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 September 30, 2011
 
¨
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
 
¨
 
Accelerated filer
 
¨
             
Non-accelerated filer
  x
(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 September 30, 2011, there were 176,952,496 shares of the registrant’s common stock, $0.01 par value, outstanding.



 
 

 

QEP Resources, Inc.
Form 10-Q for the Quarter Ended September 30, 2011
 
TABLE OF CONTENTS
 
       
Page
1
         
 
ITEM 1.
 
1
         
 
ITEM 2.
 
17
         
 
ITEM 3.
 
35
         
 
ITEM 4.
 
39
   
39
         
 
ITEM 1.
 
39
         
 
ITEM 2.
 
39
         
 
ITEM 3.
 
39
   
40

 
PART I. FINANCIAL INFORMATION
 
ITEM 1.
FINANCIAL STATEMENTS
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in millions, except per share amounts)
 
REVENUES
                       
Natural gas sales
  $ 266.7     $ 283.2     $ 795.8     $ 808.4  
Oil sales
    76.1       49.9       218.4       139.5  
NGL sales
    34.1       9.3       67.8       27.4  
Gathering, processing and other
    118.7       76.4       340.1       238.7  
Purchased gas and oil sales
    356.8       145.8       810.6       460.4  
Total Revenues
    852.4       564.6       2,232.7       1,674.4  
OPERATING EXPENSES
                               
Purchased gas and oil expense
    352.7       143.6       803.3       455.4  
Lease operating expense
    37.0       32.8       104.1       89.7  
Gathering, processing and other
    27.0       19.5       79.4       62.6  
General and administrative
    28.7       24.7       89.1       75.6  
Separation costs
    -       0.2       -       14.2  
Production and property taxes
    27.7       19.7       78.5       61.6  
Depreciation, depletion and amortization
    189.0       170.5       566.4       469.5  
Exploration expenses
    2.4       2.9       7.5       9.2  
Abandonment and impairment
    5.7       12.2       16.4       29.1  
Total Operating Expenses
    670.2       426.1       1,744.7       1,266.9  
Net gain from asset sales
    1.2       10.8       1.4       12.3  
OPERATING INCOME
    183.4       149.3       489.4       419.8  
Interest and other income (loss)
    (0.7 )     1.6       (0.5 )     4.4  
Income from unconsolidated affiliates
    2.3       1.1       4.5       2.5  
Loss from early extinguishment of debt
    (0.7 )     (13.3 )     (0.7 )     (13.3 )
Interest expense
    (22.8 )     (22.6 )     (67.0 )     (62.8 )
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    161.5       116.1       425.7       350.6  
Income taxes
    (59.1 )     (44.2 )     (156.0 )     (130.5 )
INCOME FROM CONTINUING OPERATIONS
    102.4       71.9       269.7       220.1  
Discontinued operations, net of income tax
    -       -       -       43.2  
NET INCOME
    102.4       71.9       269.7       263.3  
Net income attributable to noncontrolling interest
    (0.9 )     (0.8 )     (2.2 )     (2.1 )
NET INCOME ATTRIBUTABLE TO QEP
  $ 101.5     $ 71.1     $ 267.5     $ 261.2  
                                 
Earnings Per Common Share Attributable to QEP
                               
Basic from continuing operations
  $ 0.58     $ 0.40     $ 1.52     $ 1.24  
Basic from discontinued operations
    -       -       -       0.25  
Basic total
  $ 0.58     $ 0.40     $ 1.52     $ 1.49  
Diluted from continuing operations
  $ 0.57     $ 0.40     $ 1.50     $ 1.23  
Diluted from discontinued operations
    -       -       -       0.24  
Diluted total
  $ 0.57     $ 0.40     $ 1.50     $ 1.47  
Weighted-average common shares outstanding
                               
Used in basic calculation
    176.6       175.4       176.5       175.2  
Used in diluted calculation
    178.5       177.9       178.5       177.6  
Dividends per common share
  $ 0.02     $ 0.02     $ 0.06     $ 0.02  
 
See notes accompanying the condensed consolidated financial statements


QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
   
September 30,
2011
   
December 31,
2010
 
   
(in millions)
 
ASSETS
           
Current Assets
           
Cash and cash equivalents
  $ -     $ -  
Accounts receivable, net
    355.3       269.9  
Fair value of derivative contracts
    225.4       257.3  
Inventories, at lower of average cost or market
               
Gas, oil and NGL
    16.1       16.4  
Materials and supplies
    87.1       65.4  
Prepaid expenses and other
    35.6       45.2  
Total Current Assets
    719.5       654.2  
Property, Plant and Equipment (successful efforts method for gas and oil properties)
               
Proved properties
    7,780.8       6,874.3  
Unproved properties, not being depleted
    326.3       322.0  
Midstream field services
    1,430.6       1,360.5  
Marketing and other
    47.8       44.5  
Total Property, Plant and Equipment
    9,585.5       8,601.3  
Less Accumulated Depreciation, Depletion and Amortization
               
Exploration and production
    2,963.6       2,454.4  
Midstream field services
    283.7       244.6  
Marketing and other
    14.0       12.3  
Total Accumulated Depreciation, Depletion and Amortization
    3,261.3       2,711.3  
Net Property, Plant and Equipment
    6,324.2       5,890.0  
Investment in unconsolidated affiliates
    44.1       44.5  
Goodwill
    59.5       59.6  
Fair value of derivative contracts
    116.4       120.8  
Other noncurrent assets
    33.2       16.2  
TOTAL ASSETS
  $ 7,296.9     $ 6,785.3  
LIABILITIES AND EQUITY
               
Current Liabilities
               
Checks outstanding in excess of cash balances
  $ 26.7     $ 19.5  
Accounts payable and accrued expenses
    455.3       332.2  
Production and property taxes
    40.4       18.9  
Interest payable
    6.2       28.1  
Fair value of derivative contracts
    39.8       139.3  
Deferred income taxes
    20.7       27.8  
Current portion of long-term debt
    -       58.5  
Total Current Liabilities
    589.1       624.3  
Long-term debt, less current portion
    1,582.7       1,472.3  
Deferred income taxes
    1,535.0       1,377.7  
Asset retirement obligations
    160.2       148.3  
Fair value of derivative contracts
    -       0.3  
Other long-term liabilities
    103.3       99.3  
Commitments and contingencies
               
