, 2014, the Company recorded impairments of $1.1 billion primarily due to impairments of proved property in the Southern Region associated with lower future prices as of December 31, 2014. Additionally, the Company recorded $20.5 million of impairment expense during the first half of 2015 , of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. If commodity prices decline further during 2015, there could be additional impairment charges to our oil and gas assets or other investments.

Multi-Well Pad Drilling
To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. In certain of our producing areas, wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the commencement of production, which may cause volatility in QEP’s quarterly operating results. 

Critical Accounting Estimates
QEP’s significant accounting policies are described in Item 8 of Part II of its 2014 Annual Report on Form 10-K/A. The Company’s Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company’s Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP’s accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of oil and gas properties, asset retirement obligations, accounting for derivative contracts, revenue recognition, environmental obligations, litigation and other contingencies, benefit plan obligations, share-based compensation, income taxes, and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

RESULTS OF OPERATIONS

Our financial results for 2014 and for prior periods have been revised, in accordance with GAAP, to reflect the impact of the Midstream Sale. See Note 4 - Discontinued Operations, in Item I of Part I of this Quarterly Report on Form 10-Q for detailed information on the Midstream Sale.

Net Income

QEP generated a net loss from continuing operations during the second quarter of 2015 of $76.3 million , or $0.43 per diluted share, compared to a net loss from continuing operations of $106.1 million , or $0.59 per diluted share, in the second quarter of 2014 . The change in the second quarter of 2015 compared to the second quarter of 2014 was due to a $27.0 million decrease in QEP Energy’s net loss and a $2.8 million increase in QEP Marketing and Other's net income. QEP Energy's net loss decrease was primarily due to a $200.8 million net loss from asset sales in the second quarter of 2014 compared to a $26.5 million net gain from asset sales in the second quarter of 2015 . Additionally, QEP recognized realized derivative instrument gains in the second quarter of 2015 compared to realized losses in the second quarter of 2014 , as well as increased oil production and lower operating expenses in the second quarter of 2015 compared to the second quarter of 2014 . These increases were partially offset by decreases in average field-level prices for gas, oil and NGL, decreased gas and NGL production and larger unrealized derivative losses. QEP Marketing and Other's net income increase d in the second quarter of 2015 primarily due to a lower interest expense in the second quarter of 2015 compared to the second quarter of 2014 due to lower average debt levels, partially offset by a net loss from asset sales of $2.0 million in the second quarter of 2015 related to purchase price adjustments for the Midstream Sale and a lower resale margin in the second quarter of 2015 compared to the second quarter of 2014 .


31


QEP generated a net loss from continuing operations during the first half of 2015 of $131.9 million , or $0.75 per diluted share, compared to a net loss from continuing operations of $93.4 million , or $0.52 per diluted share, in the first half of 2014 . The change in the first half of 2015 compared to the first half of 2014 was due to a $37.4 million increase in QEP Energy’s net loss and a $1.1 million decrease in QEP Marketing and Other's net income. QEP Energy's net loss increase was primarily due to decreases in average field-level prices for gas, oil and NGL and decreased gas and NGL production. These decreases were partially offset by realized derivative instrument gains in the first half of 2015 compared to realized losses in the first half of 2014 , a $198.4 million net loss from asset sales in the first half of 2014 compared to a net loss from asset sales of $1.3 million in the first half of 2015 , as well as increased oil production and lower operating expenses in the first half of 2015 compared to the first half of 2014 . QEP Marketing and Other's net income decreased in the first half of 2015 primarily due to a lower resale margin and a net loss from asset sales of $4.7 million during the first half of 2015 related to purchase price adjustments for the Midstream Sale, partially offset by lower interest expense due to lower average debt levels during the first half of 2015 .

The following table provides a summary of net income (loss) by line of business:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
 
(in millions, except per share amounts)
QEP Energy
$
(83.4
)
 
$
(110.4
)
 
$
27.0

 
$
(142.7
)
 
$
(105.3
)
 
$
(37.4
)
QEP Marketing and Other
7.1

 
4.3

 
2.8

 
10.8

 
11.9

 
(1.1
)
Net income (loss) from continuing operations
(76.3
)
 
(106.1
)
 
29.8

 
(131.9
)
 
(93.4
)
 
(38.5
)
Net income from discontinued operations, net of income tax
—

 
13.8

 
(13.8
)
 
—

 
40.8

 
(40.8
)
Net income (loss)
$
(76.3
)

$
(92.3
)

$
16.0


$
(131.9
)

$
(52.6
)

$
(79.3
)
Diluted earnings per share from continuing operations
$
(0.43
)
 
$
(0.59
)
 
$
0.16

 
$
(0.75
)
 
$
(0.52
)
 
$
(0.23
)
Diluted earnings per share from discontinued operations
—

 
0.08

 
(0.08
)
 
—

 
0.23

 
(0.23
)
Diluted earnings per share
$
(0.43
)
 
$
(0.51
)
 
$
0.08

 
$
(0.75
)
 
$
(0.29
)
 
$
(0.46
)
Average diluted shares
176.7

 
180.1

 
(3.4
)
 
176.4

 
179.9

 
(3.5
)
 
Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company's financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. 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 non-cash and/or non-recurring items.

The following table provides a summary of Adjusted EBITDA by line of business:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
 
(in millions)
QEP Energy
$
280.9

 
$
366.5

 
$
(85.6
)
 
$
502.0

 
$
695.1

 
$
(193.1
)
QEP Marketing and Other
(1.5
)
 
1.7

 
(3.2
)
 
0.2

 
6.2

 
(6.0
)
Adjusted EBITDA from continuing operations
279.4

 
368.2

 
(88.8
)
 
502.2

 
701.3

 
(199.1
)
Adjusted EBITDA from discontinued operations
—

 
32.6

 
(32.6
)
 
—
 
85.8

 
(85.8
)
Adjusted EBITDA
$
279.4


$
400.8


$
(121.4
)

$
502.2


$
787.1


$
(284.9
)
 
Adjusted EBITDA from continuing operations decrease d to $279.4 million in the second quarter of 2015 from $368.2 million in the second quarter of 2014 , due to a 37% decrease in the average equivalent field-level price as well as an 8% decrease in gas production and a 36% decrease in NGL production, partially offset by a 22% increase in oil production and higher realized gains on derivative contracts.

Adjusted EBITDA from continuing operations decrease d to $502.2 million in the first half of 2015 from $701.3 million in the first half of 2014 , due to a 41% decrease in the average equivalent field-level price as well as a 6% decrease in gas production

32


and a 38% decrease in NGL production, partially offset by a 28% increase in oil production and higher realized gains on derivative contracts.

The following tables are reconciliations of Adjusted EBITDA to net income, the most comparable GAAP financial measures:
 
QEP Energy
 
QEP Marketing and Other (1)
 
Continuing Operations
 
Discontinued Operations
 
QEP Consolidated
Three Months Ended June 30, 2015
(in millions)
Net income (loss)
$
(83.4
)
 
$
7.1

 
$
(76.3
)
 
$
—

 
$
(76.3
)
Unrealized (gains) losses on derivative contracts
158.2

 
0.1

 
158.3

 
—

 
158.3

Net (gain) loss from asset sales
(26.5
)
 
2.0

 
(24.5
)
 
—

 
(24.5
)
Interest and other (income) expense
(3.1
)
 
(0.7
)
 
(3.8
)
 
—

 
(3.8
)
Income tax provision (benefit)
(42.4
)
 
3.6

 
(38.8
)
 
—

 
(38.8
)
Interest expense (income)
52.6

 
(16.4
)
 
36.2

 
—

 
36.2

Pension curtailment loss (2)
11.0

 
0.2

 
11.2

 
—

 
11.2

Depreciation, depletion and amortization
213.2

 
2.6

 
215.8

 
—

 
215.8

Impairment
0.5

 
—

 
0.5

 
—

 
0.5

Exploration expenses
0.8

 
—

 
0.8

 
—

 
0.8

Adjusted EBITDA
$
280.9

 
$
(1.5
)
 
$
279.4

 
$
—


$
279.4

 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(110.4
)
 
$
4.3

 
$
(106.1
)
 
13.8

 
$
(92.3
)
Unrealized (gains) losses on derivative contracts
51.8

 
0.9

 
52.7

 
—

 
52.7

Net (gain) loss from asset sales
200.8

 
0.1

 
200.9

 
0.1

 
201.0

Interest and other (income) expense
(0.6
)
 
(0.2
)
 
(0.8
)
 
—

 
(0.8
)
Income tax provision (benefit)
(67.2
)
 
5.3

 
(61.9
)
 
7.7

 
(54.2
)
Interest expense (income) (3)
56.6

 
(11.6
)
 
45.0

 
0.5

 
45.5

Depreciation, depletion and amortization (4)
232.3

 
2.9

 
235.2

 
10.5

 
245.7

Impairment
1.5

 
—

 
1.5

 
—

 
1.5

Exploration expenses
1.7

 
—

 
1.7

 
—

 
1.7

Adjusted EBITDA
$
366.5

 
$
1.7

 
$
368.2

 
$
32.6

 
$
400.8

 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015

 
 
 
 
Net income (loss)
$
(142.7
)
 
$
10.8

 
$
(131.9
)
 
$
—

 
$
(131.9
)
Unrealized (gains) losses on derivative contracts
179.9

 
1.9

 
181.8

 
—

 
181.8

Net loss from asset sales
1.3

 
4.7

 
6.0

 
—

 
6.0

Interest and other (income) expense
0.4

 
(1.6
)
 
(1.2
)
 
—

 
(1.2
)
Income tax provision (benefit)
(76.0
)
 
5.7

 
(70.3
)
 
—

 
(70.3
)
Interest expense (income)
99.8

 
(26.8
)
 
73.0

 
—

 
73.0

Pension curtailment loss (2)
11.0

 
0.2

 
11.2

 
—

 
11.2

Depreciation, depletion and amortization
405.9

 
5.3

 
411.2

 
—

 
411.2

Impairment
20.5

 
—

 
20.5

 
—

 
20.5

Exploration expenses
1.9

 
—

 
1.9

 
—

 
1.9

Adjusted EBITDA
$
502.0

 
$
0.2

 
$
502.2

 
$
—

 
$
502.2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

33


 
QEP Energy
 
QEP Marketing and Other (1)
 
Continuing Operations
 
Discontinued Operations
 
QEP Consolidated
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(105.3
)
 
$
11.9

 
$
(93.4
)
 
40.8

 
$
(52.6
)
Unrealized (gains) losses on derivative contracts
97.0

 
1.2

 
98.2

 
—

 
98.2

Net (gain) loss from asset sales
198.4

 
0.1

 
198.5

 
0.1

 
198.6

Interest and other (income) expense
(3.5
)
 
(0.2
)
 
(3.7
)
 
—

 
(3.7
)
Income tax provision (benefit)
(60.1
)
 
6.4

 
(53.7
)
 
22.9

 
(30.8
)
Interest expense (income) (3)
105.5

 
(18.6
)
 
86.9

 
0.9

 
87.8

Depreciation, depletion and amortization (4)
455.7

 
5.4

 
461.1

 
21.1

 
482.2

Impairment
3.5

 
—

 
3.5

 
—

 
3.5

Exploration expenses
3.9

 
—

 
3.9

 
—

 
3.9

Adjusted EBITDA
$
695.1

 
$
6.2

 
$
701.3

 
$
85.8

 
$
787.1

____________________________
(1)  
Includes intercompany eliminations.
(2)  
The pension curtailment loss is a non-cash loss that was incurred during the three and six months ended June 30, 2015, due to changes in the Company's pension plan (see Note 12 - Employee Benefits for additional information). The Company believes that the pension curtailment loss does not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the loss from the calculation of Adjusted EBITDA.
(3)  
Excludes noncontrolling interest's share of $0.2 million and $0.4 million during the three and six months ended June 30, 2014 , respectively, of interest expense attributable to QEP Midstream.
(4)  
Excludes noncontrolling interest's share of $4.0 million and $7.7 million during the three and six months ended June 30, 2014 , respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

34


QEP ENERGY
The following table provides a summary of QEP Energy’s financial and operating results :
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
REVENUES
(in millions)
Gas sales
$
112.0

 
$
215.1

 
$
(103.1
)
 
$
234.0

 
$
437.6

 
$
(203.6
)
Oil sales
250.3

 
358.5

 
(108.2
)
 
429.1

 
647.2

 
(218.1
)
NGL sales
26.0

 
64.8

 
(38.8
)
 
45.0

 
127.9

 
(82.9
)
Purchased gas sales
16.3

 
49.8

 
(33.5
)
 
47.8

 
86.9

 
(39.1
)
Other
3.3

 
(1.0
)
 
4.3

 
5.3

 
0.8

 
4.5

Total Revenues
407.9

 
687.2

 
(279.3
)
 
761.2

 
1,300.4

 
(539.2
)
OPERATING EXPENSES
 

 
 

 
 

 
 

 
 

 
 

Purchased gas expense
16.8

 
50.1

 
(33.3
)
 
48.0

 
88.1

 
(40.1
)
Lease operating expense
57.1

 
59.5

 
(2.4
)
 
118.9

 
115.9

 
3.0

Gas, oil and NGL transportation and other handling costs
75.5

 
72.1

 
3.4

 
142.9

 
136.6

 
6.3

General and administrative
50.0

 
52.5

 
(2.5
)
 
96.2

 
97.5

 
(1.3
)
Production and property taxes
31.2

 
53.1

 
(21.9
)
 
58.7

 
100.5

 
(41.8
)
Depreciation, depletion and amortization
213.2

 
232.3

 
(19.1
)
 
405.9

 
455.7

 
(49.8
)
Exploration expenses
0.8

 
1.7

 
(0.9
)
 
1.9

 
3.9

 
(2.0
)
Impairment
0.5

 
1.5

 
(1.0
)
 
20.5

 
3.5

 
17.0

Total Operating Expenses
445.1

 
522.8

 
(77.7
)
 
893.0

 
1,001.7

 
(108.7
)
Net gain (loss) from asset sales
26.5

 
(200.8
)
 
227.3

 
(1.3
)
 
(198.4
)
 
197.1

OPERATING INCOME (LOSS)
(10.7
)
 
(36.4
)
 
25.7

 
(133.1
)
 
100.3

 
(233.4
)
Realized gains (losses) on derivative instruments
92.6

 
(33.5
)
 
126.1

 
194.5

 
(66.8
)
 
261.3

Unrealized gains (losses) on derivative instruments
(158.2
)
 
(51.8
)
 
(106.4
)
 
(179.9
)
 
(97.0
)
 
(82.9
)
Interest and other income (expense)
3.1

 
0.6

 
2.5

 
(0.4
)
 
3.5

 
(3.9
)
Income from unconsolidated affiliates
—

 
0.1

 
(0.1
)
 
—

 
0.1

 
(0.1
)
Interest expense
(52.6
)
 
(56.6
)
 
4.0

 
(99.8
)
 
(105.5
)
 
5.7

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(125.8
)
 
(177.6
)
 
51.8

 
(218.7
)
 
(165.4
)
 
(53.3
)
Income tax (provision) benefit
42.4

 
67.2

 
(24.8
)
 
76.0

 
60.1

 
15.9

NET INCOME (LOSS)
$
(83.4
)
 
$
(110.4
)
 
$
27.0

 
$
(142.7
)
 
$
(105.3
)
 
$
(37.4
)
 
 
 
 
 
 
 
 
 
 
 
 
Production volumes (Bcfe)
 
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
Pinedale
24.9

 
25.3

 
(0.4
)
 
46.7

 
46.2

 
0.5

Williston Basin
28.6

 
19.4

 
9.2

 
54.0

 
36.2

 
17.8

Uinta Basin
7.3

 
6.8

 
0.5

 
14.2

 
13.0

 
1.2

Other Northern
2.4

 
3.5

 
(1.1
)
 
5.1

 
6.0

 
(0.9
)
Southern Region
 

 
 

 
 
 
 

 
 

 
 
Haynesville/Cotton Valley
10.4

 
13.1

 
(2.7
)
 
22.1

 
27.5

 
(5.4
)
Permian Basin
6.2

 
4.2

 
2.0

 
11.1


5.4

 
5.7

Midcontinent
1.1

 
11.6

 
(10.5
)
 
2.9

 
23.3

 
(20.4
)
Total production
80.9

 
83.9

 
(3.0
)
 
156.1

 
157.6

 
(1.5
)
Total equivalent prices (per Mcfe)
 
 

 
 

 
 

Average equivalent field-level price
$
4.80

 
$
7.62

 
$
(2.82
)
 
$
4.54

 
$
7.70

 
$
(3.16
)
Commodity derivative impact
1.14

 
(0.40
)
 
1.54

 
1.25

 
(0.42
)
 
1.67

Net realized equivalent price
$
5.94

 
$
7.22

 
$
(1.28
)
 
$
5.79

 
$
7.28

 
$
(1.49
)


35


Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP Energy’s major revenue categories for the three and six months ended June 30, 2015 , compared to the three and six months ended June 30, 2014 :
 
Gas
 
Oil
 
NGL
 
Total
 
(in millions)
QEP Energy Production Revenues
 
 
 
 
 
 
 
Three months ended June 30, 2014 Revenues
$
215.1

 
$
358.5

 
$
64.8

 
$
638.4

Changes associated with volumes (1)
(18.0
)
 
80.6

 
(23.6
)
 
39.0

Changes associated with prices (2)
(85.1
)
 
(188.8
)
 
(15.2
)
 
(289.1
)
Three months ended June 30, 2015 Revenues
$
112.0

 
$
250.3

 
$
26.0

 
$
388.3

 
 
 
 
 
 
 
 
QEP Energy Production Revenues


 


 


 
 

Six months ended June 30, 2014 Revenues
$
437.6

 
$
647.2

 
$
127.9

 
$
1,212.7

Changes associated with volumes (1)
(28.4
)
 
183.2

 
(48.5
)
 
106.3

Changes associated with prices (2)
(175.2
)
 
(401.3
)
 
(34.4
)
 
(610.9
)
Six months ended June 30, 2015 Revenues
$
234.0

 
$
429.1

 
$
45.0

 
$
708.1

  ____________________________
(1)  
The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2015 , as compared to the three and six months ended June 30, 2014 , by the average field-level price for the three and six months ended June 30, 2014 .
(2)  
The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and six months ended June 30, 2015 , as compared to the three and six months ended June 30, 2014 , by volumes for the three and six months ended June 30, 2015 . Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

Gas Volumes and Prices
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015

2014
 
Change
 
2015
 
2014
 
Change
Gas production volumes (Bcf)
 
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
Pinedale
21.5

 
19.1

 
2.4

 
40.5

 
35.0

 
5.5

Williston Basin
3.0

 
1.2

 
1.8

 
5.7

 
1.9

 
3.8

Uinta Basin
5.7

 
4.3

 
1.4

 
10.6

 
8.4

 
2.2

Other Northern
2.1

 
2.9

 
(0.8
)
 
4.5

 
5.1

 
(0.6
)
Southern Region
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley
10.3

 
13.0

 
(2.7
)
 
21.9

 
27.3

 
(5.4
)
Permian Basin
1.2

 
0.9

 
0.3

 
1.9

 
1.1

 
0.8

Midcontinent
0.7

 
7.2

 
(6.5
)
 
2.0

 
14.3

 
(12.3
)
Total production
44.5

 
48.6

 
(4.1
)
 
87.1

 
93.1

 
(6.0
)
Gas prices (per Mcf)
 
 

 
 

 
 

Northern Region
$
2.49

 
$
4.44

 
$
(1.95
)
 
$
2.66

 
$
4.75

 
$
(2.09
)
Southern Region
2.59

 
4.40

 
(1.81
)
 
2.75

 
4.65

 
(1.90
)
Average field-level price
$
2.52

 
$
4.42

 
$
(1.90
)
 
$
2.69

 
$
4.70

 
$
(2.01
)
Commodity derivative impact
0.63

 
(0.17
)
 
0.80

 
0.53

 
(0.31
)
 
0.84

Net realized price
$
3.15

 
$
4.25

 
$
(1.10
)
 
$
3.22

 
$
4.39

 
$
(1.17
)

Gas revenues decreased $103.1 million , or 48% , in the second quarter of 2015 when compared to the second quarter of 2014 due to lower field-level prices and lower gas production. Average field-level gas prices decreased 43% in the second quarter of 2015 compared to the second quarter of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The decrease in production was primarily driven by the divestitures of non-core Midcontinent properties in

36


the second and fourth quarters of 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program. These production decreases were partially offset by production increases in Pinedale due to additional 2014 net well completions in which QEP had higher net revenue interest, in the Williston Basin due to continued development and in the Uinta Basin due to higher performing well completions.

