10-Q



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 March 31, 2016
 
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 17th 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 oNo ý

At March 31, 2016, there were 216,747,837 shares of the registrant’s common stock, $0.01 par value, outstanding.
 



QEP Resources, Inc.
Form 10-Q for the Quarter Ended March 31, 2016

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
 
March 31,
 
2016
 
2015
REVENUES
(in millions, except per share amounts)
Gas sales
$
85.1

 
$
122.0

Oil sales
143.8

 
178.8

NGL sales
13.6

 
19.1

Other revenue
2.3

 
4.4

Purchased gas and oil sales
16.5

 
143.8

Total Revenues
261.3

 
468.1

OPERATING EXPENSES
 

 
 

Purchased gas and oil expense
16.9

 
145.9

Lease operating expense
60.0

 
61.8

Gas, oil and NGL transportation and other handling costs
73.6

 
65.1

Gathering and other expense
1.3

 
1.7

General and administrative
48.7

 
47.4

Production and property taxes
17.8

 
27.8

Depreciation, depletion and amortization
240.0

 
195.4

Exploration expenses
0.3

 
1.1

Impairment
1,182.4

 
20.0

Total Operating Expenses
1,641.0

 
566.2

Net gain (loss) from asset sales
0.5

 
(30.5
)
OPERATING INCOME (LOSS)
(1,379.2
)
 
(128.6
)
Realized and unrealized gains (losses) on derivative contracts (See Note 7)
50.9

 
80.9

Interest and other income (expense)
2.3

 
(2.6
)
Interest expense
(36.7
)
 
(36.8
)
INCOME (LOSS) BEFORE INCOME TAXES
(1,362.7
)
 
(87.1
)
Income tax (provision) benefit
498.9

 
31.5

NET INCOME (LOSS)
$
(863.8
)
 
$
(55.6
)
 
 
 
 
Earnings (loss) per common share
 

 
 

Basic
$
(4.55
)
 
$
(0.32
)
Diluted
$
(4.55
)
 
$
(0.32
)
 
 
 
 
Weighted-average common shares outstanding
 
 
 

Used in basic calculation
189.7

 
176.2

Used in diluted calculation
189.7

 
176.2

Dividends per common share
$

 
$
0.02


See Notes accompanying the Condensed Consolidated Financial Statements.

2



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

 
Three Months Ended
 
March 31,
 
2016
 
2015
 
(in millions)
Net income (loss)
$
(863.8
)
 
$
(55.6
)
Other comprehensive income, net of tax:
 

 
 

Pension and other postretirement plans adjustments:
 

 
 

Amortization of net actuarial losses (1)
0.1

 
0.2

Amortization of prior service costs (2)
0.1

 
0.5

Other comprehensive income
0.2

 
0.7

Comprehensive income (loss)
$
(863.6
)
 
$
(54.9
)
____________________________
(1) 
Presented net of income tax expense of $0.1 million during the three months ended March 31, 2016 and 2015, respectively.
(2) 
Presented net of income tax expense of $0.3 million during the three months ended March 31, 2015.

See Notes accompanying the Condensed Consolidated Financial Statements.


3



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
March 31,
2016
 
December 31,
2015
ASSETS
(in millions)
Current Assets
 
 
 
Cash and cash equivalents
$
616.4

 
$
376.1

Accounts receivable, net
115.5

 
278.2

Income tax receivable
170.1

 
87.3

Fair value of derivative contracts
134.4

 
146.8

Gas, oil and NGL inventories, at lower of average cost or market
7.9

 
13.3

Prepaid expenses and other
20.9

 
30.1

Total Current Assets
1,065.2

 
931.8

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

 
 

Proved properties
13,472.2


13,314.9

Unproved properties
678.6


691.0

Marketing and other
296.8


297.9

Materials and supplies
31.1


38.5

Total Property, Plant and Equipment
14,478.7

 
14,342.3

Less Accumulated Depreciation, Depletion and Amortization
 
 
 

Exploration and production
8,252.4


6,870.2

Marketing and other
90.6


87.5

Total Accumulated Depreciation, Depletion and Amortization
8,343.0

 
6,957.7

Net Property, Plant and Equipment
6,135.7

 
7,384.6

Fair value of derivative contracts
20.8

 
23.2

Other noncurrent assets
60.9

 
58.6

TOTAL ASSETS
$
7,282.6


$
8,398.2

LIABILITIES AND EQUITY
 
 
 

Current Liabilities
 

 
 

Checks outstanding in excess of cash balances
$

 
$
29.8

Accounts payable and accrued expenses
204.7

 
351.7

Production and property taxes
41.5

 
46.1

Interest payable
33.7

 
36.4

Fair value of derivative contracts

 
0.8

Current portion of long-term debt
176.7

 
176.8

Total Current Liabilities
456.6

 
641.6

Long-term debt
2,016.2

 
2,014.7

Deferred income taxes
1,033.3

 
1,479.8

Asset retirement obligations
207.4

 
204.9

Fair value of derivative contracts
3.4

 
4.0

Other long-term liabilities
108.0

 
105.3

Commitments and contingencies (Note 10)


 


EQUITY
 
 
 

Common stock – par value $0.01 per share; 500.0 million shares authorized; 
217.6 million and 177.3 million shares issued, respectively
2.2

 
1.8

Treasury stock – 0.8 million and 0.5 million shares, respectively
(18.2
)
 
(14.6
)
Additional paid-in capital
931.4

 
554.8

Retained earnings
2,554.5

 
3,418.3

Accumulated other comprehensive income
(12.2
)
 
(12.4
)
Total Common Shareholders' Equity
3,457.7

 
3,947.9

TOTAL LIABILITIES AND EQUITY
$
7,282.6

 
$
8,398.2

 

See Notes accompanying the Condensed Consolidated Financial Statements.