EQUITY
               
Common stock
    1.8       1.8  
Treasury stock
    (11.6 )     (3.8 )
Additional paid-in capital
    423.9       398.0  
Retained earnings
    2,677.2       2,420.0  
Accumulated other comprehensive income
    184.4       194.3  
Total Common Shareholders' Equity
    3,275.7       3,010.3  
Noncontrolling interest
    50.9       52.8  
Total Equity
    3,326.6       3,063.1  
TOTAL LIABILITIES AND EQUITY
  $ 7,296.9     $ 6,785.3  
 
See notes accompanying the condensed consolidated financial statements


QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)

   
Nine Months Ended
September 30,
 
   
2011
   
2010
 
   
(in millions)
 
OPERATING ACTIVITIES
           
Net income
  $ 269.7     $ 263.3  
Discontinued operations, net of income tax
    -       (43.2 )
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    566.4       469.5  
Deferred income taxes
    155.9       206.3  
Abandonment and impairment
    16.4       29.1  
Share-based compensation
    16.5       11.3  
Amortization of debt issuance costs and discounts
    2.4       1.8  
Dry exploratory well expense
    0.5       -  
Net gain from asset sales
    (1.4 )     (12.3 )
Income from unconsolidated affiliates
    (4.5 )     (2.5 )
Distributions from unconsolidated affiliates and other
    7.6       2.1  
Loss on early extinguishment of debt
    0.7       13.3  
Unrealized gain on basis-only swaps
    (86.7 )     (90.0 )
Changes in operating assets and liabilities
    12.2       (80.7 )
Net Cash Provided by Operating Activities of Continuing Operations
    955.7       768.0  
INVESTING ACTIVITIES
               
Property acquisitions
    (40.7 )     (94.1 )
Property, plant and equipment, including dry exploratory well expense
    (957.7 )     (941.8 )
Proceeds from disposition of assets
    7.4       25.4  
Change in notes receivable
    -       52.9  
Net Cash Used in Investing Activities of Continuing Operations
    (991.0 )     (957.6 )
FINANCING ACTIVITIES
               
Checks outstanding in excess of cash balances
    7.2       -  
Long-term debt issued
    280.0       819.3  
Long-term debt issuance costs paid
    (10.5 )     (18.1 )
Current portion long-term debt repaid
    (58.5 )     (91.5 )
Repayments of notes payable
    -       (39.3 )
Long-term debt repaid
    (170.0 )     (721.5 )
Long-term debt extinguishment costs
    -       (4.9 )
Other capital contributions
    1.6       1.4  
Equity contribution
    -       250.0  
Dividends paid
    (10.6 )     (3.5 )
Distribution from Questar
    0.2       (15.7 )
Distribution to noncontrolling interest
    (4.1 )     (3.7 )
Net Cash Provided by Financing Activities of Continuing Operations
    35.3       172.5  
CASH USED IN CONTINUING OPERATIONS
    -       (17.1 )
Cash provided by operating activities of discontinued operations
    -       68.6  
Cash used in investing activities of discontinued operations
    -       (39.9 )
Cash used in financing activities of discontinued operations
    -       (26.9 )
Effect of change in cash and cash equivalents of discontinued operations
    -       (1.8 )
Change in cash and cash equivalents
    -       (17.1 )
Beginning cash and cash equivalents
    -       19.3  
Ending cash and cash equivalents
  $ -     $ 2.2  

See notes accompanying the condensed consolidated financial statements
 
 
3

 
QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Note 1 – Nature of Business
 
QEP Resources, Inc. (QEP or the Company), is an independent natural gas and oil exploration and production company. QEP 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);
 
 
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.
 
Operations are focused in the Northern (formerly Rocky Mountain) and Southern (formerly Midcontinent) Regions of the United States. Company headquarters are 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 U.S. 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 presentation 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, 2010.
 
The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and nine months ended September 30, 2011, are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.
 
Reincorporation Merger and Spin-off
 
Effective May 18, 2010, Questar Market Resources, Inc. (Market Resources), then a wholly owned subsidiary of Questar Corporation (Questar), merged with and into a newly formed, wholly owned subsidiary, QEP, a Delaware corporation, in order to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. The Reincorporation Merger was approved by the boards of directors of Market Resources and QEP and submitted to a vote of, and approved by, the Board of Directors of Questar, as sole shareholder of Market Resources, and by Market Resources, as sole shareholder of QEP on May 18, 2010.
 
On June 30, 2010, Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a tax-free, pro rata dividend (the Spin-off). Each Questar shareholder received one share of QEP common stock for each one share of Questar common stock held (including fractional shares) at the close of business on the record date. In connection therewith, QEP distributed Wexpro Company (Wexpro), a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.
 
The financial information presented in this Form 10-Q presents QEP’s financial results as an independent company separate from Questar and reflects Wexpro’s financial condition and operating results as discontinued operations for all periods presented. A summary of discontinued operations can be found in Note 3 to the condensed consolidated financial statements.
 
New accounting pronouncements
 
In September of 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-08, which amends the guidance on testing goodwill for impairment. The new guidance provides entities that are testing goodwill the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If it is determined, based on the qualitative assessment, that the carrying value of the reporting unit is more likely than not less than the fair value, further impairment testing is not required. However, if the qualitative assessment does not provide such conclusive evidence, further testing and calculation of fair value of the reporting unit will be required. The amendments are effective for reporting periods (including interim periods) beginning after December 15, 2011. QEP does not expect that this ASU, once adopted, will have a material impact on its financial statements.
 
