Form 10-Q
Table of Contents

 

 

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 June 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 June 30, 2011, there were 176,905,034 shares of the registrant’s common stock, $0.01 par value, outstanding.

 

 

 


Table of Contents

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2011

TABLE OF CONTENTS

 

              Page  

PART I. FINANCIAL INFORMATION

     1   
  ITEM 1.    FINANCIAL STATEMENTS      1   
  ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      15   
  ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      33   
  ITEM 4.    CONTROLS AND PROCEDURES      35   

PART II. OTHER INFORMATION

     36   
  ITEM 1.    LEGAL PROCEEDINGS      36   
  ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS      36   
  ITEM 3.    EXHIBITS      36   

SIGNATURES

     37   

 

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Table of Contents

PART I. FINANCIAL INFORMATION

 

ITEM  1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011     2010     2011     2010  
     (in millions, except per share amounts)  

REVENUES

        

Natural gas sales

   $ 258.1      $ 260.6      $ 529.1      $ 525.2   

Oil sales

     80.0        44.7        142.3        89.6   

NGL sales

     16.5        9.0        33.7        18.1   

Gathering, processing and other

     123.5        80.4        221.4        162.3   

Marketing sales

     306.0        134.9        453.8        314.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues

     784.1        529.6        1,380.3        1,109.8   
  

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES

      

Lease operating expense

     34.3        28.6        67.1        56.9   

Gathering, processing and other

     27.2        19.6        52.4        43.1   

General and administrative

     28.7        25.7        60.4        50.9   

Separation costs

     —          14.0        —          14.0   

Production and property taxes

     27.1        19.0        50.8        41.9   

Depreciation, depletion and amortization

     186.6        151.6        377.4        299.0   

Exploration expenses

     2.3        2.7        5.1        6.3   

Abandonment and impairment

     5.3        9.3        10.7        16.9   

Marketing purchases

     303.9        133.9        450.6        311.8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     615.4        404.4        1,074.5        840.8   

Net gain from asset sales

     0.2        2.4        0.2        1.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING INCOME

     168.9        127.6        306.0        270.5   

Interest and other (loss) income

     (0.4     2.0        0.2        2.8   

Income from unconsolidated affiliates

     1.3        0.6        2.2        1.4   

Interest expense

     (22.1     (20.3     (44.2     (40.2
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     147.7        109.9        264.2        234.5   

Income taxes

     (54.2     (40.4     (96.9     (86.3
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME FROM CONTINUING OPERATIONS

     93.5        69.5        167.3        148.2   

Discontinued operations, net of income tax

     —          22.0        —          43.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME

     93.5        91.5        167.3        191.4   

Net income attributable to noncontrolling interest

     (0.7     (0.7     (1.3     (1.3
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO QEP

   $ 92.8      $ 90.8      $ 166.0      $ 190.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings Per Common Share Attributable to QEP

      

Basic from continuing operations

   $ 0.52      $ 0.39      $ 0.94      $ 0.84   

Basic from discontinued operations

     —          0.13        —          0.25   
  

 

 

   

 

 

   

 

 

   

 

 

 

Basic total

   $ 0.52      $ 0.52      $ 0.94      $ 1.09   
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted from continuing operations

   $ 0.52      $ 0.39      $ 0.93      $ 0.83   

Diluted from discontinued operations

     —          0.12        —          0.24   
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted total

   $ 0.52      $ 0.51      $ 0.93      $ 1.07   
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted-average common shares outstanding

      

Used in basic calculation

     176.6        175.1        176.4        175.0   

Used in diluted calculation

     178.6        177.6        178.5        177.4   

Dividends per common share

   $ 0.02      $ —        $ 0.04      $ —     

See notes accompanying the condensed consolidated financial statements

 

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Table of Contents

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     June 30,
2011
    December 31,
2010
 
     (in millions)  

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ —        $ —     

Accounts receivable, net

     340.7        269.9   

Fair value of derivative contracts

     183.8        257.3   

Inventories, at lower of average cost or market

    

Gas and oil storage

     11.7        16.4   

Materials and supplies

     85.8        65.4   

Prepaid expenses and other

     33.6        45.2   
  

 

 

   

 

 

 

Total Current Assets

     655.6        654.2   
  

 

 

   

 

 

 

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

    

Proved properties

     7,503.8        6,874.3   

Unproved properties, not being depleted

     323.1        322.0   

Midstream field services

     1,393.1        1,360.5   

Marketing and other

     45.6        44.5   
  

 

 

   

 

 

 

Total Property, Plant and Equipment

     9,265.6        8,601.3   
  

 

 

   

 

 

 

Less Accumulated Depreciation, Depletion and Amortization

    

Exploration and production

     2,800.2        2,454.4   

Midstream field services

     270.2        244.6   

Marketing and other

     13.3        12.3   
  

 

 

   

 

 

 

Total Accumulated Depreciation, Depletion and Amortization

     3,083.7        2,711.3   
  

 

 

   

 

 

 

Net Property, Plant and Equipment

     6,181.9        5,890.0   
  

 

 

   

 

 

 

Investment in unconsolidated affiliates

     44.0        44.5   

Goodwill

     59.6        59.6   

Fair value of derivative contracts

     109.3        120.8   

Other noncurrent assets

     24.6        16.2   
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 7,075.0      $ 6,785.3   
  

 

 

   

 

 

 

LIABILITIES AND EQUITY

    

Current Liabilities

    

Checks outstanding in excess of cash balances

   $ 18.0      $ 19.5   

Accounts payable and accrued expenses

     430.6        332.2   

Production and property taxes

     31.4        18.9   

Interest payable

     24.9        28.1   

Fair value of derivative contracts

     75.8        139.3   

Deferred income taxes

     2.2        27.8   

Current portion of long-term debt

     —          58.5   
  

 

 

   

 

 

 

Total Current Liabilities

     582.9        624.3   
  

 

 

   

 

 

 

Long-term debt, less current portion

     1,572.6        1,472.3   

Deferred income taxes

     1,470.3        1,377.7   

Asset retirement obligations

     155.7        148.3   

Fair value of derivative contracts

     —          0.3   

Other long-term liabilities

     109.1        99.3   

Commitments and contingencies

    

EQUITY

    

Common stock

     1.8        1.8   

Treasury stock

     (10.8     (3.8

Additional paid-in capital

     416.7        398.0   

Retained earnings

     2,579.4        2,420.0   

Accumulated other comprehensive income

     145.7        194.3   
  

 

 

   

 

 

 

Total Common Shareholders’ Equity

     3,132.8        3,010.3   

Noncontrolling interests

     51.6        52.8   
  

 

 

   

 

 

 

Total Equity

     3,184.4        3,063.1   
  

 

 

   

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 7,075.0      $ 6,785.3   
  

 

