form10q.htm


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


FORM 10-Q

 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarter ended March 31, 2012
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to             
 

 
QEP RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 

 
STATE OF DELAWARE
001-34778
87-0287750
(State or other jurisdiction of
incorporation or organization)
(Commission
File Number)
(I.R.S. Employer
Identification No.)
 
1050 17th Street, Suite 500, 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  x    No  ¨
 
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  x    No  ¨
 
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. (Check one):
 
Large accelerated filer
 
x
 
Accelerated filer
¨
           
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
 
Smaller reporting company
¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
 
At March 31, 2012, there were 178,386,261 shares of the registrant’s common stock, $0.01 par value, outstanding.



 
 

 
 
QEP Resources, Inc.
Form 10-Q for the Quarter Ended March 31, 2012
 
TABLE OF CONTENTS
 
       
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ITEM 2.
 
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ITEM 3.
 
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ITEM 4.
 
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ITEM 1.
 
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ITEM 1A.
 
        41
         
 
ITEM 2.
 
        41
         
 
ITEM 3.
 
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ITEM 4.
 
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ITEM 5.
 
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ITEM 6.
 
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PART I. FINANCIAL INFORMATION
 
ITEM 1.
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
   
Three Months Ended
March 31,
 
   
2012
   
2011
 
   
(in millions, except per share amounts)
 
REVENUES
           
Natural gas sales
  $ 161.2     $ 312.6  
Oil sales
    110.8       63.0  
NGL sales
    97.4       47.9  
Gathering, processing and other
    49.8       46.6  
Purchased gas and oil sales
    184.0       147.8  
Total Revenues
    603.2       617.9  
OPERATING EXPENSES
               
Purchased gas and oil expense
    188.4       146.7  
Lease operating expense
    40.1       32.8  
Natural gas, oil and NGL transportation and other handling costs
    34.5       21.7  
Gathering, processing and other
    23.7       25.2  
General and administrative
    36.0       31.7  
Production and property taxes
    24.7       23.7  
Depreciation, depletion and amortization
    199.2       190.8  
Exploration expenses
    2.0       2.8  
Abandonment and impairment
    6.6       5.4  
Total Operating Expenses
    555.2       480.8  
Net gain from asset sales
    1.5       -  
OPERATING INCOME
    49.5       137.1  
Realized and unrealized gains on commodity derivative contracts (See Note 7)
    216.3       -  
Interest and other income
    1.7       0.6  
Income from unconsolidated affiliates
    1.9       0.9  
Interest expense
    (24.7 )     (22.1 )
INCOME BEFORE INCOME TAXES
    244.7       116.5  
Income taxes
    (88.7 )     (42.7 )
NET INCOME
    156.0       73.8  
Net income attributable to noncontrolling interest
    (0.8 )     (0.6 )
NET INCOME ATTRIBUTABLE TO QEP
  $ 155.2     $ 73.2  
                 
Earnings Per Common Share Attributable to QEP
               
Basic total
  $ 0.87     $ 0.42  
Diluted total
  $ 0.87     $ 0.41  
                 
Weighted-average common shares outstanding
               
Used in basic calculation
    177.4       176.2  
Used in diluted calculation
    178.5       178.3  
Dividends per common share
  $ 0.02     $ 0.02  

See notes accompanying the condensed consolidated financial statements.
 
 
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
   
Three Months Ended
March 31,
 
   
2012
   
2011
 
   
(in millions)
 
Net income
  $ 156.0     $ 73.8  
Other comprehensive income (loss), net of tax:
               
Reclassification of previously deferred derivative gains and losses to net income (1)
    (47.0 )     (47.8 )
Pension and other postretirement plans adjustments:
               
Amortization of net actuarial loss (2)
    0.1       -  
Amortization of prior service cost (3)
    0.9       -  
Total pension and other postretirement plans adjustments
    1.0       -  
Other comprehensive income
    (46.0 )     (47.8 )
Comprehensive income
    110.0       26.0  
Comprehensive income attributable to noncontrolling interests
    (0.8 )     (0.6 )
Comprehensive income attributable to QEP
  $ 109.2     $ 25.4  
 
(1)
Presented net of income tax benefit of $27.8 million and $28.3 million during the three months ended March 31, 2012 and 2011, respectively.
(2)
Presented net of income tax expense of $0.1 million during the three months ended March 31, 2012.
(3)
Presented net of income tax expense of $0.5 million during the three months ended March 31, 2012.
 
See notes accompanying the condensed consolidated financial statements.
 
 
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
   
(in millions)
 
ASSETS
           
Current Assets
           
Cash and cash equivalents
  $ -     $ -  
Accounts receivable, net
    303.5       397.4  
Fair value of derivative contracts
    333.8       273.7  
Inventories, at lower of average cost or market
               
Gas, oil and NGL
    10.9       16.2  
Materials and supplies
    86.6       87.6  
Prepaid expenses and other
    40.6       43.7  
Total Current Assets
    775.4       818.6  
Property, Plant and Equipment (successful efforts method for gas and oil properties)
               
Proved properties
    8,468.3       8,172.4  
Unproved properties, not being depleted
    316.0       326.8  
Midstream field services
    1,510.8       1,463.6  
Marketing and other
    51.6       49.8  
Total Property, Plant and Equipment
    10,346.7       10,012.6  
Less Accumulated Depreciation, Depletion and Amortization
               
Exploration and production
    3,519.9       3,339.2  
Midstream field services
    312.2       297.5  
Marketing and other
    15.5       14.6  
Total Accumulated Depreciation, Depletion and Amortization
    3,847.6       3,651.3  
Net Property, Plant and Equipment
    6,499.1       6,361.3  
Investment in unconsolidated affiliates
    42.6       42.2  
Goodwill
    59.5       59.5  
Fair value of derivative contracts
    115.6       123.5  
Other noncurrent assets
    40.9       37.6  
TOTAL ASSETS
  $ 7,533.1     $ 7,442.7  
                 
LIABILITIES AND EQUITY
               
Current Liabilities
               
Checks outstanding in excess of cash balances
  $ 58.6     $ 29.4  
Accounts payable and accrued expenses
    380.7       457.3  
Production and property taxes
    43.5       40.0  
Interest payable
    8.9       24.4  
Fair value of derivative contracts
    -       1.3  
Deferred income taxes
    57.6       85.4  
Total Current Liabilities
    549.3       637.8  
Long-term debt
    1,673.5       1,679.4  
Deferred income taxes
    1,554.5       1,484.7  
Asset retirement obligations
    167.7       163.9  
Fair value of derivative contracts
    0.1       -  
Other long-term liabilities
    130.3       124.8  
                 
Commitments and contingencies
               
                 
EQUITY
               
Common stock - par value $0.01 per share; 500.0 million shares authorized; 178.4 million and 177.2 million shares issued, respectively
    1.8       1.8  
Treasury stock - 0.7 million and 0.4 million shares, respectively
    (23.4 )     (13.1 )
Additional paid-in capital
    442.6       431.4  
Retained earnings
    2,825.1       2,673.5  
Accumulated other comprehensive income
    161.9       207.9  
Total Common Shareholders' Equity
    3,408.0       3,301.5  
Noncontrolling interest
    49.7       50.6  
Total Equity
    3,457.7       3,352.1  
TOTAL LIABILITIES AND EQUITY
  $ 7,533.1     $ 7,442.7  
 
See notes accompanying the condensed consolidated financial statements.
 