 
In June of 2011, the FASB issued ASU 2011-05, which revises the manner entities are able to present the components of comprehensive income in their financial statements. The new guidance requires entities to report the components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. However, this ASU does not change the items that are reported in other comprehensive income. The amendments are effective for reporting periods (including interim periods) beginning after December 15, 2011. This ASU will require minor disclosure changes to QEP’s financial statements and footnotes once adopted.
 
In May of 2011, the FASB issued ASU 2011-04, which provides converged guidance on how to measure fair value and requires additional disclosures relating to fair value measurements. Most of the amendments created by this ASU are to bridge the gap between GAAP and International Financial Reporting Standards. However some of the amendments may change how the current fair value measurement guidance is applied. In addition, the ASU expands the qualitative and quantitative fair value disclosure requirements, with most of these additional disclosures pertaining to Level 3 measurements. The amendments are effective for reporting periods (including interim periods) beginning after December 15, 2011. QEP is currently evaluating the impact that this ASU will have on its financial statements and disclosures.
 
Note 3 – Discontinued Operations

Wexpro’s operating results prior to the Spin-off are reflected in this quarterly report on Form 10-Q as discontinued operations and summarized below:
 
   
Three Months Ended
 September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in millions, except per share amounts)
 
Revenues
  $ -     $ -     $ -     $ 131.2  
Income before income taxes
    -       -       -       67.4  
Income taxes
    -       -       -       (24.2 )
Discontinued operations, net of income taxes
  $ -     $ -     $ -     $ 43.2  
Earnings per common share attributable to QEP
                               
Basic from discontinued operations
  $ -     $ -     $ -     $ 0.25  
Diluted from discontinued operations
    -       -       -       0.24  
 
Note 4 – Comprehensive Income
 
Comprehensive income is the sum of net income attributable to QEP as reported in the Consolidated Statements of Income and other comprehensive income. Other comprehensive income includes certain items that are recorded directly to Equity and classified as accumulated other comprehensive income (AOCI). One component of other comprehensive income is changes in the market value of commodity-based derivative instruments that qualify for hedge accounting. Income or loss associated with commodity-based derivative instruments that qualify for hedge accounting is realized when the gas, oil or NGL underlying the derivative instrument is sold. Comprehensive income also includes changes in the underfunded portion of the defined benefit pension plans and other post retirement plans and changes in deferred income taxes on such amounts. These transactions are not the culmination of the earnings process but result from adjusting historical balances to fair value. Comprehensive income attributable to QEP is shown below:
 
   
Three Months Ended
September 30,
   
Nine Months Ended
 September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in millions)
 
Net income
  $ 102.4     $ 71.9     $ 269.7     $ 263.3  
Other comprehensive income (loss)
                               
Net unrealized income (loss) on derivatives
    59.5       125.0       (20.6 )     359.2  
Minimum pension liability adjustment
    2.2       (16.2 )     5.0       (54.9 )
Income taxes
    (23.0 )     (39.9 )     5.7       (112.6 )
Net other comprehensive income (loss)
    38.7       68.9       (9.9 )     191.7  
Comprehensive income
    141.1       140.8       259.8       455.0  
Comprehensive income attributable to noncontrolling interest
    (0.9 )     (0.8 )     (2.2 )     (2.1 )
Comprehensive income attributable to QEP
  $ 140.2     $ 140.0     $ 257.6     $ 452.9  

The components of AOCI, net of income taxes, shown on the Condensed Consolidated Balance Sheets are as follows:
 
   
September 30,
2011
   
December 31
,2010
   
Change
 
   
(in millions)
 
Net unrealized gain on derivatives
  $ 210.8     $ 223.8     $ (13.0 )
Pension and postretirement liabilities
    (26.4 )     (29.5 )     3.1  
Accumulated other comprehensive income
  $ 184.4     $ 194.3     $ (9.9 )
 
Note 5 – 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
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in millions)
 
Weighted-average basic common shares outstanding
    176.6       175.4       176.5       175.2  
Potential number of shares issuable under the Long-term Stock Incentive Plan
    1.9       2.5       2.0       2.4  
Average diluted common shares outstanding
    178.5       177.9       178.5       177.6  

Note 6 – Asset Retirement Obligations
 
QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO liability applies primarily to abandonment costs associated with 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 or (loss) from asset sales in the Consolidated Statements of Income. Changes in ARO were as follows:
 
 
   
2011
   
2010
 
   
(in millions)
 
ARO liability at January 1,
  $ 148.3     $ 124.7  
Accretion
    7.2       6.5  
Liabilities incurred
    6.5       14.8  
Revisions
    -       0.5  
Liabilities settled
    (1.8 )     (2.3 )
ARO liability at September 30,
  $ 160.2     $ 144.2  
 
Note 7 – 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.
 
   
2011
   
2010
 
   
(in millions)
 
Balance at January 1,
  $ 13.6     $ 51.7  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    -       18.8  
Reclassifications to property, plant and equipment after the determination of proved reserves
    (8.3 )     (50.3 )
Balance at September 30,
  $ 5.3     $ 20.2  
 
Note 8 – 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. 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 9) 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 based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing 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.
 
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, at September 30, 2011, or at December 31, 2010. The fair value of assets and liabilities at September 30, 2011, is shown in the table below:
 
   
Fair Value Measurements
September 30, 2011
 
   
Level 2
   
Level 3
   
Netting Adjustments
   
Total
 
   
(in millions)
 
Assets
                       
Derivative contracts - short term
  $ 258.1     $ 10.7     $ (43.4 )   $ 225.4  
Derivative contracts - long term
    116.4       -       -       116.4  
Total assets
  $ 374.5     $ 10.7     $ (43.4 )   $ 341.8  
Liabilities
                               
Derivative contracts - short term
  $ 83.2     $ -     $ (43.4 )   $ 39.8  
Derivative contracts - long term
    -       -       -       -  
Total liabilities
  $ 83.2     $ -     $ (43.4 )   $ 39.8  
 
The change in the fair value of Level 3 assets and liabilities for the nine months ended September 30, 2011, is shown below:
 
   
Derivative contracts 2011
 
   
(in millions)
 