Gas revenues decreased $203.6 million , or 47% , in the first half of 2015 when compared to the first half of 2014 due to lower field-level prices and lower gas production. Average field-level gas prices decreased 43% in the first half of 2015 compared to the first half of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The decrease in production was primarily driven by the divestitures of non-core Midcontinent properties in the second and fourth quarters of 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program. These production decreases were partially offset by production increases in Pinedale due to additional 2014 net well completions in which QEP had higher net revenue interest, in the Williston Basin due to continued development, and in the Uinta Basin due to higher performing well completions.

Oil Volumes and Prices
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Oil production volumes (Mbbls)
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
Pinedale
176.0

 
159.7

 
16.3

 
321.5

 
292.8

 
28.7

Williston Basin
3,769.2

 
2,831.5

 
937.7

 
7,200.7

 
5,351.7

 
1,849.0

Uinta Basin
202.0

 
229.9

 
(27.9
)
 
423.6

 
442.3

 
(18.7
)
Other Northern
44.3

 
92.0

 
(47.7
)
 
89.4

 
141.1

 
(51.7
)
Southern Region
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley
8.9

 
11.4

 
(2.5
)
 
16.7

 
20.6

 
(3.9
)
Permian Basin
628.1

 
418.2

 
209.9

 
1,199.9

 
558.2

 
641.7

Midcontinent
47.4

 
237.9

 
(190.5
)
 
105.5

 
485.9

 
(380.4
)
Total production
4,875.9

 
3,980.6

 
895.3

 
9,357.3

 
7,292.6

 
2,064.7

Oil prices (per bbl)
 
 

 
 

 
 

Northern Region
$
50.60

 
$
88.93

 
$
(38.33
)
 
$
44.93

 
$
87.81

 
$
(42.88
)
Southern Region
55.85

 
95.68

 
(39.83
)
 
51.47

 
94.23

 
(42.76
)
Average field-level price
$
51.34

 
$
90.06

 
$
(38.72
)
 
$
45.86

 
$
88.74

 
$
(42.88
)
Commodity derivative impact
13.24

 
(6.29
)
 
19.53

 
15.88

 
(5.21
)
 
21.09

Net realized price
$
64.58

 
$
83.77

 
$
(19.19
)
 
$
61.74

 
$
83.53

 
$
(21.79
)
 
Oil revenues decreased $108.2 million , or 30% , in the second quarter of 2015 when compared to the second quarter of 2014 , due to lower average field-level prices partially offset by higher volumes. Average field-level oil prices decreased 43% in the second quarter of 2015 compared to the second quarter of 2014 driven by a substantial decrease in average NYMEX-WTI and ICE Brent oil prices between the comparable periods. The increase in production volumes was primarily driven by increase s in the Williston and Permian basins due to continued development drilling and well completions. These production increases were partially offset by a production decrease in the Midcontinent due to the divestitures of non-core properties in the second and fourth quarters of 2014.

Oil revenues decreased $218.1 million , or 34% , in the first half of 2015 when compared to the first half of 2014 , due to lower average field-level prices partially offset by higher volumes. Average field-level oil prices decreased 48% in the first half of 2015 compared to the first half of 2014 , driven by a substantial decrease in average NYMEX-WTI and ICE Brent oil prices between the comparable periods. The increase in production volumes was primarily driven by an increase in the Williston Basin due to continued development drilling and well completions. The Company also had an increase in production of 641.7 Mbbls from the Permian Basin due to development of the area combined with six months of production in 2015 compared to four months of production in 2014. These production increases were partially offset by a production decrease in the Midcontinent due to the divestitures of non-core properties in the second and fourth quarters of 2014.


37


NGL Volumes and Prices
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
NGL production volumes (Mbbls)
 
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
Pinedale
403.8

 
854.0

 
(450.2
)
 
716.8

 
1,568.8

 
(852.0
)
Williston Basin
482.8

 
204.4

 
278.4

 
841.6

 
365.3

 
476.3

Uinta Basin
70.3

 
177.4

 
(107.1
)
 
179.7

 
316.8

 
(137.1
)
Other Northern
6.5

 
3.3

 
3.2

 
9.2

 
5.3

 
3.9

Southern Region
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley
6.8

 
11.0

 
(4.2
)
 
13.9

 
18.8

 
(4.9
)
Permian Basin
209.0

 
130.4

 
78.6

 
328.8

 
163.4

 
165.4

Midcontinent
18.8

 
505.5

 
(486.7
)
 
55.4

 
1,015.9

 
(960.5
)
Total production
1,198.0

 
1,886.0

 
(688.0
)
 
2,145.4

 
3,454.3

 
(1,308.9
)
NGL prices (per bbl)
 
 

 
 

 
 

Northern Region
$
23.41

 
$
35.55

 
$
(12.14
)
 
$
22.44

 
$
37.44

 
$
(15.00
)
Southern Region
14.59

 
32.02

 
(17.43
)
 
14.57

 
36.26

 
(21.69
)
Average field-level price
21.68

 
34.34

 
(12.66
)
 
$
20.98

 
$
37.03

 
$
(16.05
)
Commodity derivative impact
—

 
—

 
—

 
—

 
—

 
—

Net realized price
$
21.68

 
$
34.34

 
$
(12.66
)
 
$
20.98

 
$
37.03

 
$
(16.05
)
 
NGL revenues decreased $38.8 million , or 60% , during the second quarter of 2015 when compared to the second quarter of 2014 due to decrease d production volumes and a decrease d average price per barrel. Midcontinent NGL volumes decrease d due to divestitures of non-core properties in the second and fourth quarters of 2014. Additionally, Pinedale and Uinta Basin NGL volumes decreased primarily due to ethane rejection in the second quarter of 2015 compared to ethane recovery in the second quarter of 2014 . These decreases were partially offset by increases in NGL volumes in the Williston and Permian basins as a result of increased development drilling and well completions. NGL prices decrease d 37% during the second quarter of 2015 compared to the second quarter of 2014 driven by a significant decrease in the pricing of the NGL components, particularly the heavier components, which have weakened as a result of the decline in crude oil prices.

NGL revenues decreased $82.9 million , or 65% , during the first half of 2015 when compared to the first half of 2014 due to decrease d production volumes and a decrease d average price per barrel. Midcontinent NGL volumes decrease d due to divestitures of non-core properties in the second and fourth quarters of 2014. Additionally, Pinedale and Uinta Basin NGL volumes decreased primarily due to ethane rejection in the first half of 2015 compared to ethane recovery in the first half of 2014 . These decreases were partially offset by increases in NGL volumes in the Williston and Permian basins as a result of increased development drilling and well completions combined with six months of production from the Permian Basin in 2015 compared to four months of production in 2014. NGL prices decrease d 43% during the first half of 2015 compared to the first half of 2014 driven by a significant in the pricing of the NGL components, particularly the heavier components, which have weakened as a result of the decline in crude oil prices.

QEP Energy Resale Margin

QEP Energy purchases and resells gas in order to fulfill firm transportation contract commitments to partially mitigate losses on unutilized capacity. The difference between the price of the products purchased and sold, net of transportation costs, creates a resale margin that represents a gain or loss for the Company. The following table is a summary of QEP Energy's financial results from its gas resale activities:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Resale Margin
(in millions)
Purchased gas sales
$
16.3

 
$
49.8

 
$
(33.5
)
 
$
47.8

 
$
86.9

 
$
(39.1
)
Purchased gas expense
(16.8
)
 
(50.1
)
 
33.3

 
(48.0
)
 
(88.1
)
 
40.1

Resale margin
$
(0.5
)
 
$
(0.3
)
 
$
(0.2
)
 
$
(0.2
)
 
$
(1.2
)
 
$
1.0


38



During the second quarter of 2015 , QEP Energy recorded a loss on resale margin of $0.5 million compared to a loss of $0.3 million in the second quarter of 2014 . During the first half of 2015 , QEP Energy recorded a loss on resale margin of $0.2 million compared to a loss of $1.2 million in the first half of 2014 . These losses were the result of its activities to utilize pipeline transportation commitments in Louisiana.

QEP Energy Drilling Activity

The following table presents operated and non-operated well completions for the three and six months ended June 30, 2015 :
 
Operated Completions
 
Non-operated Completions
 
Three Months Ended
 
Six Months Ended
 
Three Months Ended
 
Six Months Ended
 
June 30, 2015
 
June 30, 2015
 
June 30, 2015
 
June 30, 2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale (1)
35

 
21.3

 
55

 
35.8

 
—

 
—

 
—

 
—

Williston Basin
20

 
14.4

 
36

 
27.2

 
11

 
1.0

 
33

 
2.7

Uinta Basin
8

 
8.0

 
9

 
9.0

 
4

 
—

 
17

 
0.1

Other Northern
—

 
—

 
1

 
1.0

 
—

 
—

 
—

 
—

Southern Region
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley
—

 
—

 
—

 
—

 
4

 
1.1

 
13

 
1.5

Permian Basin (2)
13

 
10.4

 
24

 
20.5

 
—

 
—

 
1

 
0.3

Midcontinent
—

 
—

 
—

 
—

 
1

 
—

 
4

 
0.1

  ____________________________
(1)  
Gross completions include seven wells for the three months ended June 30, 2015, and eight wells for the six months ended June 30, 2015, in which QEP only owns a small overriding royalty interest.
(2)  
Operated completions includes one gross, one net, vertical well for the three months ended June 30, 2015, and eight gross, 7.4 net, vertical wells for the six months ended June 30, 2015.

The following table presents operated and non-operated wells drilling or waiting on completion at June 30, 2015 :
 
Operated
 
Non-operated
 
Drilling
 
Waiting on completion
 
Drilling
 
Waiting on completion
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
25

 
17.7

 
34

 
21.5

 
—

 
—

 
—

 
—

Williston Basin
3

 
3.0

 
34

 
29.1

 
—

 
—

 
44

 
1.8

Uinta Basin
1

 
1.0

 
—

 
—

 
—

 
—

 
1

 
0.1

Other Northern
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Southern Region
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley
—

 
—

 
—

 
—

 
2

 
0.4

 
8

 
0.7

Permian Basin
4

 
3.8

 
1

 
0.9

 
—

 
—

 
1

 
0.6

Midcontinent
—

 
—

 
—

 
—

 
—

 
—

 
4

 
0.3


The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Each gross well completed in more than one producing zone is counted as a single well. QEP utilizes multi-well pad drilling where practical. In certain of our producing areas, wells drilled are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. As a result, QEP had 69 gross operated wells waiting on completion as of June 30, 2015 .

39



Operating expenses

The following table presents certain QEP Energy operating expenses on a per unit of production basis:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
 
(per Mcfe)
Depreciation, depletion and amortization
$
2.64

 
$
2.77

 
$
(0.13
)
 
$
2.60

 
$
2.89

 
$
(0.29
)
Lease operating expense
0.71

 
0.71

 
—

 
0.76

 
0.74

 
0.02

Gas, oil and NGL transportation and other handling costs
0.93

 
0.86

 
0.07

 
0.91

 
0.87

 
0.04

Production and property taxes
0.38

 
0.63

 
(0.25
)
 
0.38

 
0.64

 
(0.26
)
Operating Expenses
$
4.66

 
$
4.97

 
$
(0.31
)
 
$
4.65

 
$
5.14

 
$
(0.49
)
 
Depreciation, depletion and amortization (DD&A). DD&A expense decrease d $19.1 million , or $0.13 per Mcfe, in the second quarter of 2015 compared to the second quarter of 2014 , due to decreases in the Haynesville/Cotton Valley and Midcontinent, partially offset by an increase in the Williston Basin. The decrease in the Midcontinent was a result of the second and fourth quarter 2014 property sales, while the decrease at Haynesville/Cotton Valley was a result of declining production and a rate decrease due to an impairment at year-end 2014. The increase in the Williston Basin DD&A expense primarily relates to increased production.

DD&A expense decrease d $49.8 million , or $0.29 per Mcfe, in the first half of 2015 compared to the first half of 2014 , due to decreases in the Haynesville/Cotton Valley and Midcontinent, partially offset by an increase in the Williston Basin. The decrease in the Midcontinent was a result of the second and fourth quarter 2014 property sales, while the decrease at Haynesville/Cotton Valley was a result of declining production and a rate decrease due to an impairment at year-end 2014. The increase in the Williston Basin DD&A expense primarily relates to increased production.

Lease operating expense. The following table presents lease operating expenses (LOE) for QEP Energy by region on a unit of production basis:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
 
(per Mcfe)
Northern Region
$
0.59

 
$
0.58

 
$
0.01

 
$
0.65

 
$
0.67

 
$
(0.02
)
Southern Region
1.09

 
0.89

 
0.20

 
1.13

 
0.82

 
0.31

Average lease operating expense
0.71

 
0.71

 
—

 
0.76

 
0.74

 
0.02

 
QEP Energy’s LOE decrease d $2.4 million during the second quarter of 2015 compared to the second quarter of 2014 , and remained flat on a per Mcfe basis. The decrease was driven by a decrease in the Southern Region during the second quarter of 2015 , which was primarily due to a decrease in the Midcontinent as a result of the second and fourth quarter 2014 property sales, partially offset by an increase in the Permian Basin. Partially offsetting the decrease was an increase in the Northern Region, primarily due to increased production in the Williston Basin. On a per Mcfe basis, the increase in the Southern Region was primarily due to Midcontinent production declining at a faster rate than LOE due to QEP's remaining Midcontinent properties that carry higher operating costs than the properties that were divested in 2014.

QEP Energy’s LOE increase d $3.0 million , or $0.02 per Mcfe, during the first half of 2015 compared to the first half of 2014 . The increase in the Southern Region's LOE during the first half of 2015 was primarily driven by the Permian Basin Acquisition late in the first quarter of 2014, which are oil properties that have higher operating costs than the historical gas properties that were divested in 2014 in the Southern Region. The Northern Region per Mcfe decrease was driven primarily by higher performing well completions in the Uinta and Williston basins.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs increase d $3.4 million , or $0.07 per Mcfe, in the second quarter of 2015 when compared to the second quarter of 2014 . The per Mcfe expense increase was primarily attributable to additional expenses incurred in Pinedale due to deficiency payments on NGL volume commitments as a result of lower ethane volumes in 2015, in Haynesville/Cotton Valley due to deficiency fees on unutilized firm transportation commitments and in the Permian Basin due to higher contractual rates. These increases were

40


partially offset by a decrease in the Midcontinent due to divestitures of non-core properties in the second and fourth quarters of 2014.

Gas, oil and NGL transportation and other handling costs increase d $6.3 million , or $0.04 per Mcfe, in the first half of 2015 when compared to the first half of 2014 . The per Mcfe expense increase was primarily attributable to additional expenses incurred in Pinedale due to deficiency payments on NGL volume commitments as a result of lower ethane volumes in 2015, in Haynesville/Cotton Valley due to deficiency fees on unutilized firm transportation commitments and in the Permian Basin due to higher contractual rates. These increases were partially offset by decreases in the Williston Basin due to a reduction in the NGL processing and transportation costs and in the Midcontinent due to divestitures of non-core properties in the second and fourth quarters of 2014.

Production and property taxes. In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production taxes decrease d $21.9 million , or $0.25 per Mcfe, during the second quarter of 2015 as a result of decreased gas, oil and NGL revenues due to decreased prices and lower gas and NGL production.

Production taxes decrease d $41.8 million , or $0.26 per Mcfe, during the first half of 2015 as a result of decreased gas, oil and NGL revenues due to decreased prices and lower gas and NGL production.

Exploration expense. Exploration expenses decrease d $0.9 million during the second quarter of 2015 and $2.0 million during the first half of 2015 compared to the 2014 equivalent periods. These decrease s primarily related to lower exploration-related labor expenses.

Impairment expense. Impairment expense was $20.5 million during the first half of 2015 , of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. Of the $19.4 million impairment on proved properties, $14.5 million related to impairments on QEP's remaining Midcontinent properties and $4.9 million related to impairments in the Other Northern properties. Impairment expense was $3.5 million in the first half of 2014 due to unproved property impairments resulting from changes in drilling plans.


41


QEP MARKETING AND OTHER

QEP Marketing and Other includes the results of operations from QEP Marketing Company, including the operation of a gas gathering system and an underground storage facility, and corporate. The following table provides a summary of QEP Marketing and Other's financial and operating results:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
 
(in millions)
REVENUES
 
 
 
 
 
 
 
 
 
 
 
Purchased gas and oil sales
$
443.6

 
$
605.6

 
$
(162.0
)
 
$
784.1

 
$
1,107.1

 
$
(323.0
)
Other
5.2

 
6.0

 
(0.8
)
 
10.5

 
12.3

 
(1.8
)
Total Revenues
448.8

 
611.6

 
(162.8
)
 
794.6

 
1,119.4

 
(324.8
)
OPERATING EXPENSES
 

 
 

 
 

 
 

 
 

 
 

Purchased gas and oil expense
445.4

 
605.4

 
(160.0
)
 
788.2

 
1,103.3

 
(315.1
)
Gathering and other expense
1.4

 
1.8

 
(0.4
)
 
3.1

 
3.4

 
(0.3
)
General and administrative
1.9

 
0.5

 
1.4

 
3.7

 
1.7

 
2.0

Production and property taxes
1.5

 
0.4

 
1.1

 
1.8

 
0.9

 
0.9

Depreciation, depletion and amortization
2.6

 
2.9

 
(0.3
)
 
5.3

 
5.4

 
(0.1
)
Total Operating Expenses
452.8

 
611.0

 
(158.2
)
 
802.1

 
1,114.7

 
(312.6
)
Net gain (loss) from asset sales
(2.0
)
 
(0.1
)
 
(1.9
)
 
(4.7
)
 
(0.1
)
 
(4.6
)
OPERATING INCOME (LOSS)
(6.0
)
 
0.5

 
(6.5
)
 
(12.2
)
 
4.6

 
(16.8
)
Realized gains (losses) on derivative instruments
(0.3
)
 
(1.8
)
 
1.5

 
2.2

 
(3.9
)
 
6.1

Unrealized gains (losses) on derivative instruments
(0.1
)
 
(0.9
)
 
0.8

 
(1.9
)
 
(1.2
)
 
(0.7
)
Interest and other income
53.1

 
56.7

 
(3.6
)
 
101.1

 
105.5

 
(4.4
)
Interest expense
(36.0
)
 
(44.9
)
 
8.9

 
(72.7
)
 
(86.7
)
 
14.0

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
10.7

 
9.6

 
1.1

 
16.5

 
18.3

 
(1.8
)
Income tax (provision) benefit
(3.6
)
 
(5.3
)
 
1.7

 
(5.7
)
 
(6.4
)
 
0.7

NET INCOME (LOSS)
$
7.1

 
$
4.3

 
$
2.8

 
$
10.8

 
$
11.9

 
$
(1.1
)
 
Resale Margin

The following table is a summary of QEP Marketing’s financial results from resale activities:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Resale Margin
(in millions)
Purchased gas and oil sales  
$
443.6

 
$
605.6

 
$
(162.0
)
 
$
784.1

 
$
1,107.1

 
$
(323.0
)
Purchased gas and oil expense
(445.4
)
 
(605.4
)
 
160.0

 
(788.2
)
 
(1,103.3
)
 
315.1

Realized gains (losses) on derivative instruments
(0.3
)
 
(1.8
)
 
1.5

 
2.2

 
(3.9
)
 
6.1

Resale margin
$
(2.1
)
 
$
(1.6
)
 
$
(0.5
)
 
$
(1.9
)
 
$
(0.1
)
 
$
(1.8
)

Purchased gas and oil sales decrease d by $162.0 million , or 27% , during the second quarter of 2015 compared to the second quarter of 2014 , due to a $96.7 million decrease in resale oil sales and a $64.3 million decrease in resale gas sales. Resale oil sales decreased due to a 44% decrease in resale price, partially offset by a 39% increase in resale volumes. Resale gas sales decreased due to a 45% decrease in resale price, partially offset by a 7% increase in resale volumes.