4



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENT OF EQUITY
 
Common Stock
 
Treasury Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income(Loss)
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
(in millions)
Balance at December 31, 2015
177.3

 
$
1.8

 
(0.5
)
 
$
(14.6
)
 
$
554.8

 
$
3,418.3

 
$
(12.4
)
 
$
3,947.9

Net income (loss)

 

 

 

 

 
(863.8
)
 

 
(863.8
)
Equity issuance, net of offering costs
38.0

 
0.4

 

 

 
368.2

 

 

 
368.6

Share-based compensation
2.3

 

 
(0.3
)
 
(3.6
)
 
8.4

 

 

 
4.8

Change in pension and postretirement liability, net of tax

 

 

 

 

 

 
0.2

 
0.2

Balance at March 31, 2016
217.6

 
$
2.2

 
(0.8
)
 
$
(18.2
)
 
$
931.4

 
$
2,554.5

 
$
(12.2
)
 
$
3,457.7


See Notes accompanying the Condensed Consolidated Financial Statements.


5



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Three Months Ended
 
March 31,
 
2016
 
2015
 
(in millions)
OPERATING ACTIVITIES
 

 
 

Net income (loss)
$
(863.8
)

$
(55.6
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
240.0

 
195.4

Deferred income taxes
(446.7
)
 
(4.8
)
Impairment
1,182.4

 
20.0

Share-based compensation
8.0

 
9.1

Amortization of debt issuance costs and discounts
1.6

 
1.9

Net (gain) loss from asset sales
(0.5
)
 
30.5

Unrealized (gains) losses on marketable securities
(0.2
)
 

Unrealized (gains) losses on derivative contracts
13.5

 
23.5

Changes in operating assets and liabilities
(52.6
)
 
(492.7
)
Net Cash Provided by (Used in) Operating Activities
81.7

 
(272.7
)
INVESTING ACTIVITIES
 

 
 

Property acquisitions
(14.8
)
 

Property, plant and equipment, including dry exploratory well expense
(185.8
)
 
(342.1
)
Proceeds from disposition of assets
22.9

 
1.6

Net Cash Provided by (Used in) Investing Activities
(177.7
)

(340.5
)
FINANCING ACTIVITIES
 

 
 

Checks outstanding in excess of cash balances
(29.8
)
 
(38.9
)
Treasury stock repurchases
(2.9
)
 
(1.9
)
Other capital contributions
0.2

 
(0.4
)
Dividends paid

 
(3.5
)
Proceeds from issuance of common stock, net
368.6

 

Excess tax (provision) benefit on share-based compensation
0.2

 
(1.8
)
Net Cash Provided by (Used in) Financing Activities
336.3

 
(46.5
)
Change in cash and cash equivalents
240.3


(659.7
)
Beginning cash and cash equivalents
376.1

 
1,160.1

Ending cash and cash equivalents
$
616.4

 
$
500.4

 
 
 
 
Supplemental Disclosures:
 

 
 

Cash paid for interest, net of capitalized interest
$
37.8

 
$
37.6

Cash paid for income taxes
32.0

 
509.8

Non-cash Investing Activities:
 

 
 

Change in capital expenditure accruals and other non-cash adjustments
$
(22.6
)
 
$
(59.2
)
 
See Notes accompanying the Condensed Consolidated Financial Statements.

6



QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
Note 1 – Basis of Presentation

Nature of Business

QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas production company focused in two major regions of the United States: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol “QEP”.

Basis of Presentation of Interim Condensed 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 for the year ended December 31, 2015.
 
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 months ended March 31, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

Equity Offering

In March 2016, QEP issued 37.95 million additional shares of common stock through a public equity offering and received net proceeds of approximately $368.6 million. QEP expects to use the proceeds from this offering for general corporate purposes, which may include, among other things, reducing indebtedness, acquiring properties, funding a portion of the Company's exploration and production activities and working capital.

Termination of Marketing Agreements and QEP Marketing Segment
Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy).  In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system. As a result, QEP Energy is directly marketing its own gas, oil and NGL production. While QEP will continue to act as an agent for the sale of gas, oil and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production.  QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had in prior periods. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Update (ASU) Topic 820, Segment Reporting, and determined that QEP has one reportable segment effective January 1, 2016.

Revision of Financial Statements

In the fourth quarter of 2015, the Company determined that certain transactions that had been reported on a gross basis and included in "Purchased gas and oil sales" and "Purchased gas and oil expense" on the Condensed Consolidated Statement of Operations for the first quarter of 2015 should have been reported on a net basis, as the transactions were with the same counterparty and were entered into in contemplation of one another. The Company revised its financial statements to reflect the net accounting treatment and assessed the cumulative impact of the revisions on each period affected. The revisions had no
effect on the Company’s operating income, net income, earnings per share, cash flows or retained earnings. The Company determined that the impact of the change from gross to net accounting was not material, either individually or in the aggregate, to previously issued financial statements. The Company has, however, recast its Condensed Consolidated Statement of Operations for the three months ended March 31, 2015.

The following table details the impact of these revisions for the three months ended March 31, 2015, on the Condensed Consolidated Statement of Operations.
 
 
Three Months Ended March 31, 2015
 
 
As reported
 
As revised
 
Change
 
 
(in millions)
REVENUES
 
 
 
 
 
 
Purchased gas and oil sales
 
$
167.3

 
$
143.8

 
$
(23.5
)
Total Revenues
 
491.6

 
468.1

 
(23.5
)
OPERATING EXPENSES
 
 
 
 
 
 
Purchased gas and oil expense
 
$
169.4

 
$
145.9

 
$
(23.5
)
Total Operating Expenses
 
589.7

 
566.2

 
(23.5
)

Reclassifications

Certain prior period balances in the Condensed Consolidated Balance Sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on operating income, net income, earnings per share, cash flows or shareholders’ equity previously reported.