Balance at January 1,
  $ 36.3  
Realized gains and losses included in revenues
    10.7  
Unrealized gains and losses included in other comprehensive income
    (25.6 )
Settlements
    (10.7 )
Balance at September 30,
  $ 10.7  
 
The fair value of assets and liabilities at December 31, 2010, is shown in the table below:
 
   
Fair Value Measurements
December 31, 2010
 
   
Level 2
   
Level 3
   
Netting Adjustments
   
Total
 
   
(in millions)
 
Assets
                       
Derivative contracts - short term
  $ 374.6     $ 37.9     $ (155.2 )   $ 257.3  
Derivative contracts - long term
    121.1       -       (0.3 )     120.8  
Total assets
  $ 495.7     $ 37.9     $ (155.5 )   $ 378.1  
Liabilities
                               
Derivative contracts - short term
  $ 292.9     $ 1.6     $ (155.2 )   $ 139.3  
Derivative contracts - long term
    0.6       -       (0.3 )     0.3  
Total liabilities
  $ 293.5     $ 1.6     $ (155.5 )   $ 139.6  
 
 
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
   
Estimated
Fair Value
   
Carrying
Amount
   
Estimated
Fair Value
 
   
September 30, 2011
   
December 31, 2010
 
   
(in millions)
 
Financial assets
                       
Cash and cash equivalents
  $ -     $ -     $ -     $ -  
Financial liabilities
                               
Checks outstanding in excess of cash balances
    26.7       26.7       19.5       19.5  
Long-term debt
    1,582.7       1,640.5       1,530.8       1,575.8  

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 9 – Derivative Contracts
 
QEP uses commodity price derivative instruments in the normal course of business. QEP has established policies and procedures for managing commodity price risks through the use of derivative instruments. The Company follows the provisions of ASC 815 “Derivatives and Hedging,” which require detailed information about derivative transactions including the location and effect on the primary condensed consolidated financial statements.
 
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 same 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 when prices meet return on invested capital and cash flow objectives. 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 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. In the past, QEP Energy has used natural gas basis-only swaps to protect cash flow, project returns, and other financial results from widening natural gas price basis differentials. As of December 31, 2009, all of the Company’s natural gas basis-only swaps had been paired with NYMEX gas fixed-price swaps or costless collars and re-designated as cash flow hedges.
 
QEP generally enters into derivative instruments that do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash 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 by transacting with multiple counterparties.
 
 
All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their fair values. Reported changes in the fair value of derivatives depend upon whether the derivative instrument 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. Generally, QEP’s derivative instruments are matched to company-owned gas, oil and NGL production and are therefore highly effective, thus qualifying as cash flow hedges. Changes in the fair value of effective cash flow hedges are recorded as a component of AOCI in the Condensed Consolidated Balance Sheets and reclassified to earnings as gas, oil and NGL sales when the underlying contract is settled. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Oil hedges are typically structured as NYMEX Calendar fixed-price swaps based at Cushing, Oklahoma. Oil fixed-priced swaps inherently contain ineffectiveness because physical sales are priced at the purchaser’s published regional prices. NGL hedges are typically structured as Mont Belvieu, Texas fixed-price swaps.  Since most of our NGL sales are also based upon Mont Belvieu prices, there is no ineffectiveness. Costless collars qualify for cash flow hedge accounting. Basis-only swaps do not qualify for hedge accounting treatment. Changes in the fair value of these derivative instruments subsequent to their re-designation were recorded in AOCI, while changes in their fair value occurring prior to their re-designation were recorded in the Consolidated Statement of Income. QEP regularly reviews the effectiveness of derivative instruments. The ineffective portion of cash flow hedges and the mark-to-market adjustment in the value of basis-only swaps are recognized in the determination of net income. The effects of derivative transactions are summarized in the tables below:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in millions)
 
Effect of derivative instruments designated as cash flow hedges
                       
Gains (losses) recognized in AOCI for the effective portion of hedges
  $ 129.6     $ 221.4     $ 191.1     $ 597.3  
Gains (losses) reclassified from AOCI into income for the effective portion of hedges
                               
Natural gas sales
    71.6       97.6       209.1       240.7  
Oil sales
    0.9       (1.4 )     1.0       (5.2 )
Gathering, processing and other
    (0.3     -       (0.3 )     -  
Purchased gas and oil sales
    -       -       -       -  
Purchased gas and oil expense
    0.4       0.3       4.3       2.7  
Loss recognized in income for the ineffective portion of hedges
                               
Interest and other income
    (2.7 )     (0.1 )     (2.6 )     (0.2 )
Effect of derivative instruments not designated as hedges
                               
Unrealized gain on basis-only swaps
    27.9       27.9       86.7       90.0  
Realized loss on basis-only swaps
    (27.9 )     (27.9 )     (86.7 )     (90.0 )
 
Based on prices as of September 30, 2011, it is estimated that $137.7 million will be settled and reclassified from AOCI to the Consolidated Statements of Income during the next twelve months.
 
 
The following table discloses the fair value of derivative contracts on a gross contract basis as opposed to the net contract basis presentation in the Condensed Consolidated Balance Sheets.
 