Purchased gas and oil sales decrease d by $323.0 million , or 29% , during the first half of 2015 compared to the first half of 2014 , due to a $181.1 million decrease in resale oil sales and a $141.9 million decrease in resale gas sales. Resale oil sales

42


decreased due to a 50% decrease in resale price, partially offset by a 52% increase in resale volumes. Resale gas sales decreased due to a 54% decrease in resale price, partially offset by a 27% increase in resale volumes.

Purchased gas and oil expense, which includes transportation expense, decrease d by $160.0 million , or 26% , in the second quarter of 2015 compared to the second quarter of 2014 , due to a $97.5 million decrease in resale oil purchases and a $62.5 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 42% decrease in resale purchase price, partially offset by a 34% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 42% decrease in the resale purchase price, partially offset by a 5% increase in resale purchase volumes.

Purchased gas and oil expense, which includes transportation expense, decrease d by $315.1 million , or 29% , in the first half of 2015 compared to the first half of 2014 , due to a $179.8 million decrease in resale oil purchases and a $135.3 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 49% decrease in resale purchase price, partially offset by a 48% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 48% decrease in the resale purchase price, partially offset by an 8% increase in resale purchase volumes.

QEP Resources

Other Consolidated Expenses and Income from Continuing and Discontinued Operations

General and administrative expense. During the second quarter of 2015 , general and administrative (G&A) expense decrease d $1.0 million , or 2% , compared to the second quarter of 2014 , primarily due to a $5.6 million decrease in professional and outside services and compensation expense mainly related to the 2014 Enterprise Resource Planning (ERP) system implementation and other 2014 transactions, a $4.2 million decrease in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP) due to a decrease in QEP's stock price and a $3.5 million decrease in labor, benefits and other employee expenses. These decreases were partially offset by an $11.2 million pension curtailment loss recognized in the second quarter of 2015 related to changes in the Company's pension plan (see Note 12 - Employee Benefits for additional information).

During the first half of 2015 , G&A expense increase d $1.1 million , or 1% , compared to the first half of 2014 , primarily due to an $11.2 million pension curtailment loss recognized in the second quarter of 2015 related to changes in the Company's pension plan (see Note 12 - Employee Benefits for additional information) and a $4.0 million increase in labor and benefits costs primarily related to severance payments related to workforce reduction efforts in the first quarter of 2015. These increases were partially offset by a $12.8 million decrease in professional and outside services and compensation expense mainly related to the 2014 ERP system implementation and other 2014 transactions and a $1.8 million decrease in other employee expenses.

Net gain (loss) from asset sales. QEP recognized a gain on sale of assets of $24.5 million during the second quarter of 2015 compared to a loss on sale of $200.9 million in the second quarter of 2014 . The gain on sale of assets recognized during the second quarter of 2015 was primarily due to a $26.6 million gain recognized on the sale of non-core properties in QEP Energy's Midcontinent area during the second quarter of 2015 , partially offset by losses related to post-closing adjustments on QEP Energy's 2014 Midcontinent property sales. The loss on sale recognized during the second quarter of 2014 related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area for a pre-tax loss on sale of $200.9 million .

QEP recognized a loss on sale of assets of $6.0 million during the first half of 2015 compared to a loss on sale of assets of $198.5 million in the first half of 2014 . The loss on sale of assets recognized during the first half of 2015 was primarily due to $29.3 million in post-closing adjustments related to QEP Energy's 2014 Midcontinent property sales and $4.3 million in post-closing adjustments related to the Midstream Sale in 2014, partially offset by a $26.6 million gain recognized on the sale of non-core properties in QEP Energy's Midcontinent area during the second quarter of 2015 . The loss on sale recognized during the first half of 2014 primarily related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area for a pre-tax loss on sale of $200.9 million .


43


Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative instruments are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts and interest rate swaps, which are marked-to-market each quarter. During the second quarter of 2015 , losses on commodity derivative instruments were $66.0 million , of which $158.3 million of unrealized losses , partially offset by $92.3 million of realized gains . During the second quarter of 2014 , losses on commodity derivative instruments were $85.2 million , of which $34.1 million were realized and $51.1 million were unrealized. Additionally, during the second quarter of 2014 , losses from interest rate swaps were $2.8 million , of which $1.2 million were realized and $1.6 million were unrealized. All of QEP's interest rate swaps were settled in the fourth quarter of 2014 .

During the first half of 2015 , gains on commodity derivative instruments were $14.9 million , of which $196.7 million were realized gains , partially offset by $181.8 million of unrealized losses . During the first half of 2014 , losses on commodity derivative instruments were $165.4 million , of which $68.8 million were realized and $96.6 million were unrealized. Additionally, during the first half of 2014 , losses from interest rate swaps were $3.5 million , of which $1.9 million were realized and $1.6 million were unrealized.

Interest expense. Interest expense decrease d $8.8 million , or 20% , during the three months ended June 30, 2015 , compared to the three months ended June 30, 2014 . The decrease was attributable to average debt levels in the second quarter of 2015 that were $1,240.1 million, or 36%, lower than average debt levels in the second quarter of 2014 . The decrease in average debt levels is primarily related to repaying all outstanding borrowings under the revolving credit facility and repaying the $600.0 million term loan from the proceeds of the Midstream Sale in December 2014.

Interest expense decrease d $13.9 million , or 16% , during the six months ended June 30, 2015 , compared to the six months ended June 30, 2014 . The decrease was attributable to average debt levels in the first half of 2015 that were $1,235.9 million, or 36%, lower than average debt levels in the first half of 2014 . The decrease in average debt levels is primarily related to repaying all outstanding borrowings under the revolving credit facility and repaying the $600.0 million term loan from the proceeds of the Midstream Sale in December 2014.

Income taxes. Income tax benefit was $38.8 million during the second quarter of 2015 compared $61.9 million during the second quarter of 2014 . The income tax rate was 33.7% during the second quarter of 2015 compared to a rate of 36.8% during the second quarter of 2014 . The income tax benefits recognized in 2015 and 2014 were primarily the result of losses before income taxes for the second quarter s of 2015 and 2014 . The decrease in income tax rate was primarily the result of a change in the composition of income between subsidiaries.

Income tax benefit was $70.3 million during the first half of 2015 compared to $53.7 million during the first half of 2014 . The income tax rate was 34.8% during the first half of 2015 compared to a rate of 36.5% during the first half of 2014 . The income tax benefits recognized in 2015 and 2014 were primarily the result of losses before income taxes for the first half of 2015 and 2014 . The decrease in income tax rate was primarily the result of a change in the composition of income between subsidiaries.

Discontinued operations. Discontinued operations represent results of operations from QEP Field Services, excluding QEP’s retained Haynesville Gathering System. During the second quarter of 2014 , net income from discontinued operations was $13.8 million , primarily attributable to other revenue of $34.9 million , which primarily consists of gathering and processing revenue, and NGL sales revenue of $27.8 million , partially offset by gathering, processing and other expense of $22.8 million , DD&A of $14.5 million and G&A of $11.9 million .

During the first half of 2014 , net income from discontinued operations was $40.8 million , primarily attributable to other revenue of $76.8 million , which primarily consists of gathering and processing revenue, and NGL sales revenue of $65.8 million , partially offset by gathering, processing and other expense of $47.1 million , DD&A of $28.8 million and G&A of $23.2 million .


44


LIQUIDITY AND CAPITAL RESOURCES

QEP seeks to fund its development projects by employing a capital structure and financing strategy to provide sufficient liquidity to withstand commodity price volatility. QEP maintains a commodity price derivative strategy to reduce commodity price volatility and to provide some certainty to cash flows. QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities and borrowings under its credit facilities. Periodically, QEP accesses debt and equity capital markets and sells assets to provide additional liquidity. The Company believes cash flow from operations, cash-on-hand and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures and operating expenses during the next 12 months and the foreseeable future. To the extent actual operating results or actual commodity prices differ from the Company’s assumptions, QEP's liquidity could be adversely affected.

The following table provides QEP’s available liquidity and debt to equity ratio compared to the previous period:
 
June 30, 2015
 
December 31, 2014
 
(in millions, except %)
Cash and cash equivalents
$
445.6

 
$
1,160.1

Amount available under the QEP credit facility (1)
1,796.3

 
1,796.3

Total liquidity
$
2,241.9

 
$
2,956.4

Total debt
$
2,218.5

 
$
2,218.1

Total common shareholders' equity
$
3,947.7

 
$
4,075.3

Ratio of debt to total capital (2)
36
%
 
35
%
  ____________________________
(1)  
See discussion of revolving credit facility below. Availability under QEP's credit facility is reduced by outstanding letters of credit of $3.7 million as of June 30, 2015 and December 31, 2014 , respectively.
(2)  
Defined as total debt divided by the sum of total debt plus common shareholders’ equity.

Credit Facility
QEP’s revolving credit facility, which matures in December 2019, provides for loan commitments of $1.8 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions.

On December 2, 2014, QEP entered into the Fourth Amendment to its Credit Agreement, which increased the aggregate principal amount of commitments to $1.8 billion , extended the maturity date to December 2, 2019, and made minor adjustments to other provisions and covenants.

During the six months ended June 30, 2014 , QEP’s weighted-average interest rate on borrowings from its credit facility was 2.20% . At June 30, 2015 and December 31, 2014 , QEP had no borrowings outstanding under the credit facility, had $3.7 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit facility. At July 29, 2015, QEP had no borrowings outstanding under the credit facility and had $3.7 million of letters of credit outstanding under the credit facility.

Senior Notes
The Company’s senior notes outstanding as of June 30, 2015 , totaled $2,221.8 million principal amount and are comprised of six issuances as follows:

•
$176.8 million 6.05% Senior Notes due September 2016;
•
$134.0 million 6.80% Senior Notes due April 2018;
•
$136.0 million 6.80% Senior Notes due March 2020;
•
$625.0 million 6.875% Senior Notes due March 2021;
•
$500.0 million 5.375% Senior Notes due October 2022; and
•
$650.0 million 5.25% Senior Notes due May 2023.

Cash Flow from Operating Activities

Cash flows from operations are primarily affected by gas, oil and NGL production volumes and commodity prices (including the effects of settlements of the Company’s derivative contracts) and by changes in working capital. QEP enters into

45


commodity derivative transactions covering a substantial, but varying, portion of its anticipated future gas, oil and NGL production for the next 12 to 24 months.

Net cash from operating activities decrease d $862.9 million during the first half of 2015 compared to the first half of 2014 , due to a decrease in changes in operating assets and liabilities, lower non-cash adjustments to net income and a higher net loss incurred during the first half of 2015 compared to the first half of 2014 . Changes in operating assets and liabilities decreased $566.1 million , which was mainly due to a decrease in income taxes payable of $587.8 million, primarily from the gain on the Midstream Sale, which was paid in the first half of 2015 . Net cash from operating activities is presented below:
 
Six Months Ended June 30,
 
2015
 
2014
 
Change
 
(in millions)
Net income (loss)
$
(131.9
)
 
$
(52.6
)
 
$
(79.3
)
Net income attributable to noncontrolling interest
—

 
10.8

 
(10.8
)
Non-cash adjustments to net income
620.2

 
826.9

 
(206.7
)
Changes in operating assets and liabilities
(490.9
)
 
75.2

 
(566.1
)
Net cash (used in) provided by operating activities
$
(2.6
)
 
$
860.3

 
$
(862.9
)

Cash Flow from Investing Activities

In the first half of 2015 , net cash used in investing activities was $653.7 million , compared to $972.1 million in the first half of 2014 . This decrease in investing activities was due to a 62% decrease in capital expenditures on a cash basis. Capital expenditures decreased primarily because of the Permian Basin Acquisition, which closed in the first quarter of 2014 for a total purchase price of $941.8 million , as well as a reduction in capital activity due to the current price environment. A comparison of capital expenditures for the first half of 2015 and 2014 and a forecast for calendar year 2015 are presented in the table below:
 
Six Months Ended
 
Current
Forecast
Twelve Months
Ended
 
Prior Forecast
Twelve Months
Ended (1)
 
June 30,
 
 
 
2015
 
2014
 
Change
 
December 31, 2015
 
December 31, 2015
 
(in millions)
QEP Energy
$
554.8

 
$
1,710.5

 
$
(1,155.7
)
 
$
960.0

 
$
960.0

QEP Marketing and Other
4.9

 
6.9

 
(2.0
)
 
15.0

 
15.0

Continuing Operations
559.7

 
1,717.4

 
(1,157.7
)
 
975.0

 
975.0

Discontinued Operations
—

 
37.3

 
(37.3
)
 
—

 
—

Total accrued capital expenditures
559.7


1,754.7


(1,195.0
)

975.0


975.0

Change in accruals
91.6

 
(26.3
)
 
117.9

 
—

 
—

Total cash capital expenditures
$
651.3

 
$
1,728.4

 
$
(1,077.1
)
 
$
975.0

 
$
975.0

  ____________________________
(1)  
Forecast as reported in the March 31, 2015, Form 10-Q, filed on April 29, 2015.

In the first half of 2015 , QEP Energy's capital expenditures, on an accrual basis, decrease d $1,155.7 million over the first half of 2014 to a total of $554.8 million , which was primarily driven by the Permian Basin Acquisition which occurred in 2014. In addition, capital expenditures decreased $148.8 million in the Williston Basin, $62.6 million in Pinedale and $17.8 million in the Other Northern properties due to reductions in QEP's capital expenditures in response to the current pricing environment and $29.0 million in the Midcontinent due to 2014 divestitures. These decreases were partially offset by increases of $31.1 million in the Permian Basin due to additional horizontal well completions during the first half of 2015 compared to the first half of 2014 , and $15.5 million in Haynesville/Cotton Valley.

At June 30, 2015 , the midpoint of our forecasted capital investment for 2015 is $975.0 million , comprised of $960.0 million allocated to QEP Energy and $15.0 million between QEP Marketing and Other. QEP intends to fund capital expenditures with cash flow from operating activities, cash on hand and, if needed, borrowings under its revolving credit facility. As a result of the decline in oil and gas prices, forecasted capital investment in 2015 is expected to be significantly lower than in 2014. QEP

46


plans minimal capital expenditures for the Haynesville Shale and other dry-gas development areas in 2015 and plans to focus investment during 2015 on higher return projects, including oil-directed horizontal drilling in the Williston Basin and the Permian Basin. QEP Energy has allocated approximately 96% of its forecasted 2015 drilling and completion capital expenditure budget to oil and liquids-rich gas plays. QEP plans to invest approximately $15.0 million in capital expenditures related to corporate activities. The aggregate levels of capital expenditures for 2015 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, gas, oil and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

Cash Flow from Financing Activities

In the first half of 2015 , net cash used in financing activities was $58.2 million compared to net cash provided by financing activities of $802.2 million in the first half of 2014 . During the first half of 2015 , QEP had checks outstanding in excess of cash balances of $47.3 million and $7.1 million of regular quarterly dividend payments. During the first half of 2014 , QEP had borrowings from the credit facility of $3,151.0 million offset by repayments on the credit facility of $2,538.0 million as well as an additional issuance of $300.0 million under its term loan which were used to fund the Permian Basin Acquisition. These borrowings were offset by checks outstanding in excess of cash balances of $85.2 million , $15.2 million of distributions to noncontrolling interest, and $7.3 million of regular quarterly dividends payment during the first half of 2014 .

At June 30, 2015 , the Company did not have any borrowings outstanding under the credit facility and $2,221.8 million in senior notes (excluding $3.3 million of net original issue discount).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risk exposures arise from changes in the market price for gas, oil and NGL, and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP Energy and QEP Marketing also have long-term contracts for pipeline capacity, and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a sustained, significant decline. Furthermore, the Company’s credit facility has a floating interest rate, which expose QEP to interest rate risk. To manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price swaps to manage commodity price risk and periodically interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price swaps or collars. The volume of commodity derivative instruments utilized by the Company may vary from year-to-year based on QEP's forecasted production. The derivative instruments utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of June 30, 2015 , QEP held commodity price derivative contracts totaling 137.3 million MMBtu of gas and 8.7 million barrels of oil.

The following table presents QEP's derivative positions as of July 29, 2015. See Note 8 - Derivative Contracts, under Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of June 30, 2015 .


47


QEP Energy Commodity Derivative Swap Positions
Year
 
Index
 
Total
Volumes
 
Average Swap price per unit
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
(MMBtu)

 
 
2015
 
 NYMEX HH
 
35.0

 
$
3.48

2015
 
 IFNPCR
 
23.9

 
$
3.55

2016
 
NYMEX HH
 
18.3

 
$
3.24

2016
 
IFNPCR
 
32.9

 
$
2.92

Oil Sales
 
 
 
(bbls)

 
 

2015
 
NYMEX WTI
 
5.2

 
$
82.09

2015
 
ICE Brent
 
0.2

 
$
104.95

2016
 
NYMEX WTI

3.3

 
$
65.43


QEP Energy Gas Collars
 
 
 
 
Total Volume
 
Average Price
 
Average Price
Year
 
Index
 
 
Floor
 
Ceiling
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
(MMBtu)

 
($/MMBtu)
 
($/MMBtu)
2016
 
NYMEX HH
 
7.3

 
$
2.75

 
$
3.89

QEP Energy Gas Basis Swaps
Year
 
Index
 
Index Less Differential
 
Total
Volumes
 
Weighted Average Differential
 
 
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
(MMBtu)

 
($/MMBtu)

2015
 
NYMEX HH
 
IFNPCR
 
22.1

 
$
(0.28
)

QEP Marketing Commodity Derivative Positions
Year
 
Type of Contract
 
Index
 
Total
Volumes
 
Average Swap price
per MMBtu
 
 
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
 
 
(MMBtu)

 
 
2015

SWAP

IFNPCR

2.4


$
3.25

2016
 
SWAP
 
IFNPCR
 
2.0

 
$
3.17

Gas purchases
 
 
 
 
 
(MMBtu)

 
 

2015
 
SWAP
 
IFNPCR
 
1.1

 
$
2.77



48


Changes in the fair value of derivative contracts from December 31, 2014 to June 30, 2015 , are presented below:
 
Commodity
derivative contracts
 
(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2014
$
348.9

Contracts settled
(196.7
)
Change in oil and gas prices on futures markets
17.3

Contracts added
(2.4
)
Net fair value of oil and gas derivative contracts outstanding at June 30, 2015
$
167.1


The following table shows the sensitivity of the fair value of gas and oil derivative contracts to changes in the market price of gas, oil and NGL and basis differentials:
 
June 30, 2015
 
(in millions)
Net fair value - asset (liability)
$
167.1

Fair value if market prices of oil and gas and basis differentials decline by 10%
250.7

Fair value if market prices of oil and gas and basis differentials increase by 10%
83.2

 
Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $83.9 million , while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $83.6 million as of June 30, 2015 . However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 8 – Derivative Contracts under Part I, Item 1 of this Quarterly Report on
Form 10-Q.

Interest Rate Risk Management

The Company’s ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets as described in the risk factors in Item 1A of Part I of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014 . The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk. At June 30, 2015 , the Company did not have any borrowings outstanding under its revolving credit facility.