 

   

 

 

 

See notes accompanying the condensed consolidated financial statements

 

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QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended
June 30,
 
     2011     2010  
     (in millions)  

OPERATING ACTIVITIES

    

Net income

   $ 167.3      $ 191.4   

Discontinued operations, net of income tax

     —          (43.2

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

    

Depreciation, depletion and amortization

     377.4        299.0   

Deferred income taxes

     95.7        117.2   

Abandonment and impairment

     10.7        16.9   

Share-based compensation

     10.8        7.1   

Amortization of debt issuance costs and discounts

     1.5        0.6   

Dry exploratory well expense

     0.5        —     

Net gain from asset sales

     (0.2     (1.4

Income from unconsolidated affiliates

     (2.2     (1.4

Distributions from unconsolidated affiliates and other

     2.6        1.2   

Unrealized gain on basis-only swaps

     (58.8     (62.1

Changes in operating assets and liabilities

     23.3        (57.2
  

 

 

   

 

 

 

Net Cash Provided by Operating Activities of Continuing Operations

     628.6        468.1   
  

 

 

   

 

 

 

INVESTING ACTIVITIES

    

Property acquisitions

     (29.8     (63.8

Property, plant and equipment, including dry exploratory well expense

     (632.0     (592.3

Proceeds from disposition of assets

     1.6        4.7   

Change in notes receivable

     —          52.9   
  

 

 

   

 

 

 

Net Cash Used in Investing Activities of Continuing Operations

     (660.2     (598.5
  

 

 

   

 

 

 

FINANCING ACTIVITIES

    

Checks outstanding in excess of cash balances

     (1.5     14.6   

Long-term debt issued

     200.0        —     

Long-term debt issuance costs paid

     —          (9.8

Current portion long-term debt repaid

     (58.5     —     

Repayments of notes payable

     —          (39.3

Long-term debt repaid

     (100.0     (102.0

Other capital contributions

     1.0        —     

Equity contribution

     —          250.0   

Dividends paid

     (7.1     —     

Distribution from Questar

     0.2        —     

Distribution to noncontrolling interest

     (2.5     (2.4
  

 

 

   

 

 

 

Net Cash Provided from Financing Activities of Continuing Operations

     31.6        111.1   
  

 

 

   

 

 

 

CASH USED IN CONTINUING OPERATIONS

     —          (19.3
  

 

 

   

 

 

 

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

     —          (19.3

Beginning cash and cash equivalents

     —          19.3   
  

 

 

   

 

 

 

Ending cash and cash equivalents

   $ —        $ —     
  

 

 

   

 

 

 

See notes accompanying the condensed consolidated financial statements

 

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Table of Contents

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. 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 six months ended June 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 June of 2011 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 the ASU will have on its financial statements and disclosures.

 

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Table of Contents

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
June 30,
    Six Months Ended
June 30,
 
     2011      2010     2011      2010  
     (in millions, except per share amounts)  

Revenues

   $ —         $ 64.5      $ —         $ 131.2   

Income before income taxes

     —           34.3        —           67.4   

Income taxes

     —           (12.3     —           (24.2
                                  

Discontinued operations, net of income taxes

   $ —         $ 22.0      $ —         $ 43.2   
                                  

Earnings per common share attributable to QEP

          

Basic from discontinued operations

   $ —         $ 0.13      $ —         $ 0.25   

Diluted from discontinued operations

     —           0.12        —           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
June 30,
    Six Months Ended
June 30,
 
     2011     2010     2011     2010  
     (in millions)  

Net income

   $ 93.5      $ 91.5      $ 167.3      $ 191.4   

Other comprehensive income (loss)

        

Net unrealized income (loss) on derivatives

     (4.0     (65.0     (80.1     234.2   

Minimum pension liability adjustment

     2.8        (38.7     2.8        (38.7

Other

     —          (0.1     —          —     

Income taxes

     0.4        38.6        28.7        (72.7
                                

Net other comprehensive income (loss)

     (0.8     (65.2     (48.6     122.8   
                                

Comprehensive income

     92.7        26.3        118.7        314.2   

Comprehensive income attributable to noncontrolling interest

     (0.7     (0.7     (1.3     (1.3
                                

Comprehensive income attributable to QEP

   $ 92.0      $ 25.6      $ 117.4      $ 312.9   
                                

The components of AOCI, net of income taxes, shown on the Condensed Consolidated Balance Sheets are as follows:

 

     June 30,
2011
    December 31,
2010
    Change  
     (in millions)  

Net unrealized gain on derivatives

   $ 173.5      $ 223.8      $ (50.3

Pension and postretirement liabilities

     (27.8     (29.5     1.7   
                        

Accumulated other comprehensive income

   $ 145.7      $ 194.3      $ (48.6
                        

 

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Table of Contents

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
June 30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  
     (in millions)  

Weighted-average basic common shares outstanding

     176.6         175.1         176.4         175.0   

Potential number of shares issuable under the Long-term Stock Incentive Plan

     2.0         2.5         2.1         2.4   
                                   

Average diluted common shares outstanding

     178.6         177.6         178.5         177.4   
                                   

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

     4.8        4.2   

Liabilities incurred

     2.9        12.6   

Revisions

     —          0.5   

Liabilities settled

     (0.3     (0.7
                

ARO liability at June 30,

   $ 155.7      $ 141.3   
                

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.

 

     2011     2010  
     (in millions)  

Balance at January 1,

   $ 13.6      $ 51.7   

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

     —          1.0   

Reclassifications to property, plant and equipment after the determination of proved reserves

     (7.4     (47.9
                

Balance at June 30,

   $ 6.2      $ 4.8   
                

 

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Table of Contents

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. Level 3 inputs are unobservable inputs for the asset or liability. 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 June 30, 2011, or at December 31, 2010. The fair value of assets and liabilities at June 30, 2011, is shown in the table below:

 

     Fair Value Measurements
June 30, 2011
 
     Level 2      Level 3      Netting
Adjustments
    Total  
     (in millions)  

Assets

          

Derivative contracts - short term

   $ 245.7       $ 18.3       $ (80.2   $ 183.8   

Derivative contracts - long term

     109.3         —           —          109.3   
                                  

Total assets

   $ 355.0       $ 18.3       $ (80.2   $ 293.1   
                                  

Liabilities

          

Derivative contracts - short term

   $ 155.3       $ 0.7       $ (80.2   $ 75.8   

Derivative contracts - long term

     —           —           —          —     
                                  

Total liabilities

   $ 155.3       $ 0.7       $ (80.2   $ 75.8   
                                  

The change in the fair value of Level 3 assets and liabilities for the first half of 2011 is shown below:

 

     Derivative
Contracts
2011
 
     (in millions)  

Balance at January 1,

   $ 36.3   

Realized gains and losses included in revenues

     16.2   

Unrealized gains and losses included in other comprehensive income

     (18.7

Settlements

     (16.2
        

Balance at June 30,

   $ 17.6   
        

 

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Table of Contents

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
 
   June 30, 2011      December 31, 2010  
     (in millions)  

Financial assets

           

Cash and cash equivalents

   $ —         $ —         $ —         $ —     

Financial liabilities

           

Checks outstanding in excess of cash balances

     18.0         18.0         19.5         19.5   

Long-term debt

     1,572.6         1,655.9         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 match derivative contracts with up to 100% of forecast 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 price collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Price 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 or crude oil 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. QEP Energy also uses 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 price collars and re-designated as cash flow hedges. 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.