 
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
 
   
(in millions)
 
OPERATING ACTIVITIES
           
Net income
  $ 156.0     $ 73.8  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    199.2       190.8  
Deferred income taxes
    69.1       40.0  
Abandonment and impairment
    6.6       5.4  
Share-based compensation
    5.7       7.4  
Amortization of debt issuance costs and discounts
    1.1       0.8  
Dry exploratory well expense
    0.1       0.6  
Net gain from asset sales
    (1.5 )     -  
Income from unconsolidated affiliates
    (1.9 )     (0.9 )
Distributions from unconsolidated affiliates and other
    1.6       1.8  
Unrealized gain on derivative contracts
    (128.3 )     (31.2 )
Changes in operating assets and liabilities
    20.8       10.9  
Net Cash Provided by Operating Activities
    328.5       299.4  
INVESTING ACTIVITIES
               
Property acquisitions
    (1.4 )     (22.1 )
Property, plant and equipment, including dry exploratory well expense
    (336.5 )     (320.4 )
Proceeds from disposition of assets
    3.3       0.9  
Net Cash Used in Investing Activities
    (334.6 )     (341.6 )
FINANCING ACTIVITIES
               
Checks outstanding in excess of cash balances
    29.2       5.9  
Long-term debt issued
    500.0       -  
Long-term debt issuance costs paid
    (6.9 )     -  
Current portion long-term debt repaid
    -       (58.5 )
Proceeds from credit facility
    120.0       200.0  
Repayments of credit facility
    (626.0 )     (100.0 )
Other capital contributions
    (6.9 )     (0.8 )
Dividends paid
    (3.6 )     (3.5 )
Excess tax benefit on share-based compensation
    2.0       0.4  
Distribution from Questar
    -       0.2  
Distribution to noncontrolling interest
    (1.7 )     (1.5 )
Net Cash Provided by Financing Activities
    6.1       42.2  
Change in cash and cash equivalents
    -       -  
Beginning cash and cash equivalents
    -       -  
Ending cash and cash equivalents
  $ -     $ -  
                 
Supplemental Disclosures:
               
Cash paid for interest
  $ 39.6     $ 44.2  
Cash paid (received) for income taxes
    (2.6 )     (10.8 )
Increase (decrease) in non-cash capital expenditure accruals
    3.5      
(27.7
)

See notes accompanying the condensed consolidated financial statements.
 
 
 QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Note 1 – Nature of Business
 
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through its three principal subsidiaries:
 
 
QEP Energy Company (QEP Energy) acquires, explores for, develops, and produces natural gas, oil, and natural gas liquids (NGL);
 
 
QEP Field Services Company (QEP Field Services) provides midstream field services; including natural gas gathering, processing, compression, and treating services, for affiliates and third parties; and
 
 
QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, provides risk–management services, and owns and operates an underground gas-storage reservoir.
 
Operations are focused in the Northern Region (Rockies) and Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. Company headquarters are located in Denver, Colorado. Shares of QEP common stock trade on the New York Stock Exchange (NYSE: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 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, 2011.
 
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, 2012, are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.
 
De-designation of commodity derivative contracts
 
Effective January 1, 2012, QEP elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses will be recognized in earnings immediately each quarter as derivative contracts are settled and marked-to-market. For the first quarter of 2012 unrealized gains of $128.3 million were included in income that prior to January 1, 2012 would have been deferred in accumulated other comprehensive income under hedge accounting. Refer to Note 7 for additional information.
 
 
Transportation and other handling costs
 
In the fourth quarter of 2011, QEP revised its reporting of transportation and handling costs to reflect revenues in accordance with industry practice and GAAP. Transportation and handling costs, previously netted against revenues, have been recast on the Condensed Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for prior periods presented. The impact of this revision is immaterial to the accompanying financial statements and has no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three months ended March 31, 2011, on the Condensed Consolidated Income Statement.
 
   
As reported (1)
   
As revised
   
Change
 
   
(in millions)
 
REVENUES
                 
Natural gas sales
  $ 271.0     $ 312.6     $ 41.6  
Oil sales
    62.3       63.0       0.7  
NGL sales
    45.8       47.9       2.1  
Gathering, processing and other
    69.3       46.6       (22.7 )
OPERATING EXPENSES
                       
Natural gas, oil and NGL transportation and other handling costs
    -       21.7       21.7  
 
(1)
In addition to the revision described above, QEP Field Services NGL sales of $28.6 million in the first quarter of 2011 have been reclassified from “Gathering, processing and other” into “NGL sales” in the as reported column to be consistent with current period presentation. QEP reported NGL sales of $17.2 million and Gathering, processing and other of $97.9 million in its first quarter 2011 Form 10-Q. The reclassification is all within Revenues and has no effect on income from continuing operations, net income or earnings per share.
 
Oil, Natural Gas, and NGL prices
 
Historically, field-prices received for QEP’s natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling combined with multi-stage hydraulic fracturing, which have allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of crude oil. Changes in the market prices for natural gas, crude 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.
 
New accounting pronouncements
 
In December of 2011, the FASB issued ASU 2011-11, which enhances disclosure requirements regarding an entity’s financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity’s financial position, including the effect of rights of setoff. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. QEP is evaluating the impact of this ASU on its disclosure requirements.
 
Note 3 – Earnings Per Share
 
Basic earnings per share (EPS) are computed by dividing net income attributable to QEP 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.
 
Unvested share-based payment awards that contain nonforfeitable 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 nonforfeitable 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. Consequently, in periods of net loss, the two class method will not have an effect on the Company’s basic earnings per share. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share.
 
 
A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
 
   
(in millions)
 
Weighted-average basic common shares outstanding
    177.4       176.2  
Potential number of shares issuable under the Long-term Stock Incentive Plan
    1.1       2.1  
Average diluted common shares outstanding
    178.5       178.3  

Note 4 – 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 gas and oil wells, production facilities 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 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. Income or expense resulting from the settlement of ARO liabilities is included in “Net gain from asset sales” in the Condensed Consolidated Statements of Income. Changes in ARO were as follows:
 
   
Asset Retirement Obligations
 
   
2012
   
2011
 
   
(in millions)
 
ARO liability at January 1,
  $ 163.9     $ 148.3  
Accretion
    2.5       2.3  
Liabilities incurred
    1.6       2.0  
Liabilities settled
    (0.3 )     (0.2 )
ARO liability at March 31,
  $ 167.7     $ 152.4  

Note 5 – Capitalized Exploratory Well Costs
 
Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year after the completion of drilling.
 