The remaining $2,221.8 million of the Company’s debt is Senior Notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 9 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

Forward-Looking Statements
 
This quarterly report contains information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:

•
our growth strategies;
•
ability to deliver continued growth by focusing on exploration and production assets;
•
ability to pursue acquisition opportunities;
•
inventory of drilling locations;
•
strong liquidity position providing financial flexibility;
•
our liquidity and sufficiency of cash flow from operations, cash-on-hand and availability under our credit facility to fund our planned capital expenditures and operating expenses;
•
drilling plans;
•
focus on improving well design and reducing costs;

49


•
results from planned drilling operations and production operations;
•
plans to recover or reject ethane from produced natural gas;
•
impact of lower or higher commodity prices and interest rates;
•
anticipated oil, gas and NGL prices and factors impacting such prices;
•
impact of global geopolitical and macroeconomic events;
•
plans to enter into derivative contracts and manage counterparty risk;
•
pro forma results for acquired properties;
•
divestitures of non-core assets;
•
expected gain or loss on sale of assets;
•
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•
timing and impact of proposed environmental legislation and studies;
•
compliance with governmental regulations;
•
the outcome of contingencies such as legal proceedings;
•
assumptions regarding equity compensation;
•
recognition of compensation costs related to equity compensation grants;
•
expected contributions to our employee benefit plans;
•
employee benefit plan losses;
•
the importance of Adjusted EBITDA (a non-GAAP financial measure) as a measure of performance;
•
delays caused by transportation, processing, storage and refining capacity issues;
•
fair value and critical accounting estimates, including estimated asset retirement obligations;
•
impact of new accounting pronouncements;
•
impact of shutting in wells;
•
factors impacting our ability to transport oil and gas;
•
potential for future asset impairments and impact of impairments on financial statements;
•
impact of sale of our midstream business;
•
the timing and estimated costs of, and benefits from, the closing of our Tulsa office; and
•
factors impacting the timing and amount of share repurchases.

Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:
 
•
the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014 ;
•
changes in gas, oil and NGL prices;
•
general economic conditions, including the performance of financial markets and interest rates;
•
drilling results;
•
shortages of oilfield equipment, services and personnel;
•
lack of available pipeline, processing and refining capacity;
•
our ability to successfully integrate acquired assets;
•
the outcome of contingencies such as legal proceedings;
•
permitting delays;
•
operating risks such as unexpected drilling conditions;
•
weather conditions;
•
the availability and cost of debt and equity financing;
•
changes in laws or regulations;
•
legislation regarding climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing and water use;
•
derivative activities;
•
volatility in the commodity-futures market;
•
failure of internal controls and procedures;
•
failure of our information technology infrastructure or applications;
•
elimination of federal income tax deductions for oil and gas exploration and development costs;
•
regulatory approvals and compliance with contractual obligations;
•
actions, or inaction, by federal, state, local or tribal governments;

50


•
lack of, or disruptions in, adequate and reliable transportation for our production;
•
competitive conditions;
•
production levels;
•
reserve levels; and
•
other factors, most of which are beyond the Company’s control.
 
We undertake no obligation to publicly correct or update the forward-looking statements in this Quarterly Report on Form 10-Q, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
 

51


ITEM 4. CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures
 
The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of June 30, 2015 . Based on such evaluation, such officers have concluded that, as of June 30, 2015 , the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Controls.
 
There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended June 30, 2015 , that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION
 
ITEM 1. LEGAL PROCEEDINGS

Yannick Gagné and others similarly situated v. QEP Resources, Inc., et al., No. 480-06-1-132, Superior Court, Province of Quebec, Canada. Plaintiffs seek to represent a class of all persons who sustained damages as a result of the July 6, 2013 train derailment in Lac-Mégantic, Quebec, which resulted in substantial loss of life and property. The fourth amended motion to authorize the bringing of a class action was filed on February 19, 2014, and names numerous defendants, including the rail company that transported the crude oil (which filed for bankruptcy protection in August 2013). The plaintiffs contend that QEP, and other producer defendants, sold Bakken crude oil to third-party purchasers in North Dakota, who resold the oil and transported it on the derailed train. Plaintiffs alleged that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, knowingly added volatile light end petroleum liquids and/or vapors or blended the crude with condensate, failed to conduct adequate well site testing to determine the proper hazard classification of the oil, failed to properly classify the shipping requirements for the oil, failed to take reasonable care to ensure that the oil was properly labeled and shipped, failed to identify the risk of the train derailment and take action to prevent it, and failed to adopt, implement and enforce rules and procedures pertaining to the safe shipment of the oil. The plaintiffs seek damages, but specific monetary damages are not asserted. Class certification hearings took place in June 2014, and a court order regarding class certification is pending. Many of the defendants, including QEP, and their insurers have reached an agreement with Trustees in both Canadian and U.S. Bankruptcy Courts to resolve all of these claims. The terms of the agreement are confidential and are contingent upon the approval of the courts. In addition, on July 15, 2015, QEP was served with a complaint entitled Samuel Audet, et al. vs. Devlar Energy Marketing, LLC, et al., No. DC-15-06428, District Court of Dallas County, Texas, 95 th Judicial District. The plaintiffs, defendants, allegations, and damages sought are materially similar to those in the Yannick Gagné case, and plaintiffs state that this lawsuit is filed to preserve claims under the applicable two-year statute of limitations. Plaintiffs also filed a motion to stay proceedings in this case for 90 days pending the outcome of the global settlement discussions described above in the Yannick Gagné case. The court's order on this request for a stay is pending.

 

52



ITEM 1A. RISK FACTORS
 
Risk factors relating to the Company are set forth in its Annual Report on Form 10-K/A for the year ended December 31, 2014 . Below are material changes to such risk factors that have occurred during the six months ended June 30, 2015 .

QEP's ability to produce oil and gas economically and in commercial quantities could be impaired if it is unable to acquire adequate supplies of water for its drilling and completion operations or is unable to dispose of or recycle the water or other waste at a reasonable cost and in accordance with applicable environmental rules. The hydraulic fracture stimulation process on which QEP depends to produce commercial quantities of oil and gas requires the use and disposal of significant quantities of water. The availability of disposal wells with sufficient capacity to receive all of the water produced from QEP’s wells may affect QEP’s production. In some cases, QEP may need to obtain water from new sources and transport it to drilling sites, resulting in increased costs. QEP's inability to secure sufficient amounts of water, or to dispose of or recycle the water used in its operations, could adversely impact its operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on QEP's ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase QEP's operating costs or may cause QEP to delay, curtail or discontinue its exploration and development plans, which could have a material adverse effect on its business, financial condition, results of operations and cash flows. In addition, concerns have been raised about the potential for induced seismicity to occur from the use of underground injection wells, a predominant method for disposing of waste water (including hydraulic fracturing flowback water) from oil and gas activities. QEP operates injection wells and utilizes injection wells owned by third parties to dispose of waste water associated with its operations. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. Further, lawsuits against other companies have been filed by plaintiffs alleging they suffered damages from seismicity caused by injection of waste water into disposal wells, which may make it more expensive or difficult to conduct water disposal activities and to obtain insurance for such activities.

Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to oil and gas reserves.  Currently, well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of oil and gas well design and operation. The EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act and issued guidance related to   this newly asserted regulatory authority. The EPA appears to be considering its existing regulatory authorities for possible avenues to further regulate hydraulic fracturing fluids and/or the components of those fluids. Additionally, in May 2012, the BLM proposed new regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal lands and proposed further revision to those regulations in May 2013. The BLM finalized those regulations in March 2015, to become effective in June 2015; however, due to pending litigation (discussed below), the effective date of the rule has been postponed. The new regulations have the potential to increase the cost of drilling and completing any well requiring federal permits, and could result in further delays in getting such permits to authorize drilling and completion activities on federal and tribal lands. Several states, including some in which the Company operates, have filed suit against the Department of Interior over the final BLM hydraulic fracturing regulations, which could contribute to increased uncertainty regarding the Company’s compliance obligations on federal and tribal lands and has caused the effective date of the regulations to be postponed.

Legislation has also been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process, notwithstanding the proposed and ongoing rulemaking proceedings noted above. At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more stringent federal, state or local regulations, restrictions or moratoria are adopted in areas where QEP operates, QEP could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or stimulating wells in some areas.

The EPA is also considering other potential regulation of hydraulic fracturing activities. For example, the EPA is considering regulation of wastewater discharges from hydraulic fracturing and other natural gas production under the federal Clean Water Act. The EPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. The EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The results of this study, which has not been finalized, could result in additional regulations, which could lead to operational burdens similar to those described above. The EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (TSCA) to seek

53


comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxics Release Inventory (TRI) program of the Emergency Planning and Community Right-to-Know Act. 

Lack of availability of refining, gas processing, storage or transportation capacity will likely impact results of operations. The lack of availability of satisfactory oil, gas and NGL transportation, including trucks, railways and pipelines, gas processing, storage or refining capacity may hinder QEP's access to oil, NGL and gas markets or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability and capacity of transportation, gas processing facilities, storage or refineries owned and operated by third parties. Although QEP has some contractual control over the transportation of its production through firm transportation arrangements, third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents or other reasons. If transportation, gas processing or storage facilities do not exist near producing wells, if transportation, gas processing, storage or refining capacity is limited or if transportation, gas processing or refining capacity is unexpectedly disrupted, completion activity could be delayed, sales could be reduced, or production shut in each of which could reduce profitability. Furthermore, if QEP were required to shut in wells, it might also be obligated to pay certain demand charges for gathering and processing services, firm transportation charges on interstate pipelines as well as shut-in royalties to certain mineral interest owners in order to maintain its leases; or depending on the specific lease provisions, some leases could terminate. In addition, rail accidents involving crude oil carriers have resulted in regulations, and may result in additional regulations, on transportation of oil by railway. If transportation quality requirements change, QEP might be required to install or contract for additional treating or processing equipment, which could increase costs. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, transportation pressures, damage to or destruction of transportation facilities and general economic conditions could also adversely affect QEP's ability to transport oil and gas.
Requirements to reduce gas flaring could have an adverse effect on our operations.  Wells in the Bakken and Three Forks formations in North Dakota, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in the current gas gathering and processing network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In June 2014, the North Dakota Industrial Commission, North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. The Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. The Bureau of Land Management (BLM) has also indicated its intent to pursue a rulemaking related to further controls on the venting and flaring of natural gas on BLM land. These capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.


54


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

The following repurchases of QEP shares were made by QEP in association with vested restricted stock awards withheld for
taxes.
Period
 
Total shares purchased (1)
 
Weighted-average price paid per share
 
Total shares
purchased as part of
publicly announced
plans or programs
 
Remaining dollar amount that may be
purchased under the
plans or programs
April 1, 2015 - April 30, 2015
 
—

 
$
—

 
—

 
$
400.3

May 1, 2015 - May 31, 2015
 
—

 
—

 
—

 
400.3

June 1, 2015 - June 30, 2015
 
1,500

 
18.56

 
—

 
400.3

  ____________________________
(1)  
All of the 1,500 shares purchased during the three-month period ended June 30, 2015 , were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. Stock options that are net settled do not involve the acquisition of any shares.

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This program was extended through December 2015. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. During the six months ended June 30, 2015 , no shares were repurchased under this plan.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
 
None.
 
ITEM 4. MINE SAFETY DISCLOSURES
 
None.
 
ITEM 5. OTHER INFORMATION
 
None.


55


ITEM 6. EXHIBITS
 
The following exhibits are being filed as part of this report:
Exhibit No.
 
Exhibits
3.1
 
Certificate of Incorporation dated May 18, 2010. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 24, 2010.)
3.2
 
Amended and Restated Bylaws, deemed effective October 27, 2014. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on October 29, 2014.)
10.1†
 
QEP Resources, Inc. Supplemental Executive Retirement Plan adopted June 12, 2010 (Incorporated by reference to Exhibit 10.12 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2010), as amended and restated by the QEP Resources, Inc. Amended Supplemental Executive Retirement Plan, effective as of January 1, 2016.
10.2†
 
QEP Resources, Inc. Amended Deferred Compensation Wrap Plan adopted January 28, 2013 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on January 31, 2013), as amended and restated by the QEP Resources, Inc. Amended Deferred Compensation Wrap Plan, effective as of January 1, 2016.
31.1
 
Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1
 
Notice of Stipulation and Order, dated June 25, 2015 (Stipulation), dismissing Plumbers Local 98 Defined Benefit Fund v. Rattie , C.A. No. 10405-VCN, a shareholder derivative lawsuit (filed pursuant to the terms of the Stipulation).
101.INS*
 
XBRL Instance Document
101.SCH*
 
XBRL Schema Document
101.CAL*
 
XBRL Calculation Linkbase Document
101.LAB*
 
XBRL Label Linkbase Document
101.PRE*
 
XBRL Presentation Linkbase Document
101.DEF*
 
XBRL Definition Linkbase Document
____________________________
*
These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.
†
Indicates a management contract or compensatory plan or arrangement.

56


SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
QEP RESOURCES, INC.
 
(Registrant)
 
 
August 3, 2015
/s/ Charles B. Stanley
 
Charles B. Stanley,
 
Chairman, President and Chief Executive Officer
 
 
August 3, 2015
/s/ Richard J. Doleshek
 
Richard J. Doleshek,
 
Executive Vice President and Chief Financial Officer
 
 

57


Exhibit 10.1





QEP RESOURCES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN




QEP RESOURCES, INC.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

ARTICLE I
PURPOSE

QEP Resources, Inc. (the “Company”) established this QEP Resources, Inc. Supplemental Executive Retirement Plan (the “Plan”) as of the Effective Date, as defined herein, in order to enable the Company to attract and retain key management personnel by providing them with supplemental retirement benefits to compensate them for the limitations imposed by Federal tax laws on benefits payable from the QEP Resources, Inc. Retirement Plan (the “Retirement Plan”). The Plan also provides certain participants with the payment of compensation previously deferred under the Questar Corporation Supplemental Executive Retirement Plan, and additional supplemental retirement benefits that are based on the retirement benefit that these participants would have received under the Retirement Plan had they accrued benefits thereunder following the date of the spin-off of the Company from Questar Corporation. The Plan has been amended effective January 1, 2016, to provide continuing accruals to Participants following the freezing of the Retirement Plan.

This Plan is intended to be an unfunded, “top-hat” arrangement providing deferred compensation to “a select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended.

ARTICLE II
DEFINITIONS

The following terms, when used herein, shall have the meanings set forth below, unless a different meaning is plainly required by the context:

2.1    “ Accrued Benefit ” has the meaning set forth in the Retirement Plan.
    
2.2    “ Affiliated Company ” means any entity that is treated as the same employer as the Company under Sections 414(b), (c), (m), or (o) of the Code, any entity required to be aggregated with the Company pursuant to regulations adopted under Code Section 409A, or any entity otherwise designated as an Affiliated Company by the Company.

2.3    “ Assumed Benefits ” means, with respect to each Transferred Employee, the aggregate of his or her Pre-409A Benefit, if any, and Pre-Spinoff Benefit as set forth in Section 6.3.

2.4    “ Benefit Commencement Date ” has the meaning set forth in Section 7.3.

2.5    “ Board ” means the Board of Directors of the Company.

2.6    “ Change in Control ” has the meaning set forth in Section 15.2.

2.7    “ Code ” means the Internal Revenue Code of 1986, as amended.

2.8    “ Committee ” means the Compensation Committee of the Board.

2.9    “ Company ” means QEP Resources, Inc., a corporation organized and existing under the laws of the State of Delaware, or its successor or successors.

2.10    “ Disability ” means a condition that renders a Participant unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, as described in Treas. Reg. Section 1.409A-3(i)(4)(i)(A). A Participant shall not be considered to be disabled unless the Participant furnishes proof of the existence of such disability in such form and manner as may be required by regulations promulgated under, or applicable to, Code Section 409A.

2.11    “ Distribution Event ” has the meaning set forth in Section 7.3.

2.12    “ Earliest Retirement Age ” has the meaning set forth in the Retirement Plan.

2.13    “ Effective Date ” shall have the meaning set forth in Article III.





2.14    “ Eligible Employee ” means any employee (as determined in accordance with Section 3401(c) of the Code and the Treasury Regulations thereunder) of an Employer who satisfies each of the following conditions:

(a)    is a member of a “select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA;

(b)    has an accrued benefit under the Retirement Plan; and

(c)    either (i) receives or is expected to receive compensation in any calendar year in excess of the limitation on annual compensation that may be taken into account for purposes of providing benefits under a tax-qualified retirement plan pursuant to Section 401(a)(17) of the Code, as adjusted from time to time, or (ii) has deferred compensation under any of the Company’s nonqualified deferred compensation plans.

2.15    “ Employer ” means the Company and each Affiliated Company that employs any individual who is a current or former participant in the Retirement Plan and consents to the adoption of the Plan.

2.16    “ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended.

2.17    “ Participant ” means any individual who has commenced participation in the Plan in accordance with Article IV.

2.18    “ Plan ” means this QEP Resources, Inc. Supplemental Executive Retirement Plan, as amended or restated from time to time.

2.19    “ Post-Spinoff Benefit ” has the meaning set forth in Section 6.2.

2.20    “ Pre-409A Benefit ” has the meaning set forth in Section 6.3(b).

2.21    “ Pre-Spinoff Benefit ” has the meaning set forth in Section 6.3(a).

2.22    “ Questar Plan ” means the Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005, including its predecessor plans as set forth therein.

2.23    “ Questar Retirement Plan ” means the Questar Corporation Retirement Plan, as amended and restated effective January 1, 2009, as in effect as of the “Distribution Date” (as such term is defined in the Separation Agreement) and without regard to any subsequent amendment or restatement thereof.

2.24    “ Retirement Income ” has the meaning set forth in the Retirement Plan.

2.25    “ Retirement Plan ” means the QEP Resources, Inc. Retirement Plan, as amended or restated from time to time, or any successor plan. If not otherwise defined, capitalized words or terms used in the Plan shall have the same definitions used in the Retirement Plan.

2.26    “ Separation Agreement ” means that certain Separation and Distribution Agreement, by and between Questar Corporation and the Company, dated as of June 14, 2010).

2.27    “ Separation from Service ” means a “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Code and Treasury Regulation Section 1.409A-1(h).

2.28    “ Supplemental Retirement Benefit ” means (i) with respect to any Eligible Employee who becomes a Participant on or after the Effective Date, the supplemental retirement benefits payable as set forth in Article V hereof, and (ii) with respect to any Transferred Employee, the supplemental retirement benefits payable as set forth in Article VI hereof.

2.29    “ Transferred Employee ” means any “QEP Employee” (as defined in that certain Employee Matters Agreement, by and between Questar Corporation and the Company, dated as of June 14, 2010) who either had an accrued benefit under or was eligible to participate in the Questar Plan immediately prior to the Effective Date.





ARTICLE III
EFFECTIVE DATE

The terms of the Plan shall govern all compensation deferred hereunder on and after the “Distribution Date” (as such term is defined in the Separation Agreement) (such date, the “Effective Date”).

ARTICLE IV
PARTICIPATION IN THE PLAN; ELIGIBILITY FOR BENEFITS; VESTING

4.1     General .

(a)    Any individual who is an Eligible Employee shall become a Participant in the Plan if (and when) the individual receives written notification from the Committee or its designee, in its sole and absolute discretion, that the individual has been selected to participate in the Plan; provided however , that no Eligible Employee shall become a Participant after December 31, 2015. Once a Participant, the individual shall be eligible to accrue Supplemental Retirement Benefits under Article V of the Plan.

(b)    Notwithstanding any other provision herein, each Transferred Employee shall automatically become a Participant in the Plan as of the Effective Date.

4.2     Failure of Eligibility . If the Committee determines, in its sole and absolute discretion, that any Participant is no longer an Eligible Employee or no longer qualifies as a member of a select group of management or highly compensated employees of the Employer, the Participant shall cease active participation in this Plan and all accruals under this Plan by or on behalf of the Participant shall cease as of the date of such determination by the Committee. The Committee’s determination hereunder shall be final and binding on all persons.