 

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Table of Contents

QEP 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 and oil 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 and oil 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. Price collars qualify for cash flow hedge accounting. Basis-only swaps do not qualify for hedge accounting treatment. 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
June 30,
    Six Months Ended
June 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

   $ 61.3      $ 31.3      $ 61.5      $ 375.9   

Gains (losses) reclassified from AOCI into income for the effective portion of hedges

        

Natural gas sales

     64.4        97.5        137.5        143.1   

Oil and NGL sales

     0.1        (1.8     0.1        (3.8

Marketing sales

     —          —          —          —     

Marketing purchases

     0.5        0.6        3.9        2.4   

Loss recognized in income for the ineffective portion of hedges

        

Interest and other income

     0.3        0.3        0.1        (0.1

Effect of derivative instruments not designated as hedges

        

Unrealized gain on basis-only swaps

     27.6        27.4        58.8        62.1   

Realized loss on basis-only swaps

     (27.6     (27.4     (58.8     (62.1

Based on prices as of June 30, 2011, it is estimated that $104.9 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.

 

     June 30,
2011
     December 31,
2010
 
     (in millions)  

Assets

     

Fixed-price swaps

   $ 245.7       $ 374.6   

Price collars

     18.3         37.9   
                 

Fair value of derivative instruments - short term

   $ 264.0       $ 412.5   
                 

Fixed-price swaps

   $ 109.3       $ 121.1   

Price collars

     —           —     
                 

Fair value of derivative instruments - long term

   $ 109.3       $ 121.1   
                 

Liabilities

     

Fixed-price swaps

   $ 96.4       $ 175.2   

Price collars

     0.7         1.6   

Basis-only swaps

     58.9         117.7   
                 

Fair value of derivative instruments - short term

   $ 156.0       $ 294.5   
                 

Fixed-price swaps

   $ —         $ 0.6   

Price collars

     —           —     

Basis-only swaps

     —           —     
                 

Fair value of derivative instruments - long term

   $ —         $ 0.6   
                 

 

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Table of Contents

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 June 30, 2011:

 

Year

 

Time Period

 

Quantity

 

Average Price

per Mcf or Bbl,

Net to the Well(1)

            (estimated)
Gas Fixed-price Swaps (Bcf)

2011

  6 months   66.7   $4.50

2012

  12 months   112.7   4.71

2013

  12 months   50.3   5.54
Gas Price Collars (Bcf)
      Floor-Ceiling

2011

  6 months   14.5   $4.14-$6.10
Oil Fixed-price Swaps (Mbbl)

2011

  6 months   92.0   $98.00

2012

  12 months   915.0   $96.10

2013

  12 months   182.5   $103.80
Oil Price Collars (Mbbl)
      Floor-Ceiling

2011

  6 months   552.0   $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 Production

QEP Field Services enters into commodity derivative transactions to lock in a margin on extracted propane sales volumes. The following table sets forth QEP Field Service’s volumes and swap prices for its commodity derivative contracts as of June 30, 2011:

 

Year

 

Time Period

 

Quantity

 

Average Price

per gallon

Propane Sales Fixed-price Swaps (thousands of gallons)

2011

  6 months   7,728.0   $1.45

2012

  6 months(1)   7,644.0   1.45

 

(1) 

The swaps outstanding as of June 30, 2011 extend through the first half 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 June 30, 2011:

 

Year

 

Time Period

 

Quantity

 

Average Price

per MMBtu

Gas Sales Fixed-price Swaps (millions of MMBtu)

2011

  6 months   3.2   $4.51

2012

  12 months   0.8   4.77

Gas Purchases Fixed-price Swaps (millions of MMBtu)

2011

  6 months   1.3   $4.17

2012

  12 months   —     —  

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:

 

     June 30,
2011
     December 31,
2010
 
     (in millions)  

Revolving Credit Facility

   $ 500.0       $ 400.0   

7.50% 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   

 

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Table of Contents
     June 30,
2011
    December 31,
2010
 
     (in millions)  

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

     1,578.4        1,536.9   
  

 

 

   

 

 

 

Less unamortized discount

     (5.8     (6.1
  

 

 

   

 

 

 

Total long-term debt outstanding

   $ 1,572.6      $ 1,530.8   
  

 

 

   

 

 

 

Of the total debt outstanding on June 30, 2011, only the $500 million drawn under the revolving credit facility (described below) will mature within the next five years.

Credit Arrangements

QEP has a revolving credit facility which provides for loan commitments of $1.0 billion from a syndicate of financial institutions. The facility matures March 2013. The credit facility has restrictive covenants that limit the amount of funded indebtedness that QEP may incur. At June 30, 2011, QEP was in compliance with all of its debt covenants.

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 and 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. 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 testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed 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 Utah’s CAA program or 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. The Ute Indian Tribe and individual members of its Business Committee have now intervened as co-plaintiffs asserting the same CAA claims as the federal government.

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 $3.4 million in the second quarter of 2011 compared to $3.5 million for the second quarter of 2010. Shared based compensation for the first half of 2011 was $10.8 million compared to $7.1 million in the first half of 2010. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 14.2 million shares available for future grants at June 30, 2011.