   
Capitalized Exploratory Well Costs
 
   
2012
   
2011
 
   
(in millions)
 
Balance at January 1,
  $ 5.0     $ 13.6  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    -       -  
Reclassifications to property, plant and equipment after the determination of proved reserves
    -       (5.5 )
Balance at March 31,
  $ 5.0     $ 8.1  

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, but does not change existing guidance as to whether or not an instrument is carried at fair value. 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. At March 31, 2012, the Company does not have Level 1 fair value measurements since it uses a broker to access the futures market. 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. QEP’s Level 2 fair value measurements consist of fixed-price swaps of natural gas, oil and NGL. Level 3 inputs are unobservable inputs for the asset or liability. QEP’s Level 3 measurements are made up of costless collars for natural gas and oil. The Level 2 fair value of derivative contracts (see Note 7 “Derivative Contracts”) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry standard discounted cash flow models. The Level 3 fair value of derivative contracts is computed by QEP’s risk management group using the Black-Scholes option pricing model with observable inputs from the NYMEX futures prices, LIBOR one year interest rates, credit default swap rates, and unobservable input of volatility computed from historical prices using the Black-Scholes model.
 
 
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.
 
Certain of QEP’s derivative instruments, however, 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 a counterparty exists.
 
QEP did not have any assets or liabilities measured at fair value on a non-recurring basis, other than ARO’s and property, plant and equipment values for purposes of determining the impairment calculation, at March 31, 2012, or at December 31, 2011. The fair value of financial assets and financial liabilities at March 31, 2012, is shown in the table below:
 
   
Fair Value Measurements
 
   
March 31, 2012
 
   
Level 2
   
Level 3
   
Netting
Adjustments
   
Total
 
   
(in millions)
 
Financial Assets
                       
Commodity derivative instruments - short-term
  $ 347.5     $ -     $ (13.7 )   $ 333.8  
Commodity derivative instruments - long-term
    115.8       -       (0.2 )     115.6  
Total financial assets
  $ 463.3     $ -     $ (13.9 )   $ 449.4  
                                 
Financial Liabilities
                               
Commodity derivative instruments - short-term
  $ 11.6     $ 2.1     $ (13.7 )   $ -  
Commodity derivative instruments - long-term
    0.3       -       (0.2 )     0.1  
Total financial liabilities
  $ 11.9     $ 2.1     $ (13.9 )   $ 0.1  
 
The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the three months ended March 31, 2012, is shown below:
 
   
Change in Level 3 Fair Value Measurements
 
   
2012
   
2011
 
   
(in millions)
 
Balance at January 1,
  $ -     $ 36.3  
Realized gains and losses
    -       17.9  
Unrealized gains and losses
    (2.1 )     (13.1 )
Settlements
    -       (17.9 )
Balance at March 31,
  $ (2.1 )   $ 23.2  
 
 
The fair value of financial assets and financial liabilities at December 31, 2011, is shown in the table below:
 
   
Fair Value Measurements
 
   
December 31, 2011
 
   
Level 2
   
Level 3
   
Netting Adjustments
   
Total
 
   
(in millions)
 
Financial Assets
                       
Commodity derivative instruments - short-term
  $ 284.1     $ -     $ (10.4 )   $ 273.7  
Commodity derivative instruments - long-term
    123.5       -       -       123.5  
Total financial assets
  $ 407.6     $ -     $ (10.4 )   $ 397.2  
                                 
Financial Liabilities
                               
Commodity derivative instruments - short-term
  $ 11.7     $ -     $ (10.4 )   $ 1.3  
Commodity derivative instruments - long-term
    -       -       -       -  
Total financial liabilities
  $ 11.7     $ -     $ (10.4 )   $ 1.3  
 
The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to 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, 2012
   
December 31, 2011
 
   
(in millions)
 
Financial assets
                       
Cash and cash equivalents
  $ -     $ -     $ -     $ -  
Financial liabilities
                               
Checks outstanding in excess of cash balances
  $ 58.6     $ 58.6     $ 29.4     $ 29.4  
Long-term debt
    1,673.5       1,770.8       1,679.4       1,754.9  

The carrying amounts of cash, 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.
 
Note 7 – Derivative Contracts
 
QEP uses commodity price derivative instruments in the normal course of business. QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses derivative instruments to reduce the impact of downward movements in commodity prices on cash flow, returns on capital, and other financial results. However, these instruments typically limit future gains from favorable price movements. The volume of production subject to 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 derivative contracts for up to 100% of forecasted production from proved reserves. QEP does not enter into derivative instruments for speculative purposes.
 
QEP uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Costless collars are combinations of put and call options that have a floor price and a ceiling price and payments are made or received only if the settlement price is outside the range between the floor and ceiling prices. QEP’s derivative instruments do not require the physical delivery of natural gas, crude oil, or NGL between the parties at settlement. Swap and costless collar 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. Natural gas price derivative instruments are typically structured as fixed-price swaps at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. NGL price derivative instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.
 
QEP enters into derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. 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.
 
 
All derivative instruments are recorded on the Condensed Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Reporting changes in the fair value of derivatives depend upon whether the derivative instrument has been designated as a cash flow hedge and qualifies for hedge accounting. A derivative instrument qualifies for hedge accounting if, at inception, the derivative is expected to be highly effective in offsetting the underlying unhedged cash flows. Through December 31, 2011, QEP designated most of its natural gas, oil and NGL derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to Accumulated Other Comprehensive Income (AOCI). Effective January 1, 2012, QEP elected to de-designate all of its natural gas, oil and NGL derivative contracts that had previously been designated as cash flow hedges and discontinue hedge accounting prospectively. As a result, as of January 1, 2012, QEP will recognize all gains and losses from changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any such amounts in AOCI. At December 31, 2011, AOCI consisted of $395.9 million ($248.6 million after tax) of unrealized gains, representing the mark-to-market value of QEP’s cash flow hedges at December 31, 2011, less any ineffectiveness recognized. As a result of discontinuing hedge accounting on January 1, 2012, the mark-to-market values at December 31, 2011 are frozen in AOCI as of the de-designation date and will be reclassified into the statement of income in future periods as the original hedged transactions occur and effect earnings. QEP expects to reclassify into earnings from AOCI the frozen value related to de-designated natural gas, oil and NGL hedges during the remainder of 2012 and in 2013. In addition, in connection with QEP’s election to discontinue hedge accounting, all realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012 will be presented in the statement of income in “Realized and unrealized gains on commodity derivative contracts” below operating income.
 