 
 
September 30,
2011
   
December 31,
2010
 
 
 
(in millions)
 
Assets
           
Fixed-price swaps
  $ 258.1     $ 374.6  
Costless collars
    10.7       37.9  
Fair value of derivative instruments - short term
  $ 268.8     $ 412.5  
Fixed-price swaps
  $ 116.4     $ 121.1  
Costless collars
    -       -  
Fair value of derivative instruments - long-term
  $ 116.4     $ 121.1  
Liabilities
               
Fixed-price swaps
  $ 52.2     $ 175.2  
Costless collars
    -       1.6  
Basis-only swaps
    31.0       117.7  
Fair value of derivative instruments - short term
  $ 83.2     $ 294.5  
Fixed-price swaps
  $ -     $ 0.6  
Costless collars
    -       -  
Basis-only swaps
    -       -  
Fair value of derivative instruments - long-term
  $ -     $ 0.6  
 
QEP Energy Production
 
 The following table sets forth QEP Energy’s volumes and average net-to-the-well prices (see definition below table) for its commodity derivative contracts as of September 30, 2011:
 
Year
 
Time period
 
Quantity
 
Average Price per Mcf or Bbl, Net to the Well (1)
 
           
(estimated)
 
    Gas Fixed-price Swaps (Bcf)      
2011
  3 months    33.8   $4.40  
2012
  12 months   112.7   4.63  
2013
  12 months   50.3   5.44  
    Gas Costless Collars (Bcf)      
             Floor - Ceiling  
2011
  3 months   7.3   $4.04 - $5.97  
   
Oil Fixed-price Swaps (Mbbl)
     
2011
  3 months   46.0   $98.00  
2012
  12 months   915.0   96.10  
2013
  12 months   182.5   103.80  
               
   
Oil Costless Collars (Mbbl)
     
            Floor - Ceiling  
2011   3 months   276.0   $51.73 - $ 102.10  
_____________________
(1)
The fixed-price swap and collar prices are adjusted for basis differential, gathering costs and product quality to determine the net-to-the-well price.
 
 
QEP Field Services NGL Volumes
 
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 September 30, 2011:
 
Year
 
Time period
 
Quantity
 
Average Price per Gallon
 
Propane Sales Fixed-price Swaps (millions of gallons)
 
2011
 
3 months
  3.9   $1.45  
2012
 
6 months (1)
  7.6   1.45  
_____________________
(1)
The swaps outstanding as of September 30, 2011, extend through the first six months of 2012.
 
QEP Marketing Transactions
 
QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of September 30, 2011:
 
Year
 
Time period
 
Quantity
 
Average Price per MMBtu
Gas Sales Fixed-price Swaps (millions of MMBtu)
2011
 
3 months
 
2.1
 
$4.67
2012
 
12 months
 
2.7
 
4.55
2013
 
12 months
 
0.9
 
4.77
Gas Purchases Fixed-price Swaps (millions of MMBtu)
2011
 
3 months
 
2.0
 
$3.85
 
Note 10 – 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:
 
   
September 30,
2011
   
December 31,
2010
 
   
(in millions)
 
Revolving Credit Facility
  $ 510.0     $ 400.0  
7.5% Senior Notes due 2011
    -       58.5  
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  
Total principal amount of debt
    1,588.4       1,536.9  
Less unamortized discount
    (5.7 )     (6.1 )
Total long-term debt outstanding
  $ 1,582.7     $ 1,530.8  

Of the total debt outstanding on September 30, 2011, the $510.0 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
 
During the third quarter of 2011, QEP entered into a new revolving credit facility, which matures in August 2016 and replaced the previous $1.0 billion credit facility.  Proceeds from borrowings under the credit facility were used to refinance outstanding amounts under the Company’s previous credit facility and will be used for general corporate purposes, including working capital and capital expenditures. The terms of the new credit facility provide for loan commitments of $1.5 billion from a syndicate of financial institutions. The new credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The 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. In conjunction with the replacement of the previous credit facility, QEP expensed $0.7 million of unamortized financing fees, which are included as a loss on extinguishment of debt on the Consolidated Income Statement. At September 30, 2011, QEP was in compliance with all of its debt covenants.  At September 30, 2011 QEP had $510.0 million drawn and $4.0 million in letters of credit outstanding under the credit facility.
 
 
Senior Notes
 
The Company has $1,078.4 million principal amount of senior notes outstanding with maturities ranging from September 2016 to March 2021 and coupons ranging from 6.05% 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.
 
Note 11 – 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. 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. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve 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.
 
Environmental Claims
 
United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah. 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 have now 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. 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 reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome.
 
QEP Energy v. U.S. Environmental Protection Agency, No. 09-9538, U.S. Court of Appeals for the 10th Circuit.  On July 10, 2009, QEP Energy filed a petition with the U.S. 10th Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009 (Order), issued by EPA which asserts that QEP Energy’s Flat Rock 14P well in the Uinta Basin and associated equipment is a major source of hazardous air pollutants and its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance.  QEP Energy denied that the drilling and operation of the 14P well and associated equipment violated any provisions of the CAA.   QEP and EPA entered into an administrative order on consent, effective June 17, 2011, resolving all disputes associated with prospective CAA compliance at the Flat Rock 14P well.  Among other matters, the order requires installation of pollution control equipment to destroy vapors from the well’s dehydration equipment and ongoing monitoring and reporting associated with operation of that control equipment.
 
Note 12 – Share-Based Compensation
 
QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and performance based share units under its Long-Term Cash Incentive Plan (LTCIP) to certain officers, employees and non-employee directors. QEP recognizes expense over time as the stock options or restricted shares vest. Share-based compensation expense amounted to $5.7 million in the third quarter of 2011 compared to $4.2 million for the third quarter of 2010. Shared based compensation for the nine months ended September 30, 2011 was $16.5 million compared to $11.3 million during the same period of 2010. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 14.1 million shares available for future grants at September 30, 2011.
 
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
Nine Months Ended
September 30, 2011
 
Fair value of options at grant date
  $ 18.80  
Risk-free interest rate
    2.1 %
Expected price volatility
    54.7 %
Expected dividend yield
    0.21 %
Expected life in years
    5.0  

Stock option transactions under the terms of the LTSIP are summarized below:
 
   
Options Outstanding
   
Price Range
   
Weighted-Average Price
 
Balance at January 1, 2011
    1,914,922       $7.78 - $27.84     $ 19.02  
Granted
    202,235       39.07       39.07  
Exercised
    (111,797 )     7.78 - 27.55       15.69  
Forfeited
    (1,666 )     23.98       23.98  
Balance at September 30, 2011
    2,003,694       7.78 - 39.07       21.23  
 