 

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Table of Contents

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
Six Months Ended
June 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

     (103,970   7.78 - 27.55      15.07   

Forfeited

     —        —        —     
  

 

 

      

Balance at June 30, 2011

     2,013,187      7.78 - 39.07      21.24   
  

 

 

      

 

Options Outstanding

   Options Exercisable      Unvested Options  

Range of

Exercise Prices

   Number
Outstanding
at June 30,
2011
     Weighted-
Average
Remaining
Term in
Years
     Weighted-
Average
Exercise Price
   Number
Exercisable  at
June 30,
2010
     Weighted-
Average
Exercise
Price
     Number
Unvested at
June 30,
2010
     Weighted-
Average
Exercise
Price
 

$7.78 – $11.89

     582,050         1.1       $8.57      582,050       $ 8.57         —         $ —     

19.37 – 27.84

     1,228,902         4.2       24.31      759,556         24.45         469,346         24.09   

39.07

     202,235         6.7       39.07      —           —           202,235         39.07   
  

 

 

          

 

 

       

 

 

    
     2,013,187         3.6       21.24      1,341,606      

 

17.56

  

     671,581         28.60   
  

 

 

          

 

 

       

 

 

    

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 June 30, 2011, was 17 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

     416,103      32.29 – 41.04      39.14   

Distributed

     (249,631   19.86 – 47.28      29.05   

Forfeited

     (9,185   17.03 – 40.03      35.58   
  

 

 

      

Balance at June 30, 2011

     1,124,248      17.03 – 45.31      32.73   
  

 

 

      

 

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Table of Contents

Performance Share Units

During the first half of 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 June 30, 2011, was 32 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 June 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 six months ended June 30, 2011, the Company made contributions of $2.5 million to its retirement plans which increased plan assets. During the remainder of 2011, the Company expects to contribute $12.3 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 June 30, 2011      Six Months Ended June 30, 2011  
     Pension     Post Retirement
Benefits
     Pension     Post-
Retirement
Benefits
 
     (in millions)  

Service cost

   $ 0.7      $ —         $ 1.4      $ —     

Interest cost

     1.1        0.1         2.2        0.2   

Expected return on plan assets

     (0.6     —           (1.2     —     

Amortization of prior service costs

     1.3        0.1         2.6        0.2   

Recognized net actuarial loss

     —          —           —          —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Periodic expense

   $ 2.5      $ 0.2       $ 5.0      $ 0.4   
  

 

 

   

 

 

    

 

 

   

 

 

 

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). 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
June 30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  
     (in millions)  

Revenues from Unaffiliated Customers

           

QEP Energy

   $ 513.2       $ 315.8       $ 865.9       $ 635.5   

QEP Field Services

     120.2         78.5         215.3         158.8   

QEP Marketing and other

     150.7         135.3         299.1         315.5   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 784.1       $ 529.6       $ 1,380.3       $ 1,109.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Revenues from Affiliated Companies

           

QEP Field Services

   $ 0.8       $ 0.6       $ 1.4       $ 1.2   

 

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     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010     2011      2010  
     (in millions)  

QEP Marketing and other

     145.1         112.4        278.2         255.7   
                                  

Total

   $ 145.9       $ 113.0      $ 279.6       $ 256.9   
                                  

Operating Income

          

QEP Energy

   $ 95.3       $ 101.0      $ 183.2       $ 204.8   

QEP Field Services

     72.3         39.5        119.6         76.6   

QEP Marketing and other

     1.3         1.1        3.2         3.1   

Certain separation costs

     —           (14.0     —           (14.0
                                  

Total

   $ 168.9       $ 127.6      $ 306.0       $ 270.5   
                                  

Net Income from Continuing Operations Attributable to QEP

          

QEP Energy

   $ 46.8       $ 52.6      $ 89.9       $ 106.4   

QEP Field Services

     44.2         24.3        72.2         47.5   

QEP Marketing and other

     1.8         0.5        3.9         1.6   

Certain separation costs

     —           (8.6     —           (8.6
                                  

Total

   $ 92.8       $ 68.8      $ 166.0       $ 146.9   
                                  

Note 15 – Subsequent event

In July, construction of QEP Field Services’ Blacks Fork II gas processing plant located in southwestern Wyoming was completed and the company commenced commissioning and start-up operations. The plant is a deep-cut, cryogenic gas processing facility with an inlet capacity of 420 MMcf per day and processes company-owned and third-party natural gas produced primarily from the Pinedale Anticline. In conjunction with the plant start-up, QEP Energy and QEP Field Services executed a long-term, fee-based processing agreement. Approximately half of the volumes processed by the plant are owned by QEP Energy. It is expected that the plant will ultimately recover approximately 15,000 barrels of NGL’s, net to the Company, of which approximately half will be for the account of QEP Energy and the remainder will be for the account of QEP Field Services.

 

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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 six month periods ended June 30, 2011 and June 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 that 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

 

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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 and crude oil 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.

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. Oil and NGL production increased by approximately 32% in the second quarter of 2011 compared with the second quarter of 2010 and oil and NGL revenue accounted for approximately 30% of net production revenues (including realized losses on basis-only swaps) in the second quarter of 2011 compared to 19% in the second quarter of 2010. Oil and NGL production increased by approximately 32% in the first half of 2011 compared with the first half of 2010 and oil and NGL revenue accounted for approximately 27% of net production revenues (including realized losses on basis-only swaps) in the first half of 2011 compared to 19% in the first half of 2010. The Company has allocated almost 40% of its forecasted 2011 capital expenditures to oil and liquids-rich natural gas projects.

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 transportation and processing services to third parties in addition to QEP Energy. Net income from QEP’s midstream business accounted for approximately 48% of the Company’s total income from continuing operations during the second quarter of 2011 compared with 35% for the second 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 first half of 2011 compared with 32% for the first half of 2010.

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.

Highlights of Three and Six Months Ended June 30, 2011

In the second quarter of 2011, QEP reported production of 64.7 Bcfe compared to 53.7 Bcfe in the 2010 second quarter. During the six months ended June 30, 2011, QEP production of 130.6 Bcfe was above the comparable period reported production of 105.2 Bcfe. In the second quarter and first half of 2011, the Southern Region (formerly the Midcontinent Region) contributed 57% and 58% and the Northern Region (formerly the Rocky Mountain Region) contributed 43% and 42% 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 $1.60 per Mcfe in the second quarter of 2011 compared to $1.58 per Mcfe in the second quarter of 2010. The slight increase was due to higher production taxes per Mcfe related to higher field-level crude oil and NGL prices. During the first half of 2011, cash operating costs decreased to $1.56 per Mcfe compared to $1.65 per Mcfe in the first half of 2010. This decrease was a result of increased production volumes partially offset by higher production costs.

QEP Field Services reported gathering system throughput of 1.3 million MMBtu per day for the three and six months ended June 30, 2011, 6% and 5% higher than the three and six months ended June 30, 2010, respectively. The increased volumes were primarily in northwest Louisiana. During the second quarter and first half of 2011 QEP Field Services reported a 36% and 25% increase in NGL sales volumes to a total of 36.4 million and 64.2 million gallons, respectively. The increase in NGL sales volumes along with a 52%

 

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increase in the per unit NGL margin (NGL revenue less fuel and shrinkage) resulted in a 107% increase to the keep-whole processing margin during the second quarter of 2011. For the first half of 2011 the increased NGL sales volumes along with a 31% increase in the per unit NGL margin resulted in a 64% increase to the keep-whole processing margin.