QEP derivative contracts as a percentage of reported production
 
The following table details the percentage of reported production subject to commodity price derivative contracts for QEP Energy and QEP Field Services.
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
 
QEP Energy
           
Natural gas derivative volumes as a percent of QEP Energy natural gas production
           
Fixed price swaps
    60 %     43 %
Costless collars
    0 %     12 %
Oil derivative volumes as a percent of QEP Energy oil production
               
Fixed price swaps
    37 %     0 %
Costless collars
    15 %     35 %
NGL derivative volumes as a percent of QEP Energy NGL production
               
Fixed price swaps
    16 %     0 %
Costless collars
    0 %     0 %
                 
QEP Field Services
               
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
               
Fixed price swaps
    13 %     0 %
Propane derivative volumes as a percent of propane volumes - QEP Field Services
               
Fixed price swaps
    71 %     0 %
 

QEP Energy Outstanding Derivative Contracts
 
The following table sets forth QEP Energy’s volumes and average prices for its commodity derivative contracts as of March 31, 2012:
 
                 
Swaps
   
Collars
 
Year
 
Type of Contract
 
Index
 
Total Volumes
   
Average price per unit
   
Floor price
   
Ceiling price
 
           
(in millions)
                   
Natural gas sales
         
(MMBtu)
                   
2012
 
 Swap
 
NYMEX
    57.8     $ 4.72              
2012
 
 Swap
 
IFPEPL (1)
    6.1       4.47              
2012
 
 Swap
 
IFNPCR (2)
    65.4       4.69              
2012
 
 Swap
 
IFCNPTE (3)
    7.7       2.67              
2013
 
 Swap
 
NYMEX
    29.2       3.68              
2013
 
 Swap
 
IFNPCR (2)
    65.7       5.66              
Oil sales
         
(Bbls)
                     
2012
 
 Swap
 
 NYMEX WTI
    1.4     $ 97.03              
2012
 
 Collar
 
 NYMEX WTI
    1.1             $ 87.50     $ 115.36  
2013
 
 Swap
 
 NYMEX WTI
    0.2       105.80                  
NGL sales
         
(Gals)
                         
2012
 
 Swap
 
 Mt. Belvieu Ethane
    11.6     $ 0.64                  
2012
 
 Swap
 
 Mt. Belvieu Propane
    17.3     $ 1.28                  
 
(1)
Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.
(2)
Inside FERC monthly settlement index for the Northwest Pipeline Corp. Rocky Mountains.
(3)
Inside FERC monthly settlement index for Centerpoint East.
 
QEP Field Services Outstanding Derivative Contracts
 
QEP Field Services enters into commodity derivative transactions to manage price risk on extracted NGL volumes. The following table sets forth QEP Field Services’ volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

                     
Year
 
Type of Contract
 
Index
 
Total Volumes
   
Average Swap price per gallon
 
           
(in millions)
       
NGL sales
         
(Gals)
       
2012
 
Swap
 
Mt. Belvieu Ethane
    11.6     $ 0.64  
2012
 
Swap
 
 Mt. Belvieu Propane
    9.6     $ 1.35  

QEP Marketing Outstanding Derivative Contracts
 
QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and to lock in a fixed price for some of its customers. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of March 31, 2012:
 
Year
 
Type of Contract
 
Index
 
Total Volumes
   
Average Swaps price per MMBtu
 
           
(in millions)
       
Natural gas sales
         
(MMBtu)
       
2012
 
Swaps
 
IFNPCR (1)
    1.7     $ 4.15  
2013
 
Swaps
 
IFNPCR (1)
    1.2       4.57  
Natural gas purchases
     
(MMBtu)
         
2012
 
Swaps
 
IFNPCR (1)
    1.1     $ 2.80  
 
 
(1)
Inside FERC monthly settlement index for the Northwest Pipeline Corp. Rocky Mountains.
 
 
The following table presents the balance sheet location of QEP’s outstanding commodity 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,
2012
   
December 31,
2011
 
Balance Sheet
line item
 
March 31,
2012
   
December 31,
2011
 
 
   
(in millions)
     
(in millions)
 
Current
                           
Commodity
Fair value of derivative contracts
  $ 347.5     $ 284.1  
Fair value of derivative contracts
  $ 13.7     $ 11.7  
Long-term:
                                   
Commodity
Fair value of derivative contracts
    115.8       123.5  
Fair value of derivative contracts
    0.3       -  
Total commodity derivative instruments
    $ 463.3     $ 407.6       $ 14.0     $ 11.7  
 
The effects and location of derivative transactions on the Condensed Consolidated Income Statements are summarized in the following tables.
 
       
Three Months Ended
March 31,
 
Derivatives not designated as hedging instruments  
Location of gain (loss) recognized in earnings
  2012     2011  
    (in millions)  
Realized gain (loss) on commodity derivative contracts
           
QEP Energy
               
Natural gas derivative contracts
      $ 85.7     $ (31.2 )
Oil derivative contracts
        (2.7 )     -  
NGL derivative contracts
        0.4       -  
QEP Field Services
                   
NGL derivative contracts
        1.1       -  
QEP Marketing
                   
Natural gas derivative contracts
        3.5       -  
Total realized gain (loss)
 
Realized and unrealized gains on commodity derivative instruments
    88.0       (31.2 )
         
Unrealized gain (loss) on commodity derivative contracts
     
QEP Energy
                   
Natural gas derivative contracts
        132.3       31.2  
Oil derivative contracts
        (11.5 )     -  
NGL derivative contracts
        2.9       -  
QEP Field Services
                   
NGL derivative contracts
        3.0       -  
QEP Marketing
                   
Natural gas derivative contracts
        1.6       -  
Total unrealized gain (loss)
 
Realized and unrealized gains on commodity derivative instruments
    128.3       31.2  
Total realized and unrealized gain (loss)
 
Realized and unrealized gains on commodity derivative instruments
  $ 216.3     $ -  
 

       
Three Months Ended
March 31,
 
Cash flow hedge derivative instruments
 
Location of gain (loss) recognized in earnings
  2012     2011  
Commodity derivatives
       
(in millions)
 
Gain (loss) on derivative instruments for the effective portion of hedge recognized in AOCI
 
Accumulated other comprehensive income (loss)
  $ -     $ 0.2  
Gain (loss) reclassified from AOCI into income for effective portion of hedge
 
Natural gas sales
    -       73.1  
Gain (loss) reclassified from AOCI into income for effective portion of hedge
 
Oil sales
    -       -  
Gain (loss) reclassified from AOCI into income for effective portion of hedge
 
NGL sales
    -       -  
Gain (loss) reclassified from AOCI into income for effective portion of hedge
 
Marketing purchases
    -       3.4  
Gain (loss) recognized in income for the ineffective portion of hedges
 
Interest and other income
    -       (0.2 )

It is estimated that derivative contracts that had a fair value at December 31, 2011 of $144.2 million will be settled and reclassified from AOCI to the Condensed Consolidated Statements of Income during the next twelve months.
 