Options Outstanding
   
Options Exercisable
   
Unvested Options
 
Range of
Exercise Prices
   
Number
Outstanding at September 30,
2011
   
Weighted-
Average
Remaining Term
in Years
   
Weighted-
Average
Exercise
 Price
   
Number
Exercisable at
September 30,
2011
   
Weighted-
Average
Exercise
 Price
   
Number
Unvested at
September 30,
2011
   
Weighted-
Average
 Exercise
Price
 
$7.78 - $11.89       582,050       0.9     $ 8.57       582,050     $ 8.57       -     $ -  
19.37 - 27.84       1,219,409       4.0       24.31       751,729       24.45       467,680       24.09  
39.07       202,235       6.4       39.07       -       -       202,235       39.07  
        2,003,694       3.3       21.23       1,333,779       17.52       669,915       28.61  

Restricted Shares
 
Restricted share grants typically vest in equal installments over a three or four-year period from the grant date. Several grants vest in a single installment after a specified period. The weighted-average vesting period of unvested restricted shares at September 30, 2011, was 15 months. Transactions involving restricted shares under the terms of the LTSIP are summarized below:
 
   
Restricted Shares Outstanding
   
Price Range
   
Weighted-Average Price
 
Balance at January 1, 2011
    966,961       $17.03 - $47.28     $ 29.05  
Granted
    426,953       32.29 - 44.12       39.18  
Distributed
    (300,478 )     17.03 - 47.28       29.37  
Forfeited
    (14,150 )     17.03 - 40.03       35.44  
Balance at September 30, 2011
    1,079,286       19.86 - 44.12       32.48  

 
Performance Share Units
 
During the nine months ended September 30, 2011, the Company granted its first performance based share units. Vesting is dependent upon the Company’s total shareholder return compared to a group of its peers. The awards are denominated in share units but delivered in cash at the end of the performance period. The weighted-average vesting period of unvested performance shares at September 30, 2011, was 29 months. Transactions involving performance shares units under the terms of the LTCIP are summarized below:
 
   
Performance Shares Outstanding
   
Price Range
   
Weighted-Average Price
 
Balance at January 1, 2011
    -     $ -     $ -  
Granted
    116,074       39.07       39.07  
Distributed
    -       -       -  
Forfeited
    (800 )     39.07       39.07  
Balance at September 30, 2011
    115,274       39.07       39.07  

Note 13 – Employee Benefits
 
In association with the Spin-off, the Company established defined-benefit pension and postretirement medical plans providing coverage to approximately one-quarter of its employees. QEP only retained liability for active employees and all retired employees remained participants in Questar’s retirement plans. At the Spin-off, Questar transferred certain assets and liabilities from its defined-benefit pension and postretirement medical plans related to QEP employees into QEP’s newly established plans. The transfer resulted in the establishment of liabilities of $54.9 million related to the unfunded portions of the defined-benefit pension plans and other postretirement benefits with corresponding amounts in AOCI. These changes have been reflected in other long-term liabilities, deferred income taxes and AOCI.
 
During the nine months ended September 30, 2011, the Company made contributions of $13.5 million to its retirement plans which increased plan assets. During the remainder of 2011, the Company expects to contribute $1.3 million to its retirement plan. The components of pension and post retirement benefits expense are as follows. The pension expense includes costs of both qualified and nonqualified pension plans:
 
   
Three Months Ended
September 30, 2011
   
Nine Months Ended
September 30, 2011
 
   
Pension
   
Postretirement benefits
   
Pension
   
Postretirement benefits
 
   
(in millions)
 
Service cost
  $ 0.7     $ 0.1     $ 2.1     $ 0.1  
Interest cost
    1.2       -       3.4       0.2  
Expected return on plan assets
    (0.7 )     -       (1.9 )     -  
Amortization of prior service costs
    1.4       0.1       4.0       0.3  
Recognized net actuarial loss
    -       -       -       -  
Periodic expense
  $ 2.6     $ 0.2     $ 7.6     $ 0.6  
 
 
Note 14 – Operations by Line of Business
 
QEP’s lines of business include 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. Following is a summary of operating results by line of business:
 
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in millions)
 
Revenues from unaffiliated customers
                       
QEP Energy
  $ 590.6     $ 343.5     $ 1,456.5     $ 979.0  
QEP Field Services
    116.3       75.3       331.6       234.1  
QEP Marketing and other
    145.5       145.8       444.6       461.3  
Total
  $ 852.4     $ 564.6     $ 2,232.7     $ 1,674.4  
Revenues from affiliated companies
                               
QEP Field Services
  $ 0.8     $ 0.5     $ 2.2     $ 1.7  
QEP Marketing and other
    148.7       121.0       426.9       376.7  
Total
  $ 149.5     $ 121.5     $ 429.1     $ 378.4  
Operating income
                               
QEP Energy
  $ 113.9     $ 112.2     $ 297.1     $ 317.0  
QEP Field Services
    68.4       35.3       188.0       111.9  
QEP Marketing and other
    1.1       2.0       4.3       5.1  
Separation costs
    -       (0.2 )     -       (14.2 )
Total
  $ 183.4     $ 149.3     $ 489.4     $ 419.8  
Net income from continuing operations attributable to QEP
                               
QEP Energy
  $ 58.3     $ 58.6     $ 148.2     $ 165.0  
QEP Field Services
    42.0       21.0       114.2       68.5  
QEP Marketing and other
    1.6       2.0       5.5       3.6  
Separation and debt extinguishment costs
    (0.4 )     (10.5 )     (0.4 )     (19.1 )
Total
  $ 101.5     $ 71.1     $ 267.5     $ 218.0  


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 Item 1 of this Quarterly Report on Form 10-Q.
 
The following information updates the discussion of QEP’s financial condition provided in its 2010 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2011 and September 30, 2010. 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 2010 Annual Report on Form 10-K.
 