Impairment of Long-Lived Assets

During the three months ended March 31, 2016, QEP recorded impairment expense of $1,182.4 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $10.8 million was related to expiring leaseholds on unproved properties and $3.7 million was related to impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to Other Southern properties.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principle versus agent considerations. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2017, and early adoption is not permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.


7



Note 2 – Acquisitions and Divestitures

During the three months ended March 31, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $21.0 million, which primarily included additional interests in QEP's operated wells and the associated leasehold. As a part of the purchase price allocation, the Company recorded $3.7 million of goodwill.

Additionally, during the three months ended March 31, 2016, QEP received proceeds of $22.9 million, primarily related to the divestiture of certain non-core properties in the Southern Region.

Note 3 – 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 are eligible to 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 months ended March 31, 2016 and 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
 
March 31,
 
2016

2015
 
(in millions)
Weighted-average basic common shares outstanding
189.7

 
176.2

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
189.7

 
176.2


Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below. The balance at March 31, 2016, represents the amount of capitalized well costs that are pending the determination of proved reserves.

 
 
Capitalized Exploratory Well Costs
 
 
2016
 
 
(in millions)
Balance at January 1,
 
$
2.6

Additions to capitalized exploratory well costs pending the determination of proved reserves
 
11.5

Balance at March 31,
 
$
14.1



8



Note 5 – 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 $209.2 million and $206.8 million ARO liability for the periods ended March 31, 2016 and December 31, 2015, respectively, $1.8 million and $1.9 million, respectively, were included as a liability within "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

The following is a reconciliation of the changes in the Company's ARO for the period specified below:
 
Asset Retirement Obligations
 
2016
 
(in millions)
ARO liability at January 1,
$
206.8

Accretion
2.1

Additions
1.5

Liabilities settled
(1.2
)
ARO liability at March 31,
$
209.2


Note 6 – 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 7 – 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.

9




The fair value of financial assets and liabilities at March 31, 2016 and December 31, 2015, 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
 
 
 
March 31, 2016
 
(in millions)
Financial Assets
 
 
 
 
 
 
 
 
 
Commodity derivative instruments – short-term
$

 
$
134.5

 
$

 
$
(0.1
)
 
$
134.4

Commodity derivative instruments – long-term

 
20.9

 

 
(0.1
)
 
20.8

Total financial assets
$

 
$
155.4

 
$

 
$
(0.2
)
 
$
155.2


 
 
 
 
 
 
 
 
 
Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity derivative instruments – short-term
$

 
$
0.1

 
$

 
$
(0.1
)
 
$

Commodity derivative instruments – long-term

 
3.5

 

 
(0.1
)
 
3.4

Total financial liabilities
$

 
$
3.6

 
$

 
$
(0.2
)
 
$
3.4

 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
(in millions)
Financial Assets
 
 
 
 
 
 
 
 
 
Commodity derivative instruments – short-term
$

 
$
147.8

 
$

 
$
(1.0
)
 
$
146.8

Commodity derivative instruments – long-term

 
23.2

 

 

 
23.2

Total financial assets
$

 
$
171.0

 
$

 
$
(1.0
)
 
$
170.0

 
 
 
 
 
 
 
 
 
 
Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity derivative instruments – short-term
$

 
$
1.8

 
$

 
$
(1.0
)
 
$
0.8

Commodity derivative instruments – long-term

 
4.0

 

 

 
4.0

Total financial liabilities
$


$
5.8


$


$
(1.0
)

$
4.8

_______________________
(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 7 – 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
 
March 31, 2016
 
December 31, 2015
 
(in millions)
Financial Assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
616.4

 
$
616.4

 
$
376.1

 
$
376.1

Financial Liabilities
 

 
 

 
 

 
 

Checks outstanding in excess of cash balances
$

 
$

 
$
29.8

 
$
29.8

Long-term debt
2,192.9

 
2,028.9

 
2,191.5

 
1,784.6


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.

10




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 5 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the three months ended March 31, 2016 and 2015, the Company recorded impairments on certain proved oil and gas properties of $1,167.9 million and $19.4 million, respectively, resulting in a reduction of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models. Given the unobservable nature of the inputs, proved oil and gas property impairments are considered Level 3 within the fair value hierarchy.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: estimated quantities of gas, oil and NGL reserves; estimates of future commodity prices; and estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the properties is considered Level 3 within the fair value hierarchy.

Note 7 – 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 enters into commodity derivative contracts for approximately 50% to 75% 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 storage 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 or oil between the parties at settlement. All 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 sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative transactions that 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.