Note 8 – Restructuring Costs
 
During the first quarter of 2012, QEP announced the closure of its Oklahoma City office and consolidation of its two division offices in Oklahoma into one regional office in Tulsa. The creation of one office for QEP’s Southern Region will increase QEP’s efficiency, collaboration, and productivity over the long-term. As part of the restructuring plan and closure of the Oklahoma City office, the Company will incur costs associated with the severance and relocation of employees and other exit costs associated with the termination of the operating lease of its Oklahoma City office space. All costs will be incurred by QEP Energy and are reported within QEP Energy’s financial statements. QEP anticipates total restructuring costs to be approximately $5.8 million, with $1.7 million of those costs relating to one-time termination benefits, $3.6 million relating to the retention and relocation of certain employees to the Tulsa office, and the remaining $0.5 million for the termination of the lease for the Oklahoma City office space. During the three months ended March 31, 2012, a total of $2.7 million of restructuring costs were incurred and recorded in “General and administrative” expense on the Condensed Consolidated Income Statement, of which $1.1 million related to one-time termination benefits. The remaining one-time termination benefits will be recognized ratably over the remaining transition period. QEP expects to recognize the remaining costs not yet incurred in the remainder of 2012. The relocation costs and contract termination costs will be recorded in future periods as the costs are incurred. The following is a reconciliation of QEP Energy’s restructuring liability, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets.
 
   
Restructuring Costs
 
   
(in millions)
 
Balance at December 31, 2011
  $ -  
Costs incurred and charged to expense
    2.7  
Costs paid or otherwise settled
    (2.4 )
Balance at March 31, 2012
  $ 0.3  
 
 
Note 9 – Debt
 
As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under its revolving credit facility, consisted of the following:
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
   
(in millions)
 
Revolving Credit Facility
  $ 100.5     $ 606.5  
6.05% Senior Notes due 2016
    176.8       176.8  
6.80% Senior Notes due 2018
    138.6       138.6  
6.80% Senior Notes due 2020
    138.0       138.0  
6.875% Senior Notes due 2021
    625.0       625.0  
5.375% Senior Notes due 2022
    500.0       -  
Total principal amount of debt
    1,678.9       1,684.9  
Less unamortized discount
    (5.4 )     (5.5 )
Total long-term debt outstanding
  $ 1,673.5     $ 1,679.4  
 
Of the total debt outstanding on March 31, 2012, the $100.5 million drawn under the revolving credit facility (described below) due August 25, 2016, and the 6.05% Senior Notes due September 1, 2016, will mature within the next five years.
 
Credit Arrangements
 
QEP’s revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The revolving credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The revolving credit agreement also contains provisions that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for up to two additional one-year periods. During the first quarter of 2012, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.06%. At March 31, 2012, and December 31, 2011, QEP was in compliance with all of its debt covenants. At March 31, 2012 QEP had $100.5 million drawn and $4.1 million in letters of credit outstanding under the credit facility.
 
Senior Notes
 
During the first quarter of 2012, the Company issued $500 million of Senior Notes due October 2022, with a coupon of 5.375%. The senior notes were issued at face value. Interest on the senior notes will be paid semi-annually, in April and October of each respective year. The net proceeds of approximately $493.0 million were used to repay indebtedness under QEP Resources’ revolving credit facility. The finance costs incurred of approximately $7.0 million will be deferred and amortized over the life of the senior notes. The amortization of all of the Company’s deferred finance costs is included in “Interest expense” on the Condensed Consolidated Income Statement.
 
At March 31, 2012, the Company has $1,578.4 million principal amount of senior notes outstanding with maturities ranging from September 2016 to October 2022 and coupons ranging from 5.375% 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 some or 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 indenture governing QEP’s senior notes contains customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.
 
See Note 14 for additional information regarding the term loan agreement entered into after the balance sheet date.
 
 
Note 10 – Contingencies
 
QEP is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company’s financial position, results of operations or cash flows. In accordance with ASC 450, a liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company believes that the exposure to potential losses from its contingencies deemed as probable is immaterial. For claims deemed reasonably possible the Company does not have a range of potential exposure as an estimate cannot be made because the cases are in their early stages or have a large number of plaintiffs. Disclosures are provided for contingencies reasonably possible to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows but have not yet been accrued. Some of the claims involve numerous plaintiffs, highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined. The following discussion describes the nature of QEP’s major loss contingencies.
 
Environmental Claims
 
United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. Individual members of the Ute Indian Tribe’s Business Committee intervened as co-plaintiffs asserting the same CAA claims as the federal government. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed and operated by QEP Field Services. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air pollutant regulations for monitoring, testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed, as part of their operational design, that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended itself against EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying EPA’s prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all probable outcomes; however, management believes the Company has accrued an estimated loss contingency that is an immaterial amount, for the anticipated most likely outcome.
 
Litigation
 
Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for Oklahoma filed on January 20, 2011. This is a class action filed by a royalty owner on behalf of every QEP Energy royalty owner in the state of Oklahoma since 1988 asserting various claims for damages related to royalty valuation, including breach of contract, breach of fiduciary duty, fraud and conversion, based generally on asserted improper deduction of post-production costs. Because this case is in an early stage prior to full discovery, it is difficult to reasonably estimate potential liability. QEP Energy believes it has properly valued and paid royalty under Oklahoma law and will vigorously defend this claim. Because of the complexities and uncertainties of this legal dispute and the number of plaintiffs, it is difficult to predict all reasonably possible outcomes; however, management believes, at this early litigation stage, the potential loss contingency is an immaterial amount.
 
Note 11 – Share-Based Compensation
 
QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance based share units vest. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 13.2 million shares available for future grants under the LTSIP at March 31, 2012. Share-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Income Statements. During the three months ended March 31, 2012 and 2011, QEP recognized $5.7 million and $7.4 million, respectively, in total compensation expense related to share-based compensation.
 
 
Stock Options
 
QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. 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 calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:
 
   
Stock Option Variables
Three Months Ended
March 31, 2012
 
Fair value of options at grant date
  $ 14.49  
Risk-free interest rate
    0.81 %
Expected price volatility
    55.9 %
Expected dividend yield
    0.26 %
Expected life in years
    5.0  
 
Stock option transactions under the terms of the LTSIP are summarized below:
 
   
Options
Outstanding
   
Weighted-
Average Price
   
Weighted-Average
Remaining
Contractual Term
   
Aggregate
Intrinsic Value
 
         
(per share)
   
(in years)
   
(in millions)
 
Outstanding at December 31, 2011
    2,003,694     $ 21.23              
Granted
    283,029       30.90              
Exercised
    (313,342 )     8.15              
Forfeited
    -       -              
Outstanding at March 31, 2012
    1,973,381     $ 24.69       3.8     $ 13.3  
Options Excercisable at March 31, 2012
    1,393,956     $ 22.08       3.0     $ 12.4  
Unvested Options at March 31, 2012
    579,425     $ 30.97       6.0     $ 0.9  
 
The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $6.9 million and $1.8 million during the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $5.4 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.6 years.
 