OVERVIEW
 
QEP is an independent natural gas and oil exploration and production company. QEP 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 (formerly referred to as the Midcontinent Region) of the U.S, which includes the Haynesville/Cotton Valley area in northwest Louisiana and the Midcontinent area with properties primarily located in Oklahoma, Arkansas and Texas) and the Northern Region (formerly referred to as the Rocky Mountain Region) of the U.S., which includes the Pinedale Anticline in western Wyoming; the Uinta Basin in eastern Utah; and the Rockies Legacy area, which includes all of the Northern Region properties except the Pinedale Anticline and the Uinta Basin;
 
 
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 in the Rocky Mountains and in northwest Louisiana; and
 
 
QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil in the Rocky Mountains, Pacific Northwest and Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines; provides risk-management services; and owns and operates an underground gas storage reservoir in western Wyoming.
 
Reincorporation Merger and Spin-off
 
Effective May 18, 2010, Market Resources, then a wholly owned subsidiary of Questar, merged with and into QEP, a Delaware corporation and a newly formed, wholly owned subsidiary of Questar, in order to reincorporate in the State of Delaware. The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. On June 30, 2010, Questar distributed to existing Questar stockholders all of the shares of common stock of QEP in a tax-free, pro rata spin-off, establishing QEP as an independent, publicly traded company. In connection with the Spin-off, QEP distributed Wexpro, a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.
 
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:
 
 
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 best plays
 
 
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
 
 
Operate in a safe and environmentally responsible manner
 
 
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 economic hydrocarbon resource plays including the Bakken/Three Forks, Pinedale, Haynesville and Woodford “Cana” 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 and 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 also has one of the lowest cash cost structures among its exploration and production company peers. However, in certain of its resource plays the Company 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 65% in the third quarter of 2011 compared with the third quarter of 2010 and oil and NGL revenue accounted for approximately 32% of net production revenues (including realized losses on basis-only swaps) in the third quarter of 2011 compared to 19% in the third quarter of 2010. QEP Energy oil and NGL production increased by approximately 44% in the nine months ended September 30, 2011, compared with the same period in 2010 and oil and NGL revenue accounted for approximately 29% of net production revenues (including realized losses on basis-only swaps) in the first nine months of 2011 compared to 19% in the first nine months of 2010. The increases in NGL sales volumes were a result of the start-up of the Blacks Fork II plant in July 2011 and the liquids recovered for QEP Energy under the fee-based processing agreement entered into with QEP Field Services along with development of liquids-rich plays in the Midcontinent. The Company has allocated approximately 65% of its forecasted 2011 drilling and completion capital expenditure budget to oil and liquids-rich natural gas plays.
 
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 the Southern and Northern Regions, 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 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 in addition to QEP Energy. Net income from QEP’s midstream business accounted for approximately 41% of the Company’s total income from continuing operations during the third quarter of 2011 compared with 30% for the third quarter of 2010. Net income from QEP’s midstream business accounted for approximately 43% of the Company’s total income from continuing operations during the nine months ended September 30, 2011, compared with 31% for the same period in 2010.
 
Highlights of Three and Nine Months Ended September 30, 2011
 
During the third quarter and the nine months ended September 30, 2011, QEP had strong performance from QEP Energy, its exploration and production business, and QEP Field Services, its gathering and processing business.  Though crude oil and NGL prices decreased in the third quarter of 2011 from the second quarter of 2011, QEP Energy benefitted from higher production and higher crude oil and NGL prices during the three and nine months ended September 30, 2011 from the 2010 comparative periods.  Field Services benefited from the Iron Horse plant having two full quarters of operations, the commencement of the Blacks Fork II processing plant, and continued robust gas processing margins.
 
In the third quarter of 2011, QEP Energy reported production of 70.7 Bcfe compared to 61.7 Bcfe in the 2010 third quarter. During the nine months ended September 30, 2011, QEP Energy production of 201.3 Bcfe was 21% above the comparable period reported production of 166.9 Bcfe. During the three and nine months ended September 30, 2011, the Southern Region (formerly the Midcontinent Region) contributed 55% and 57%, respectively, and the Northern Region (formerly the Rocky Mountain Region) contributed 45% and 43%, respectively, of total equivalent production.
 
 
QEP Energy continues to focus on the controllable cash cost of production per Mcfe. The Company defines cash cost of production as the sum of lease operating expense, general and administrative expense, allocated interest and production taxes. Cash operating costs were $1.53 per Mcfe in the third quarter of 2011 compared to $1.47 per Mcfe in the third quarter of 2010. The increase was due to higher production taxes per Mcfe related to higher field-level crude oil and NGL prices and higher general and administrative expenses primarily related to employee benefit plan related expenses, increased legal and outside professional services and higher insurance costs, which were partially offset by lower allocated interest expense per Mcfe. During the first nine months of 2011, cash operating costs decreased to $1.55 per Mcfe from $1.58 per Mcfe in the first nine months of 2010.  This decrease was a result of increased production volumes partially offset by higher overall production costs.
 
QEP Field Services reported gathering system throughput of 1.4 million MMBtu per day for the three months ended September 30, 2011 and 2010, respectively. During the nine months ended September 30, 2011 and 2010, QEP Field Services gathering system throughput was 1.3 million MMBtu per day.  During the three and nine months ended September 30, 2011, QEP Field Services reported a 32% and 27% increase in NGL sales volumes to a total of 34.0 million and 98.2 million gallons, respectively. The increase in NGL sales volumes along with a 71% increase in the per unit NGL margin (NGL revenue less fuel and shrinkage) resulted in a 126% increase to the keep-whole processing margin during the third quarter of 2011. For the first nine months of 2011, the increased NGL sales volumes along with a 43% increase in the per unit NGL margin resulted in an 82% increase to the keep-whole processing margin.
 
In January 2011, QEP Field Services put into service its 150 MMcf per day cryogenic Iron Horse processing plant, an expansion of its Stagecoach processing complex in the Uinta Basin of eastern Utah. This plant predominantly provides fee-based processing services to third-parties. In July 2011, QEP Field Services commissioned its 420 MMcf per day Blacks Fork II cryogenic processing plant, an expansion of its Blacks Fork processing complex located in the Green River Basin of southwestern Wyoming, ahead of schedule. The Blacks Fork complex is about 100 miles south of QEP’s operations at Pinedale. QEP expects that the Blacks Fork II plant, when fully operational, will have the capacity to extract an incremental 15,000 Bbls per day of NGL net to QEP.
 