11




Derivative Contracts Production
The following table sets forth QEP’s quantities and average prices for its commodity derivative swap contracts as of March 31, 2016
Year
 
Index
 
Total
Volumes
 
Average Swap Price per Unit
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
(MMBtu)

 
($/MMBtu)

2016
 
 NYMEX HH
 
42.2

 
$
2.80

2016
 
 IFNPCR
 
55.0

 
$
2.53

2017
 
NYMEX HH
 
73.0

 
$
2.75

2017
 
IFNPCR
 
32.9

 
$
2.51

2018
 
NYMEX HH
 
7.3

 
$
2.80

Oil sales
 
 
 
(bbls)

 
($/bbl)

2016 (April through June)
 
NYMEX WTI
 
1.7

 
$
57.09

2016 (July through December)
 
NYMEX WTI
 
4.8

 
$
52.44

2017
 
NYMEX WTI
 
3.7

 
$
51.71


The following table sets forth details of QEP's gas collars as of March 31, 2016:
 
 
 
 
Total Volume
 
Average Price
 
Average Price
Year
 
Index
 
 
Floor
 
Ceiling
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
(MMBtu)

 
($/MMBtu)

 
($/MMBtu)

2016
 
NYMEX HH
 
5.5

 
$
2.75

 
$
3.89


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

The following table sets forth details of QEP's gas basis swaps as of March 31, 2016:
Year
 
Index Less Differential
 
Index
 
Total Volumes
 
Weighted-Average Differential
 
 
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
(MMBtu)

 
($/MMBtu)

2016
 
NYMEX HH
 
IFNPCR
 
27.5

 
$
(0.16
)
2017
 
NYMEX HH
 
IFNPCR
 
51.1

 
$
(0.18
)

12




Derivative Contracts Storage
QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table sets forth QEP’s volumes and swap prices for its storage commodity derivative contracts as of March 31, 2016:
Year
 
Type of Contract
 
Index
 
Total
Volumes
 
Average Swap Price per MMBtu
 
 
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
 
 
(MMBtu)

 
($/MMBtu)

2016
 
SWAP
 
IFNPCR
 
1.9

 
$
2.57

2017
 
SWAP
 
IFNPCR
 
0.2

 
$
2.69

Gas purchases
 
 
 
 
 
 
 
 

2016
 
SWAP
 
IFNPCR
 
0.7

 
$
1.73


 
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
 
March 31,
2016
 
December 31, 2015
 
March 31,
2016
 
December 31, 2015
 
 
 
(in millions)
Current:
 
 
 
 
 
 
 
 
 
Commodity
Fair value of derivative contracts
 
$
134.5

 
$
147.8

 
$
0.1

 
$
1.8

Long-term:
 
 
 

 
 

 
 
 
 

Commodity
Fair value of derivative contracts
 
20.9

 
23.2

 
3.5

 
4.0

Total derivative instruments
 
$
155.4

 
$
171.0

 
$
3.6

 
$
5.8



13



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
Derivative instruments not designated as cash flow hedges
 
March 31,
 
2016
 
2015
Realized gains (losses) on commodity derivative contracts
 
(in millions)
Production
 
 
 
 
Gas derivative contracts
 
$
21.5

 
$
17.9

Oil derivative contracts
 
40.8

 
84.0

Storage
 
 

 
 

Gas derivative contracts
 
2.1

 
2.5

Total realized gains (losses) on commodity derivative contracts
 
64.4

 
104.4

Unrealized gains (losses) on commodity derivative contracts
 
 
 
 
Production
 
 

 
 

Gas derivative contracts
 
15.4

 
11.4

Oil derivative contracts
 
(27.9
)
 
(33.1
)
Storage
 
 

 
 

Gas derivative contracts
 
(1.0
)
 
(1.8
)
Total unrealized gains (losses) on commodity derivative contracts
 
(13.5
)
 
(23.5
)
Total realized and unrealized gains (losses) on commodity derivative contracts
 
$
50.9

 
$
80.9


Note 8 – Restructuring Costs

During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The Company estimates that the total costs related to the 2015 reorganizations will be approximately $8.1 million, of which approximately $5.3 million is related to one-time termination benefits and approximately $2.8 million is related to relocation of certain employees. During the three months ended March 31, 2016, restructuring costs of $0.3 million were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company estimates that the remaining $0.1 million of restructuring costs related to the 2015 reorganizations will be incurred during the remainder of 2016. These restructuring costs were recorded within "General and administrative" expense of the Condensed Consolidated Statement of Operations.

Note 9 – Debt
 
As of the indicated dates, the principal amount of QEP’s debt consisted of the following:
 
March 31,
2016
 
December 31,
2015
 
(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

Less: unamortized discount and unamortized debt issuance costs
(28.9
)
 
(30.3
)
Total principal amount of debt (including current portion)
2,192.9


2,191.5

Less: current portion of long-term debt
(176.7
)
 
(176.8
)
Total long-term debt outstanding
$
2,016.2

 
$
2,014.7


14



 
Of the total debt outstanding on March 31, 2016, the 6.05% Senior Notes due September 1, 2016, the 6.80% Senior Notes due April 1, 2018, the 6.80% Senior Notes due March 1, 2020 and the 6.875% Senior Notes due March 1, 2021, will mature within the next five years. In addition, 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 provisions and restrictions. The credit agreement contains financial covenants (as defined in the credit agreement) that limit the amount of debt the Company may incur and may limit the amount available to be drawn under the credit facility, including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) a present value coverage ratio under which the present value of the Company’s proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2018, and 1.50 times at any time on or after January 1, 2018. At March 31, 2016, QEP was in compliance with the covenants under the credit agreement.

During the three months ended March 31, 2016 and 2015, QEP had no borrowings under the credit facility. Additionally, as of March 31, 2016 and 2015, QEP had no borrowings outstanding under the credit facility and had $2.8 million and $3.7 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes
At March 31, 2016, 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 Condensed Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material 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.

Litigation

Rocky Mountain Resources Lawsuit Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleges that the defendants 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. In February 2015, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. QEP is appealing the verdict to the Wyoming Supreme Court, and, in connection with such appeal, has posted a bond for approximately $20.0 million (representing the amount of the verdict and two years of accrued interest at the statutory rate of 10%). In accordance with the Court’s order, QEP is depositing the future monthly revenues attributable to the 4% overriding royalty interest with the Court as it becomes due and payable.  The overriding royalty payments will be subject to the direction of the Court following the conclusion of the appeal. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to approximately $20.0 million.