Restricted Shares
 
Restricted share grants typically vest in equal installments over a three or four-year period from the grant date. The total fair value of restricted stock that vested was $11.6 million and $7.9 million during the three months ended March 31, 2012 and 2011, respectively. The weighted average grant-date fair value of restricted stock was $30.89 per share and $39.00 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $30.0 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 2.6 years. Transactions involving restricted shares under the terms of the LTSIP are summarized below:
 
   
Restricted Shares
Outstanding
   
Weighted-
Average Price
 
         
(per share)
 
Unvested balance at December 31, 2011
    1,099,752     $ 32.80  
Granted
    659,370       30.89  
Vested
    (362,743 )     32.85  
Forfeited
    (31,036 )     32.89  
Unvested balance at March 31, 2012
    1,365,343     $ 31.87  
 
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 delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $30.90 per share and $39.07 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $4.4 million of unrecognized compensation cost, or the fair market value, related to performance shares granted under the CIP is expected to be recognized over a weighted-average vesting period of 2.6 years. Transactions involving performance shares units under the terms of the CIP are summarized below:
 
   
Performance Share
Units Outstanding
   
Weighted-
Average Price
 
Unvested balance at December 31, 2011
    115,274     $ 39.07  
Granted
    168,448       30.90  
Vested
    -       -  
Forfeited
    (2,707 )     39.07  
Unvested balance at March 31, 2012
    281,015     $ 34.17  
 
Note 12 – Employee Benefits
 
The Company has both qualified and supplemental plans defined-benefit pension plans. The Company also has postretirement benefits that provide certain health care and life insurance benefits for certain retired employees. During the three months ended March 31, 2012, the Company made contributions of $1.3 million to its funded pension plan, and $1.0 million to its unfunded pension plan. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2012, the Company expects to contribute approximately $5.0 million to its funded pension plans, and approximately $0.3 million to its unfunded pension plans. The following table sets forth the Company’s pension and postretirement benefits net period benefit costs:
 
   
Pension
   
Postretirement benefits
 
   
Three Months Ended March 31,
   
Three Months Ended March 31,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in millions)
 
Service cost
  $ 1.0     $ 0.7     $ -     $ -  
Interest cost
    1.2       1.1       0.1       0.1  
Expected return on plan assets
    (0.9 )     (0.6 )     -       -  
Amortization of prior service costs
    1.3       1.3       0.1       0.1  
Amortization of actuarial loss
    0.2       -       -       -  
Periodic expense
  $ 2.8     $ 2.5     $ 0.2     $ 0.2  
 
Note 13 – Operations by Line of Business
 
QEP’s lines of business include natural gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services) and marketing (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. The following table is a summary of operating results by line of business:
 
 
17

 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
 
   
(in millions)
 
Revenues from unaffiliated customers (1) (2)
           
QEP Energy
  $ 396.8     $ 396.2  
QEP Field Services
    93.6       73.3  
QEP Marketing and other
    112.8       148.4  
Total
  $ 603.2     $ 617.9  
                 
Revenues from affiliated companies
               
QEP Field Services
  $ 26.1     $ 23.3  
QEP Marketing and other
    132.3       133.1  
Total
  $ 158.4     $ 156.4  
                 
Operating (loss) income (2)
               
QEP Energy
  $ (12.9 )   $ 87.9  
QEP Field Services
    66.0       47.3  
QEP Marketing and other
    (3.6 )     1.9  
Total
  $ 49.5     $ 137.1  
                 
Net income attributable to QEP
               
QEP Energy
  $ 108.1     $ 43.1  
QEP Field Services
    45.4       28.0  
QEP Marketing and other
    1.7       2.1  
Total
  $ 155.2     $ 73.2  
 

(1)
Revenues for the three months ended March 31, 2011 have been recast to reflect QEP’s revised reporting of its transportation and handling costs. See Note 2 “Basis of Presentation of Interim Consolidated Financial Statements” for additional information. In addition, revenues for the three months ended March 31, 2011 reflect the impact of QEP’s settled derivative contracts which during the three months ended March 31, 2012 are reflected below operating income. See Note 7 “Derivative Contracts” for detailed information on derivative contract settlements in the first quarter of 2011.
(2)
Operating (loss) income in the first quarter of 2012 excludes the impact of realized commodity derivative contract settlements. During the first quarter of 2012 realized gains and losses from realized commodity derivative contract settlements were included below operating income. Conversely, under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the first quarter of 2011.
(3)
Net income attributable to QEP in the first quarter of 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contract. Conversely, under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the first quarter of 2011.
 
Note 14 – Subsequent Events
 
In April 2012, the Company entered into a $300 million senior, unsecured term loan agreement with a group of financial institutions. The term loan agreement provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as the Company’s existing revolving credit agreement. The term loan agreement matures in April of 2017, and the maturity date may be extended one year with the agreement of the lenders. At closing, the Company borrowed $100 million. The Company may borrow the remaining $200 million available under the term loan by June 30, 2012 at which time, any undrawn commitment under the facility will expire.
 
 
ITEM 2. 
 
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 Item 1 of this Quarterly Report on Form 10-Q.
 
The following information updates the discussion of QEP’s financial condition provided in its 2011 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three-month periods ended March 31, 2012 and 2011. For definitions of commonly used gas and oil terms found in this Quarterly Report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in QEP’s 2011 Annual Report on Form 10-K.
 
OVERVIEW
 
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – conducted through three principal subsidiaries:
 
 
QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL) in two principal operating regions: the Southern Region of the United States, which includes the Haynesville/Cotton Valley area in northwest Louisiana and the Midcontinent area with properties primarily located in Oklahoma and Texas, and the Northern Region of the United States, which includes the Pinedale Anticline in western Wyoming, the Uinta Basin in eastern Utah, and the Rockies Legacy, which includes the Bakken/Three Forks area in western North Dakota and other properties primarily in Wyoming, Colorado and New Mexico;
 
 
QEP Field Services Company (QEP Field Services) provides midstream field services, including natural gas gathering and processing, compression and treating services, for affiliates and third parties; and
 
 
QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, provides risk-management services, and owns and operates an underground gas storage reservoir.
 
Strategies
 
We create value for our shareholders through returns-focused growth, superior execution, and a low cost structure. To achieve these objectives we will strive to:
 
 
Operate in a safe and environmentally responsible manner
 
 
Allocate capital to the projects that generate the best returns
 
 
Maintain a sustainable inventory of low-cost, high-margin resource plays
 
 
Be in the best parts of the plays in which we operate
 
 
Build contiguous acreage positions to drive efficiencies
 
 
Be the operator of our assets whenever possible
 
 
Be the low-cost driller and producer in each area where we operate
 
 
Own and operate midstream infrastructure in our core producing areas to control our future and capture value downstream of the wellhead
 
 
Build gas processing plants to extract liquids from our gas streams
 
 
Gather, compress and treat our production to drive down costs
 
 
Actively market our QEP Energy production to maximize value
 
 
Utilize commodities derivatives to reduce the impact of a decline in the prices of our natural gas, crude oil or NGL and to lock in acceptable cash flows to support future capital expenditures
 
 
Attract and retain the best people
 
 
Maintain a strong balance sheet and financial flexibility that allows us to take advantage of both organic growth and acquisition opportunities
 
Outlook
 
The Company has substantial acreage positions and operations in some of North America’s most important hydrocarbon resource plays, including the Bakken/Three Forks, Pinedale, Uinta Basin, Woodford “Cana” and Haynesville Shale. These resource plays are characterized by unconventional oil or natural 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. 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 consistent organic production and reserve growth. QEP believes that it has one of the lowest cash cost structures among its exploration and production company peers. However, in certain of its resource plays, the Company, like its peers, has experienced rising completed well costs which could impact future drilling plans.
 