4.3     Vesting .

(a)    Each Participant, other than a Transferred Employee, shall vest in his or her Supplemental Retirement Benefits under Article V of the Plan upon the later of (i) the date on which the Participant becomes vested in his or her Accrued Benefit under the Retirement Plan, or (ii) the earliest of (A) the 13-month anniversary of the date on which such individual first becomes a Participant in the Plan, provided that such individual remains continuously employed by an Employer throughout such period, (B) the date of the Participant’s death or Disability, or (C) the occurrence of a Change in Control; provided, however , in the event that the Participant’s employment with an Employer is terminated for any reason prior to the Participant becoming vested in his or her Supplemental Retirement Benefits, the Participant shall forfeit any right, title and interest to any such benefits under the Plan immediately upon such termination of employment.

(b)    Notwithstanding the foregoing, each Transferred Employee who first became eligible to participate in the Questar Plan on or after January 1, 2008 shall vest in his or her Post-Spinoff Benefits and, if applicable, such portion of his or her Pre-Spinoff Benefits that accrued during the period beginning on or after January 1, 2008 and ending immediately prior to the Effective Date, upon the later of (i) the date on which the Transferred Employee becomes vested in his or her Accrued Benefit under the Retirement Plan (as assumed by the Company from the Questar Plan pursuant to Section 6.3), or (ii) the earlier of (A) the 13-month anniversary of the date on which such individual first became a Participant in the Questar Plan, provided that such individual remains continuously employed by an Employer throughout such period (which shall be deemed to include any period of continuous employment with Questar or its affiliates prior to the Effective Date), (B) the date of the Transferred Employee’s death or Disability, or (C) the occurrence of a Change in Control; provided, however , in the event that the Transferred Employee’s employment with an Employer is terminated for any reason prior to the Transferred Employee becoming vested in his or her Post-Spinoff Benefits and, if applicable, such portion of his or her Pre-Spinoff Benefits, the Transferred Employee shall forfeit any right, title and interest to any such benefits immediately upon such termination of employment.

(c)    Notwithstanding the foregoing, each Transferred Employee who first became eligible to participate in the Questar Plan prior to January 1, 2008 shall vest in his or her Post-Spinoff Benefits and, if applicable, such portion of his or her Pre-Spinoff Benefits that accrued during the period beginning on or after January 1, 2005 and ending on December 31, 2007 and his or her Pre-409A Benefit, upon becoming vested in his or her Accrued Benefit under the Retirement Plan.





ARTICLE V
SUPPLEMENTAL RETIREMENT BENEFITS
FOR NEW PARTICIPANTS

An Eligible Employee who first becomes a Participant pursuant to Section 4.1(a) shall be eligible to receive a Supplemental Retirement Benefit under the Plan equal to the following:

(a)    (i) The total amount of Retirement Income that would have been payable under the Retirement Plan (whether to the Participant or the Participant’s spouse or beneficiary) if (A) the limitation on annual benefits imposed by Section 415 of the Code were not applicable, (B) the limitation on annual compensation imposed by Section 401(a)(17) of the Code were not applicable, and (C) the Participant had not voluntarily chosen to defer any compensation under the terms of any of the Company’s nonqualified deferred compensation plans, plus (ii) effective January 1, 2016, (the “Retirement Plan Freeze Date”) the total amount of Retirement Income that would have accrued under the Retirement Plan (whether to the Participant or the Participant’s spouse or beneficiary) if (I) “Compensation” (as defined in the Retirement Plan) included the compensation paid to the Participant on and after the Retirement Plan Freeze Date by an Employer, and “Credited Service” (as defined in the Retirement Plan) included the Participant’s period of employment with an Employer on and after the Retirement Plan Freeze Date, subject to the other terms and conditions set forth in the Retirement Plan at the Retirement Plan Freeze Date; less

(b)    The actual Retirement Income payable under the Retirement Plan (whether to the Participant or the Participant’s spouse or beneficiary).

Distribution of a Participant’s Supplemental Retirement Benefit shall be determined in accordance with the applicable provisions of Articles VII and XV.

ARTICLE VI
SUPPLEMENTAL RETIREMENT BENEFITS
FOR TRANSFERRED EMPLOYEES

6.1     Applicability of Section . Each Transferred Employee shall be eligible to receive those Supplemental Retirement Benefits described in Sections 6.2 and 6.3, to the extent applicable.

6.2     Post-Spinoff Benefits . On and after the Effective Date, each Transferred Employee shall be eligible to receive a Post-Spinoff Benefit under the Plan equal to the following:

(a)    The total amount of Retirement Income that would have been payable under the Retirement Plan (whether to the Transferred Employee or the Transferred Employee’s spouse or beneficiary) if (I) “Compensation” (as defined in the Retirement Plan) included the compensation paid to the Transferred Employee on and after the Effective Date by an Employer, and “Credited Service” (as defined in the Retirement Plan) included the Transferred Employee’s period of employment with an Employer on and after the Effective Date; provided, however, that for the avoidance of doubt, effective on the Retirement Plan Freeze Date, the total amount of Retirement Income that would have accrued under the Retirement Plan (whether to the Participant or the Participant’s spouse or beneficiary) if “Compensation” (as defined in the Retirement Plan) included the compensation paid to the Participant on and after the Retirement Plan Freeze Date by an Employer, and “Credited Service” (as defined in the Retirement Plan) included the Participant’s period of employment with an Employer on and after the Retirement Plan Freeze Date, subject to the other terms and conditions set forth in the Retirement Plan from the Effective Date through the Retirement Plan Freeze Date, (II) the limitation on annual benefits imposed by Section 415 of the Code were not applicable, (III) the limitation on annual compensation imposed by Section 401(a)(17) of the Code were not applicable, and (IV) the Transferred Employee had not voluntarily chosen to defer any compensation under the terms of any of the Company’s nonqualified deferred compensation plans, less

(b)    The actual Retirement Income payable under the Retirement Plan (whether to the Transferred Employee or the Transferred Employee’s spouse or beneficiary).

Distribution of a Transferred Employee’s Post-Spinoff Benefit shall be determined in accordance with the applicable provisions of Articles VII and XV.

6.3     Assumed Benefits . As of the Effective Date, the Company has assumed all accrued benefits under the Questar Plan with respect to each Transferred Employee (“Assumed Benefits”), and as of the Effective Date, Questar shall have no further liabilities or obligations with respect to such Assumed Benefits, which shall be composed of the following:





(a)     Pre-Spinoff Benefit . The total amount of Retirement Income that would have been payable under the Questar Retirement Plan (whether to the Transferred Employee or the Transferred Employee’s spouse or beneficiary) immediately prior to the Effective Date if (I) the limitation on annual benefits imposed by Section 415 of the Code were not applicable, (II) the limitation on annual compensation imposed by Section 401(a)(17) of the Code were not applicable, and (III) the Transferred Employee had not voluntarily chosen to defer any compensation under the terms of any of Questar’s nonqualified deferred compensation plans, less the actual Retirement Income payable under the Questar Retirement Plan as (whether to the Transferred Employee or the Transferred Employee’s spouse or beneficiary) immediately prior to the Effective Date, but excluding any Pre-409A Benefit (the “Pre-Spinoff Benefit”). For the avoidance of doubt, the Pre-Spinoff Benefit shall include only “amounts deferred” within the meaning of Code Section 409A after December 31, 2004, and prior to the Effective Date. Distribution of a Transferred Employee’s Pre-Spinoff Benefit shall be determined in accordance with the applicable provisions of Articles VII and XV.

(b)     Pre-409A Benefits . Any portion of a Transferred Employee’s “Supplemental Retirement Benefit” as defined in the Questar Plan that constitutes an “amount deferred” prior to January 1, 2005, as determined pursuant to Code Section 409A, Treas. Reg. Section 1.409A-6(a)(3), and any subsequent guidance (the “Pre-409A Benefit”). The Pre-409A Benefit shall remain subject to the applicable provisions of the Questar Plan as in effect immediately prior to the Effective Date as may be amended from time to time, except to the extent that any such modification would result in the Pre-409A Benefits becoming subject to compliance with Code Section 409A. The adoption of this Plan is not intended to constitute a “material modification” (within the meaning of Treas. Reg. Section 1.409A-6(a)(4)) with respect to the Pre-409A Benefits and any provision of the Plan that is deemed to be a material modification with respect to the Pre-409A Benefits shall have no force and effect unless and until amended to prevent such provision from being considered such a material modification (which amendment may be retroactive, if permitted). Distribution of a Transferred Employee’s Pre-409A Benefit shall be determined in accordance with the applicable provisions of the Questar Plan.

ARTICLE VII
DISTRIBUTION OF SUPPLEMENTAL RETIREMENT BENEFITS

7.1      Applicability of Section . This Article VII shall apply to the distribution of (i) a Participant’s Supplemental Retirement Benefits under Article V and (ii) such portion of a Transferred Employee’s Supplemental Retirement Benefit that constitutes a Pre-Spinoff Benefit and Post-Spinoff Benefit under Sections 6.2 and 6.3(a), respectively. Distribution of any portion of a Transferred Employee’s Supplemental Retirement Benefit that constitutes a Pre-409A Benefit shall be determined in accordance with terms of the Questar Plan.

7.2     Distribution Elections . A Participant’s distribution election with respect to any of the Supplemental Retirement Benefits described in this Article VII shall be made in accordance with Section 409A(a)(4) of the Code and the regulations thereunder.

(a)    Each Eligible Employee who first becomes a Participant in the Plan pursuant to Section 4.1(a), may elect the time and form of distribution of his or her Supplemental Retirement Benefits under Article V from among the options available under Sections 7.3 and 7.4 below, provided that such election is made within thirty (30) days after the date on which the Eligible Employee first becomes a Participant in the Plan.

(b)    Each Transferred Employee may elect the time and form of distribution of such portion of his or her Post-Spinoff Benefit for which benefit accruals commence on and after January 1, 2011, from among the options available under Sections 7.3 and 7.4 below, provided that such election is made on or prior to December 31, 2010.

(c)    Each Transferred Employee shall automatically be deemed to have elected the same time and form of distribution with respect to (i) such portion of his or her Post-Spinoff Benefits for which benefits accrue during the period beginning on and after the Effective Date and ending on December 31, 2010 and (ii) his or her Pre-Spinoff Benefits under this Plan, as the Transferred Employee had elected under the Questar Plan in accordance with its terms with respect to (x) such portion of his or her “Post 409A Benefits” (as defined in the Questar Plan) for which benefits accrued on or after January 1, 2010, and (y) such portion of his or her “Post 409A Benefits” (as defined in the Questar Plan) for which benefits accrued during the period beginning on or after January 1, 2005 and ending on December 31, 2009, respectively.

(d)     Default . If any Participant, including any Transferred Employee, fails to make a timely election under Section 7.2(a) or 7.2(b) respectively, or such election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive distribution of his or her Supplemental Retirement Benefits in the form of a lump sum within 60 days following the later of (i) the Participant’s 55 th birthday, or (ii) the earliest to occur of the Participant’s death, Disability, or Separation from Service.





(e)     Subsequent Changes in Time and Form of Distribution . A Participant may irrevocably elect, at least 12 months before a scheduled payment date, to delay the payment date for a minimum period of 5 years from the originally scheduled date of payment, provided that, such irrevocable election will be effective no earlier than 12 months after the date on which such election is made; further, provided, that any such election shall be made in accordance with Section 409A(a)(4)(C) of the Code and the Treasury Regulations thereunder, pursuant to procedures and rules prescribed by the Committee in its sole and absolute discretion.

7.3     Time of Distribution . A Participant may elect to receive distribution of his or her Supplemental Retirement Benefits under Article V, or if the Participant is a Transferred Employee, may elect to receive distribution of his or her Post-Spinoff Benefit for which benefit accruals commence on and after January 1, 2011, on the date of, or at a designated anniversary date following, the later of (i) the Participant’s 55 th birthday or (ii) the first to occur of any of the following (the “Distribution Event”):

(a)
the Participant’s Disability,

(b)
the Participant’s Separation from Service; or

(c)
the Participant’s death.

The Participant may designate a different distribution date for each of the events specified in clauses (a), (b), and (c), above; provided, however, that distribution of benefits cannot commence prior to the Participant’s 55 th birthday or later than the Participant’s 65 th birthday. The actual date on which distribution of benefits commences under this Section or Section 7.2(d), as applicable, shall be the “Benefit Commencement Date.”

7.4     Forms of Distribution . A Participant may elect to receive distribution of his or her Supplemental Retirement Benefits under Article V, or if the Participant is a Transferred Employee may elect to receive distribution of his or her Post-Spinoff Benefit for which benefit accruals commence on and after January 1, 2011, in any of the following forms:

(a)    a single lump sum; or

(b)    equal quarterly installments over a period of 1 to 10 years (with actuarial equivalence computed using the interest rate described in Section 7.5(b)(i) and without regard to the applicable mortality table referenced therein).

The Participant may designate a different form of distribution with respect to each of the different Distribution Events specified in clauses (a), (b), and (c) of Section 7.3.
    
7.5     Calculation of Supplemental Retirement Benefits .

(a)    A Participant’s Supplemental Retirement Benefits under Article V, or if the Participant is a Transferred Employee such portion of his or her Supplemental Retirement Benefit that constitutes a Pre-Spinoff Benefit and Post-Spinoff Benefit, shall be calculated in accordance with the respective principles set forth herein on the earlier to occur of (i) the Benefit Commencement Date or (ii) the first date as of which any benefits under the Retirement Plan commence to either the Participant or the Participant’s spouse or beneficiary (the “Calculation Date”). Such calculation shall take into account the Participant’s marital status and any related subsidies as of the date such benefit is determined, and shall, in the event that the Participant’s death is the Distribution Event, take into account the effect that the death of the Participant has on the calculation of Retirement Income.

(b)    The Committee shall calculate the distribution of a Participant’s Supplemental Retirement Benefits under Article V, or if the Participant is a Transferred Employee such portion of his or her Supplemental Retirement Benefit that constitutes a Pre-Spinoff Benefit and Post-Spinoff Benefit, as follows:

(i)    The lump-sum present value of the applicable Supplemental Retirement Benefit shall be determined on the Calculation Date pursuant to Section 7.5(a), using the standard mortality table referred to as the 1983 Group Annuity Mortality table and an interest rate equal to 80% of the average of the IRS 30-year Treasury Securities Rates for the six-month period preceding the Benefit Commencement Date (the “Lump Sum Present Value”).

(ii)    To the extent that the applicable Supplemental Retirement Benefit is payable after the Calculation Date, the Lump Sum Present Value of such benefit will be credited with monthly interest for the period commencing on the Calculation Date and ending on the date(s) of distribution, using the 30-year Treasury bond with the closest maturity date




(by month) preceding the date on which the interest is to be credited as quoted in the Wall Street Journal on the first business day of each month.

7.6     Effect of Death on Distributions .

(a)     Death After Distribution Event . In the event of a Participant’s death following a Distribution Event, the Participant’s Supplemental Retirement Benefits under Article V, or if the Participant is a Transferred Employee such portion of his or her Supplemental Retirement Benefit that constitutes a Pre-Spinoff Benefit and Post-Spinoff Benefit, to the extent remaining, shall be paid to the beneficiary selected by the Participant pursuant to Article XIV below at the same time and in the same amounts as would have been paid to the Participant had he or she not died.

(b)     Death as a Distribution Event . In the event that a Participant’s death is the Distribution Event for the Participant’s Supplemental Retirement Benefits under Article V, or if the Participant is a Transferred Employee such portion of his or her Supplemental Retirement Benefit that constitutes a Pre-Spinoff Benefit and Post-Spinoff Benefit, such benefits shall be paid to the beneficiary selected by the Participant pursuant to Article XIV below in accordance with the distribution election made (or deemed to have been made) by the Participant.

7.7     Six-Month Delay . Notwithstanding anything to the contrary in the Plan, no distribution shall be made to a Participant under the Plan on account of the Participant’s Separation from Service during the 6-month period following such Separation from Service to the extent that the Company determines that the Participant is a “specified employee” (as defined in Section 409A(a)(2)(B)(i) of the Code and the Treasury Regulations thereunder) at the time of such Separation from Service and that paying such amounts at the time or times indicated in the Plan would be a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code. If the payment of any such amounts is delayed as a result of the previous sentence, then on the first business day following the end of such 6-month period (or such earlier date upon which such amount can be paid under Section 409A of the Code without being subject to such additional taxes, including as a result of the Participant’s death), a lump-sum distribution shall be made to the Participant under the Plan equal to the cumulative amount that would have otherwise been payable to the Participant during such 6-month period, plus interest credited at the rate specified in Section 7.5(b)(ii) above.

ARTICLE VIII
FUNDING

The Supplemental Retirement Benefits payable under this Plan shall be paid by the Employers out of their general assets. In its discretion, the Board may establish a trust fund or make other arrangements to assure payment of the Supplemental Retirement Benefits. Until paid or made available to a Participant or beneficiary, all assets of any trust fund or any account established by the Company shall be solely the property of the Company and shall be subject to the claims of the general creditors of the Company by means of writs, orders of attachment, garnishment, levies of execution or any other manner in which a general creditor seeks to satisfy its claims against the Company. The Participants and their beneficiaries shall be unsecured creditors of the Company with respect to the Supplemental Retirement Benefits provided for in this Plan.

ARTICLE IX
ALLOCATION OF COSTS

The cost of Supplemental Retirement Benefits paid to or on behalf of any Participant shall be allocated to and be the responsibility of the Employers for which the Participant performed services, and shall be divided among the Employers in the same manner as contributions under the Retirement Plan are or would otherwise be divided with respect to such Participant.


ARTICLE X
ADMINISTRATION

10.1     Committee to Administer and Interpret Plan . The Committee shall administer the Plan and shall have all discretion and power necessary for that purpose. The Committee shall have the discretion, authority, and power to (i) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of this Plan and (ii) decide or resolve any and all questions including interpretations of this Plan and determinations of eligibility to participate and to receive distributions under this Plan, as may arise in connection with this Plan. Any individual serving on the Committee shall not vote or act on any matter relating solely to himself. When making a determination or calculation, the Committee shall be entitled to rely on information supplied by a Participant, beneficiary, or the Employer, as the case may be. If a trust has been established, the Committee shall direct the trustee concerning all payments from the trust fund in accordance with the provisions of the Plan and the trust agreement and shall




have such other powers in the administration of the trust fund as may be conferred upon it by the trust agreement. The Committee shall maintain all records of the Plan except records of the trust fund if a trust has been established.

10.2     Agents . In the administration of this Plan, the Committee may, from time to time, employ agents (including officers and other employees of the Company) and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to the Company.

10.3     Binding Effect of Decisions . The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.

10.4     Indemnity of Committee . The Company shall indemnify and hold harmless the members of the Committee and any employee to whom duties of the Committee may be delegated against any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan, except in the case of willful misconduct by the Committee, any of its members, or any such employee.

10.5     Employer Information . To enable the Committee to perform its functions, the Employer shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the date and circumstances of the Disability, death or Separation from Service of a Participant, as applicable, and such other pertinent information as the Committee may reasonably require.

10.6     Agent for Legal Process . The Committee shall be agent of the Plan for service of all legal process.



ARTICLE XI
CLAIMS PROCEDURE

11.1     Filing a Claim . All claims shall be filed in writing by the Participant, his or her beneficiary, or the authorized representative of either, by completing the procedures that the Committee requires. The procedures shall be reasonable and may include the completion of forms and the submission of documents and additional information. All claims under this Plan shall be filed in writing with the Committee according to the Committee’s procedures no later than one year after the occurrence of the event that gives rise to the claim. If the claim is not filed within the time described in the preceding sentence, the claim shall be barred.