15



Note 11 – Share-Based Compensation
 
QEP issues stock options, restricted shares and restricted share units 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 the expense over the vesting periods for the stock options, restricted shares, restricted share units and performance share units. There were 6.9 million shares available for future grants under the LTSIP at March 31, 2016.

Share-based compensation expense is recognized within “General and administrative” expense on the Condensed Consolidated Statements of Operations and is summarized in the table below:
 
Three Months Ended
 
March 31,
 
2016
 
2015
 
(in millions)
Stock options
$
0.7

 
$
0.8

Restricted share awards
6.5

 
6.3

Performance share units
0.8

 
2.0

Restricted share units

 

Total share-based compensation expense
$
8.0

 
$
9.1


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 three months ended March 31, 2016:
 
Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period
$
3.76

Weighted-average risk-free interest rate
1.15
%
Weighted-average expected price volatility
43.4
%
Expected dividend yield
%
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, 2015
2,200,776

 
$
27.94

 
 
 
 
Granted
436,726

 
10.12

 
 
 
 
Canceled
(386,999
)
 
23.98

 
 
 
 
Outstanding at March 31, 2016
2,250,503

 
$
25.17

 
4.22
 
$
1.7

Options Exercisable at March 31, 2016
1,448,779

 
$
30.00

 
3.06
 
$

Unvested Options at March 31, 2016
801,724

 
$
16.43

 
6.32
 
$
1.7


16



 
During the three months ended March 31, 2016 and 2015, there were no exercises of stock options. As of March 31, 2016, $2.8 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average period of 2.45 years.
 
Restricted Share Awards
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 three months ended March 31, 2016 and 2015, was $20.4 million and $18.0 million, respectively. The weighted-average grant date fair value of restricted stock was $10.13 per share and $21.67 per share for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016, $36.2 million of unrecognized compensation cost related to restricted shares granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.55 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, 2015
2,008,210

 
$
24.18

Granted
2,356,919

 
10.13

Vested
(783,782
)
 
26.01

Forfeited
(41,193
)
 
18.32

Unvested balance at March 31, 2016
3,540,154

 
$
14.50

 
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 and have historically been delivered in cash. 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 March 31, 2016, the Company expects to settle all awards in cash. The weighted-average grant date fair value of the performance share units was $10.12 per share and $21.69 per share for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016, $12.7 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.33 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, 2015
630,786

 
$
27.50

Granted
594,245

 
10.12

Vested and Paid
(178,169
)
 
30.07

Forfeited
(3,024
)
 
27.39

Unvested balance at March 31, 2016
1,043,838

 
$
17.17


Restricted Share Units
Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. The weighted-average grant date fair value of the restricted share units was $10.12 per share for the three months ended March 31, 2016. As of March 31, 2016, $0.3 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 2.94 years.

17




 
Restricted Share Units Outstanding
 
Weighted-Average Grant Date Fair Value
Unvested balance at December 31, 2015

 
$

Granted
21,493

 
10.12

Unvested balance at March 31, 2016
21,493

 
$
10.12


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).

As a result of the Company's divestitures in 2014 and retirements in 2015, the number of active participants in the Pension Plan fell to 50 employees during the year ended December 31, 2015, which is the minimum number of active 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 was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services.

The Pension Plan is a closed, qualified defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the three months ended March 31, 2016, the Company made contributions of $2.0 million to the Pension Plan and expects to contribute $2.0 million to the Pension Plan during the remainder of 2016. Contributions to the Pension Plan increase plan assets.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the three months ended March 31, 2016, the Company made contributions of $1.1 million to its SERP and expects to contribute an additional $2.5 million to its SERP during the remainder of 2016. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and was 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 three months ended March 31, 2016, the Company made contributions of $0.1 million to its Medical Plan and expects to contribute an additional $0.2 million to its Medical Plan during the remainder of 2016. Contributions to the Medical Plan are used to fund current benefit payments.


18



The following table sets forth the Company’s net periodic benefit costs related to its Pension Plan, SERP and Medical Plan:
 
Three Months Ended
 
March 31,
 
2016
 
2015
Pension Plan and SERP benefits
(in millions)
Service cost
$
0.2

 
$
0.6

Interest cost
1.2

 
1.3

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

 
0.8

Amortization of actuarial losses (1)
0.2

 
0.3

Periodic expense
$
0.3

 
$
1.6

 
 
 
 
Medical Plan benefits
 
 
 
Interest cost
$
0.1

 
$
0.1

Periodic expense
$
0.1

 
$
0.1

____________________________
(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" expense.

Note 13 – Subsequent Event

In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The Company estimates that the total cost related to this restructuring will be approximately $2.2 million, all of which is related to one-time termination benefits and will be recorded in the second quarter of 2016.

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 2015 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three months ended March 31, 2016 and 2015. 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 2015 Annual Report on Form 10-K.

OVERVIEW

QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas production company focused in two major regions of the United States: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol “QEP”.

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 believes it has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore U.S. that provide a solid base for growth in organic production and reserves.

19




Outlook

In response to the commodity price environment, we reduced drilling and completion activities, slowed production growth, reduced costs and preserved our liquidity in 2015 and the first quarter of 2016, and plan to continue these strategies for the remainder of 2016. We are focused on driving improved operating performance by optimizing reservoir development, enhancing well completion designs, and aggressively pursuing cost reductions.