 
While predominantly a natural gas producer, the Company has increased its focus on growing the relative proportion of crude oil and NGL production in its exploration and production business. QEP Energy oil and NGL production increased by approximately 113% in the first quarter of 2012 compared with the first quarter of 2011. In the first quarter of 2012 oil and NGL revenue accounted for approximately 50% of field-level production revenues in the first quarter of 2012 compared to 25% in the first quarter of 2011. The increased NGL volumes in the first quarter of 2012 were the result of the agreement entered into by QEP Energy with QEP Field Services for Pinedale production, effective August 1, 2011, for fee-based processing at the Blacks Fork II plant, and the liquids recovered for QEP Energy by third party processors associated with the development of liquids-rich plays in the Midcontinent and in the Bakken/Three Forks formations. QEP Energy has allocated approximately 89% of its 2012 total forecasted capital expenditure budget to oil and liquids-rich natural gas plays due to depressed current natural gas prices.
 
While QEP believes that it can grow its production and reserves from its extensive inventory of drilling locations, the Company also evaluates acquisition opportunities that might have the potential to create significant long-term value. QEP believes that its experience, expertise and substantial presence in its core operating areas, combined with its low-cost operating structure and financial strength, enhance its ability to pursue acquisition opportunities in those geographic areas.
 
The Company also owns and operates gathering and transmission pipelines and natural gas processing and treatment facilities in many of its core producing areas, which allows the Company to promptly connect its wells, better control its costs, and generate a significant revenue stream by providing gathering and processing services to third parties. Net income from QEP’s midstream business accounted for 29% of the Company’s total net income during the first quarter of 2012.
 
Financial and Operating Results
 
During the first quarter of 2012, QEP had continued growth from QEP Energy, its exploration and production business, and QEP Field Services, its gathering and processing business. Though natural gas and NGL prices decreased in the first quarter of 2012 from the first quarter of 2011, QEP Energy benefitted from higher total production and higher crude oil prices during the three months ended March 31, 2012, as compared to the 2011 period. In the first quarter of 2012, QEP Field Services benefited from attractive gas processing margins, higher NGL volumes from the Blacks Fork II processing plant, which commenced operations in the second half of 2011.
 
In the first quarter of 2012, QEP Energy reported production of 74.2 Bcfe compared to 65.9 Bcfe in the 2011 first quarter, an increase of 13%. During the three months ended March 31, 2012, the Southern Region contributed 55%, and the Northern Region contributed 45%, respectively, of total equivalent production.
 
QEP Field Services reported gathering system throughput of 1.4 million MMBtu per day for the three months ended March 31, 2012, up from 1.3 million MMBtu in the first quarter of 2011. During the three months ended March 31, 2012, QEP Field Services reported a 63% increase in NGL sales volumes to a total of 45.2 million gallons. The increase in NGL sales volumes, along with a 23% increase in the per unit NGL margin (NGL revenue less fuel and shrink), resulted in a 61% increase to the keep-whole processing margin during the first quarter of 2012.
 
In the first quarter of 2012, QEP issued $500 million of Senior Notes due October 2022, with a coupon of 5.375%. The Senior Notes were issued at face value. The net proceeds of approximately $493.0 million were used to repay indebtedness under QEP’s revolving credit facility. Interest on the Senior Notes is payable April 1 and October 1 of each year, with the first interest payment due on October 1, 2012.
 
Factors Affecting Results of Operations
 
Oil, Natural Gas, and NGL Prices
 
Historically, field-prices received for QEP’s natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling combined with multi-stage hydraulic fracturing, which have allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of crude oil. Changes in the market prices for natural gas, crude 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.
 
 
QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to protect cash flow and returns on invested capital from a drop in commodity prices. In general, QEP plans to hedge approximately 50% of its forecasted production by the end of the first quarter of the current year. As of March 31, 2012, QEP Energy had approximately 66% of its remaining forecasted 2012 natural gas, oil and NGL production covered with fixed-price swaps or costless collars assuming 2012 annual production of 307.5 Bcfe. At March 31, 2012, QEP Energy had approximately 74% of its remaining forecasted 2012 natural gas production covered with fixed-price swaps assuming 2012 annual natural gas production of 242.5 Bcfe. In the first quarter of 2012, QEP has hedged a greater portion of its 2012 natural gas production in light of concerns of oversupply in the natural gas market. See Item 3 “Quantitative and Qualitative Disclosures about Market Risk—Commodity Derivative Transactions” for further details concerning QEP’s commodity derivatives transactions. In addition, as a result of the continued spread between oil and natural gas prices, QEP Energy has allocated approximately 89% of its forecasted 2012 drilling and completion capital expenditure budget to oil and liquids-rich natural gas projects in its portfolio.
 
Unrealized Derivative Gains and Losses
 
Unrealized gains and losses that result from changes in the mark-to-market values of derivative positions that are not accounted for as cash flow hedges are reflected as unrealized commodity derivative gains or losses in the Company’s income statement. The Company has elected to discontinue hedge accounting beginning January 1, 2012, and unrealized gains and losses that result from mark-to-market valuations of all derivative positions will be reflected as unrealized commodity derivative gains or losses in the Company’s income statement. See Note 7 - Derivative Contracts to the Condensed Consolidated Financial Statements, in Item 1, Part I of this Quarterly Report on Form 10-Q for additional information regarding the discontinuance of hedge accounting. Payments due to or from counterparties in the future on these derivatives will typically be offset by corresponding changes in prices ultimately received from the sale of QEP’s production. QEP has incurred significant unrealized gains and losses in the 2012 first quarter and prior periods and may continue to incur these types of gains and losses in the future.
 
Global Economy and the European Debt Crisis
 
QEP continues to monitor the outlook of the global economy, including the European debt crisis and its potential impact on global economic growth and the banking and financial sectors, the United States federal budget deficit, and commodity prices. QEP expects natural gas prices to remain low in the United States if the natural gas drilling rig count does not decline, natural gas storage levels remain high and natural gas production continues to grow. QEP expects oil prices to remain at or above current levels if the global economy continues its recovery. Disruption to the global oil supply system or other factors could trigger additional oil price volatility with sharp increases in the crude oil price that could be followed by sharp declines in the crude oil price that the Company may receive for its oil production. Because of the global economic outlook and the uncertainty around the commodity pricing environment, QEP continues to plan its capital spending program and financial flexibility appropriately.
 