11.2     Review of Initial Claim .

(a)     Initial Period for Review of the Claim . The Committee shall review all materials and shall decide whether to approve or deny the claim. If a claim is denied in whole or in part, written notice of denial shall be furnished by the Committee to the claimant within a reasonable time after the claim is filed but not later than ninety (90) days after the Committee receives the claim. The notice shall set forth the specific reason(s) for the denial, reference to the specific plan provisions on which the denial is based, a description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary, and a description of the Plan’s review procedures, including the applicable time limits and a statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following a denial of the appeal.

(b)     Extension . If the Committee determines that special circumstances require an extension of time for processing the claim, it shall give written notice to the claimant and the extension shall not exceed ninety (90) days. The notice shall be given before the expiration of the ninety (90) day period described in Section 11.2(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

11.3     Appeal of Denial of Initial Claim . The claimant may request a review upon written application, may review pertinent documents, and may submit issues or comments in writing. The claimant must request a review within a reasonable period of time prescribed by the Committee. In no event shall such a period of time be less than sixty (60) days.

11.4     Review of Appeal .





(a)     Initial Period for Review of the Appeal . The Committee shall conduct all reviews of denied claims and shall render its decision within a reasonable time, but not less than sixty (60) days of the receipt of the appeal by the Committee. The claimant shall be notified of the Committee’s decision in a notice, which shall set forth the specific reason(s) for the denial, reference to the specific plan provisions on which the denial is based, a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, and other information relevant to the claimant’s claim, and a statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following a denial of the appeal.

(b)     Extension . If the Committee determines that special circumstances require an extension of time for reviewing the appeal, it shall give written notice to the claimant and the extension shall not exceed sixty (60) days. The notice shall be given before the expiration of the sixty (60) day period described in Section 11.3 above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

11.5     Form of Notice to Claimant . The notice to the claimant shall be given in writing or electronically and shall be written in a manner calculated be understood by the claimant. If the notice is given electronically, it shall comply with the requirements of Department of Labor Regulation Section 2520.104b-1(c)(1)(i), (iii), and (iv).

11.6     Discretionary Authority of Committee . The Committee shall have full discretionary authority to determine eligibility, status, and the rights of all individuals under the Plan, to construe any and all terms of the Plan, and to find and construe all facts.

ARTICLE XII
AMENDMENT OR TERMINATION

The Board may at any time amend, modify, or terminate this Plan; provided, however, that no such amendment may alter in any way the time, form, or amount of benefits payable to any retired Participant or his or her surviving spouse or beneficiary, nor shall any such amendment, modification, or termination adversely affect the rights of any Participant to receive Supplemental Retirement Benefits earned prior to such action.

ARTICLE XIII
SUCCESSOR TO THE COMPANY

The Company shall require any successor or assign, whether direct or indirect, by purchase, merger, consolidation or otherwise, to all or substantially all of the business and/or assets of the Company, to assume and agree to pay any Supplemental Retirement Benefits under the Plan in the same manner and to the same extent that the Company would be required to perform if no such succession or assignment had taken place.

ARTICLE XIV
BENEFICIARIES

Each Participant may designate one or more beneficiaries to receive any lump sum or installment payments distributable under this Plan on or after the Participant’s death. In the absence of an effective beneficiary designation as to all or any part of any lump sum or installment payments, payment of such amounts shall be made to the Participant’s beneficiary under the QEP Resources, Inc. Employee Investment Plan, if any, or, if none, to the designated beneficiary under the Company’s basic life insurance plan, if any, or, if none, to the personal representative of the Participant’s estate.
ARTICLE XV
CHANGE IN CONTROL

15.1     Payments .

(a)     Change in Control . In the event that a Change in Control occurs and a Participant dies, incurs a Disability, or incurs a Separation from Service within two years following the date of such Change in Control, the Participant (or his or her beneficiary) shall receive a lump-sum payment of all accrued Supplemental Retirement Benefits within 30 days following the date of such death, Disability or Separation from Service, subject to the provisions of Section 7.7 hereof.

(b)     Calculation of Benefits . All Supplemental Retirement Benefits to which a Participant may be entitled under Section 15.1(a) shall be calculated in accordance with the applicable principles set forth in Articles V, VI and VII, except




that the date of distribution established under Section 15.1(a) shall be the Benefit Commencement Date for purposes of calculating such benefits. In the event that such Benefit Commencement Date precedes the Participant’s Earliest Retirement Age under the Retirement Plan, the Supplemental Retirement Benefits payable shall be reduced by the applicable actuarial and supplemental factors set forth in the Retirement Plan for lump sum distributions, and, to the extent that the Retirement Plan’s applicable actuarial or supplemental factors do not contemplate a distribution as of such Benefit Commencement Date, the Committee shall extrapolate such factors in good faith, in its sole discretion.

15.2     Change in Control Definition . A Change in Control of the Company shall be deemed to have occurred if: (i) any individual, entity, or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act”)) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, is or becomes the beneficial owner (as such term is used in Rule 13d-3 under the Exchange Act) of securities of the Company representing 25 percent or more of the combined voting power of the Company; or (ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, as of the Effective Date, constitute the Company’s Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation, relating to the election of directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds of the directors then still in office who either were directors on the Effective Date, or whose appointment, election or nomination for election was previously so approved or recommended; or (iii) the consummation of a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any corporation, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60 percent of the combined voting power of the securities of the Company or such surviving entity or its parent outstanding immediately after such merger or consolidation, or a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 25 percent or more of the combined voting power of the Company’s then outstanding securities; or (iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company or there is consummated for the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity, at least 60 percent of the combined voting power of the voting securities of which are owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale. In addition, if a Change in Control constitutes a payment event with respect to any payment under the Plan which provides for the deferral of compensation and is subject to Section 409A of the Code, the transaction or event described in clauses (i), (ii), (iii) and (iv) with respect to such payment must also constitute a “change in control event,” as defined in Treasury Regulation Section 1.409A-3(i)(5) to the extent required by Section 409A of the Code.

15.3     Payment of Legal Fees for Disputes Following a Change in Control . The Company agrees to pay as incurred, to the full extent permitted by law all legal fees and expenses which a Participant may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Participant, or others following a Change in Control regarding the validity or enforceability of, or liability under, any provision of this Plan or any guarantee of performance thereof (including as a result of any contest by the Participant about the amount of any payment pursuant to this Plan), plus in each case interest on any delayed payment computed at the interest rate set forth in Section 7.5(b)(ii). The foregoing right to legal fees and expenses shall not apply to any contest brought by a Participant (or other party seeking payment under the Plan) that is found by a court of competent jurisdiction to be frivolous or vexatious. To the extent that any payments or reimbursements provided to the Participant under this Section are deemed to constitute compensation to the Participant, such amounts shall be paid or reimbursed reasonably promptly, but not later than December 31 of the year following the year in which the expense was incurred.  The amount of any payments or expense reimbursements that constitute compensation in one year shall not affect the amount of payments or expense reimbursements constituting compensation that are eligible for payment or reimbursement in any subsequent year, and the Participant’s right to such payments or reimbursement of any such expenses shall not be subject to liquidation or exchange for any other benefit.

ARTICLE XVI
MISCELLANEOUS

16.1     No Assignment or Alienation .

(a)     General . Except as provided in subsection (b) below, the Supplemental Retirement Benefits provided for in this Plan shall not be anticipated, assigned (either at law or in equity), alienated, or be subject to attachment, garnishment, levy, execution or other legal or equitable process. Any attempt by any Participant or any beneficiary to anticipate, assign or alienate any portion of the Supplemental Retirement Benefits provided for in this Plan shall be null and void.





(b)     Exception: DRO . The restrictions of subsection (a) shall not apply to a distribution to an “alternate payee” (as defined in Code Section 414(p)) pursuant to a “domestic relations order” (“DRO”) within the meaning of Code Section 414(p)(1)(B). The Committee shall have the discretion, power, and authority to determine whether an order is a DRO. Upon a determination that an order is a DRO, the Committee shall direct the Employer or the Trustee, as the case may be, to distribute to the alternate payee or payees named in the DRO, as directed by the DRO.

16.2     Not An Employment Contract . This Agreement is not a contract of employment, and any Participant may terminate his or her employment, or his or her employment may be terminated by the Company, at any time, subject to the terms and conditions of any employment agreements between the Participant and the Employer.

16.3     Furnishing Information . A Participant or his or her beneficiary shall cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and the payment of benefits hereunder.

16.4     Payments to Incompetents . If the Committee determines in its discretion that a benefit under this Plan is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of his or her property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the account of the Participant and the Participant’s beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.

16.5     Court Order . The Committee is authorized to make any payments directed by court order in any action in which the Plan or the Committee has been named as a party.

16.6     Code Section 409A Savings Clause . The payments and benefits provided under the Plan are intended to be compliant with the requirements of Section 409A of the Code. Notwithstanding any provision of this Plan to the contrary, including, without limitation, Article XII hereof, in the event that the Company reasonably determines that any payments or benefits hereunder are not either exempt from or compliant with the requirements of Section 409A of the Code, the Company shall have the right adopt such amendments to this Plan or adopt such other policies and procedures (including amendments, policies and procedures with retroactive effect), or take any other actions, that are necessary or appropriate (i) to preserve the intended tax treatment of the payments and benefits provided hereunder, to preserve the economic benefits with respect to such payments and benefits, and/or (ii) to exempt such payments and benefits from Section 409A of the Code or to comply with the requirements of Section 409A of the Code and thereby avoid the application of penalty taxes thereunder; provided, however, that this Section 16.6 does not, and shall not be construed so as to, create any obligation on the part of the Company to adopt any such amendments, policies or procedures or to take any other such actions or to indemnify any Participant for any failure to do so.


16.7     Distribution in the Event of Taxation . If, for any reason, all or any portion of a Participant’s benefits under this Plan becomes subject to tax under Code Section 409A prior to receipt, a Participant may petition the Committee for a distribution of that portion of his or her benefit that has become taxable, or such lesser amount as may be permitted by Code Section 409A. Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Employer, or if applicable, the trustee, shall distribute to the Participant immediately available funds in an amount equal to the taxable portion of his or her benefit or such lesser amount as may be permitted by Code Section 409A (which amount shall not exceed a Participant’s unpaid Supplemental Retirement Benefit under the Plan). If the petition is granted, the tax liability distribution shall be made within 90 days of the date when the Participant’s petition is granted. Such a distribution shall affect and reduce the benefits to be paid under this Plan. Any distribution under this Section 16.7 must meet the requirements of Code Section 409A and related Treasury guidance or Regulations.

16.8     Governing Law . To the extent not preempted by federal law, this Plan shall be governed by the laws of the State of Colorado, without regard to conflicts of law principles.

[ Signature Page Follows ]





I hereby certify that this restated QEP Resources, Inc. Supplemental Executive Retirement Plan was duly adopted by the Board of Directors of QEP Resources, Inc. on June 1, 2015.    

Executed on this first day of June, 2015.

By: /s/ Richard J. Doleshek
Richard J. Doleshek
Executive Vice President and Chief Financial Officer






Exhibit 10.2


QEP RESOURCES, INC.

DEFERRED COMPENSATION WRAP PLAN




incorporating the:

Deferred Compensation Program
401(k) Supplemental Program









QEP RESOURCES, INC.
DEFERRED COMPENSATION WRAP PLAN

ARTICLE 1
INTRODUCTION

1.1     Purpose . QEP Resources, Inc. hereby restates this QEP Resources, Inc. Deferred Compensation Wrap Plan (the “Plan” or “Wrap Plan”) effective January 1, 2016. This Plan was created in order to provide specified benefits to a select group of management and highly compensated employees and to allow such employees to defer the receipt of compensation. The Plan consists of a common Deferred Compensation Wrap Plan containing definitions and other operative provisions and two separate component Programs - the Deferred Compensation Program and the 401(k) Supplemental Program.

1.2     Status of Plan . This Plan and its component Programs are intended to constitute two unfunded, nonqualified deferred compensation arrangements for the purpose of providing deferred compensation to “a select group of management or highly-compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended. The Plan and its component Programs are also intended to comply with Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations and guidance promulgated thereunder. Finally, each of the component Programs is intended to qualify as a separate “plan, program, or arrangement” for purposes of 4 U.S.C. 114, thus making payments under the 401(k) Supplemental Program subject to state income tax solely of the state in which the recipient of the payment resides or is domiciled at the time payment is made. Notwithstanding any other provision herein, this Plan and its component Programs shall be interpreted, operated and administered in a manner consistent with these intentions.
    
ARTICLE 2
DEFINITIONS

For purposes of the Plan and each component Program established under the Plan, the following terms or phrases shall have the following indicated meanings, unless the context clearly requires otherwise:

2.1    “ 401(k) Supplemental Program ” means the component benefit program of this Plan attached hereto as Exhibit B.

2.2    “ Account ” or “ Account Balance ” means, for each Participant, the account or accounts established for his or her benefit under each Program, which records the credit on the records of the Employer equal to the amounts set aside under the Program and the deemed earnings, if any, credited to such account. The Account Balance shall be a bookkeeping entry only and shall be used solely as a device for the measurement and determination of the amounts to be paid to a Participant, or his or her designated Beneficiary, pursuant to this Plan and its component Programs.

2.3    “ Affiliated Company ” means any entity that is treated as the same employer as the Company under Sections 414(b), (c), (m), or (o) of the Code, any entity required to be aggregated with the Company pursuant to regulations adopted under Code Section 409A, or any entity otherwise designated as an Affiliated Company by the Company.

2.4    “ Beneficiary ” means that person or persons who become entitled to receive a distribution of benefits under the component Programs in the event of the death of a Participant prior to the distribution of all benefits to which he or she is entitled.

2.5    “ Board ” means the Board of Directors of the Company.

2.6    “ Change in Control ” shall be deemed to have occurred if: (i) any individual, entity, or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act”)) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, is or becomes the beneficial owner (as such term is used in Rule 13d-3 under the Exchange Act) of securities of the Company representing 30 percent or more of the combined voting power of the Company; or (ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, as of the Effective Date, constitute the Company’s Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation, relating to the election of directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds of the directors then still in office who either were directors on the Effective Date, or whose appointment, election or nomination for election was previously so approved or recommended; or (iii) there is consummated a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any corporation, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent




(either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60 percent of the combined voting power of the securities of the Company or such surviving entity or its parent outstanding immediately after such merger or consolidation, or a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 30 percent or more of the combined voting power of the Company’s then outstanding securities; or (iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company or there is consummated the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity, at least 60 percent of the combined voting power of the voting securities of which are owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale. In addition, if a Change in Control constitutes a payment event with respect to any payment under the Plan which provides for the deferral of compensation and is subject to Section 409A of the Code, the transaction or event described in clauses (i), (ii), (iii) and (iv) with respect to such payment must also constitute a “change in control event,” as defined in Treasury Regulation Section 1.409A-3(i)(5) before any such payment can be made.

2.7    “ Code ” means the Internal Revenue Code of 1986, as amended.

2.8    “ Committee ” means the Compensation Committee of the Board or such other person or entity to which any responsibilities may be delegated by such Committee.

2.9    “ Common Stock ” means the no par value common stock of the Company.

2.10    “ Company ” means QEP Resources, Inc., a corporation organized and existing under the laws of the State of Delaware, or its successor or successors.

2.11    “ Compensation ” means:

(a)     Deferred Compensation Program . For purposes of the Deferred Compensation Program, the total earnings paid by an Employer to an Employee and properly reportable on IRS Form W-2 for an applicable Plan Year (including payments under annual incentive compensation plans) and all amounts that are not included in such Employee’s gross income for federal income tax purposes solely on account of his or her election to have compensation reduced pursuant to the Plan, a qualified cash or deferred arrangement described in Section 401(k) of the Code, a cafeteria plan as defined in Section 125 of the Code, or a qualified transportation fringe benefit plan as defined in Section 132(f)(4) of the Code, but excluding the following forms of compensation, unless otherwise determined by the Committee: the Employer’s cost for any public or private employee benefit plan, any income recognized by the Employee as a result of exercising stock options, moving expenses, loan forgiveness, welfare benefits, and severance payments.

(b)     401(k) Supplemental Program . For purposes of the 401(k) Supplemental Program, the same meaning as Benefit Compensation as defined in the Investment Plan, but (i) without regard to the Compensation Limit and (ii) including all amounts that are not included in such Employee’s gross income for federal income tax purposes solely on account of his or her election to make Deferral Contributions to the 401(k) Supplemental Program.

2.12    “ Compensation Limit ” means the annual limit of compensation that may be taken into account for purposes of providing benefits under a tax-qualified retirement plan pursuant to Section 401(a)(17) of the Code, as adjusted from time to time.

2.13    “ Deferral Contributions ” means that portion of a Participant’s Compensation that is deferred by a Participant pursuant to the Programs.

2.14    “ Deferred Compensation Program ” means the component benefit program of this Plan attached hereto as Exhibit A.

2.15    “ Deferred Compensation Sub-Account ” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.16    “ Disability ” means a condition that renders a Participant unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, as described in Treas. Reg. Section 1.409A-3(i)(4)(i)(A). A Participant shall not be considered to be disabled unless the Participant furnishes proof of the existence of such disability in such form and manner as may be required by regulations promulgated under, or applicable to, Code Section 409A.





2.17    “ Eligible Employee ” means any Employee who meets the eligibility requirements set forth in the applicable Program.

2.18    “ Employee ” means any individual who is among a select group of management or highly compensated employees (as determined in accordance with Section 3401(c) of the Code and the Treasury Regulations thereunder) of an Employer.

2.19    “ Employer ” means the Company and each Affiliated Company that consents to the adoption of the Plan.

2.20    “ ERISA ” shall mean the Employee Retirement Income Security Act of 1974, as amended.

2.21    “ Fair Market Value ” means the closing benchmark price of the Company’s Common Stock as reported on the composite tape of the New York Stock Exchange for any given valuation date, or if the Common Stock shall not have been traded on such date, the closing price on the next preceding day on which a sale occurred.

2.22    “ Investment Plan ” means the QEP Resources, Inc. Employee Investment Plan, as amended from time to time, or any successor plan.

2.23    “ Matching Contributions ” means Employer contribution amounts credited to Participants under the Deferred Compensation Program and 401(k) Supplemental Program in addition to (and made on account of) the Participants’ Deferral Contributions under such Programs.

2.24    “ Matching Contribution Sub-Account ” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.25    “ Participant ” means any individual who has commenced participation in the Plan and any of its component Programs in accordance with Article 3.

2.26    “ Plan ” or “ Wrap Plan ” means this QEP Resources, Inc. Deferred Compensation Wrap Plan, as amended or restated from time to time.

2.27    “ Plan Year ” means the calendar year.

2.28    “ Program ” means the Deferred Compensation Program and the 401(k) Supplemental Program, or either of them, as the context may require.

2.29    “ Separation from Service ” means a Participant’s termination or deemed termination from employment with the Employer.  For purposes of determining whether a Separation from Service has occurred, the employment relationship is treated as continuing intact while the Participant is on military leave, sick leave or other bona fide leave of absence if the period of such leave does not exceed six months, or if longer, so long as the Participant retains a right to reemployment with his Employer under an applicable statute or by contract.  For this purpose, a leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the Participant will return to perform services for the Employer.  If the period of leave exceeds six months and the Participant does not retain a right to reemployment under an applicable statute or by contract, the employment relationship will be deemed to terminate on the first date immediately following such six-month period.  For purposes of this Plan, a Separation from Service occurs at the date as of which the facts and circumstances indicate either that, after such date: (i) the Participant and Employer reasonably anticipate the Participant will perform no further services for the Company or an Affiliate (whether as an employee or an independent contractor), or (ii) that the level of bona fide services the Participant will perform for the Company or any Affiliate (whether as an employee or independent contractor) will permanently decrease to no more than 20 percent of the average level of bona fide services performed over the immediately preceding 36-month period or, if the Participant has been providing services to the Company or an Affiliate for less than 36 months, the full period over which the Participant has rendered services, whether as an employee or independent contractor.  The determination of whether a Separation from Service has occurred shall be governed by the provisions of Treasury Regulation section 1.409A-1, as amended, taking into account the objective facts and circumstances with respect to the level of bona fide services performed by the Participant after a certain date.