Based on current commodity prices, we expect to be able to fund our planned capital program with cash flow from operating activities and, if needed, cash on hand and availability under our credit facility. Our total capital expenditures for 2016, primarily related to development and recompletion activities, are expected to be approximately $475.0 million, a decrease of over 50% from 2015 capital expenditures. With this capital program we expect total equivalent production to be relatively flat compared to 2015. We plan to continuously evaluate our level of drilling and completion activity in light of both commodity prices and changes we are able to make to our costs of operations and adjust our capital spending program as appropriate. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures. We will also continue to pursue acquisitions and divest of non-core properties.

Equity Offering

In March 2016, QEP issued 37.95 million additional shares of common stock through a public equity offering and received net proceeds of approximately $368.6 million. QEP expects to use the proceeds from this offering for general corporate purposes, which may include, among other things, reducing indebtedness, acquiring properties, funding a portion of the Company's exploration and production activities and working capital.

Termination of Marketing Agreements and QEP Marketing Segment
Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy).  In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system. As a result, QEP Energy is directly marketing its own gas, oil and NGL production. While QEP will continue to act as an agent for the sale of gas, oil and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production.  QEP has substantially reduced its marketing activities, and subsequently is reporting lower resale revenue and expenses than it had in prior periods. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Update (ASU) Topic 820, Segment Reporting, and determined that QEP has one reportable segment effective January 1, 2016.

Acquisitions and Divestitures

During the three months ended March 31, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $21.0 million, which primarily included additional interests in QEP's operated wells and the associated leasehold. As a part of the purchase price allocation, the Company recorded $3.7 million of goodwill.

Additionally, during the three months ended March 31, 2016, QEP received proceeds of $22.9 million, primarily related to the divestiture of certain non-core properties in the Southern Region.

While QEP believes its extensive inventory of identified drilling locations provide a solid base for growth in production and reserves, 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 a low-cost operating model and financial strength, enhances its ability to pursue acquisition opportunities.

Financial and Operating Results

During the three months ended March 31, 2016, QEP:

Achieved natural gas equivalent production of 82.7 Bcfe, a 10% increase over the same period in 2015;
Increased oil production to 5,176.4 Mbbls, a 16% increase over the first three months of 2015, including increased production in both the Permian and Williston basins;
Reduced lease operating and transportation expense by $0.07/Mcfe to $1.62/Mcfe;

20



Generated a net loss of $863.8 million, or $4.55 per diluted share;
Achieved Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $115.1 million;
Incurred impairment expense of $1,182.4 million;
Issued 37.95 million additional shares of common stock through a public equity offering and received net proceeds of approximately $368.6 million; and
Maintained $616.4 million in cash and cash equivalents and have nothing drawn under our credit facility.

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 and completion activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill, complete and operate 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 the 2014-2015 heating season, and adequate storage levels led to natural gas price declines later in the year, which continued throughout 2015 and into 2016. Similarly, growth in U.S. oil production, global crude oil supplies that exceed global demand, a strong U.S. dollar and the failure of the Organization of Petroleum Exporting Countries (OPEC) countries to cut production, led to a dramatic weakening of global oil prices starting in late 2014, which continued throughout 2015 and into 2016.

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and 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 experienced greater declines as a result of growing North American oversupply. In addition, QEP's NGL prices are affected by ethane recovery or 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. As permitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery and processing agreements permit it to do so, QEP rejects ethane from the NGL stream. In instances where QEP can make an election, QEP rejected ethane during the three months ended March 31, 2016, and plans to reject ethane for the remainder of 2016.

During the past five years, the posted price for WTI has ranged from a low of $26.19 per barrel in February 2016 to a high of $113.39 per barrel in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. Throughout 2015 and into 2016, the prices of crude oil and natural gas decreased dramatically due to over-supplied markets combined with weak and uncertain global demand. If the prices of oil and natural gas continue at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

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 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% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. At March 31, 2016, assuming forecasted 2016 annual production of approximately 316 Bcfe, QEP had approximately 76% of its forecasted gas production and 45% of its forecasted oil production covered with fixed-price swaps and collars. The average swap price for the derivative contracts settling in 2016 and 2017 is significantly lower than the average swap price for the derivative contracts settled prior to 2016 and, therefore, QEP's derivative portfolio may not contribute as much to QEP's net realized prices for current and future production. See Part 1, Item 3 – “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk Management” for further details on QEP’s commodity derivatives transactions.


21



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 U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; the 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 natural gas, crude oil and NGL supply, demand and prices and 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
Increased oil production in the U.S. over the last five years combined with various other global factors have led to substantially lower oil prices. According to data from the Energy Information Administration (EIA), U.S. oil production has increased by approximately four million barrels per day, or approximately 70%, since 2011. International oil supply disruptions in previous years have prevented oversupply and a corresponding negative price impact, but reduced supply disruptions 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 continued throughout 2015 and into 2016. As a result, many oil producers around the world are dramatically reducing their drilling activity.

In December 2015, the U.S. lifted a 40-year ban on the export of crude oil. U.S. producers now have access to a wider market, and the U.S. could become a significant exporter of oil if the necessary infrastructure is built to support oil exports. 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.

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, due to efficiency gains that 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 throughout 2015 and into 2016, 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 the first half of 2014. Natural gas prices weakened in the second half of 2014 and continued to decline throughout 2015 and into 2016 due to comparatively mild winter heating demand levels and continued increases in supply. Given the high production and storage inventory levels, QEP expects U.S. natural gas prices to remain range-bound over the near term. Relatively low natural gas prices in recent years caused U.S. exploration and production companies, including QEP, to shift capital investments away from predominantly dry gas areas toward plays that produce crude oil, condensate and liquids-rich gas, but crude oil and liquids-rich gas drilling economics are no longer as compelling due to price declines in crude oil and NGL. Recent dramatic declines in completed well costs in response to lower overall commodity prices have made new well economics in some dry gas areas competitive with liquids-rich gas and crude oil plays, potentially stimulating new capital investment in some gas-prone areas despite current low natural gas prices.