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, natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling and hydraulic fracturing that has 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 unrest in the Middle East and other factors has caused the price of crude oil to increase. 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 19% increase in natural gas production in the second quarter of 2011 compared to the second quarter of 2010, natural gas revenues decreased 1% due to significantly lower net realized natural gas prices. When compared to the first half of 2010, natural gas production in the first half of 2011 increased 23%, while natural gas revenues increased only 1% 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. As of June 30, 2011, QEP had approximately 62% of its remaining forecast 2011 natural gas, oil and NGL production covered with fixed-price swaps or price collars assuming 2011 annual production of 267.0 Bcfe. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Derivative Transactions” for further details concerning its commodity derivatives transactions. In addition, as a result of the continued spread between oil and natural gas prices, the Company has allocated almost 40% of its forecasted 2011 capital expenditure budget to crude oil and liquids-rich natural gas projects in its portfolio and reduced the overall allocation of capital expenditures directed to the development of dry natural gas plays.

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.

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, income taxes, unrealized gain and losses on basis-only swaps, discontinued operations, gains and losses from assets sales, and exploration expense.

 

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Following are comparisons of Adjusted EBITDA by line of business:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      2010      Change      2011      2010      Change  
     (in millions)  

QEP Energy

   $ 247.7       $ 222.4       $ 25.3       $ 489.7       $ 437.8       $ 51.9   

QEP Field Services

     86.9         52.3         34.6         148.3         102.7         45.6   

QEP Marketing and other

     2.0         1.3         0.7         4.4         4.0         0.4   
                                                     

Total Adjusted EBITDA

   $ 336.6       $ 276.0       $ 60.6       $ 642.4       $ 544.5       $ 97.9   
                                                     

Adjusted EBITDA increased 22% to $336.6 million for the second quarter of 2011 compared to $276.0 million in the 2010 period, despite a 17% decrease in net realized natural gas prices. The impact of lower net realized natural gas prices during the second quarter of 2011 was offset by a 20% increase in total production, 39% higher net realized crude oil prices and 30% higher net realized NGL prices in QEP Energy, along with increased gathering (36% higher) and processing margins (92% higher) in QEP Field Services. Adjusted EBITDA increased 18% to $642.4 million for the first half of 2011 compared to $544.5 million in the 2010 period, despite an 18% decrease in net realized natural gas prices. The lower natural gas prices in the first half of 2011 were offset by a 24% increase in total production, 32% higher net realized crude oil prices and 14% higher net realized NGL prices in QEP Energy, along with a 30% and 59% increase in gathering and processing margins, respectively.

A reconciliation of Adjusted EBITDA to net income follows:

 

     Three Months Ended
June  30,
    Six Months Ended
June 30,
 
     2011     2010     Change     2011     2010     Change  
     (in millions)  

Net income attributable to QEP Resources

   $ 92.8      $ 90.8      $ 2.0      $ 166.0      $ 190.1      $ (24.1

Net income attributable to non-controlling interest

     0.7        0.7        —          1.3        1.3        —     
                                                

Net Income

     93.5        91.5        2.0        167.3        191.4        (24.1

Discontinued operations, net of tax

     —          (22.0     22.0        —          (43.2     43.2   
                                                

Income from continuing operations

     93.5        69.5        24.0        167.3        148.2        19.1   

Unrealized gain on basis-only swaps

     (27.6     (27.4     (0.2     (58.8     (62.1     3.3   

Net gain from asset sales

     (0.2     (2.4     2.2        (0.2     (1.5     1.3   

Interest and other loss (income)

     0.4        (2.0     2.4        (0.2     (2.8     2.6   

Income taxes

     54.2        40.4        13.8        96.9        86.3        10.6   

Interest expense

     22.1        20.3        1.8        44.2        40.2        4.0   

Separation costs

     —          14.0        (14.0     —          14.0        (14.0

Depreciation, depletion and amortization

     186.6        151.6        35.0        377.4        299.0        78.4   

Abandonment and impairment

     5.3        9.3        (4.0     10.7        16.9        (6.2

Exploration expenses

     2.3        2.7        (0.4     5.1        6.3        (1.2
                                                

Adjusted EBITDA

   $ 336.6      $ 276.0        60.6      $ 642.4      $ 544.5      $ 97.9   
                                                

Net Income

Following are comparisons of net income from continuing operations attributable to QEP by line of business:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30, 2011
 
     2011      2010     Change     2011      2010     Change  
     (in millions)  

QEP Energy

   $ 46.8       $ 52.6      $ (5.8   $ 89.9       $ 106.4      $ (16.5

QEP Field Services

     44.2         24.3        19.9        72.2         47.5        24.7   

QEP Marketing and other

     1.8         0.5        1.3        3.9         1.6        2.3   

Certain separation costs

     —           (8.6     8.6        —           (8.6     8.6   
                                                  

Net Income from continuing operations attributable to QEP

   $ 92.8       $ 68.8      $ 24.0      $ 166.0         146.9      $ 19.1   
                                                  

Earnings per diluted share from continuing operations

   $ 0.52       $ 0.39      $ 0.13      $ 0.93       $ 0.83      $ 0.10   

Average diluted shares

     178.6         177.6        1.0        178.5         177.4        1.1   

 

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Revenue, Volumes and Prices

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  
     (in millions)  

Revenues

                

Natural gas sales

   $ 258.1       $ 260.6       $ (2.5   $ 529.1       $ 525.2       $ 3.9   

Oil sales

     80.0         44.7         35.3        142.3         89.6         52.7   

NGL sales

     16.5         9.0         7.5        33.7         18.1         15.6   

Gathering, processing and other

     123.5         80.4         43.1        221.4         162.3         59.1   

Marketing sales

     306.0         134.9         171.1        453.8         314.6         139.2   
                                                    

Total Revenues

   $ 784.1       $ 529.6       $ 254.5      $ 1,380.3       $ 1,109.8       $ 270.5   
                                                    

QEP Energy’s revenues for the three and six months ended June 30, 2011, derived from the sale of natural gas, oil and NGLs increased primarily due to increased production volumes and higher oil and NGL prices, offset by lower prices for natural gas, as follows:

 

     Three Months Ended
June 30,
 
     Natural
Gas
    Oil      NGLS      Total  
     (in millions)  

QEP Energy Revenues

          

2010 revenues

   $ 260.6      $ 44.7       $ 9.0       $ 314.3   

Changes associated with volumes(1)

     49.9        12.6         3.7         66.2   

Changes associated with prices(2)

     (52.4     22.7         3.8         (25.9
                                  

2011 revenues

   $ 258.1      $ 80.0       $ 16.5       $ 354.6   
                                  
     Six Months Ended
June 30,
 
     Natural
Gas
    Oil      NGLS      Total  
     (in millions)  

QEP Energy Revenues

          

2010 revenues

   $ 525.2      $ 89.6       $ 18.1       $ 632.9   

Changes associated with volumes(1)

     122.4        18.3         11.6         152.3   

Changes associated with prices(2)

     (118.5     34.4         4.0         (80.1
                                  

2011 revenues

   $ 529.1      $ 142.3       $ 33.7       $ 705.1   
                                  

 

(1) 

The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2011, to the three and six months ended June 30, 2010, by the average price or fee for the three and six months ended June 30, 2010.