2.30    “ Unforeseeable Emergency ” means a severe financial hardship to a Participant resulting from (a) an illness or accident of the Participant, the Participant’s spouse, Beneficiary or dependant (within the meaning of section 152 of the Code, without regard to section 152(b)(1), (b)(2) and (d)(1)(B)); (b) the loss of the Participant’s property due to casualty; or (c) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.






ARTICLE 3
ELIGIBILITY; PARTICIPATION

3.1     Eligibility . Eligibility to participate in the Plan shall be determined for each program as provided in Article 2 thereof.

3.2     Enrollment and Commencement of Deferrals . Except as provided below with regard to automatic enrollment in the 401(k) Supplemental Program, each Eligible Employee who wishes to participate in the Plan for a Plan Year must make an irrevocable election to make Deferral Contributions for the Plan Year by timely completing, executing, and returning to the Committee such election forms or other enrollment materials, including electronic enrollment, as the Committee requires on or prior to December 31 st of the prior Plan Year, or such other earlier date as the Committee establishes in its sole and absolute discretion.

If an Eligible Employee fails to timely complete, execute and return such election forms or other enrollment materials, or if the Eligible Employee is not eligible to make Deferral Contributions but is eligible to receive Transition Credits under the 401(k) Supplemental Program, the Eligible Employee shall be automatically enrolled in the 401(k) Supplemental Program as provided in Section 4.1(a), but shall not participate in the Deferred Compensation Program until the first day of the first Plan Year beginning after the date on which he or she first becomes eligible and timely completes, executes and returns such election forms or other enrollment materials to the Committee.

3.3     Failure of Eligibility . If the Committee determines, in its sole and absolute discretion, that any Participant should no longer qualify to participate, the Participant shall cease to be an active Participant in the Plan and future contributions to the Plan made by or on behalf of the Participant shall cease as of the date of such determination by the Committee. The Committee’s determination hereunder shall be final and binding on all persons.

ARTICLE 4
ELECTIONS

4.1     Deferral Elections .    Any deferral election under the Plan and its component Programs shall be made in accordance with Section 409A(a)(4)(B) of the Code and the regulations thereunder.

(a)     First Year of Plan Participation . In connection with a Participant’s enrollment in the Plan pursuant to Section 3.2, the Participant, unless he or she is a Participant who is eligible only to receive Transition Credits under the 401(k) Supplemental Program, shall make an irrevocable election to defer Compensation in accordance with the terms of the component Programs for which he or she is eligible, which election shall apply to the Plan Year in which the Participant commences participation. A Participant may elect to defer Compensation only with respect to services performed for periods following the date of such election. The Participant’s initial deferral election under this Section 4.1(a) shall continue to apply for all succeeding Plan Years unless and until revoked or modified pursuant to Section 4.1(b), below. If the Participant fails to timely complete, execute and return such forms or other enrollment materials as required by the Committee in accordance with Section 3.2, then the Participant shall be deemed to have elected to make the Deferral Contributions permitted under the 401(k) Supplemental Program for the Plan Year in which the Participant commences participation and shall not be permitted to make any Deferral Contributions under the Deferred Compensation Program for such Plan Year.
(b)     Subsequent Plan Years . For each succeeding Plan Year, the Participant, if eligible to make Deferral Contributions, may, prior to December 31 st of the immediately preceding Plan Year (or such earlier deadline as is established by the Committee in its sole discretion) make an irrevocable election to initially defer Compensation under the Deferred Compensation Program for succeeding Plan Years, or to modify or revoke his or her existing elections to defer Compensation under either or both of the Programs for succeeding Plan Years. All such elections shall be made in accordance with the terms of the Programs and shall remain in effect for all succeeding Plan Years unless timely revoked or modified by the Participant in accordance with this Section. Any such modification shall apply prospectively only and shall not apply to Compensation previously deferred under either or both of the Programs.
(c)     Performance-Based Compensation . The Committee may, in its sole discretion, determine that an irrevocable deferral election pertaining to Compensation that constitutes “performance-based compensation” (as defined in Treas. Reg. Section 1.409A-1(e)) may be made no later than six (6) months before the end of the performance service period, provided that the Participant performs services continuously from the later of the beginning of the performance period or the date upon which the performance criteria are established through the date upon which the Participant makes a deferral election for such compensation; provided, further that in no event shall an election to defer performance-based compensation be permitted after such compensation has become readily ascertainable. Any deferral election under this Section 4.1(c) shall be made in accordance with Treas. Reg. Section 1.409A-2(a)(8).




        
(d)     Compensation Subject to Risk of Forfeiture . With respect to
Compensation (i) to which a Participant has a legally binding right to payment in a subsequent year, and (ii) that is subject to a forfeiture condition requiring the Participant’s continued services for a period of at least twelve (12) months from the date the Participant obtains the legally binding right to such payment, the Committee may, in its sole discretion, determine that an irrevocable election to defer such Compensation may be made no later than the 30 th day after the Participant obtains the legally binding right to the Compensation, provided that the election is made at least twelve (12) months in advance of the earliest date at which the forfeiture condition could lapse. Any deferral election under this Section 4.1(d) shall be made in accordance with Treas. Reg. Section 1.409A-2(a)(5).

Any election(s) made in accordance with this Section shall be irrevocable; provided, however, that if the Committee permits Participants to make a deferral election for “performance-based compensation” or “compensation subject to a substantial risk of forfeiture” by the deadline(s) described above, it may, in its sole discretion, and in accordance with Code Section 409A and related Treasury guidance or regulations, permit a Participant to subsequently change his or her elections for such Compensation no later than the deadlines established by the Committee pursuant to Section 4.1(c) or 4.1(d), above.

4.2     Elections as to Time and Form of Payment .    In connection with a Participant’s enrollment in the Plan pursuant to Section 3.2, the Participant shall also make the following elections with respect to each Program under the Plan:
(a)     Deferred Compensation Program . If eligible to participate in the Deferred Compensation Program for the Plan Year in which the Participant commences participation under the Plan, the Participant shall make an irrevocable election (from the options available under Article 6 below) as to the time and form of payment of all deferrals (in the form of Deferral and/or Matching Contributions) credited to his or her Account under the Deferred Compensation Program for such Plan Year (including earnings thereon). If the Participant fails to make such election, or such election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive a lump sum distribution as soon as legally and administratively practicable following the earliest to occur of the Participant’s (i) Separation from Service, (ii) Disability, or (iii) death. Except in the case of an election to receive an in-service distribution pursuant to Section 6.1(b)(iii), the Participant’s election (or deemed election) shall continue to apply for succeeding Plan Years unless and until the election is modified pursuant to Section 4.2(c), below.
(b)     401(k) Supplemental Program . The Participant shall make an irrevocable election as to the time and form of payment of all deferrals (in the form of Deferral Contributions, Matching Contributions or Transition Credits) credited to his or her Account Balance under the 401(k) Supplemental Program from the options available under Section 6 below. If the Participant fails to make such election, or if such election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive a lump-sum distribution as soon as legally and administratively practicable following the earliest to occur of the Participant’s (i) Separation From Service, (ii) Disability, or (iii) death.

(c)    A Participant may make an irrevocable election to modify his or her existing elections as to the time and form of payment of any future Deferral Contributions, Matching Contributions and Transition Credits credited to his or her Account Balance (and related earnings) under either or both of the Programs for succeeding Plan Years. Such election shall be made in accordance with the terms of the Deferred Compensation Program and 401(k) Supplemental Program and Article 6 below, and except in the case of an election to receive an in-service distribution pursuant to Section 6.1(b)(iii), which election must be made separately for each Plan Year, the election shall remain in effect for all succeeding Plan Years unless and until timely modified by the Participant in accordance with this Section. Any such modification shall apply prospectively only and shall not apply to Deferral Contributions, Matching Contributions or Transition Credits previously credited under the Program (or any earnings thereon).
        
4.3     Election Forms . All elections shall be made on forms, including electronic forms, provided by the Committee and must be filed with the Company’s Vice President of Human Resources in order to be valid.
ARTICLE 5
ACCOUNT STATEMENTS

At least once a year within 60 days after the end of each Plan Year, a statement shall be sent to each Participant showing his or her Account Balance for each Program as of the last day of the Plan Year. The statement shall also include the Deferral Contributions made by the Participant to each Program for the Plan Year, along with any Matching Contributions and Transition Credits credited to the Participant’s Account and the investment gains or losses (including reinvested dividends) credited during the Plan Year.





ARTICLE 6
DISTRIBUTIONS

6.1     Permissible Times and Forms of Payments . A Participant may elect to receive his or her Account under the Deferred Compensation Program or his or her Account under the 401(k) Supplemental Program pursuant to an election form filed in accordance with Article 4 at the following times and in the following forms:

(a)     Time of Distribution . A Participant may elect to receive a distribution as of the date of, or at a designated anniversary date following, the first to occur of the Participant’s Disability, Separation from Service, death or in the case of a distribution from the Participant’s Deferred Compensation Sub-Account, at a designated time or times specified by the Participant in his or her election forms, which shall not be earlier than 24 months from the date of deferral of the amount to be distributed.

(b)     Form of Distribution . A Participant may elect to receive a distribution of his or her Account in any of the following forms:

(i)
a single lump sum;

(ii)
up to ten (10) annual installments; or

(iii)    in the case of an in-service distribution from a Participant’s Deferred Compensation Sub-Account a single lump sum of the entire Account Balance attributable to the Participant’s Deferral Contributions made in one or more Plan Years, as designated by the Participant.

(c)     Subsequent Deferrals . Notwithstanding an actual or deemed election as to the timing of the distribution of a Participant’s Account, at such times and in such manner as the Committee may determine, a Participant may make an irrevocable election to delay the payment, or the commencement of payment, of his or her Account, but only if such election (i) is made not less than 12 months before the date the payment or commencement of installment payments is scheduled to be paid or to begin; (ii) shall not take effect until at least 12 months after the date the election is made; and (iii) relating to a payment not being made on account of death, Disability or an Unforeseeable Emergency, delays the payment or commencement of payments for a period of at least five years from the date the payment or series of payments was scheduled to be paid or begin.

(d)     Unforeseeable Emergency Distributions . A participant may request that a distribution of amounts credited to his Account may be made due to an Unforeseeable Emergency.

(i) In no event shall a distribution due to an Unforeseeable Emergency exceed the balance of the Participant’s Account, determined as of the end of the month immediately preceding the date of the distribution, less any amounts distributed from or charged to the Participant Account since such date. The Committee may promulgate uniform rules regarding the effective date of any distribution, minimum amounts to be distributed and the frequency of distributions.
(ii) A distribution may be made pursuant to this Section 6.1(d) due to an Unforeseeable Emergency only if the Participant satisfies the Committee that the Participant has an Unforeseeable Emergency and that the distribution is reasonably necessary in order to satisfy the Unforeseeable Emergency.
(iii) A distribution because of an Unforeseeable Emergency may be made for one of the reasons listed in subparagraphs (A) through (C) of this paragraph (iii):
(A) Medical expenses, including non-refundable deductibles and the cost of prescription drugs; or
(B) The need to pay for funeral expenses of a spouse, Beneficiary or a dependent as defined; or
(C) The need to prevent the imminent eviction of the Participant from his principal residence or foreclosure on the mortgage on the Participant’s principal residence.
(iv) A distribution will be considered to be reasonably necessary to satisfy an emergency need of a Participant only if the need may not be satisfied from other resources that are reasonably available to the Participant and the distribution does not exceed the amount needed to satisfy the need. The Committee shall consider all relevant facts and circumstances in determining whether a distribution is necessary in order to satisfy an emergency need. Generally, a distribution shall be deemed necessary if the Participant demonstrates to the Committee that the need cannot be relieved through reimbursement or compensation from insurance or otherwise, by the liquidation of the Participant’s assets (to the extent that such liquidation would not itself cause severe financial hardship) or by cessation of Deferral Contributions under the Plan. A distribution will be deemed to be reasonably necessary to satisfy the emergency need of a Participant only if the distribution is not in excess of the amount reasonable necessary




to satisfy the emergency need of the Participant (which may include amounts necessary to pay any federal, state, local or foreign income taxes or penalties reasonably anticipated to result from the distribution).

6.2     Change in Control . Notwithstanding any election made by the Participant under Section 6.1, in the event of a Change in Control, all amounts then credited to the Participant’s Account shall be distributed to the Participant in a single lump sum within 60 days following the date of such Change in Control.

6.3     Calculation of Distributions .

(a)     Lump Sum . All lump sum distributions shall be based on the value of the Participant’s Account as of a valuation date as soon as administratively feasible preceding the date distribution is made, in accordance with rules established by the administrator.

(b)     Installment Distributions . Under an installment payout, the amount to be distributed in each installment payment shall be determined by dividing the value of the Participant’s Accounts being paid in installments as of a valuation date preceding the date of each distribution by the number of installment payments remaining to be made, in accordance with rules established by the administrator.  In the event of the death of the Participant prior to the full payment of his Accounts being paid in installments, payments will continue to be made to his Beneficiary in the same manner as would have been payable to the Participant.

6.4     Six-Month Delay . Notwithstanding anything to the contrary in the Plan, no distribution shall be made to a Participant under the Plan on account of the Participant’s Separation from Service during the 6-month period following such Separation from Service to the extent that the Company determines that the Participant is a “specified employee” (as defined in Section 409A(a)(2)(B)(i) of the Code and the Treasury Regulations thereunder) at the time of such Separation from Service and that paying such amounts at the time or times indicated in the Plan would be a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code. If the payment of any such amounts is delayed as a result of the previous sentence, then on the first business day following the end of such 6-month period (or such earlier date upon which such amount can be paid under Section 409A of the Code without being subject to such additional taxes, including as a result of the Participant’s death), a lump-sum distribution shall be made to the Participant under the Plan equal to the cumulative amount that would have otherwise been payable to the Participant during such 6-month period.

6.5     Method of Payment . All payments under the Plan shall be made in cash.

ARTICLE 7
ADMINISTRATION

7.1     Committee to Administer and Interpret Plan and Component Programs . The Committee or its designee shall administer the Plan and its component Programs and shall have all discretion and power necessary for that purpose. The Committee shall have the discretion, authority, and power to (i) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and its component Programs and (ii) decide or resolve any and all questions that may arise in connection with this Plan and its component Programs, including interpretations of the Plan and its component Programs and determinations of eligibility to participate and to receive distributions under the Plan and its component Programs. Any individual serving on the Committee, or anyone delegated responsibilities by the Committee, shall not vote or act on any matter relating solely to himself. When making a determination or calculation, the Committee shall be entitled to rely on information supplied by a Participant, Beneficiary, or the Employer, as the case may be. The Committee shall maintain all records of the Plan and its component Programs.
7.2     Agents . In the administration of this Plan and its component Programs, the Committee may, from time to time, employ agents (including officers and other employees of the Company) and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to the Company.
7.3     Binding Effect of Decisions . The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and its component Programs and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan and its component Programs.
7.4     Indemnity of Committee . The Company shall indemnify and hold harmless the members of the Committee and any employee to whom duties of the Committee may be delegated against any and all claims, losses, damages, expenses or liabilities




arising from any action or failure to act with respect to this Plan and its component Programs, except in the case of willful misconduct by the Committee, any of its members, or any such employee.
7.5     Agent for Legal Process . The Committee shall be agent of the Plan and its component Programs for service of all legal process.

ARTICLE 8
CLAIMS PROCEDURE

8.1     Filing a Claim . All claims under this Plan and its component Programs shall be filed in writing or electronically by the Participant, his or her Beneficiary, or the authorized representative of either, by completing the procedures that the Committee requires. The procedures shall be reasonable and may include the completion of forms and the submission of documents and additional information. All claims shall be filed in writing or electronically with the Committee according to the Committee’s procedures no later than one year after the occurrence of the event that gives rise to the claim. If the claim is not filed within the time described in the preceding sentence, the claim shall be barred.

8.2     Review of Initial Claim .
(a)     Initial Period for Review of the Claim . The Committee shall review all materials and shall decide whether to approve or deny the claim. If a claim is denied in whole or in part, written notice of denial shall be furnished by the Committee to the claimant within a reasonable time after the claim is filed but not later than ninety (90) days after the Committee receives the claim. The notice shall set forth the specific reason(s) for the denial, reference to the specific Plan or Program provisions on which the denial is based, a description of any additional material or information necessary for the claimant to perfect his or her claim and an explanation of why such material or information is necessary, and a description of the Plan’s review procedures, including the applicable time limits and a statement of the claimant’s right to bring a civil action under ERISA section 502(a) following a denial of the appeal.
(b)     Extension . If the Committee determines that special circumstances require an extension of time for processing the claim, it shall give written notice to the claimant and the extension shall not exceed ninety (90) days. The notice shall be given before the expiration of the ninety (90) day period described in Section 8.2(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.
8.3     Appeal of Denial of Initial Claim . The claimant may request a review upon written application, may review pertinent documents, and may submit issues or comments in writing. The claimant must request a review within a reasonable period of time prescribed by the Committee. In no event shall such a period of time be less than sixty (60) days.
8.4     Review of Appeal .
(a)     Initial Period for Review of the Appeal . The Committee shall conduct all reviews of denied claims and shall render its decision within a reasonable time, but not to exceed sixty (60) days from the receipt of the appeal by the Committee. The claimant shall be notified of the Committee’s decision in a notice, which shall set forth the specific reason(s) for the denial, reference to the specific Plan or Program provisions on which the denial is based, a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, and other information relevant to the claimant’s claim, and a statement of the claimant’s right to bring a civil action under ERISA section 502(a) following a denial of the appeal.
(b)     Extension . If the Committee determines that special circumstances require an extension of time for reviewing the appeal, it shall give written notice to the claimant and the extension shall not exceed sixty (60) days. The notice shall be given before the expiration of the sixty (60) day period described in Section 8.4(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.
8.5     Form of Notice to Claimant . The notice to the claimant shall be given in writing or electronically and shall be written in a manner calculated to be understood by the claimant. If the notice is given electronically, it shall comply with the requirements of Department of Labor Regulation Section 2520.104b-1(c)(1)(i), (iii), and (iv).
8.6     Discretionary Authority of Committee . The Committee shall have full discretionary authority to determine eligibility, status, and the rights of all individuals under the Plan and its component Programs, to construe any and all terms of the Plan and its component Programs, and to find and construe all facts.
ARTICLE 9
AMENDMENT AND TERMINATION OF PLAN





The Board may at any time amend, modify, or terminate this Plan and its component Programs; provided, however, that no such amendment may reduce any Participant’s Account Balances under the Plan or any component Program as it existed prior to the date of such amendment or termination.

ARTICLE 10
MISCELLANEOUS

10.1     Source of Payments . Each participating Employer will pay all benefits for its Employees arising under this Plan and its component Programs, and all costs, charges and expenses relating to such benefits, out of its general assets.

10.2     No Assignment or Alienation .

(a)     General . Except as provided in subsection (b) below, the benefits provided for in this Plan and its component Programs shall not be anticipated, assigned (either at law or in equity), alienated, or be subject to attachment, garnishment, levy, execution or other legal or equitable process. Any attempt by any Participant or any Beneficiary to anticipate, assign or alienate any portion of the benefits provided for in this Plan or its component Programs shall be null and void.

(b)     Exception: DRO . The restrictions of subsection (a) shall not apply to a distribution to an “alternate payee” (as defined in Code Section 414(p)) pursuant to a “domestic relations order” (“DRO”) within the meaning of Code Section 414(p)(1)(B). The Committee shall have the discretion, power, and authority to determine whether an order is a DRO. Upon a determination that an order is a DRO, the Committee shall direct the Employer to distribute to the alternate payee or payees named in the DRO, as directed by the DRO.
10.3     Beneficiaries . A Participant shall have the right, in accordance with forms and procedures established by the Committee, to designate one or more beneficiaries to receive some or all amounts payable under each of the component Programs after the Participant’s death. The Participant need not designate the same Beneficiary for each Program under the Plan. In the absence of an effective beneficiary designation, all payments shall be made to the beneficiary designated by the Participant (or deemed by law to be designated) under the terms of the Investment Plan.