The reallocation of drilling capital to liquids-rich gas and crude oil in response to prolonged depressed natural gas prices has caused domestic NGL production to increase dramatically. Increased NGL production has contributed to a weakening of domestic NGL prices, particularly ethane and propane. QEP expects that ethane prices will continue to be range-bound and ethane processing economics challenged until new ethylene crackers and export facilities are completed, beginning in 2017. Propane prices have also declined as a result of lower crude oil prices and due to crude oil and liquids-rich gas-directed drilling. Increased supply coupled with lower domestic demand as a result of a comparatively mild winter in 2014-2015, resulted in abnormally high inventory levels that further depressed prices. Completion of new propane export capacity in 2014 and 2015 and favorable export economics during the winter of 2015-2016 resulted in a significant decline in propane inventories and firming propane prices despite a mild winter that negatively impacted traditional domestic propane demand. The prices of heavier components of the NGL barrel have weakened as a result of the decline in crude oil prices and also remain challenged.

In addition, transportation, processing, fractionation, cracking, 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, crude oil and NGL price environments, QEP continues to manage its capital program and liquidity accordingly and has reduced its capital expenditure budget and drilling and completion activities planned for 2016.

22




Potential for Future Asset Impairments
The carrying value of the Company's properties is sensitive to declines in natural gas, crude oil and NGL prices. The value of these assets are at risk of impairment if future natural gas, crude oil and/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 gas, oil and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. During the three months ended March 31, 2016, the Company recorded impairments of $1,182.4 million, of which $1,167.9 million was related to impairments of proved properties due to lower future prices, primarily in Pinedale, $10.8 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. During the three months ended March 31, 2015, impairments were $20.0 million, of which $19.4 million was related to proved properties due to lower future prices and $0.6 million was related to expiring leaseholds on unproved properties. If commodity prices decline during 2016, 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 cased and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP’s quarterly operating results. 

Critical Accounting Estimates
QEP's significant accounting policies are described in Item 7 of Part II of its 2015 Annual Report on Form 10-K. 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 long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, derivative contracts, pension and other postretirement benefits, 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.

Drilling Activity
The following table presents operated and non-operated well completions for the three months ended March 31, 2016:
 
Operated Completions
 
Non-operated Completions
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
Pinedale

 

 

 

Williston Basin
17

 
16.8

 
3

 
0.0

Uinta Basin
8

 
8.0

 
2

 
0.0

Other Northern

 

 

 

Southern Region
 

 
 

 
 

 
 

Haynesville/Cotton Valley

 

 
5

 
1.1

Permian Basin
7

 
6.7

 

 

Other Southern

 

 

 



23



The following table presents operated and non-operated wells drilling or waiting on completion at March 31, 2016:
 
Operated
 
Non-operated
 
Drilling
 
Waiting on completion
 
Drilling
 
Waiting on completion
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
5

 
1.6

 
31

 
18.9

 

 

 

 

Williston Basin
9

 
8.7

 
20

 
17.0

 
3

 
0.5

 
26

 
1.1

Uinta Basin

 

 

 

 

 

 
1

 
0.0

Other Northern

 

 

 

 

 

 

 

Southern Region
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley

 

 

 

 
3

 
0.5

 
5

 
0.4

Permian Basin

 

 
4

 
4.0

 

 

 

 

Other Southern

 

 

 

 

 

 
2

 
0.0


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 typically utilizes multi-well pad drilling where practical. 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. QEP sometimes suspends completion activities due to adverse weather conditions, operational factors or other macroeconomic circumstances, such as low commodity prices. As a result, QEP had 55 gross operated wells waiting on completion as of March 31, 2016.

RESULTS OF OPERATIONS

Net Income

QEP generated net loss during the first quarter of 2016 of $863.8 million, or $4.55 per diluted share, compared to net loss of $55.6 million, or $0.32 per diluted share, in the first quarter of 2015. QEP's increase in net loss was primarily due to an increase in impairment expense of $1,162.4 million, a 31% decrease in average field-level prices, a $44.6 million increase in depreciation, depletion and amortization and a $40.0 million decrease in realized derivative gains. These changes were partially offset by a 10% increase in natural gas equivalent production, a $10.0 million decrease in unrealized derivative losses and lower operating expenses in the first quarter of 2016 compared to the first quarter of 2015.




24



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.

 
Three Months Ended March 31,
 
2016
 
2015
 
(in millions)
Net income (loss)
$
(863.8
)
 
$
(55.6
)
Interest expense
36.7

 
36.8

Interest and other (income) expense
(2.3
)
 
2.6

Income tax provision (benefit)
(498.9
)
 
(31.5
)
Depreciation, depletion and amortization
240.0

 
195.4

Unrealized (gain) loss on derivative contracts
13.5

 
23.5

Exploration expenses
0.3

 
1.1

Net (gain) loss from asset sales
(0.5
)
 
30.5

Impairment
1,182.4

 
20.0

Other (1)
7.7

 

Adjusted EBITDA
$
115.1

 
$
222.8

 ____________________________
(1) 
Reflects additional legal expenses that the Company believes do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore they have been excluded from the calculation of Adjusted EBITDA.

Adjusted EBITDA decreased to $115.1 million in the first quarter of 2016 from $222.8 million in the first quarter of 2015, due to a 31% decrease in the average equivalent field-level prices and lower realized gains on derivative contracts, partially offset by a 10% increase in natural gas equivalent production.