(2) 

The revenue variance attributed to the change in price is calculated by multiplying the change in prices or fee from the three and six months ended June 30, 2011, to the three and six months ended June 30, 2010, by volume for the quarter ended June 30, 2011.

Gathering, processing and other revenues also increased for the three and six months ended June 30, 2011, as a result of higher volumes and improved processing and gathering fees.

 

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     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     Gathering
and
Processing
     Other      Total      Gathering
and
Processing
     Other      Total  
     (in millions)  

QEP Field Services and Other Revenues

                 

2010 revenues

   $ 71.2       $ 9.2       $ 80.4       $ 141.4       $ 20.9       $ 162.3   

Changes associated with volumes(1)

     11.3         —           11.3         17.0         —           17.0   

Changes associated with fees(2)

     13.5         —           13.5         15.6         —           15.6   

Changes associated with other factors

     —           18.3         18.3         —           26.5         26.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2011 revenues

   $ 96.0       $ 27.5       $ 123.5       $ 174.0       $ 47.4       $ 221.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2011, to the three and six months ended June 30, 2010, by the average price or fee for the three and six months ended June 30, 2010.

(2) 

The revenue variance attributed to the change in fees is calculated by multiplying the change in prices or fee from the three and six months ended June 30, 2011, to the three and six months ended June 30, 2010, by volume for the quarter ended June 30, 2011.

Marketing sales, which include QEP Energy purchased gas sales, were $171.1 million and $139.2 higher in the three and six months ended June 30, 2011, respectively. These increases were due to $156.0 million in purchased gas sales during the 2011 second quarter, which increased primarily related to gas purchases made in northwest Louisiana to fulfill pipeline shipping commitments.

Production

QEP Energy reported production of 64.7 Bcfe in the second quarter of 2011 compared to 53.7 Bcfe in the 2010 quarter, a 20% increase. During the first half of 2011 QEP Energy reported production of 130.6 Bcfe compared to 105.2 Bcfe in the first half of 2010. On an energy-equivalent basis, crude oil and NGL comprised approximately 12% and 11%, respectively, of QEP Energy’s second quarter and first half 2011 production. A summary of production is shown in the following table:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      2010      Change      2011      2010      Change  

QEP Energy production volumes

                 

Natural gas (Bcf)

     57.0         47.9         9.1         116.1         94.2         21.9   

Oil (Mbbl)

     873.6         681.6         192.0         1,636.6         1,359.4         277.2   

NGL (Mbbl)

     394.3         280.8         113.5         780.6         476.2         304.4   

Total production (Bcfe)

     64.7         53.7         11.0         130.6         105.2         25.4   

Average daily production (MMcfe)

     710.8         590.0         120.8         721.7         581.2         140.5   

A summary of natural gas production by major operating area is shown in the following table:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

QEP Energy – Natural Gas (Bcf)

                

Southern Region

                

Haynesville/Cotton Valley

     25.5         18.4         7.1        53.6         34.5         19.1   

Midcontinent

     8.0         6.6         1.4        15.8         14.8         1.0   

Northern Region

                

Pinedale Anticline

     17.0         15.7         1.3        32.4         30.4         2.0   

Uinta Basin

     3.4         3.7         (0.3     8.2         7.4         0.8   

Rockies Legacy

     3.1         3.5         (0.4     6.1         7.1         (1.0
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total production

     57.0         47.9         9.1        116.1         94.2         21.9   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

A summary of oil production by major operating area is shown in the following table:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

QEP Energy – Oil (Mbbl)

                

Southern Region

                

Haynesville/Cotton Valley

     10.5         15.9         (5.4     24.0         36.0         (12.0

Midcontinent

     191.8         159.3         32.5        356.5         324.9         31.6   

Northern Region

                

 

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Table of Contents
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

Pinedale Anticline

     139.2         129.8         9.4        269.8         254.8         15.0   

Uinta Basin

     233.4         235.3         (1.9     458.7         470.0         (11.3

Rockies Legacy

     298.7         141.3         157.4        527.6         273.7         253.9   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total production

     873.6         681.6         192.0        1,636.6         1,359.4         277.2   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

A summary of NGL production by major operating area is shown in the following table:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

QEP Energy – NGL (Mbbl)

                

Southern Region

                

Haynesville/Cotton Valley

     —           —           —          —           —           —     

Midcontinent

     339.3         229.6         109.7        664.8         370.4         294.4   

Northern Region

                

Pinedale Anticline

     —           —           —          —           —           —     

Uinta Basin

     25.2         30.8         (5.6     59.5         57.7         1.8   

Rockies Legacy

     29.8         20.4         9.4        56.3         48.1         8.2   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total production

     394.3         280.8         113.5        780.6         476.2         304.4   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

A summary of natural gas-equivalent production by major operating area is shown in the following table:

 

     Three Months Ended June 30,     Six Months Ended June 30,      Year Ended December 31,  
     2011      2010      Change     2011      2010      Change      2010      2009      2008  

QEP Energy – Total Production (Bcfe)

  

Southern Region

                         

Haynesville/Cotton Valley

     25.6         18.5         7.1        53.8         34.7         19.1         78.9         46.5         31.3   

Midcontinent

     11.3         9.0         2.3        21.9         19.0         2.9         41.5         41.3         36.5   

Northern Region

                         

Pinedale Anticline

     17.8         16.5         1.3        34.0         32.0         2.0         68.5         61.8         56.8   

Uinta Basin

     5.0         5.4         (0.4     11.4         10.6         0.8         21.4         23.2         26.9   

Rockies Legacy

     5.0         4.3         0.7        9.5         8.9         0.6         18.7         16.7         19.9   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total production

     64.7         53.7         11.0        130.6         105.2         25.4         229.0         189.5         171.4   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As shown in the table above, production from the Haynesville/Cotton Valley area continues trending upward from 2008. Continuing this trend, net production in the Haynesville/Cotton Valley area grew 38% to 25.6 Bcfe in the second quarter of 2011 compared to the second quarter of 2010 and represented 40% of the Company’s total production compared to 34% in the year earlier period. During the first half of 2011 net production from the Haynesville/Cotton Valley area was 53.8 Bcfe compared to 34.7 Bcfe in the comparable period, which represented 41% of the Company’s first half of 2011 total production compared to 33% in 2010. Haynesville/Cotton Valley area production growth was driven by ongoing development drilling in the Haynesville Shale play in northwest Louisiana.