During the third quarter of 2011, QEP entered into a new revolving credit facility, which matures in August 2016 and replaced the previous $1.0 billion credit facility.  The terms of the new credit facility provide for loan commitments of $1.5 billion from a syndicate of financial institutions. The new credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The agreement also contains provisions which would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods.
 
Factors Affecting Results of Operations
 
Oil and Natural Gas Prices
 
Historically, 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, the domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling and 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 caused the price of crude oil to decrease in the current quarter though they remain higher than comparable 2010 prices. Changes in the market prices for crude oil and natural gas directly impact many aspects of QEP’s business, including its financial condition, revenues, results of operations, 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. For example, despite a 9% increase in natural gas production in the third quarter of 2011 compared to the third quarter of 2010, natural gas revenues decreased 6% due to significantly lower net realized natural gas prices. When compared to the first three quarters of 2010, natural gas production in the first three quarters of 2011 increased 18%, while natural gas revenues decreased 2% due to lower net realized natural gas prices.
 
QEP uses commodity derivatives to reduce the variability of the prices QEP receives for a portion of its production and to provide a minimum revenue stream. 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 September 30, 2011, QEP Energy had approximately 60% of its remaining forecasted 2011 natural gas, oil and NGL production covered with fixed-price swaps or costless collars assuming 2011 annual production of 272.0 Bcfe. QEP hedged a greater portion of its second half 2011 natural gas production in light of concerns during the first half of 2011 of oversupply in the natural gas market. See “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, the Company has allocated approximately 65% of its forecasted 2011 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 mark-to-market valuations 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. 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 prior periods and may continue to incur these types of gains and losses in the future.
 
 
Blacks Fork II Processing Plant
 
QEP believes the new Blacks Fork II processing plant will result in increased NGL production from QEP Field Services and QEP Energy, however, QEP expects that the first few months of operation of the Blacks Fork II plant will not be indicative of normal liquids production volumes or of revenue generation. As part of the agreement, QEP Field Services recorded line pack for the NGL line-fill requirements which is recorded as inventory on the QEP Field Services balance sheet at September 30, 2011.
 
In conjunction with the start up of the Blacks Fork II, QEP Energy entered into a fee-based processing agreement with QEP Field Services to process QEP Energy’s share of Pinedale gas. As a result, about 46% of the NGL recovered at the Blacks Fork II plant will be accounted for as NGL production in QEP Energy, with the about 40% included in the keep-whole volumes in QEP Field Services.
 
Critical Accounting Estimates
 
QEP’s significant accounting policies are described in Item 7 of Part II of its 2010 Annual Report on Form 10-K. The Company’s condensed consolidated financial statements are prepared in accordance with U.S. 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
 
Adjusted EBITDA
 
Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company’s cash flow and liquidity and an important measure for comparing the Company’s financial performance to other gas and oil producing companies. Management defines Adjusted EBITDA as net income before the following items: depreciation, depletion and amortization, abandonment and impairment, interest and other income, interest expense, separation costs, loss on early extinguishment of debt, income taxes, unrealized gain and losses on basis-only swaps, discontinued operations, gains and losses from assets sales, and exploration expense.

Following are comparisons of Adjusted EBITDA by line of business:
 
   
Three Months Ended
 September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
Change
   
2011
   
2010
   
Change
 
   
(in millions)
 
QEP Energy
  $ 267.3     $ 246.0     $ 21.3     $ 757.0     $ 683.8     $ 73.2  
QEP Field Services
    84.8       48.7       36.1       233.1       151.4       81.7  
QEP Marketing and other
    1.6       2.8       (1.2 )     6.0       6.8       (0.8 )
Total Adjusted EBITDA
  $ 353.7     $ 297.5     $ 56.2     $ 996.1     $ 842.0     $ 154.1  
 
Adjusted EBITDA increased 19% to $353.7 million for the third quarter of 2011 compared to $297.5 million in the 2010 period, despite a 14% decrease in net realized natural gas prices. The impact of lower net realized natural gas prices during the third quarter of 2011 was offset by a 15% increase in total production, 31% higher net realized crude oil prices and 27% higher net realized NGL prices in QEP Energy, along with increased gathering (26% higher) and processing margins (127% higher) in QEP Field Services.  Adjusted EBITDA increased 18% to $996.1 million for the first three quarters of 2011 compared to $842.0 million in the 2010 period, despite a 16% decrease in net realized natural gas prices. The lower natural gas prices in the first three quarters of 2011 were offset by a 21% increase in total production, 31% higher net realized crude oil prices and 16% higher net realized NGL prices in QEP Energy, along with a 29% and 80% increase in gathering and processing margins, respectively.


A reconciliation of Adjusted EBITDA to net income follows:
 
   
Three Months Ended
 September 30,
   
Nine Months Ended
 September 30,
 
   
2011
   
2010
   
Change
   
2011
   
2010
   
Change
 
   
(in millions)
 
Net income attributable to QEP Resources
  $ 101.5     $ 71.1     $ 30.4     $ 267.5     $ 261.2     $ 6.3  
Net income attributable to non-controlling interest
    0.9       0.8       0.1       2.2       2.1       0.1  
Net income
    102.4       71.9       30.5       269.7       263.3       6.4  
Discontinued operations, net of tax
    -       -       -       -       (43.2 )     43.2  
Income from continuing operations
    102.4       71.9       30.5       269.7       220.1       49.6  
Unrealized gain on basis-only swaps
    (27.9 )     (27.9 )     -       (86.7 )     (90.0 )     3.3  
Net gain from asset sales
    (1.2 )     (10.8 )     9.6       (1.4 )     (12.3 )     10.9  
Interest and other loss (income)
    0.7       (1.6 )     2.3       0.5       (4.4 )     4.9  
Income taxes
    59.1       44.2       14.9       156.0       130.5       25.5  
Interest expense
    22.8       22.6       0.2