25



Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP’s major revenue categories for the three months ended March 31, 2016, compared to the three months ended March 31, 2015:
 
Gas
 
Oil
 
NGL
 
Total
 
(in millions)
Production revenues
 
 
 
 
 
 
 
Three months ended March 31, 2015 revenues
$
122.0

 
$
178.8

 
$
19.1

 
$
319.9

Changes associated with volumes (1)
2.3

 
27.7

 
8.4

 
38.4

Changes associated with prices (2)
(39.2
)
 
(62.7
)
 
(13.9
)
 
(115.8
)
Three months ended March 31, 2016 revenues
$
85.1

 
$
143.8

 
$
13.6

 
$
242.5

 ____________________________
(1) 
The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three months ended March 31, 2016, as compared to the three months ended March 31, 2015, by the average field-level price for the three months ended March 31, 2015.
(2) 
The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three months ended March 31, 2016, as compared to the three months ended March 31, 2015, by volumes for the three months ended March 31, 2016. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

Total Volumes and Prices
 
Three Months Ended March 31,
 
2016
 
2015
 
Change
Production volumes (Bcfe)
 
 
 
 
 
Northern Region
 
 
 
 
 
Pinedale
25.2

 
21.8

 
3.4

Williston Basin
29.4

 
25.4

 
4.0

Uinta Basin
7.3

 
6.9

 
0.4

Other Northern
2.3

 
2.7

 
(0.4
)
Southern Region
 
 
 
 


Haynesville/Cotton Valley
9.1

 
11.7

 
(2.6
)
Permian Basin
9.1

 
4.9

 
4.2

Other Southern
0.3

 
1.8

 
(1.5
)
Total production
82.7

 
75.2

 
7.5

Total equivalent prices (per Mcfe)
 
 
 
 
 
Average equivalent field-level price
$
2.93

 
$
4.25

 
$
(1.32
)
Commodity derivative impact
0.75

 
1.36

 
(0.61
)
Net realized equivalent price
$
3.68

 
$
5.61

 
$
(1.93
)


26



Gas Volumes and Prices
 
Three Months Ended March 31,
 
2016

2015
 
Change
Gas production volumes (Bcf)
 
 
 
 
 
Northern Region
 
 
 
 
 
Pinedale
21.7

 
19.0

 
2.7

Williston Basin
3.2

 
2.7

 
0.5

Uinta Basin
5.8

 
4.9

 
0.9

Other Northern
2.0

 
2.4

 
(0.4
)
Southern Region
 

 
 

 
 

Haynesville/Cotton Valley
9.1

 
11.6

 
(2.5
)
Permian Basin
1.4

 
0.7

 
0.7

Other Southern
0.2

 
1.3

 
(1.1
)
Total production
43.4

 
42.6

 
0.8

Gas prices (per Mcf)
Northern Region
$
1.98

 
$
2.85

 
$
(0.87
)
Southern Region
1.91

 
2.89

 
(0.98
)
 
 
 
 
 
 
Average field-level price
1.96

 
2.87

 
(0.91
)
Commodity derivative impact
0.50

 
0.42

 
0.08

Net realized price
$
2.46

 
$
3.29

 
$
(0.83
)

Gas revenues decreased $36.9 million, or 30%, in the first quarter of 2016 compared to the first quarter of 2015, due to lower field-level prices, partially offset by higher gas production. Average field-level gas prices decreased 32% in the first quarter of 2016 compared to the first quarter of 2015 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The 2% increase in production volumes was primarily driven by comparatively strong well completions in Pinedale and the Uinta, Permian and Williston basins. These production increases were partially offset by a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program and the continued divestitures of non-core Other Southern properties.


27



Oil Volumes and Prices
 
Three Months Ended March 31,
 
2016
 
2015
 
Change
Oil production volumes (Mbbl)
 
 
 
 
 
Northern Region
 
 
 
 
 
Pinedale
176.3

 
145.5

 
30.8

Williston Basin
3,718.0

 
3,431.5

 
286.5

Uinta Basin
208.3

 
221.6

 
(13.3
)
Other Northern
36.4

 
45.1

 
(8.7
)
Southern Region
 

 
 

 
 

Haynesville/Cotton Valley
6.6

 
7.8

 
(1.2
)
Permian Basin
1,019.4

 
571.8

 
447.6

Other Southern
11.4

 
58.1

 
(46.7
)
Total production
5,176.4

 
4,481.4

 
695.0

Oil prices (per bbl)
 
 
 
 
 
Northern Region
$
26.72

 
$
38.75

 
$
(12.03
)
Southern Region
31.99

 
46.76

 
(14.77
)
 
 
 
 
 
 
Average field-level price
27.77

 
39.89

 
(12.12
)
Commodity derivative impact
7.87

 
18.75

 
(10.88
)
Net realized price
$
35.64

 
$
58.64

 
$
(23.00
)
 
Oil revenues decreased $35.0 million, or 20%, in the first quarter of 2016 compared to the first quarter of 2015, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 30% in the first quarter of 2016 compared to the first quarter of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 16% increase in production volumes was primarily driven by increases in the Permian and Williston basins due to continued development drilling. These production increases were partially offset by a production decrease in Other Southern due to the continued divestitures of non-core properties.

NGL Volumes and Prices
 
Three Months Ended March 31,
 
2016
 
2015
 
Change
NGL production volumes (Mbbl)
 
 
 
 
 
Northern Region
 
 
 
 
 
Pinedale
402.0

 
313.0

 
89.0

Williston Basin
639.5

 
358.8

 
280.7

Uinta Basin
44.3

 
109.4

 
(65.1
)
Other Northern
3.7

 
2.7

 
1.0

Southern Region
 

 
 

 
 

Haynesville/Cotton Valley
8.4

 
7.1

 
1.3

Permian Basin
262.1

 
119.8