Net production in the Midcontinent area grew 26% to 11.3 Bcfe in the second quarter of 2011 compared to the second quarter of 2010 and represented 17% of the Company’s total production for both 2011 and 2010 periods. During the first half of 2011 net production in the Midcontinent was 21.9 Bcfe compared to 19.0 Bcfe in the comparable period, which represented 17% of the Company’s 2011 total production compared to 18% in 2010. Midcontinent production growth was driven by continued development of the Granite Wash/Atoka Wash play in the Texas Panhandle and the Woodford “Cana” Shale horizontal gas play in the Anadarko Basin of western Oklahoma.

Net production from the Pinedale Anticline in western Wyoming grew 8% to 17.8 Bcfe in the second quarter of 2011 compared to the 2010 second quarter as a result of ongoing development drilling. The Pinedale Anticline net production during the first half of 2011 increased 6% to 34.0 Bcfe from the comparable period in 2010.

In the Uinta Basin, production decreased 0.4 Bcfe in the second quarter of 2011 but increased 0.8 Bcfe in the first six months of 2011, due to a first quarter 2011 prior-period adjustment of QEP’s ownership interest within a federal unit, which resulted in a positive adjustment to reported production volumes of 1.6 Bcfe.

 

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Rockies Legacy net production in the second quarter of 2011 increased to 5.0 Bcfe due to increased oil directed drilling activity in the North Dakota Bakken/Three Forks play. During the first half of 2011, Rockies Legacy net production increased by 7% to 9.5 Bcfe from the first half of 2010. Most of QEP’s wells in North Dakota have been connected to oil gathering lines during the first half of 2011 thereby eliminating future weather-related oil sales interruptions. QEP Energy Rockies Legacy properties include all Northern Region properties except the Pinedale Anticline and the Uinta Basin.

Pricing

Field level and realized prices (after hedges) for natural gas and NGLs at QEP Energy were lower than the prior year comparative period, while realized oil prices were higher when compared to the 2010 prior-year. A regional comparison of average field level prices is shown in the following table:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

QEP Energy – Average field-level natural gas price ($ per Mcf)

                

Southern Region

   $ 3.44       $ 3.65       $ (0.21   $ 3.40       $ 4.22       $ (0.82

Northern Region

     3.33         3.14         0.19        3.33         3.88         (0.55

Average field-level natural gas price

   $ 3.39       $ 3.40       $ (0.01   $ 3.37       $ 4.06       $ (0.69
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

QEP Energy – Average field-level oil price ($ per bbl)

                

Southern Region

   $ 94.03       $ 74.63       $ 19.40      $ 92.07       $ 74.64       $ 17.43   

Northern Region

     90.67         66.14         24.53        85.30         66.62         18.68   

Average field-level oil price

   $ 91.45       $ 68.32       $ 23.13      $ 86.88       $ 68.75       $ 18.13   
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010      Change     2011      2010      Change  

QEP Energy – Average field-level NGL price ($ per bbl)

                

Southern Region

   $ 40.00       $ 31.27       $ 8.73      $ 41.43       $ 37.32       $ 4.11   

Northern Region

     53.07         35.80         17.27        52.82         40.07         12.75   

Average field-level NGL price

   $ 41.82       $ 32.10       $ 9.72      $ 43.12       $ 37.93       $ 5.19   

A comparison of net realized average natural gas, oil and NGL prices, including the realized losses on basis-only swaps, which did not qualify for hedge accounting and are therefore not included in revenue, is shown in the following table:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011     2010     Change     2011     2010     Change  

Natural gas ($ per Mcf)

            

Average field-level natural gas price ($ per Mcf)

   $ 3.39      $ 3.40      $ (0.01   $ 3.37      $ 4.06      $ (0.69

Natural gas commodity derivative impact ($ per Mcf)

     1.13        2.04        (0.91     1.19        1.52        (0.33
                                                

Average revenue ($ per Mcf)(1)

     4.52        5.44        (0.92     4.56        5.58        (1.02

Realized losses on basis-only swaps ($ per Mcf)(2)

     (0.48     (0.57     0.09        (0.51     (0.66     0.15   
                                                

Net realized natural gas price ($ per Mcf)

   $ 4.04      $ 4.87      $ (0.83   $ 4.05      $ 4.92      $ (0.87
                                                

Oil ($ per bbl)

            

Average field-level oil price ($ per bbl)

   $ 91.45      $ 68.32      $ 23.13      $ 86.88      $ 68.75      $ 18.13   

Oil commodity derivative impact ($ per bbl)

     0.14        (2.66     2.80        0.07        (2.79     2.86   
                                                

Net realized oil price ($ per bbl) (1)

   $ 91.59      $ 65.66      $ 25.93      $ 86.95      $ 65.96      $ 20.99   
                                                

NGL ($ per bbl)

            

Average field-level NGL price ($ per bbl) (1)

   $ 41.82      $ 32.10      $ 9.72      $ 43.12      $ 37.93      $ 5.19   
                                                

 

(1)

Reported in revenues in the consolidated income statement.

(2)

Reported below operating income in the consolidated income statement.

 

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Table of Contents

Commodity Derivatives Impact

The Company enters into commodity derivative instruments to manage its exposure to price fluctuations on a portion of its forecasted natural gas and oil production. The impact of QEP’s commodity derivatives transactions on the Company’s financial statements for the periods disclosed is presented below. The net effect of the portion of natural gas basis-only swaps that do not qualify for hedge accounting is reported in the Consolidated Statements of Income below operating income. Derivative positions as of June 30, 2011, are summarized in Note 9 to the condensed consolidated financial statements in Item 1 of Part I in this Quarterly Report on Form 10-Q.

 

     Three Months Ended
June 30
    Six Months Ended
June 30
 
     2011     2010     2011     2010  

Volumes subject to commodity derivatives as a percent of gas production

        

Fixed price swaps

     46     79     44     79

Price collars

     12     3     12     4

Volumes subject to commodity derivatives as a percent of oil production

        

Fixed price swaps

     3     33     2     33

Price collars

     31     27     33     27

 

     Three Months Ended
June 30, 2011
    Six Months Ended
June 30,
 
     2011     2010     Change     2011     2010     Change  

Impact of settled commodity derivatives on financial statements (millions)

            

Natural gas sales

   $ 64.4      $ 97.5      $ (33.1   $ 137.5      $ 143.1      $ (5.6

Oil sales

   $ 0.1      $ (1.8   $ 1.9      $ 0.1      $ (3.8   $ 3.9   

Impact of settled commodity derivatives that do not qualify for hedge accounting (millions)

            

Unrealized gain (loss) on basis-only swaps

   $ 27.6      $ 27.4      $ 0.2      $ 58.8      $ 62.1      $ (3.3

Realized (loss) on basis-only swaps

   $ (27.6   $ (27.4   $ (0.2   $ (58.8   $ (62.1   $ 3.3   

The change in unrealized gains and losses on natural gas basis-only swaps increased the second quarter 2011 net income $17.3 million compared to an increase of $17.2 million in the second quarter of 2010. During the first half of 2011, net income increased $36.9 million from the impact of unrealized gains and losses on natural gas basis-only swaps compared to an increase of $39.0 million in the first half of 2010. As of December 31, 2009, all of the Company’s basis-only swaps had been paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of these derivative instruments subsequent to their re-designation were recorded in AOCI; however, changes in the fair value of these derivative instruments occurring prior to their re-designation were recorded in the Consolidated Statement of Income.