Potential for Future Asset Impairments
 
Natural gas prices in the United States decline in the first quarter of 2012 due to market concerns about growing natural gas production and record high levels of natural gas storage levels after an unusually warm winter. The carrying value of some of the Company’s properties are sensitive to declines in natural gas prices. These assets are at risk of impairment if future prices for natural gas as reflected in the forward curve continue to decline. 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 and gas 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 natural gas prices alone could result in an impairment of properties that are sensitive to declines in natural gas prices. A significant drop in oil prices, though not anticipated, could also trigger impairment. For additional information see Item 1A “Risk Factors” of Part I and see Item 8, Note 1 “Significant Accounting Policies” of Part II of QEP’s 2011 Annual Report on Form 10-K.
 
Critical Accounting Estimates
 
QEP’s significant accounting policies are described in Item 7 of Part II of its 2011 Annual Report on Form 10-K. The Company’s Condensed Consolidated Financial Statements are prepared in accordance with United States Generally Accepted Accounting Principles. The preparation of 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 gas and oil reserves, successful efforts accounting for gas and oil operations, accounting for derivative contracts and revenue recognition, among others, may involve a higher degree of complexity and judgment on the part of management.
 
 
RESULTS OF OPERATIONS
 
Net Income
 
Net income attributable to QEP for the first quarter of 2012 was $155.2 million or $0.87 per diluted share, compared to $73.2 million or $0.41 per diluted share in the first quarter of 2011. The increase in 2012 was due to a 151% increase in QEP Energy’s net income and a 62% increase in QEP Field Services net income. QEP Energy’s net income increased in the first quarter of 2012 due to a $123.7 million gain on unrealized commodity derivative contracts, deferred in accumulated other comprehensive income in the first quarter of 2011, along with significant increases in oil and NGL production and increased oil prices. QEP Field Services’ increase in net income was driven by 75% higher processing margins. Following are comparisons of net income attributable to QEP by line of business:
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
   
Change
 
   
(in millions)
 
QEP Energy
  $ 108.1     $ 43.1     $ 65.0  
QEP Field Services
    45.4       28.0       17.4  
QEP Marketing and other
    1.7       2.1       (0.4 )
Net income from continuing operations attributable to QEP
  $ 155.2     $ 73.2     $ 82.0  
                         
Earnings per diluted share from continuing operations
  $ 0.87     $ 0.41     $ 0.46  
Average diluted shares
    178.5       178.3       0.2  
 
Adjusted EBITDA
 
Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company’s cash flow and liquidity and its ability to incur and service debt, fund capital expenditures and make distributions to shareholders, and an important measure for comparing the Company’s financial performance to other gas and oil producing companies. In addition, Adjusted EBITDA is part of the Company’s debt covenants under its revolving credit and term loan agreements. Management defines Adjusted EBITDA as net income before the following items: depreciation, depletion and amortization (DD&A), abandonment and impairment, interest and other income, interest expense, income taxes, unrealized gains and losses on derivative contracts, discontinued operations, gains and losses from assets sales, and exploration expense. During the year ended December 31, 2011, QEP revised its reporting of transportation and handling costs to align with industry practice and GAAP. This revised disclosure does not change current or prior period disclosure of net income or Adjusted EBITDA. For additional information, see Note 2 - Basis of Presentation of Interim Consolidated Financial Statements to the Condensed Consolidated Financial Statements, in Item 1, Part I of the Quarterly Report on Form 10-Q, for additional details. Following are comparisons of Adjusted EBITDA by line of business:
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
   
Change
 
   
(in millions)
 
QEP Energy
  $ 260.8     $ 242.0     $ 18.8  
QEP Field Services
    84.3       61.4       22.9  
QEP Marketing and other
    0.6       2.4       (1.8 )
Total Adjusted EBITDA
  $ 345.7     $ 305.8     $ 39.9  
 
Adjusted EBITDA increased to $345.7 million for the first quarter of 2012 compared to $305.8 million in the 2011 period, despite a 13% decrease in net realized natural gas prices and 13% lower net realized NGL prices. The impact of lower net realized natural gas and NGL prices during the first quarter of 2012 was offset by a 13% increase in total production, 7% higher net realized crude oil prices in QEP Energy, along with increased processing margins in QEP Field Services.
 
 
A reconciliation of Adjusted EBITDA to net income follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
   
Change
 
   
(in millions)
 
Net income attributable to QEP
  $ 155.2     $ 73.2     $ 82.0  
Net income attributable to non-controlling interest
    0.8       0.6       0.2  
Net income
    156.0       73.8       82.2  
Unrealized (gain) on derivative contracts
    (128.3 )     (31.2 )     (97.1 )
Net (gain) from asset sales
    (1.5 )     -       (1.5 )
Interest and other income
    (1.7 )     (0.6 )     (1.1 )
Income taxes
    88.7       42.7       46.0  
Interest expense
    24.7       22.1       2.6  
Depreciation, depletion and amortization
    199.2       190.8       8.4  
Abandonment and impairment
    6.6       5.4       1.2  
Exploration expenses
    2.0       2.8       (0.8 )
Adjusted EBITDA
  $ 345.7     $ 305.8     $ 39.9  
 
Revenue, Volumes and Prices
 
On January 1, 2012, QEP discontinued hedge accounting. During the first quarter of 2012, commodity derivative realized gains and losses from derivative contract settlements were included below operating income in “Realized and unrealized gains on commodity derivative instruments on the Condensed Consolidated Income Statement. Conversely, during the first quarter of 2011, the commodity derivative realized gains and losses on settlements were included in each respective revenue category in conjunction with hedge accounting and the realization of the underlying contract. For additional information regarding the discontinuance of hedge accounting and impact on the Condensed Consolidated Income Statement, see Note 7 - Derivative Contracts, in Part I, Item 1 of this Quarterly Report on Form 10-Q.
 
   
Three Months Ended
 
   
March 31,
 
   
2012
   
2011
   
Change
 
   
(in millions)
 
QEP Resources Revenues
                 
Natural gas sales
  $ 161.2     $ 312.6     $ (151.4 )
Oil sales
    110.8       63.0       47.8  
NGL sales
    97.4       47.9       49.5  
Gathering, processing and other
    49.8       46.6       3.2  
Purchased gas and oil sales
    184.0       147.8       36.2  
Total Revenues
  $ 603.2     $ 617.9     $ (14.7 )
 

 
QEP Energy’s revenues for the three months ended March 31, 2012, resulting from the sale of natural gas, oil and NGLs increased primarily due to increased production volumes and higher oil prices, offset by lower prices for natural gas and NGL, as follows:
   
Three Months Ended March 31,
 
   
Natural Gas
   
Oil
   
NGLs
   
Total
 
   
(in millions)
 
QEP Energy Revenues
                       
2011 revenues
  $ 312.6     $ 63.0     $ 18.4     $ 394.0  
Changes associated with volumes (1)
    2.4       37.9       39.7       80.0  
Changes associated with prices (2)
    (80.7 )     9.9       (8.2 )     (79.0 )
Changes associated with discontinuance of hedge accounting (3)
    (73.1 )     -       -       (73.1 )
2012 revenues
  $ 161.2     $ 110.8     $ 49.9     $ 321.9  

(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, 2012, to the three months ended March 31, 2011, by the average realized price or fee for the three months ended March 31, 2011.