10.4     No Creation of Rights . Nothing in this Plan or its component Programs shall confer upon any Participant the right to continue as an Employee of an Employer. The right of a Participant to receive a cash distribution shall be an unsecured claim against the general assets of his or her Employer. Nothing contained in this Plan or its component Programs nor any action taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between the Company and the Participants, Beneficiaries, or any other persons. All Accounts under the Plan and its component Programs shall be maintained for bookkeeping purposes only and shall not represent a claim against specific assets of any Employer.

10.5     Furnishing Information . A Participant or his or her Beneficiary shall cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and its component Programs and the payment of benefits thereunder.

10.6     Payments to Incompetents . If the Committee determines in its discretion that a benefit under this Plan or any of its component Programs is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of his or her property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the account of the Participant and the Participant’s Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan and its component Programs for such payment amount.

10.7     Court Order . The Committee is authorized to make any payments directed by court order in any action in which the Plan or the Committee has been named as a party.

10.8     Code Section 409A Savings Clause . The payments and benefits provided under the Plan and its component Programs are intended to be compliant with the requirements of Section 409A of the Code. Notwithstanding any provision of this Plan to the contrary, including, without limitation, Article 9 hereof, in the event that the Company reasonably determines that any payments or benefits hereunder are not either exempt from or compliant with the requirements of Section 409A of the Code, the Company shall have the right adopt such amendments to this Plan and its component Programs or adopt such other policies and procedures (including amendments, policies and procedures with retroactive effect), or take any other actions, that are necessary or appropriate (i) to preserve the intended tax treatment of the payments and benefits provided hereunder, to preserve the economic benefits with respect to such payments and benefits, and/or (ii) to exempt such payments and benefits from Section 409A of the




Code or to comply with the requirements of Section 409A of the Code and thereby avoid the application of penalty taxes thereunder; provided, however, that this Section 10.8 does not, and shall not be construed so as to, create any obligation on the part of the Company to adopt any such amendments, policies or procedures or to take any other such actions or to indemnify any Participant for any failure to do so.

10.9     Attorney Fees; Interest . The Company agrees to pay as incurred, to the full extent permitted by law all legal fees and expenses which a Participant may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Participant, or others following a Change in Control regarding the validity or enforceability of, or liability under, any provision of this Plan or any guarantee of performance thereof (including as a result of any contest by the Participant about the amount of any payment pursuant to this Plan), plus in each case interest on any delayed payment at the applicable Federal rate provided for in Section 7872(f)(2)(A) of the Code. The foregoing right to legal fees and expenses shall not apply to any contest brought by a Participant (or other party seeking payment under the Plan) that is found by a court of competent jurisdiction to be frivolous or vexatious. To the extent that any payments or reimbursements provided to the Participant under this Section are deemed to constitute compensation to the Participant, such amounts shall be paid or reimbursed reasonably promptly, but not later than December 31 of the year following the year in which the expense was incurred.  The amount of any payments or expense reimbursements that constitute compensation in one year shall not affect the amount of payments or expense reimbursements constituting compensation that are eligible for payment or reimbursement in any subsequent year, and the Participant’s right to such payments or reimbursement of any such expenses shall not be subject to liquidation or exchange for any other benefit.

10.10     Distribution in the Event of Taxation . If, for any reason, all or any portion of a Participant’s benefits under this Plan or any of its component Programs becomes subject to federal income tax with respect to the Participant prior to receipt, a Participant may petition the Committee for a distribution of that portion of his or her benefit that has become taxable, or such lesser amount as may be permitted by Code Section 409A. Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Employer shall distribute to the Participant immediately available funds in an amount equal to the taxable portion of his or her benefit or such lesser amount as may be permitted by Code Section 409A (which amount shall not exceed a Participant’s unpaid Account Balances). If the petition is granted, the tax liability distribution shall be made within 90 days of the date when the Participant’s petition is granted. Such a distribution shall affect and reduce the benefits to be paid under this Plan and its component Programs. Any distribution under this Section 10.10 must meet the requirements of Code Section 409A and related Treasury guidance or Regulations.

10.11     Governing Law . To the extent not preempted by federal law, this Plan and its component Programs shall be governed by the laws of the State of Colorado without regard to conflicts of law principles.








I hereby certify that this revised QEP Resources, Inc. Deferred Compensation Wrap Plan was duly adopted by the Board of Directors of QEP Resources, Inc. on June 1, 2015.    

Executed on this first day of June, 2015.

By: /s/ Richard J. Doleshek
Richard J. Doleshek
Executive Vice President and Chief Financial Officer







Exhibit A






DEFERRED COMPENSATION PROGRAM






a component Program of the
QEP Resources, Inc. Deferred Compensation Wrap Plan




QEP RESOURCES, INC.
DEFERRED COMPENSATION PROGRAM

ARTICLE 1
INTRODUCTION

1.1     Establishment of Program . The Company hereby establishes this revised Deferred Compensation Program under the Wrap Plan, as of January 1, 2012. Unless otherwise defined herein, all capitalized terms herein shall the meanings set forth in the QEP Resources, Inc. Deferred Compensation Wrap Plan.

1.2     Purpose . The purposes of the Deferred Compensation Program are (i) to provide Participants with the opportunity to defer receipt of specified portions of their annual Compensation including Bonuses in order to reduce current taxable income and to provide for future financial needs, and (ii) to provide a benefit to each Participant approximately equal to the benefit the Participant would have received under the Investment Plan if the Participant did not elect to defer Compensation under the Deferred Compensation Program but instead contributed an applicable portion of such amount to the Investment Plan.

ARTICLE 2
PARTICIPATION; ELECTIONS

2.1     Participation . An Employee shall be an Eligible Employee for purposes of this Program if he or she is in a salary classification designated by the Committee as eligible to participate in the Program for a Plan Year or is otherwise designated as an Eligible Employee by the Committee.

2.2     Elections . Each Participant shall make elections with regard to the deferral of Compensation and the time and form of payments under the Deferred Compensation Program in accordance with Articles 4 and 6 of the Wrap Plan.

ARTICLE 3
DEFERRAL CONTRIBUTIONS

Each Plan Year, a Participant, electing to defer Compensation under the Deferred Compensation Program for such Plan Year may defer up to a maximum of 50% of his or her Compensation for such Plan Year, or such larger percentage of Compensation or a component thereof as may be designated by the Committee for a Plan Year. For the avoidance of doubt, to the extent permitted by the Committee for a Plan Year, a Participant may make separate deferral elections with respect to separate components of Compensation, in each case within the time periods required under the Wrap Plan and Section 409A of the Code and the Treasury Regulations thereunder.

ARTICLE 4
MATCHING CONTRIBUTIONS

4.1     Determination of Matching Contributions . A Participant who makes Deferral Contributions to the Deferred Compensation Program for a Plan Year may receive a Matching Contribution. The Committee will determine annually the amount, if any, of the Matching Contribution, which, for the avoidance of doubt, may be determined separately for separate components of Deferral Contributions in the discretion of the Committee.

4.2     Vesting . Except with respect to any Deferral Contributions that relate to unvested Compensation, a Participant shall be fully vested at all times in the portion of his or her Account attributable to Deferral Contributions. Any Deferral Contributions that relate to unvested Compensation shall be subject to the same vesting terms, conditions and provisions as applied to the underlying Compensation (or component thereof) to which the Deferral Contributions relate. A Participant shall be vested in the portion of his or her Account attributable to Matching Contributions to the same extent as such Participant is vested in any matching contributions under the Investment Plan, unless otherwise determined by the Committee at the time of making any applicable Matching Contribution.

ARTICLE 5
ACCOUNTS; DEEMED INVESTMENTS

5.1     Accounts . The Committee shall establish an Account for each Participant with at least two sub-accounts as follows:





(a)    a Deferred Compensation Sub-Account which shall reflect all Deferral Contributions made by the Participant for each Plan Year, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein;

(b)    a Matching Contribution Sub-Account which shall reflect all Company Matching Contributions made under the Deferred Compensation Program for each Plan Year, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein.

The Committee shall establish such other sub-accounts as it deems necessary or desirable for the proper administration of the Deferred Compensation Program. Amounts deferred by a Participant under the Deferred Compensation Program shall be credited to the Participant’s Account as soon as administratively practicable after the amounts would have otherwise been paid to the Participant.
5.2     Status of Accounts . Accounts and sub-accounts established hereunder shall be record-keeping devices utilized for the sole purpose of determining benefits payable under the Deferred Compensation Program, and will not constitute a separate fund of assets but shall continue for all purposes to be part of the general, unrestricted assets of the Employer, subject to the claims of its general creditors.

5.3     Deemed Investment of Amounts Deferred .

(a)     Deferred Compensation Program . In connection with his or her enrollment in the Deferred Compensation Program, a Participant may elect to have earnings, gains, or losses with respect to his or her Matching Contribution Sub-Account and Deferred Compensation Sub-Account calculated based on the deemed investment alternatives below, in increments of 1%. In the event the Participant fails to make an election regarding the deemed investment of his or her Matching Contribution Sub-Account and Deferred Compensation Sub-Account, the Participant shall be deemed to have elected to invest 100% of his or her Matching Contribution Sub-Account and Deferred Compensation Sub-Account in the Money Market Fund within Investment Option (as described below). The Participant’s investment election shall continue in effect unless and until modified by the Participant. Any such modification shall apply prospectively and may apply to amounts previously deferred under the Deferred Compensation Program (and related earnings).

(b)     Common Stock Option . Any portion of the Matching Contribution Sub-Account and Deferred Compensation Sub-Account deemed invested under this option (the “Common Stock Option”) shall be accounted for as if invested in shares of Common Stock purchased at Fair Market Value on the date on which a Deferral Contribution is credited to the Participant’s Account. The Participant’s Matching Contribution Sub-Account and Deferred Compensation Sub-Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends. Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date. The Committee may prescribe such limitations as it deems advisable in its sole discretion on a Participant’s deemed investment in the Common Stock Option.

(c)     Investment Options . Any portion of the Matching Contribution Sub-Account and Deferred Compensation Sub-Account deemed invested under this option (the “Investment Option”) shall be deemed invested in one or more of the investment options made available from time to time for Participants under the Plan. Each such deemed investment shall be credited or debited with earnings or losses as if the amount invested had been invested in the applicable investment fund made available by the Committee.

ARTICLE 6
DISTRIBUTIONS

All distributions of a Participant’s Account under the Deferred Compensation Program shall be made in accordance with the Participant’s election(s) (or deemed election(s)) under Articles 4 and 6 of the Wrap Plan.








Exhibit B






401(k) SUPPLEMENTAL PROGRAM






a component Program of the
QEP Resources, Inc. Deferred Compensation Wrap Plan




QEP RESOURCES, INC.
401(k) SUPPLEMENTAL PROGRAM

ARTICLE 1
INTRODUCTION

1.1     Establishment of Program . The Company hereby establishes this revised 401(k) Supplemental Program under the Wrap Plan, as of January 1, 2016. Unless otherwise defined herein, all capitalized terms herein shall the meanings set forth in the QEP Resources, Inc. Deferred Compensation Wrap Plan.

1.2     Purpose . The purpose of the 401(k) Supplemental Program is to provide a benefit to a Participant approximately equal to the benefit that the Participant would have received under the Investment Plan if the Compensation Limit were inapplicable, and to provide certain transition credits for Participants whose accrued benefits in the QEP Resources, Inc. Retirement Plan were frozen as of December 31, 2015.

ARTICLE 2
PARTICIPATION; ELECTIONS

2.1     Participation .
An Employee shall be an Eligible Employee for purposes of this Program if he or she is in a salary classification designated by the Committee as eligible to participate in the Program for a Plan Year or is otherwise designated as an Eligible Employee by the Committee and will receive Compensation in excess of a threshold established by the Committee. An Employee shall begin participation in the 401(k) Supplemental Program on the date in any Plan Year that the Employee first receives Compensation in excess of the Compensation Limit or on a date in any Plan Year as otherwise determined by the Compensation Committee.

2.2     Elections . Each Participant shall make elections with regard to the deferral of Compensation and the time and form of payments under the 401(k) Supplemental Program in accordance with Articles 4 and 6 of the Wrap Plan.

ARTICLE 3
DEFERRAL CONTRIBUTIONS

Each Plan Year, a Participant electing to defer Compensation under the 401(k) Supplemental Program must defer a percentage of his or her compensation equal to the company matching contributions as determined for the Investment Plan commencing on the date the Participant is deemed eligible to begin participation in the Program.

ARTICLE 4
MATCHING CONTRIBUTIONS

A Participant who makes Deferral Contributions to the 401(k) Supplemental Program for a Plan Year shall be entitled to a Matching Contribution for such Plan Year in an amount equal to the amount deferred by the Participant.


ARTICLE 5
TRANSITION CREDITS

For any Plan Year beginning on or after January 1, 2016, the Company shall make certain age-based contributions (“Transition Credits”) to the 401(k) Supplemental Program in accordance with the table below for Participants who were active participants in the Company’s Retirement Plan on December 31, 2015, and who are employed on the day of the last payroll of the Plan Year for which such Company Transition Credit is made. For purposes of this Article 5, the Transition Credits for Participants shall be an amount equal to the percentage of Compensation based on each Participant’s age on December 31, 2015, in accordance with the table below.

Age of Eligible Employee on December 31, 2015
Percentage of Compensation
Less than 40
2%
At least 40 but less than 50
6%
At least 50
15%





ARTICLE 6
VESTING

A Participant shall be fully vested at all times in the portion of his or her Account attributable to Deferral Contributions and shall be vested in the portion of his or her Account attributable to Matching Contributions and Transition Credits to the same extent as such Participant is vested in any matching contributions under the Investment Plan.


ARTICLE 7
ACCOUNTS; DEEMED INVESTMENTS

7.1     Accounts . The Committee shall establish an Account and sub-accounts for each Participant as are necessary for the proper administration of the 401(k) Supplemental Program. Such Accounts shall reflect Deferral Contributions, Matching Contributions and Transition Credits made by or on behalf of the Participant, together with any adjustments for income, gain or loss and any payments from the Account as provided herein. Deferral Contributions and related Matching Contributions shall be credited to the Participant’s Account as soon as administratively practicable after the Deferral Contribution would have otherwise been paid to the Participant. The Transition Credits shall be credited to Participants Accounts not later than the last day of the year for which the Transition Credit is made.

7.2     Status of Accounts . Accounts and sub-accounts established hereunder shall be record-keeping devices utilized for the sole purpose of determining benefits payable under the 401(k) Supplemental Program, and will not constitute a separate fund of assets but shall continue for all purposes to be part of the general, unrestricted assets of the Employer, subject to the claims of its general creditors.

7.3     Deemed Investment of Accounts in 401(k) Supplemental Program .

(a)     401(k) Supplemental Program . In connection with his or her enrollment in the 401(k) Supplemental Program, a Participant may elect to have earnings, gains, or losses with respect to his or her Matching Contributions, Deferral Contributions and Transition Credits Account calculated based on the deemed investment alternatives below, in increments of 1%. In the event the Participant fails to make an election regarding the deemed investment of his or her Account, the Participant shall be deemed to have elected to invest 100% of his or her Account in the Money Market Fund within the Investment Plan Option (as described below). The Participant’s investment election shall continue in effect unless and until modified by the Participant. Any such modification shall apply prospectively and may apply to amounts previously credited under the 401(k) Supplemental Program (and related earnings).

(b)     Common Stock Option . Any portion of a Participant’s Account deemed invested under this option (the “Common Stock Option”) shall be accounted for as if invested in shares of Common Stock purchased at Fair Market Value on the date on which a Matching Contribution, Deferral Contribution or Transition Credit is credited to the Participant’s Account. The Participant’s Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends. Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date. The Committee may prescribe such limitations as it deems advisable in its sole discretion on a Participant’s deemed investment in the Common Stock Option.

(c)     Investment Plan Option . Any portion of a Participant’s Account deemed invested under this option (the “Investment Plan Option”) shall be deemed invested in one or more of the investment options made available from time to time for Participants under the Plan. Each such deemed investment shall be credited or debited with earnings or losses as if the amount invested had been invested in the underlying fund in the Investment Plan.
    
ARTICLE 8
DISTRIBUTIONS

All distributions of a Participant’s Account under the 401(k) Supplemental Program shall be made in accordance with the Participant’s election(s) (or deemed election(s)) under Articles 4 and 6 of the Wrap Plan.






Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:

1.
I have reviewed this Form 10-Q of QEP Resources, Inc.;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

August 3, 2015
 
/s/ Charles B. Stanley
Charles B. Stanley
Chairman, President and Chief Executive Officer





Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:

1.
I have reviewed this Form 10-Q of QEP Resources, Inc.;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

August 3, 2015
 
/s/ Richard J. Doleshek
Richard J. Doleshek
Executive Vice President and Chief Financial Officer





Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended June 30, 2015 , as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)
The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
 
QEP RESOURCES, INC.
 
 
August 3, 2015
 
 
 
 
/s/ Charles B. Stanley
 
Charles B. Stanley
 
Chairman, President and Chief Executive Officer
 
 
August 3, 2015
 
 
 
 
/s/ Richard J. Doleshek
 
Richard J. Doleshek
 
Executive Vice President and Chief Financial Officer
 
 






Exhibit 99.1

On November 26, 2014, Plumbers Local 98 Defined Benefit Fund (“Plaintiff”) brought suit in the Court of Chancery of the State of Delaware against the Company, members of its Board of Directors, and Wells Fargo Bank, N.A. (“Wells Fargo”), in its capacity as Administrative Agent under the Company’s Credit Agreement and Term Loan Agreement. The suit was captioned Plumbers Local 98 Defined Benefit Fund v. Rattie , C.A. No. 10405-VCN. Plaintiff alleged that the Company’s directors breached their fiduciary duties by unjustifiably permitting the Company’s Credit Agreement and Term Loan Agreement to each contain what Plaintiff calls a “dead hand proxy put” change of control provision, which would allow the lenders under the Credit Agreement and Term Loan Agreement to declare that all amounts outstanding under the Credit Agreement and Term Loan Agreement were immediately due and payable in the event that a majority of the board of directors was replaced in a proxy contest. Plaintiff alleged that this provision has a coercive effect on stockholder voting for change on the board of directors and entrenches the Company’s incumbent directors. The complaint further asserted that Wells Fargo aided and abetted the defendant directors in their alleged breach of fiduciary duties. On December 2, 2014, the Company and its lenders executed an amendment to the Credit Agreement to remove the “dead hand proxy put,” and the Company repaid and terminated the Term Loan Agreement and these actions were reported on Form 8-K which was filed with the Securities Exchange Commission on December 4, 2014.
On December 24, 2014, Plaintiff wrote a letter informing the Court that the amendment and termination had rendered its claims moot and that it would coordinate with the Company regarding dismissal of the claims and Plaintiff’s application for an award of attorneys’ fees. The parties reached an agreement with respect to such fees of $300,000 during the first quarter of 2015 and the Court entered a Stipulation and Order dismissing the suit on June 30, 2015. The Company has denied any wrongdoing and maintains that the subject provision in the Credit Agreement and Term Loan Agreement was the result of negotiations with lenders that predated the filing of the complaint. The Court did not pass on the amount of the attorneys’ fees, and the Company paid the fees by July 10, 2015. Any stockholder seeking additional information about this matter should contact Joel Friedlander, counsel for Plaintiff, at jfriedlander@friedlandergorris.com or (302) 573-3500, or Garrett Moritz, counsel for the Company, at gmoritz@ramllp.com or (302) 576-1600.