Gathering

QEP Field Services posted a 36% increase in gathering margin in the second quarter of 2011, primarily due to an increase in the liquids value received from a short-term, third-party gathering and processing arrangement and a 6% increase in gathering system throughput volume to 1.3 million MMBtu per day. QEP Field Service gathering margins increased 30% in the first half of 2011 as a result of an increase in the liquids value received from a short-term third-party gathering and processing arrangement and from a 5% increase in gathering system throughput volume to 1.3 million MMBtu per day. The increased volumes were mainly related to the northwest Louisiana gathering system, which accounted for 20% and 22% of the total throughput during the second quarter and first half of 2011, respectively.

 

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Table of Contents

Following is a summary of QEP Field Services’ financial and operating results from gathering activities:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011     2010     Change     2011     2010     Change  
     (in millions)  

Gathering Margin

            

Gathering revenues

   $ 38.7      $ 38.4      $ 0.3      $ 78.1      $ 74.4      $ 3.7   

Other gathering revenues

     25.0        7.9        17.1        42.7        18.6        24.1   

Gathering expense

     (12.4     (8.7     (3.7     (24.3     (18.6     (5.7
                                                

Gathering Margin

   $ 51.3      $ 37.6      $ 13.7      $ 96.5      $ 74.4      $ 22.1   
                                                

Operating Statistics

            

Natural gas gathering volumes (in millions of MMBtu)

            

For unaffiliated customers

     66.0        65.2        0.8        127.1        135.7        (8.6

For affiliated customers

     55.1        49.0        6.1        113.0        92.2        20.8   
                                                

Total Gas Gathering Volumes

     121.1        114.2        6.9        240.1        227.9        12.2   
                                                

Average gas gathering revenue (per MMBtu)

   $ 0.32      $ 0.34      $ (0.02   $ 0.33      $ 0.33      $ —     

Processing

Processing margin increased 92% in the second quarter 2011 and 59% in the first half of 2011 compared to the 2010 comparable periods, due to increased keep-whole processing margins and increased fee-based processing revenues. The increased keep-whole processing margin was mostly the result of increased NGL prices and volume. NGL prices increased 39% in the second quarter and 20% in the first half of 2011 compared to the 2010 periods. NGL volumes increased 36% in the second quarter and 25% in the first half of 2011 compared to the 2010 periods. Processing fees increased 36% during the second quarter 2011 when compared to the second quarter 2010, due to a 6% increase in fee-based processing volumes to 60.3 million MMBtu and a 31% increase in the processing fee rate. During the first half of 2011 processing fees increased 28% over the 2010 comparable period, due to a 6% increase in fee-based process volumes to 117.3 million MMBtu and a 19% increase in the processing fee rate. The increased processing volume was primarily the result of the start-up of the 150 MM per day Iron Horse cryogenic processing plant in the Uinta Basin of eastern Utah during the first quarter of 2011. Approximately 69% and 73% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing contracts in the three and six months ended June 30, 2011, compared to 77% and 78% during the three and six months ended June 30, 2010. The decline in the relative percentage of fee-based revenues was due primarily to the increase in keep-whole processing margins in 2011.

Following is a summary of QEP Field Services’ processing financial and operating results:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011     2010     Change     2011     2010     Change  
     (in millions)  

Processing Margin

            

NGL sales

   $ 45.1      $ 23.8      $ 21.3      $ 73.7      $ 49.7      $ 24.0   

Processing (fee based) revenues

     12.2        9.0        3.2        22.2        17.3        4.9   

Processing (expense)

     (3.1     (3.0     (0.1     (5.8     (6.0     0.2   

Processing plant fuel and shrinkage (expense)

     (11.4     (7.5     (3.9     (21.6     (17.9     (3.7
                                                

Processing Margin

   $ 42.8      $ 22.3      $ 20.5      $ 68.5      $ 43.1      $ 25.4   
                                                

Frac spread (NGL sales – processing plant fuel and shrinkage)

   $ 33.7      $ 16.3      $ 17.4      $ 52.1      $ 31.8      $ 20.3   

Operating Statistics

            

Natural gas processing volumes

            

NGL sales (MMgal)

     36.4        26.7        9.7        64.2        51.5        12.7   

Average NGL sales price (per gal)

   $ 1.24      $ 0.89      $ 0.35      $ 1.15      $ 0.96      $ 0.19   

Fee based processing volumes (in millions of MMBtu)

            

For unaffiliated customers

     33.1        30.4        2.7        64.5        58.5        6.0   

For affiliated customers

     27.2        26.7        0.5        52.8        52.3        0.5   
                                                

Total Fee-Based Processing Volumes

     60.3        57.1        3.2        117.3        110.8        6.5   
                                                

Average fee-based processing revenue (per MMBtu)

   $ 0.21      $ 0.16      $ 0.05      $ 0.19      $ 0.16      $ 0.03   

 

24


Table of Contents

Operating Expenses

The following table presents QEP’s total operating expenses and the changes from the three and six months ended June 30, 2010 to the three and six months ended June 30, 2011. The narrative below the table explains the significant variances between the periods.

 

     Three Months Ended
June 30,
    Six Months Ended
June 30
 
     2011      2010      Change     2011      2010      Change  
     (in millions)  

Lease operating expense

   $ 34.3       $ 28.6       $ 5.7      $ 67.1       $ 56.9       $ 10.2   

Gathering, processing and other

     27.2         19.6         7.6        52.4         43.1         9.3   

General and administrative

     28.7         25.7         3.0        60.4         50.9         9.5   

Separation costs

     —           14.0         (14.0     —           14.0         (14.0

Production and property taxes

     27.1         19.0         8.1        50.8         41.9         8.9   

Depreciation, depletion and amortization

     186.6         151.6         35.0        377.4         299.0         78.4   

Exploration expenses

     2.3         2.7         (0.4     5.1         6.3         (1.2

Abandonment and impairment

     5.3         9.3         (4.0     10.7         16.9         (6.2

Marketing purchases

     303.9         133.9         170.0        450.6         311.8